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Safety Evaluation Supporting Amend 163 to License DPR-72
	ML20199J306
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Site:	Crystal River
Issue date:	01/24/1998
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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 163 TO FACILITY OPERATING LICENSE NO. DPR-72 FLORIDA POWER CORPORATION. ET AL.

CRYSTAL RIVER UNIT N0. 3 NUCLEAR GENERATING PLANT QQCKETNO.50-302 1,0 INTRODUCTION This Safety Evaluation addresses Florida Power Corporation's application dated June 14, 1997, as sup)lemented September 25, and November 21, 1997, that proposed changes to tie Crystal River 3 Technical Specifications.

Table 1 provides a listing of_the acronyms and abbreviations used in this safety evaluation. Table 2 provides the list of TS and other changes that are addressed in this safety evaluation. The licensee's submittal identified this request as TSCRN 210.

The proposed thanges are related to small break loss of coolant accident mitigation and emergency diesel generator upgrade. The proposed changes are necessary as a result of the licensee's latest accident analyses and certain hardware changes. The hardware and TS changes are associated with the EFW, HPI. EFIC systems, and the EDGs.

Changes to licensing and design bases associated with these systems, and TS for certain other supporting systems are also proposed.

The licensee made its original request on June 14, 1997, and as required by 10 CFR 50.91(a), provided its analysis of the issue of no significant hazards consideration which was noticed in the Federal Register (62 FR 52581) on October 6. 1997.

In response to requests for additional information by staff's letters dated September 10, and November 5, 1997, and other meetings with the licensee, FPC provided additional sup>orting information by letters dated August 4. September 2. and Novem]er 5, and 15.

and December 3, 5, 11, and 24, 1997, and January 15, and 22, 1998. This additional information provided clarification, technical supporting details or proposed more restrictive conditions such that the changes did not affect the original no significant hazards consideration.

2.0 BACKGROUND

Concerns which led to these proposed changes were initially discovered by the licensee during a September 1996 forced outage and identified to the staff in a licensee submittal dated October 28, 1996 and described in LER 96-024-001 dated February 14. 1997.

FPC determined that a previous modification to the EFW system during the 1996 refueling outage (Refuel 10) created an Unreviewed Safety Question (US0) regarding EDG loading. While preparing a TSB change to address the EDG loading issue, additional questions arose regarding the modification to the EFW system.

These questions necessitated evaluation of EFW system failure modes including reliance on the turbine-driven (Train "B")

EFW pump for load management (includes securing the motor-driven EFW pump) jgg20;ggg,gg;ggg,

2 associated with the Train "A" EDG (EDG-1A) to ensure that the system could perform its safety function.

Due to the EFW/EDG issues and other design-related issues, the licensee decided to extend its voluntary plant shutdown until all of the issues were adequately addressed.

In (,AL 2-97-001 dated March 4,1997, the staff confirmed the required actions to be completed prior to CR-3 restart.

As part of its resolution of design issues the licensee identified that several plant modifications and operator actions would be recuired to mitigate the consequences of certain SBLOCAs with concurrent LOOP. anc certain single failures. The licensee also determined that a number of TS changes are necessary to reflect these modifications and operator actions.

Based on its analyses, the licensee determined that there are three limiting EDG capacity-related single failures for SBLOCA/ LOOP scenarios involving LOBA.

LOBB, and loss of the turbine-driven EFW pump.

Certain SBLOCA break sizes require EFW to maintain primary to secondary cooling via the steam generators until the reactor core decay heat can be removed solely by HPI and LPI flow via the break. The licensee determined that EFW is required for a period of time (time is variable and is dependent on the particular scenario and single failure) after the SBLOCA. even with two HPl pumps providing injection flow.

The licensee is addressing the above issues through a combination of plant and operational modifications. These modifications result in TS. FSAR and E0P revisions. Therefore. the licensee's June 14, 1997 submittal re than just staff review and approval of the proposed TS changer. quested more It also requested specific staff review of associated integrated design and operating strategies (modifications / procedures and their supporting accident and transient analyses and required manual operator actions) to resolve the identified US0s.

Some of the proposed TS changes are intended as interim measures and will be applicable for one cycle. Fuel Cycle 11.

Prior to Fuel Cycle 12. the licensee plans to assess and implement appropriate permanent actions to address the EDG capacity limitations.

The two primary oations under consideration by the licensee are to (1) modify the existing EDGs further increasing their capacity or (2) install a diesel-driven EFW pump.

Prior to the beginning of Cycle 12.

the licensee will submit another TS change request to reflect the resolution of the EDG capacity limitations and to remove the interim measures proposed in the TS changes described herein.

2.0 DISCUSSION The licensee's initial submittal included seven attachments (Attachments A through G). The licensee requested specific staff review of Attachments B through F which provided specific proposed TS changes and supporting technical information. Following is a summary of the Attachments B through F:

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3 2.1 Attachmont B - Safety Assessment Attachment B describes the three SBLOCA scenarios of concern and. heir proposed solution sets and provides a safety assessment of the accident solution sets based on specific plant modifications and resulting E0P changes.

The licensee's safety assessment confirmed the importance of EFW for SBLOCAs and presented its program for EDG load management to ensure that the EDGs are not overloaded.

2.2 Attachment C - Technical Soecification Chance Reouest Notice 210 Attachment C provide; the licensee's proposed TS revisions to reflect the new accident mitigation strategy / analysis and resolve the SBLOCA-related issues.

The proposed TS changes are divided into three major parts:

(1) SBLOCA mitigation. (2) EDG upgrade and (3) EDG Load Rejection Test and Steady State Loads. Table 2 provides a list of proposed TS cWnges and identifies them appropriately as bein permanent TS changes.g applicable for one cycle (Cycle 11) only or as 2.2.1 Part 1 - SBLOCA Mitiaation The TS and associated Bases are being changed to reflect the lmost recent analysis for the SBLOCA/ LOOP ad single failure scenarios.

Licensee analyses have shown that for certain sized breaks, a combination of ECCS flow to the reactor vessel and EFW flow to the OTSGs is needed to provide for adequate core decay heat removal.

Due to the expected load and ca>acity limits on EDG-1A the length of time that the EFP-1 would be ava11aale is limited. To ensure adequate EFW flow, other actions must be taken.

These actions would include extending the time EFP-1 would be available by managing the load connected to EDG 1A and/or by taking cction to provide EFW flow using EFP-2.

This will be accomplished by opening the cross-tie valve between the EFW pump discharge paths.

Specifically, the licensee proposed changes to TS 3.5.2 "ECCS - Operating "

TS 3.7.5 " Emergency Feedwater (EFW) System " TS 3.7.7 " Nuclear Services Ciosed Cycle Cooling Water (SW) system." TS 3.7.8 " Decay Heat Closed Cycle Cooling

[DHCCC System." TS 3.7.9 " Nuclear Services Seawater System." TS 3.7.10

" Decay Heat Seawater System." TS 3.8.1 "AC Sources - Operating." and TS 3.8.9

" Distribution Systems - Operating."

In addition, the licensee a new specification. TS 3.7.18 " Control Com31ex Cooling System.preposed to add Changes to the associated Bases sections for each of t1ese TS sections and some other unrelated Bares sections have also been proposed.

In sumary. TS 3.7.5 for the EFW system has been revised to add a new Action Statement D to require within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , verification of the operability of SWP-IB: Train B of the nuclear services seawater system: Train B of the control complex cooling system; and both trains of the ECCS, DC system. decay heat seawater system. EDGs AC electrical power distribution subsystem, and AC vital bus subsystem when EFP-2 is inoperable. Corresponding action statement requirements have been added to the TS for ECCS (3.5.2). SW (3.7.7). DHCCC (3.7.8), nuclear services seawater (3.7.9). decay heat seawater (3.7.10).

control complex cooling (3.7.18 - new). the EDGs (3.8.1), and the distribution

4 system (3.8.9). The proposed changes to these TS sections specify actions to verify within I hour that EFP-2 and its associated flow path are operable. -for certain inoperabilities of the associated equi) ment. Some of these proposed changes for system cross-tie dependencies and EDG load management would be required through the remainder of Cycle 11 only.

2.2.2 Part 2 - EDG Uoarade The required minimum inventories of the EDG fuel oil-storage tanks lube oil storage, and day tanks were increased. Also, the maximum and minimum EDG load capacity limits for the refueling interval test increased and the Background.

LCO. - Actions and SR sections of the TSB are being revised accordingly. The Action requirement for EDG stored lube oil is revised to clarify that the lube oil storage is common to both EDGs. Additionally, the SR Basis for the lube oil is clarified to ensure sufficient oil for one EDG, rather than each EDG.

The SR Basis for the refueling EDG load test is revised for a test that bounds the maximum expected accident -loads.

Specifically, the licensee proposed to change SR 3.8.1.4. to increase the t

minimum required EDG day tank volume from 245 gallons to 280 gallons and-t SR 3.8.1.11 to increase the minimum required-test (24-month test) load from 3100 kW to 3300 kW. and increase the maximum load for the test from 3250 kW to 3400 kW. TS 3.8.3. Action A (minimum fuel oil storage tank volumes) has been revised to reflect that the lower volume of stored fuel for each EDG11s being changed from 15.933 to 19.643 gallons, and that the upper volume is changed from 18.589 to 22.917 gallons. The minimum combined stored fuel oil specified in TS 3.8.3. Action A has also been increased from 37.177-to 45.834 gallons.

The associated SR 3.8.3.1 has also been changed to require a minimum of 22.917 gallons for a single tank and 45.834 gallons for combined fuel oil storage.

TS 3.8.3. -Action B (minimum lube oil volume) has been revised to reflect that-thelowervolumeoflubeoilinventoryfortheEDGsisbeingchangedfrom200 to 240 gallons, and the upper volume is being changed from c33 to 280 gallons.

4 The associated R 3.8.3.2 will be changed to require a minimum volume of 280

-gallons. The Action requirement for lube oil storage has also been clarified to reflect that both EDGs should be declared inoperable when the storage volume is below the minimum level because the volume is common to both EDGs.

The upper volume limits : identify the TS volume required for 7 days of EDG operation, while the lower volume limits assure that during the A0T for the upper volume, at least a 6-day supply remain available.

2.2.3 Part 3 - Load Reiection Tests & Steady State loads This aart involves changes to TSB 3.8.1 "AC Sources - Operating." to assure that EDG testing adequately demonstrates that EDGs are capable of rejecting the largest single load without exceeding predetermined limits and EDG tests are not invalidated by loads im)osed by the starting of motors. Specifically the changes would affect the TS3 for SR 3.8.1.8 (EDG load rejection test).

SR 3.8.1.11 (Refueling EDG load test) and the Background section of TSB 3.8.1.

The basis for the EDG load rejection test is revised to bound the recently calculated largest single load.

The Bases of the Background for TS 3.8.1 is

5 revised to provide a description of " steady state" with examples of short duration loads and loads imposed by the starting of motors.

The Bases for the refueling load test is revised to indicate that the EDG tests are not invalidated by loads imposed by the starting of motors such as during block loading.

2,3 Attachment D - Framatome Document FTI 51-1266138-01 Attachment D provides the FTI safety analyses and evaluations of accident mitigation challenges to the SBLOCA solution sets.

These evaluations include a limited use of RELAP5.

The FTl document is partially based on calculations performed and data provided by the licensee.

2.4 Attachment E - Assessment of limited lise of RELAP5 The analvis in Attachment D provides a summary of FTI's evaluation of certain SBLOCA scenarios. The FTl evaluation used, in part, a staff approved RELAP5 evaluation model. This code was addressed for B&W plants in Topical Report BAW 10192-P, "BWNT Loss-of Coolant Accident Evaluation Model For Once-Through Steam Generator Plants."

In a February 18, 1997, letter to FTI. the staff approved the Topical Report for referencing in licensing applications involving LOCAs for OTSG piants.

However, the staff conditioned its approval for using the Topical Report based on satisfying eleven conditions. Hence.

Attachment E addresses taese eleven conditions and is intended to provide information to assure they are satisfied.

2.5 Attarhment F - Suonortino Information To address the SBLOCA scenarios and the EDG capacity Attachment F provides a description of the 1) resolution of US0s, 2) modifications, 3) operator actions, 4) FSAR changes, and 5) related LERs.

2.6 Risk Persoectives The licensee (letters dated December 3.1997 and December 24, 1997) also provided information related to their estimation of CR-3 plant core damage frequency contribution from SBLOCA/ LOOP accident sequences. Based on its analysis, the licensee concluded that the changes in procedures and the new load management strategies proposed by TSCRN 210 do not have an appreciable effect on the core damage frequency at CR-?

The licensee estimated the initiating event frequency of SBLOCA/ LOOP as 2.24E-5/Yr. using the method described in NUREG/CR-6538. ' Evaluation of LOCA with Delayed LOOP and LOOP with Delayed LOCA Accident Scenarios -

TSCRN-210 indicated that the limiting transients affecting the EDG loading and EFW were identified as both the initiating event of LOCA/ LOOP and three limiting single failures.

These three single failures included LGBA. LOBB and loss of EFP-2.

whose failure rates were estimated to be 4.49E-2, 4.49E-2. and 5.7E-2.

respectively. Taking into accoent these single failures, the licensee reported that the largest sequence frequency, without taking credit for any operator or equipment mitigation, is 1.28E-6/Yr.

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6 The licensee reported that if both the operator actions aroposed in TSCRN-210 and the equipment needed to perform a mitigation to the _0CA/ LOOP initiating event and the above single failures are credited, the risk would be significantly low. This conclusion was based on the licensee's sensitivity analysis which showed that even if human error probabilities of the new operator actions were assumed to be 1.0. the core damage frequency from all internal events would increase by 3.2E-7/Yr (increase from 7.19E-6/Yr to 7.51E-6/Yr).

The main reason for this relatively small increase was credited to the availability of feedwater pump-7 JWP-7) which was recently installed with its own dedicated diesel generator.

It is noted that although CR-3 has procedures to ensure availability and reliability of FWP-7. this pump nor its dedicated diesel generator are not within the current plant TS re nor are they tracked under the current maintenance rule criteria.quirements The licensee estimated that even 'c FWP-7 is not c" edited in the analysis (in addition to not taking credit for operator actions), the core damage frequency would increase by 3.31E-6/Yr.

The licensee's estimate of risk increase due to LOCA/ LOOP along with the above single failures is not considered to be significant.

Nevertheless. +5e analysis indicates that FWP-7 plays an important role in reducing tne risk contribution from LOCA/ LOOP should the pro would raise the CDF by approximately 50%. posed operator actions fail, i.e..

The licensee did not provide details of its risk analysis and staff did not review or perform independent verification of the numerical results of the licensee's analysis.

3.0 EVALUATION This evaluation has been divided into 9 sections to coincide with the licensee's submittal (Attachments B through F) to the extent practical, and to reflect the various aspects of the staff's review.

Sections 3.4 and 3.5

_ provide the staff's evaluation associated with the electrical aspects (EDG upgrade), and Section 3.9 provides the staff's evaluation of the human factors aspects of the pro)osed. operator actions and procedure changes. The remaining sections r :tlect t7e systems and analysis aspects of the review including the licensee's overall accident mitigation strategy. The proposed TS changes (systems and electrical) are evaluated in Sections 3.4 and 3.5.

3.1 EFW "vstem Descriotion/ Analysis The EFW system at CR-3 consists of a motor-driven pump train (Train A) and a turbine-driven pumrtrain (Train B).

Each of the two trains normally supply both OTSGs via an EFW supply nozzle in each generator.

The discharge line from each EFW pump splits into two distribution headersLfor a total of four distribution headers. Each of the motor-driven pump headers combines with one of the turbine-driven pump headers to-form a single injection line into the OTSG EFW nozzle.

Each distribution header contains a motor-operated block valve and an air-operated flow control valve in series for a-total of four block valves and four control valves. All eight valves rel and motive power (solenoid valves for air-operated valves) y on DC for control such that they are available without EDG operation.

Each series block valve / control valve combination has a Train A/ Train B or Train B/ Train A DC power supply combination.

For the turbine-driven pump train (Train B) the block valves

7 are powered from DC Train A (DC-A) while the control valves rely on )ower from DC Train B (DC-B). For the motor-driven pump train (Train A). tie block valves are powered from DC-B and the control valves are powered from DC-A.

Upstream of the block and control valves. a cross-tie header provides the capability to cross-connect the discharge of each EFW pump before it splits into the distribution headers. The cross-tie header currently contains two normally closed manual isolation valves (modifications associated with this request will replace one of the manual valves [EFV-12] with a remotely controlled MOV and the other manual valve [EFV-13] will be maintained open).

Steam is directed to the turbine-driven pump from each OTSG via a normally open DC powered (DC B) MOV associated with each steam generator.

Downstream of the open MOVs the piping joins to form a common header before it splits, providing steam to the turbine via two normally closed. DC powered automatic isolation valves (ASV-5 [DC-B] and ASV-204 [DC-A]). The opening of either ASV-5 or ASV-204 starts the turbine-driven EFW pump.

In addition to the EFW system pumps there is a nonsafety-related motor-driven AFW pump. FWP-7. which takes suction from the CST and discharges into the EFW injection line of each OTSG (downstream of all EFW discharge valves). The AFW pump discharge header splits and flow is directed to each EFW injection line via a manual isolation valve and an air-operated AFW flow control valve.

FWP-7 is not powered by the emergency power supplies.

However, the licensee has proposed modifications to install a dedicated nonsafety-related diesel generator and to have remote-start capability of both the diesel generator and FWP-7 from the control room. While not credited in the SBLOCA analyses. FWP-7

"(FWsystenoperation.rovides defense-in-depth protection for SBLOCAs and other scenario Existing EDG-1A load capacity limits prohibit concurrent operation of EFP-1, with either the decay heat (low pressure injection) pump DHP-1A or the Train A control complex chiller, when the reactor building spray pump BSP-1A is operating.

To help prevent EDG-1A overloading. an earlier plant modification

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(circa 1990) installed an EFP-1 auto-trip function based on LOOP and concurrent LPI actuation.

For this modification it was assumed that if the break depressurized the RCS to the LPI actuation setpoint. then EFW would no longer be required to mitigate the accident.

It was further assumed that EFP-2 would always be available.

The consequences of a SBLOCA with a concurrent LOOP and loss of EFP-2 as the single failure were not previously analyzed with respect to the subsequent loss of EFP-1 due to the auto-trip function, or the need to shutdown EFP-1 to support ECCS aiggyback operation (LPI pump discharge supplying HPI pumps). The loss of E P-1 under these circumstances could potentially challenge successful accident mitigation and

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the licensee, therefore. determined that further evaluation was needed.

The licensee's TSCRN-210 submittal includes the results of that additional evaluation. The overall resuit is to provide adequate EDG load management and ensure the operability of EFP-2 when necessary w ch that EFP-1 would not have to be secured until after it is no longer requi. d for decay heat removal.

ASV-204 (steam admission valve) was initially installed as a Train B component (installed during another earlier modification in 1985) to improve the reliability of EFP-2 (ASV-05 was also powered from DC-8). ASV-204 was subsequently reconfigured in 1987 as a Train A component such that it derived

8 power from the Train A DC power supply and would open by a signal generated in Train A of the EFIC system.

This new configuration reduced EDG-1A auto-connected load by virtue of EFP-2 starting and sharing EFW flow with EFP-1 during a Train B ES failure (prior to this modification. ASV-05 and ASV-204

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would not have opened to start EFP-2 on loss-of ES Train B).

It-was later determined that for this configuration (ASV-204 powered from DC-A/EFIC-A), a failure of DC power Train B could result in a loss of EFP-2 due to ina'dequate net NPSH.

This condition would develop due to the loss of control and motive power to the two EFW Train B flow control valves (EFV-55 and EFV 56) in the distribution headers of the turbine-driven pump train.

The flow control valves are air-operated (AO) and designed to fail open on loss of air or control (DC-B) power.

and uncontrolled flow resulting in possible loss of NPSH.As a result. EFP-2 w OTSG overfill protection would still be maintained by the EFW Train 8 block valves EFV-11 and EFV-32 which receive power from DC Train A.

Therefore, to prevent EFP-2 from starting under these conditions, the EFIC-A signal tt. open ASV-204 was removed b Train B).y a 1996 modification (ASV-05 would remain closeo during a loss of DC The unavailability EFP-2 created a condition such that no credit could be taken for reduced load on EDG-1A (EFP-1 supplying all EFW flow) which challenged the EDG load calculations.

The EFIC-A signal will be reconnected as part of the proposed mee cations included in support of this TS change To allow this r.. ;,nection, the licensee will add cavitating request.

venturis at the discharge of each EFW pump to limit the flow (control valves fail wide open) sufficiently to maintain an adequate NPSH for each pump under all postulated pump discharge pressure conditions.

Thus. EFP-2 will be available following loss of ES Train 8 to reduce the load on EDG-1A from EFP-1.

3.2 Attachment B - Safety Assessment Certain size SBLOCAs require EFW to maintain OTSG cooling until the reactor core decay heat can be removed solely by HPI cooling.

determined that EFW is required for some period of time even with two HPIThe licen pumps providing injection flow.

The significance of this new information increases the importance of maintaining EFW availability.

EFW is required following a SBLOCA for a period of time which is a function of decay hett load, sizt and location of the RCS break, and HPI flow (reaching the RCS).

The licens Ts analysis indicates that EFW is required for approximately 35 hours4.050926e-4 days 0.00972 hours 5.787037e-5 weeks 1.33175e-5 months if only one HPI pump is operating.

If two HFI pumps are operating. EFW is re Therefore, for a SBLOCA. quired until piggyback operation is established.

EFW mission time is a function of how many HPI pumps are operating or how much HPI flow reaches the RCS.

If a loss of EFW occurs after the mission time is achieved, then adequate core cooling will be accomplished by HPI/ break flow. The purpose of the licensee's safety assessment is to demonstrate EFW availability for those accidents that require its use.

During its assessment the licensee reviewed the DBAs and licensing basis accidents from FSAR Chapter 14 that require ECCS/EFW systems response to mitigate the accident consequences.

Various single failures were analyzed to determine the most limiting combinations from an EFW and EDG loading U

9 perspective.

Various pump. EDG, and battery failures were postulated. The following three failures were determined to be limiting:

(1) failure of Battery A or its associated distribution panel, or (2) failure of Battery B or its associated distribution panel, or (3) failure of the steam turbine-driven EFW pump. EFP-2.

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The licensee examined each accident with the three identified single failures in order to determine which accident created the greatest challenge for maintaining the required ECCS and EFW operation within the EDG load limits.

Of the accidents analyzed. the SBLOCA creates the largest load on the EDGs as it potentially involves the operation of all ECCS components and EFW.

For a SBLOCA. an automatic reactor trip occurs on lowering RCS pressure or a manual trip is initiated based on lowering pressurizer level coupled with high makeup flow.

The analysis assumed that a LOOP occurs coincident with the reactor / main turbine trip as this has been determined to be the lost limitirg accident scenario. An ES actuation occurs when RCS pressure decreases to 1500 psig.

Both EDGs automatically start and supply emergency power to tiieir respective busses.

E 3.2.1. Loss of Batterv 'A' (LOBA) 3.2.1.1 Failure Scenario This failure results in a loss of Train A of ECCS. EDG-1A. and EFP-1.

EDG-1A starts but does not load due to the loss of DC-A power.

EDG-1B starts and supplies power for the Train B auto-connected loads. One HPI pump (MVP-1B or MVP-1C) will be available to provide inventory makeup and some core cooling.

One EFW pump. EFP-2, will automatically start (via ASV-5) to supply the OTSGs to maintain secondary side cooling.

OTSG cooling must be maintained for approximately 35 hours4.050926e-4 days 0.00972 hours 5.787037e-5 weeks 1.33175e-5 months . or until decay b.t can be removed by HPI/ break cooling alone.

The 'B' CHHE-1B and its associated chilled water pump. CHP-1B, will be manually loaded on EDG-1B within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

3.2.1.2 Accident Mitiaatina Challences for LD M The licensee's LOCA cooldown procedure (EOP-08) provides gidance to initiate an RCS cooldown using TBVs or AnVs. However, the ADVs and TBVs are not credited in the accident analysis.

In this case (LOBA) only one ADV 15 available to lower OTSG pressure. FTI developed 0TSG pressure profiles based on realistic and Appendix K decay heat values (Attachment D to licensee's submittal). The licensee's integrated safety assessment (accident mitigation strategy) relied on 10 CFR 50. Appendix K values for determining the required EFW inventory and times available for various operator actions. The staff has reviewed Attachment D and concluded that the analysis is acceptable for reference (see Section 3.6 of this evaluation) as it uses bot, Appendix K decay heat values and realistic decay heat values in the final analysis for determining required EFW inventory and time available for operator actions.

Based on tne FTI analysis, the steam drawn by EFP-2 is sufficient to depressurize the OTSGs and that for some SBLOCAs, OTSG pressure would decrease below 200 psig with a corresponding reduction in RCS pressure.

FTI. the licensee, and IDR the vendor for the EFP-2 turbine, collectively determined

10 that EFP-2 could continue operation with OTSG pressure down to 20 psig.

Recent testing by IDR on a pum) similar to EFP-2 confirmed that at an inlet pressure of 20 psig. EFP-2 turaine speed would be about 1080 rpm. With the recently installed venturis this turbine speed would result in a total EFP-2 flow rate of 280 gym.

By the time the OTSG pressure could be reduced sufficiently for E P-2 to be challenged. decay heat would have been reduced to a point where 200 gpm would be more than adequate to remove decay heat based on Appendix K decay heat values.

However, to prevent challenging EFP-2 over the mission time for OTSG cooling, operation of EFP-2 will be managed by securing the turbine (closing ASV-5 [ASV-204 did not open due to LOBA]) if 0TSG pressure reaches 200 psig.

Once OTSG pressure recovers (after closing ASV-5), then EFP 2 can be placed back in service. The licensee has incorporated such guidance into the appro)riate procedures (see Sections 3.8 and 3.9 below). Based on its review of t1e licensee's analysis the staff concludes that the licensee's pro)osed management of EFP-2 operation is acceptable and that reliance on EJP-2 under the conditions identified is also acceptable.

In its evi on, the staff gave consideration to the fact that the plant conditions iequiring such operation is highly unlikely given the availability of FWP-7 (as modified) and the future availability of EFP-1 after Cycle 11.

There are also several additional methods for assuring OTSG cooling. These methods while not fully qualified. are considered to be available at different times in the accident as described below.

(1) FWP-7 is powered by a newly installed diesel generator with start capability from the control room.

The isolation valves, located in the intermediate building could be opened to allow use of FWP-7 within the first couple of hours into the event.

(2)

Auxiliary steam from Units 1 and 2 could be lined u) to EFP-2 within several hours.

This steam source is normally available wit1 the supply line kept warm.

It connects to the auxiliary steam distribution header in the turbine building.

(3) The recovery of offsite power would restore EFP-1 and other Train A equipment.

3.2.2 Loss of Batterv *B' (LOBB) 3.2.2.1 Failure Scenario This failure results in a loss of ECCS Train B and EDG-1B which starts but does not load due to the loss of DC-B power.

EDG-1A starts and supplies emergency power for the auto connected Train A loads. One HPI pump (MVP-1A or MUP-18) will be available to provide RCS makeup and some core cooling.

As with a LOBA. EFW is required for approximately 35 hours4.050926e-4 days 0.00972 hours 5.787037e-5 weeks 1.33175e-5 months based on Appendix K decay heat and only one HPI pump available.

EFP-1 automatically starts to supply the OTSGs with EFW flow to maintair secondary side cooling.

EFP-2 starts as a result of the EFIC-A actuation which opens ASV-204.

The flow control valves for EFP-2. EFV-55 and EFV-56. would fail open resulting in uncontrolled (limited by cavitating venturi) EFW flow to the OTSGs.

3.2.2.2 Accident Mitiaatina Challenaes for LOBB EFP-1 operation is limited by EDG-1A loading capability.

EFP-1 must be secured prior to reaching any one of the following operational limitations:

11 (1) establishing control complex cooling which requires starting the CHHE Train A chiller and support systems within I hour. (2) starting DHP-1A to support EO 3 piggyback operation when the BWST reaches the swapover level, or (3) receiving an LPI actuation (approximately 500 psig RCS pressure) based on operator induced cooldown which automatically trips EFP-1.

Prior to losing EFP-1 for any of the above reasons. EFW will be cross-connected by opening motor-operated isolation valve EFV-12 (motor optrator added by modification) which will be accomplished within the Train A 480 volt ES switchgear room. This routes E.cW flow from EFP-2 through the o Train A side flow path (via flow control valves EFV-57 and EFV-58)perable The Train B side flow path to each OTSG would be isolated by the operator closing EFV-11 and EFV-32 which are DC-A powered MOVs.

EFP-2 would be operating with EFW flow limited by the newly installed cavitating venturi until the Train B EFW isolation valves are closed.

Since the EFP-2 flow control valves EFV 55 and EFV 56 would fail open and be unable to control flow the EFW block or isolation valves. EFV-11 and EFV-32 will close if and when the OTSG overfill setpoint is reached.

As OTSG 1evels decrease to the overfill reset setpoint. the EFW block valves would re-open allowing flow to the OTSGs.

In its September 25. 1997 submittal, the licensee provided the results of a block valve cycling evaluation which indicated that there will be no challenge to the valve / operator within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Since EFW will be cross-connected to allow securing EFP-1 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to start CHHE-1A. the EFW block valves will function as needed. Also, as discussed later, analyses show that chilled water to the control complex cooling heat exchangers is not needed for over 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (approximately 80 minutes).

The same three additional defense-in death methods of assuring OTSG cooling for the LOBA scenario above (para 3.2.1'.2), are potentially available for the LOBB scenario.

Based on its review of the licensee's analysis, the staff concludes that the licensee's 3roposed management of EFP-1 operation and that cross-connecting EFP-2 under tie conditions identified for achieving necessary EFW flow are acceptable.

3.2.3 Loss of EFP-2 3.2.3.1 Failure Scenario This failure results in a loss of the steam-driven EFW pump. Both EDGs start.

and provide emergency power for both trains of auto-connected loads.

EFP-1 provides EFW to the OTSGs while two HPI pumps provide RCS makeu) and some core cooling. Control complex cooling is established by operating tie Train B chiller, loaded on EDG-1B.

3.2.3.2 Accident Mitiaation Challences EFP 1 operation is limited by EDG-1A load capability.

EFP-1 must be secured arior to reaching either of the following operational limitations, absent an EDG-1A load management strategy: 1) BWST depletion which requires star"ng DHP-1A to support ECCS piggyback operation, or 2) rece13t of an LPI at mation based on operator induced cooldown which trips EFP-1.

3rior to losing EFP-1

o 12 for either of these two reasons it must be demonstrated that EFW will no longer be required to mitigate the accident or event.

With two HPI aumps operating. EFW is required until the BWST has emptied and the ECCS has aeen reconfigured for piggyback operation. The licensee's analysis determined that the higher HPI flow achieved in the piggyback alignment effectively reduces EFW requirements to 1.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . However, the BWST would not reach the level at which transfer to the RB sump occurs until 2.7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months into the accident.

Therefore. EFP-1 could be shutdown at the time ECCS piggyback is establ'.shed and still mitigate the accident.

If OTSG cooling is a contributing factor to RCS cooldown (as opposed to HPI/ break alone), then the E0P provides guidance for managing cooldown rate within limits by adjusting TBVs or ADVs as necessary.

If RCS pressure decreases as a result of HPI/ break alone, calculations have shown that OTSG cooling is not needed. Additional guidance will be )rovided to the operators to control cooldown to maintain RCS pressure above tie EFP-1/LPI interlock setpoint until either EDG load management is accomplished (which includes defeating the interlock) or another source of EFW (such as FWP-7) can be supplied to the OTSGs.

A new HPI line isolation criterion was developed to address one and two HPI Sum) operation.

If the highest HPI line flow indicates greater than 50 gpm ligier than the next highest-reading line. then the highest flow HPI line will be isolated.

This new criterion is applied throughout the accident with HPI in an unthrottled condition and normal makeup isolated.

One of the purposes for developing the new isolation criterion, especially for the two H)I pump case, was to determine EFW mission time. As noted earlier, if two HPI pumps are operating. then EFW is required until piggyback operation is established.

During the course of the evaluation, the licensee determined that a single failure to isolate a broken HPI line (a postulated SBLOCA) results in the need to maintain EFW flow for a much longer period of time.

However, with both trains of ECCS and EFW available (assumed single failure was inability to isolate broken HPI line). OTSG cooling and thus adequate core cooling is assured.

Maintaining EFW flow via EFP-11s important to accident management, and EDG load management will be employed to that end.

Procedural guidance will provide the framework to control EDG load management. Train A SWPs and RWPs.

SWP-1A and RWP-2A. are not needed to manage the accident and can be secured 3rovided their counterparts (SWP-1B and RWP-2B) are operating. A subsequent ES signal would restart the secured pumps thus undermining the strategy and potentially overloading the EDG, Therefore. the licensee has installed PTL switches on the main control board for SWP-1A. SWP-1B. RWP-2A, and RWP-2B to prevent automatic restart on a subsequent ES actuation.

For this scenario, only SWP-1A and RWP-2A would be placed in the PTL position. This will allow starting DHP-1A to support ECCS piggyback operation while maintaining EFP-1 o)erating. Another modification has been made to install a " defeat" switch in t1e control room which would bypass the EFP-1 auto-trip on LPI actuation, with a concurrent LOOP. This will allow DHP-1A to automatically start without having to secure EFP-1.

Prior to defeating the EFP-1 auto-trip, che EDG load management discussed above must first be accomplished and will be controlled by procedural guidance.

13 For the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months EFW block valve cycnng concern identified for LOBB. the licensee performed calculations based on the number of cycles the valves would experience, the OTSG overfill and reset setpoints, and the time limits for cycling the valves.

EFW block valve cycle time has been conservatively limited to the time to reach the design temperature of the motor operator, which is a function of the number of cy.les, the stroke time, and the ambient temperature postulated in the vicinity of the valves, and reflects revised setpoints for the overfill and reset settings. The calculations were based on a stroke time which is conservatively greater than the stroke time acceptance criteriaforsurveillancetestingofthevalves.

The ambient temperature assumed is based on the licensee s Environmental Qualification Program, which documents the temperature postulated in the intermediate building after 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months assuming a-loss of ventilation.

The results of the licensee's calculations determined that the valves would be capable of cycling for the minimum required I hour period. The staff has reviewed the assurrations used in the licensee analysis for block valve cycling and concludes t1at they are conservative and, if necessary the block ialves should be capable of cycling for the requited 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The staff therefore, concludes that reliance on the EFW block valve operation for the accident mitigation / load management 3

strategies is acceptable.

j In support of the proposed load management strategy for LOBA and LOBB, the l

licensee also performed calculations to verify acce consequences without control complex cooling for u)ptable environmental to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months following a SBLOCA. This was necessary because for certain SB.0CA scenarios, r.FP-1 must be secured prior to loading a control complex chiller.

The licensee determined the transient temperature profile for the rooms in the control complex for the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period and compared them to the maximum allowed temperature for each room in the complex. The licensee's calculations determined that the maximum temperature limits for each of the control complex rooms would not be exceeded for at least 80 minutes as long as the control complex and EFIC room ventilation fans are operating within 30 minutes.

The assessment of the EDG loads and load management reflects the operation of these ventilation fans concurrently with EFP-1. Based on the results of the licensee's calculations, the staff concludes that the licensee's proposed reliance on no control complex chiller operation for up to I hour (and no control complex ventilation for up to 30 minutes) following certain SBLOCAs is acceptable.

In addition to making equipment u) grades, the licensee has addressed a number of system design deficiencies. T1e licensee's proposed resolution of these system design problems involve several operator actions to rritigate some aspects of design basis accidents including manual initiation of safety systems. Although the applicable Standard Review Plan indicates that a minimum number of manual actions should be identified and required for ECCS o>eration, the licensee has performed a risk assessment that indicates that tie initiating event frequency for the events that require these operator actions is low and that the overall risk contribution from these actions is low.

(See Section 2.6 of this SE.).

Additionally, the licensee has demonstrated that the operator actions are reasonably achievable (See Section 3.9 of this SE). The staff has reviewed the required operator actions and founo them to be acceptable. The review and evaluation of the operator actions is described in greater detail in Section 3.9 of this SE. As a mm

14 result, because the risk associated with the operator actions is low. the demonstration that the operator acticas are.acce mitigation strategy acceptable. y for one cycle,ptable, and t of the actions are only necessar the staff finds the i

It is noted that the licensee's risk analyses (See Section 2.6) considered the effect of the FWP-7 and its associated diesel. Though these components are not safety-related, they were installed by the licensee to augment the safety-related EFW system.

In the risk analysis, this feature contributes-significantly to attenuate the potential risk-due to operator error in implementing the demanding SBLOCA response

. procedures.

The staff concludes that the licensee's accident mitigation strategies and the overall approach are acceptable. The staff's acceptance is based on its evaluation of the proposed technical specification changes (Attachment C), the FTI/ licensee analyses in Attachments 0 and E. and the supporting information provided in Attachment F which includes proposed plant modifications and operator actions. The details of the staff's related evaluations and conclusions are provided in the remaining sections of this safety evaluation.

3,3 Attachment C - Technical Snecification Chanoes 3

As discussed in Section 2.0 above. this evaluation. have been divided into three parts: SBLOCA mitigation. EDG Upgrade and-EDG Load Rejection Test &

Steady. State Loads. The staff's evaluation of the proposed specific TS changes are evaluated below and in Sections 3.4 and 3.5.

3.3.1 Chanaes to TS 3.5.2 The licensee has proposed to revise TS 3.5.2 (ECCS - Operating) to add a new Action for Fuel Cycle 11 only. The current Action, which would still apply, for one or more inoperable ECCS trains (Condition A) requires that the train (s) be restored to an Operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Condition A also stipulates that there must be at least 100% of the ECCS flow equivalent to a single 0)erable ECCS train available during the 72-hour A0T or Completion Time. T1e proposed TS revision requires an additional Action for Condition A which would verify EFP-2 and its associated flow path Operable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of entering Condition A.

This additional reliance on EFW and proposed change is necessary because of the in particular. EFP-2. for SBLOCA mitigation (with EFP-2 inoperable, both trains of HPI are assumed in the SBLOCA analysis) and to prevent overloading EDG-1A.

Without this proposed change, the plant could be in a condition where an adequate combination of ECCS and EFW to mitigate a SBLOCA would not be available because of EDG-1A load limitations (EFP-1 is tripped at 500 asig). Therefore. EFP-2 must be available for EDG load management. The 72-lour limitation to restore the inoperable train to Operable would still apply because the configuration would not be capable of i1 withstanding an additional single failure. This proposed change is more restrictive and conservative than the existing spec 1fications which would allow the turbine-driven EFW pump to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months while in Condition A of TS 3.5.2.

The proposed change would ensure that a combination of ECCS/EFW equipment will be available to mitigate all postulated SBLOCAs fGr the duration of the A0T and is, therefore, acceptable.

The 1-hour Completion

15 Time is also acceptable because it minimizes the time (and hence, any associated increase in risk) the plant is potentially exposed to unacceptable consequences from certain SBLOCAs.

TSB G.5.2 have also been modified to reflect the necessary components and flow

_]

paths needed to successfully mitigate the different SBLOCAs.

The new Bases indicate that with one HP1 pump running (the other is assumed to be lost due to the single failure), three flow saths injecting into the core provide sufficient core cooling.

The fourti flow path is assumed to be isolated because it is assumed to be broken and the operators have isolated the broken injection line. With two HPI to be injecting into the core, pumps running, only two flow paths are required with the third injection pati assumed to be lost to a failed closed injection valve and the forth injection path is assumed to be flowing to a postulated break in the HPI injection line. This condition bounds the failure of one of the MPI injection valves failing closed or the operator isolating the wrong injection line. These conclusions are supported by the licensee's anal changes to TSB 3.5.2 acceptable.ysis and therefore, the staff finds the 3.3.2 Chances to TS 3.7.5 The licensee has proposed a number of revisions to TS 3.7.5 that reflect EFW system modifications and the additional reliance on EFW for the latest SBLOCA analyses. Some of these channes are permanent and some are for Cycle 11 only.

The current LC0 3.7.5 includes a note which specifies that only the motor-driven EFP-1 is required to be Operable in Mode 3 with OTSG pressure less than 200 asig. The proposed revision would aermanently delete this note such that two EFW trains are required to be Opera)le during Modes 1. 2. and 3 reaardless of OTSG pressure.

This proposed change is necessary to meet the single failure criterion for a SBLOCA.

The proposed change is more restrictive and more conservative than the existing TS and is therefore, acceptable.

This proposed change is also consistent with the STS for B&W plants and other pressurized water reactors where all EFW (AFW) pumps are required to be operable in Modes 1. 2. and 3.

The licensee has proposed to add a new Condition B that would be a)plicable for Cycle 11 only, to TS 3.7.5 for an inoperable ASV-5. the Train 3 steam supply inlet valve for EFP-2. The associated Action B.1 would require restoring ASV-5 to an Operable status with an A0T of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . According to the current TSB. ASV-204 is not credited for EFP-2 operability (disconnected from EFIC), and could be inoperable indefinitely. The inoperability of ASV-5 was, therefore, addressed by declaring EFP-2 inoperable and entering the required 72-hour A0T (Condition A applied only to MSV-55 and MSV-56).

However, based on the latest analyses as discussed above, with ASV-5 or ASV-204 inoperable, the ECCS/EFW systems can mitigate all SBLOCAs only if no additional single failures are assumed. With ASV-5 inoperable, a LOBA wou b result in loss of EFP-2 and the loss of EDG-1A resulting in loss of EFP-1.

The pro 30 sed 72-hour A0T is consistent with the Completion Time for a totally inoperaale EFP-2 or ES equipment failures that result in a system not being able to meet the single failure criterien.

It is also consistent with similar A0Ts in NUREG-1430. This proposed change is identified as necessary only for Cycle 11 because future modifications could eliminate the dependency of EFP-1

=

16 on EDG-1A/DC Train A.

However, if future modifications maintain this dependency, the 72-hour A0T should be a permanent TS change since a LOBA would result in a loss of EFP-1 and a failure of ASV-204 (EFIC-A) to open resulting in EFP-2 operation relying solely on ASV-5.

The staff will review the final system modifications, when the licensee submits its request for Cycle 12 TS

.3 change.

The proposed changes would also add, for Cycle 11. a new Condition C to TS 3.7.5 for an inoperable EFV-12. EFV-13. or ASV-204.

EFV-12 and EFV-13 are the respective motor-operated and manually operated valves in the EFW cross-tie piping between EFP-1 and EFP-2. ASV-204 is the Train A steam supply to EFP-2.

The inoperability of either one of these valves results in a configuration of the EFW system such that if a SBLOCA were to occur, an additional single active failure may result in less than design-basis decay heat removal capability.

Currently none of these three valves have any o3erability requirements.

If either EFV-12 or EFV-13 were inoperable. EF)-2 could not be cross-connected to supply flow through the Train A (EFP-1) flow path which is a necessary operation to cope with a SBLOCA/LOBB failure scenario as described in Section 3.1 above.

The inoperability of ASV-204, sim'.lar to the inoperability of ASV-5, also results in the inability to withstand certain single failures following a SBLOCA. such as a LOBB.

]

A 72-hour A0T for the inoperability of these valves is acceptable for the same reasons identified in the evaluation for ASV-5 above.

Additionally, for the inoperability of ESV-12. ESV-13. or ASV-204. Action C.1 has been added to verify. within I hour, the operability of the Train B EDG (TS 3.8.1). the Train B AC electrical power distribution subsystem (TS 3.8.9),

and the Train B AC vital bus subsystem (TS 3.8.9).

This additional action is required to assure the capability for ade during EDG-1A load management procedures.quate decay heat removal capability Without this verification action for AC Train B. the potential exists for not having Train B equipment available to allow EDG-1A load management.

The 1-hour completion time ensures that prompt action will be taken tc confirm core decay heat removal capability and minimizes the time that the plant could be exposed to these potentially unacceptable combination of conoitions.

The staff considers that the 1-hour Completion Time is reasonable based on the low probability of an event during that period plus the high probability that the equipment will be available during that time.

Corresponding changes have also been proposed for TS 3.8.1 and 3.8.9 such that ESV-12. ESV-13. and ASV-204 are verified Operable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months whenever the Train B EDG, AC power distribution subsystem or AC vital bus subsystem is determined to be inoperable. These proposed TS changes are conservative in nature compared to the current TS in that they maximize the availability of the EFW/ECCS systems during periods of certain equipment inoperability. The proposed changes are, therefore, acceptable.

A new Condition D (Cycle 11 only) has also been proposed to address inoperable turbine-driven EFW pump. EFP-2. and its associated flow path for reasons other than Condition A (one inoperable steam supply).

If either EFP-2 or its flow path are found to be inoperable then the licensee is required to take certain actions (0.1 and 0.2) within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and restore the pump and/or flow path to Operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The required actions are necessary to ensure that the combination of available EFW/ECCS equipment is adequate to mitigate the consequences of certain SBLOCAs as previously described, during the 72-

a 17 hour1.967593e-4 days 0.00472 hours 2.810847e-5 weeks 6.4685e-6 months A0T.. Action D.1 requires that within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the licensee verify the operability of SWP-1B (TS 3.7.7). RW Train 8 (TS 3.7.9), and Train B control complex cooling system chiller and pump. CHHE-1B and CHP-1B (new TS 3.7.18).

Action D 2 requires the licensee to verify (within I hour) the operability of bath trains of ECCS DHCCC. DHSW. EDGs. AC electrical power distribution subsystems, and AC vital bus subsystems.

These actions are necessary to assure the availability of EFP 1 during its mission time for a SBLOCA by providing adequate EDG-1A load management capability.

These actions will also assure that an adequate combination of EFW/ECCS equipment is available for decay heat removal in the event of a SBLOCA (assuming no additional single failures) during the 72-hour A0T for an inoperable EFP-2 or its associated flow path. The proposed 1-hour verification time and the 72-hour A0T are acceptable to the staff on the same bases identified in the above evaluations for Conditions B and C.

Reciprocal or com)lementary changes have also been aroposed for TS 3.7.7. 3.7.9. and 3.7.18 t1at will verify the operability of EFP 2 whenever one of the corresponding Train B components or s RW train B. CHHE-18, or CHP-1B) is determined to be inoperable.ystems (SWP-18.

Likewise, verification of EFP-2 operability is also required by proposed changes to TS 3.5.2. 3.7.B. 3.7.10. 3.8.1. and 3.8.9 which require such verification whenever either train of the required system is determined to be inoperable.

These changes are necessary to assure adequate decay heat removal capability (and EDG load management capability) will be available regarcless of the sequence of failures. Also, for Cycle 11 only, the licensee has proposed a new Condition E for the motor driven pump that would allow EFP-1 or its associated flow path to be ino)erable for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This new condition is similar to Condition B of t1e existing TS 3.7.5 which specifies a 72-hour A0T for any one EFW train which would include EFP-1.

These proposed changes are conservative in nature in that they require the availability of more equipment than the current TS for certain equipment failures and would ensure that adequate decay heat removal capability exists during the inoperability of the specific equipment.

Therefore, the proposed changes are acceptable to the staff.

Existing Condition C of TS 3.7.5 specifies that if the required Action and associated Completion Time of Condition A or B are not met, the plant shall be brought to Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and be in Mode 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The proposed changes would expand this condition for Cycle 11 such that the recuired Action and Completion Time would apply whenever the required Action anc associated Completion Times of Conditions A. B. C. D. or E are not met.

The proposed revisions would also relocate this condition within the TS such that it would become new Condition F.

Likewise, current Condition D for two inoperable EFW trains becomes Condition G without any changes to the technical content.

The preposed changes to both these conditions are administrative in nature and are necessary to reflect the changes associated with the rest of the proposed revisions to TS 3.7.5.

Because the staff has concluded that the technical changes to TS 3.7.5 are acceptable, it also concludes that these necessary administrative changes are also acceptable.

The current completion times or A0Ts for TS 3.7.5 Conditions A and B also include provisions that preclude remaining in this LC0 for greater than 10 days which would otherwise be allowed by switching back and forth between conditions.

Current Condition A specifies that the required Action to restore two Operable steam supplies must be completed within 7 days AND within 10 days

18 from discovery of failure to meet the LCO (two Operable EFW trains).

Similarly, current Condition B requires restoration of an inoperable EFW train to Operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months @ 10 days from failure of discovery of failure to meet the LCO, The E connector, as explained in the TS Bases for TS 3.7.5. dictates that both Completion Times apply simultaneously, and the more restrictive time must be met.

Accordingly, to maintain this preclusion for the length of time that this LC0 will not be met, the licensee has included the 10 day limit in each of the proposed new Conditions A. B. C. D.

and E with the E connector in addition to the equipment A0T. The proposed change to add the M19 connector to these conditions is acceptable because without it, it would be possible to alternate between conditions in such a manner that operation could continue indefinitely without ever restoring the system to being fully operable.

Thus, from a safety standpoint the g connector is considered to be a conservative improvement to the specification.

This proposed change is also consistent with NUREG-1430 for similar conditions.

Current SR 3.7.5.2 has a modifying Note which specifies that the 45-day test for EFP-2 is not-required until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching 200 psig in the OTSGs.

t A corresponding Note is included for the LCO that specified only the motor-driven p' ump. EFP-1 is required to be Operable in Mode 3 with the steam generator pressure less than 200 psig.

Since the LC0 Note will be deleted as previously described, the licensee has proposed to revise the Note for SR 3.7.5.2 to specify that the surveillance is not required to be performed for EFP-2 until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering Mode 3 in lieu of after reaching 200 psig in the steam generators. As identified in the staff's evaluation for the elimination to the LC0 note the staff considers this to be a more restrictive and conservative change because EFP-2 will be required to be demonstrated Operable by performing this test in a shorter period of time after entering Mode 3.

Under the current specification the plant could remain in Mode 3 without performing the test indefinitely as long as OTSG pressure remained below 200 psig.

Because the proposed change is necessary to be consistent with the proposed changes to the LCO and is more conservative in nature. the staff concludes that it is acceptable.

?,

The current 24-month SRs 3 7.5.3 and 3.7.5.4 for verifying valve actuation and automatic EFW pum) start on an actual or simulated actuation signal have a note similar to SR 3.7.5.2 where the SR does not have to be performed (in Mode

3) until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after OTSG pressure reaches 200 psig.

The licensee has also proposed to revise these notes such that the surveillances would have to be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after entering Mode 3 regardless of the steam generator pressure. The staff considers these pro>osed changes to be acceptable based on the same reasoning described a)cve for the same changes to the notes for the LC0 and SR 3.7.5.2.

The licensee has also identified a number of changes to the EFW TS Bases Section B 3.7.5 to reflect the TS revisions and EFW equipment modifications associated with the latest SBLOCA analyses.

The staff has reviewed these changes to the Bases and determined that they provide an adequate Bases for the revised TS 3.7.5 and are consistent with the licensee's revised SBLOCA analyses.

U

19 3.3.3 Chanaes to TS 3.7.7 The licensee has proposed changes to TS 3.7.7 (SW System) to reflect the actions recuired to preclude the simultaneous inoperability of EFP-2 ard SWP-

18. The Sk system basically consists of two aumps and three heat exchangers, all of which are required to be Operable by t1e current and proposed I.C0 3.7.7 during Modes 1, 2, 3. and 4.

The SW system transfers heat to the nuclear services seawater (RW) system. The current Action A permits a 72-hour A0T for the ino>erability of one SW pump (either SWP-1A or SWP-18) @ the inopera)111ty of one heat exchanger.

The proposed changes would add a new Action A that applies only to the inoperability of SWP-1B and would reflect the cross-dependencies between SWP-1B and EFP-2 (to preclude simultaneous operation of SWP-1A and EFP-1).

The required Actions under the new condition would require that within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , verify EFP-2 and its associated flow Mth are Operable (Action A.1) a'id to restore SWP-1B to an Operable stitus within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (Action A.2).

A modifying Note to Action A.1 will s)ecify that i.ha action is not ap)licable in Mode 4.

This note is acceptable 3ecause EFP 2 is not required to 3e Operable in Mode 4 and there is insuf ficimt steam supply to verify pump operation. As a result of the new Condition A. the r.uricnt Condition A will become Condition B and be modified to apply o"ly to SWP 1A (in lieu of either SW pump) in addition to any one of the heat nch. rgers The A0T of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for SWP-1A (or for any one heat exchangec) has not beur, changed from the existing specification. Also the existing CoMit Hn 3 dw.:n recuires )lant shutdown if the conditions are not met will !:Num a # Ma C anc be otlerwise unchanged.

The net change to this spee! fical ion Lc e n T.

the operability of EFP-2 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after detennining that %P O s inoperable. The rest of the changes are essentially admim am W maintain consistency and completeness within TS 3.' /.

M lea :Ded o che

/

evaluation of the corresponding changes to TS 3.7.5. the proposed chse are more restrictive and more conservative than the existing TS ed E= wmsw'y to assure adequate decay heat removal capability for certs v ip+nt failures. They are, therefore, acceptable.

The corresponding TSB section. 3.7.7 has been revised to rel%ct itat m tn SWP-1B inoperable, prompt action must be taken within I hou" to.mure that sufficient capability is available on EDG-1A for SWP-1A in certain S8t.0CA scenarios.

In these circumstances EFP-1 would be secured and EFP ? on;y.ndn be available for OTSG cooling. Therefore. EFP-2 must be 0pecau i.o A $te these SBLOCAs. ~ With SWP-1B Operable. SWP-1A can be secm. 4

.m-W EFP-1 in the event EFP-2 is inoperable. Hence. if EFP % h i v rablo SWI IB must be Operable and vice-versa to assure adequate decay i.m t e rbC 4

capability during the respective 72-hour A0T. The staff has reviewed the changes to TSB 3.7.7 and determined that they adequately reflect the proposeo TS changes and latest SBLOCA analyses.

3.3.4 Chanaes to TS 3.7.8 The proposed changes to TS 3.7.8 (DHCCC System) would add a required Action A.1 to the existing Condition A for one inoperable cooling water train (in Modes 1. 2. 3. and 4) that would verify EFP-2 and its associated flow path Operable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of entering the condition. This action would also be modified by a Note that specifies the action is not applicable in Mode 4.

The proposed changes are also for Cycle 11 only.

This proposed change corresponds

4 20 to the new Action 0.2 of TS 3.7.5 which requires both trains of the DHCCC system to be Operable whenever EFP-2 is determined to be inoperable. -The proposed change is necessary to maintain adequate decay heat removal capability during entry into this condition and is acce basis discussed above for the similar change to TS 3.7.ptable on the same 7_ for the SW system, rhe DHCCC c.ystem removes heat from the DHR system and transfers it to the DHSW system Acceptable i. hanged have also been made to TSB 3.7.7 reflecting the-TS changes and-the SBl.0CA analytics that necessitated the changes.

In part. TSB 3.7.8 has hmn mdified to reflect that certain SBLOCA scenarios require EFW to maintain e.W; 'ouling unti' core decay heat can be removed solely by ECCS cooling.

Wlui itY 4 oc ils associated flow path inoperable. SWP-1B, Train 3 of the "h

,wvbra seawder system CHHE-1B and CHP-18, as well as both-trains-in'

.:,w heet clowd cycle cooling water. decay heat seawater. EDGs. AC i

ci r

' power distrihation subsystems, and vital AC bus subsystems are w

m 1p mble.

S _um w n.1/.4 y 'i m.1N been proposed for fS 3.7 9 (RW System). for Cycle 11

.3 i.u : ; let t ik ev: sed SBt00A analyses and inter-system dependencies for UU load

. u ment

ic current specification provides a 72-hour A0T for 1

3..A tm while in Modes-1. ?. 3 and 4 The proposed change prate co# Uuns for frains A (Condition A) and 8 (Condition r

17:

e t

o' A R" e tM would <till-have a /2 hour A0T. the same as e

at

.>o, n m e..ents.

Condition A for the inoperability of 4

Nvr a. M tieval Action A,1 to verify within I hour, the p M. y a O P-2 end i; c 'usociated flow path. A modifying Note-N L A 1-it at applicable in Mode s1.

These changes are

~

c.< C

.L < al in ur changes for TS 33./. and are acceptable on the hw a ku iemm ive Cycle il to reflect the TS changes and the

Lc3 ' U? :n.dyws

[n part, the revision identif'es that for certain aBLOC.

W h a concure ent i.00P,_ securing SWP-1A and RWP-2A would provide ap.b ;:y on th9 Enr, to load the Train A LPI pump and other required loads.

1

>i br m w a ly securnd and locked out (via added PTL switches) e o n

, Nn h these situal.%nt SWP 18 and RWP 2B p.

p. m

.e

r,i.inued flow for

.N SW and RW systems.

The

.Walely rihet the proposed changes and the latest SBl.0CA 4;,,o no HE Md management and are considered acceptable to the ry

_ iair 4

UU Chaugn.l,0.K_3.]. LO.

The proposed Cycle 11 changes to DHSW system are essentially identical to the

.hanga propomd for TS 3./.8 and would require verification of EFP-2 0)erebility when either train of the DHSW is determined to be inoperable.

4 T11s serification is not applicable in Mode 4.

The proposed changes are acceptable on the same basis aut forth in the above evaluation for TS 3.7.8.

The staff has also reviewed t1e revised TSB 3.7.10 and determined that they dre essential!y the same as the revisions to TSB 3.7.8 and. are acceptable.

21 3.3.7 Chances to TSB 3.7.12-Changes have also been proposed to TSB 3.7.12 relating to CREVS. Current TSB 3.7.12 stipulates that the abilit complex is not addressed in TS 3.y to maintain temperature in the control 7.12. but instead is addressed administratively outsioe of the TS. This would be changed to reflect that the ability to maintain control complex temperature is addressed in the proposed new TS 3.7.18. Control Complex Cooling System. This is a permanent change that is administrative in nature and is necessary for completeness.

It is.

therefore, acceptable.

3.3.8 New TS 3.7.18 The licensee has proposed a new permanent TS 3.7.18 (CCCS) with some conditions and actions that will only apply during Cycle 11.

This TS is being added as part of this SBLOCA TS change package because for certain SBLOCA/ LOOP scenarios (at least for Cycle 11). it is necessary to provide capability on EDG-1A to load the Train A LPI pump and other required loads.

In these situations. CHHE-1B and CHP-1B would be relied upon to provide required cooling (see changes to TS 3.7.5).

As described in the proposed TSB 3.7.18. the CCCS consists of two redundant chillers (CHHE-1A and CHHE-1B) and associated chilled water pumps-(CHP-1A and 1B). and two control complex heat exchangers that provide cooling of recirculated control complex air. Cooling water to the chillers is provided by the SW system. The safety-related function M the system is to maintain suitable temperature conditions in the control complex for operating personnel and safety-related control equipment.

The proposed LC0 would specify that during Modes 1. 2. 3. and 4. [and during movement of irradiated fuel assemblies] the CCCS shall be Operable with: two Operable chillers and associated pumps: and two Operable heat exchangers. The addition of a TS and LCO for the CCCS is consistent with TS 3.7.11 " Control Room Emergency Air Temperature Control System (CREATCS)." in NUREG-1430 and com)lements the CR-3 TS 3.7.12 " Control Room Emergency Ventilation System

~ (CR EVS ). "

Both systems (CREVS and CCCS) are necessary to maintain acceptable environmental conditions in an isolated control room throughout the course of an accident. The system is designed such that the operation of one CCCS chiller and associated chilled water pump along with either one of the two heat exchangers will perform-the system safety function to maintain adequate temperature control within the control complex.

Since this system operates in conjunction with the CREVS. the system is required to be Operable in the same modes, i.e.. Modes 1. 2. 3. and 4. and whenever irradiated fuel assemblies are being moved. Therefore, the proposed LCO and Applicability requirements are acceptable.

Because of the current EDG load management concerns during SBLOCAs (Cycle 11 only) the licensee has proposed required actions for the inoperability of a Train B chiller or chilled water pump that are different (more restrictive) from the actions for the same inoperable Train A components and. therefore, different from the corresponding actions in NUREG-1430.

Proposed Condition A specifies that with CHHE-1B or CHP-1B inoperable, operation may continue for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided that within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . EFP-2 and its associated flow path

22 are verified Operable (Action A.1).

Pro)osed Condition 8 specifies that with CHHE-1A. CHP-1A, or one of the required leat exchangers inoperable operation may continue for up to 7 days (the same as recommended for chilled water systems in NUREG 1432, the STS for Combustion Engineering (CE) plants). The STS for B&W plants (NUREG 1430) do not include TS for chilled water systems.

The proposed Conditic'ns A and B are acceptable because with either Train's chiller and associated chilled water pump, or either one of the required heat exchangers inoperable, the remaining components are adequate to maintain the control complex within limits. The A0T of 7 days for the Train A components or either heat exchanger is acceptable because of the low probability of an event occurring requiring control complex isolation and emergency cooling during this time period, plus the remaining components can still perform the system safety function (with no additional single failures), and the potential for alternate cooling capabilities via safety-and nonsafety-related equipment via compensatory actions such as opening of normally closed doors / ventilation pathways.

For inoserable Train B chiller components, the potential exists during Cycle 11. taat EFW/ECCS system functions could also be directly affected by single failures (due to EDG 1A overloading) such that the A0T is reduced to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The 72-hour A0T for Train B is acceptable because it is consistent with other ES system A0Ts when the system does not meet the single failure criterion. The 1-hour Completion Time to verify EFP-2 operability is also acceptable as previously described for the TS changes having this same proposed action requirement.

This 1-hour verification of EFP-2 operability is necessary to assure adequate SBLOCA response during the 72-hour A0T.

Proposed Condition C requires that if the required Action and associated Completion Time of Condition A or B are not met durin the movement of irradiated fuel assemblies, the CCCS shall immediatel be placed in operation (Action C.1), or the movement of irradiated fuel asse lies shall be immediately suspended (Action C.2).

Proposed Condition F addresses the condition for a totally inoperable CCCS during movement of irradiated fuel assemblies and requires (Action F.1) the immediate sus)ension of fuel assembly movement (suspending fuel movement does not preclude t1e movement of fuel to a safe position).

Proposed Actions C.1. C.2, and F.1 are consistent with the required Actions for the CREVS in TS 3.7.12 which require the Operable CREVS train to immediately be placed in the emergency recirculation mode, or immediately suspend the movement of irradiated fuel assemblies (with both trains inoperable). They are also consistent with NUREG-1430.

The proposed actions minimize the risk associated with a fuel handling accident by ensuring the control room is isolated and with ventilation and cooling systems operating in the recirculation mode, thereby ensuring protection for the control room operators.

When the combination of inoperable components is such that the CCCS system is inoperable and the function is lost. the risk from a fuel handling accident are minimized by safely suspending the movement of fuel to reduce the probability of the event. Based on the above, the staff considers the proposed changes acceptable.

Proposed Condition D requires the plant to be in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . and Mode 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months if the required Action and associated Completion Time (Condition A or B) are not met during Modes 1, 2. 3. and 4.

Proposed Condition E recuires an immediate entry into LCO 3.0.3 with any combination of components rencering the CCCS inoperable. The actions associated with these

23 conditions place the plant in a mode where the LC0 is no longer ap)licable.

The action times to reach these modes via Actions C.1 and C.2. or.C0 3.0.3 are reasonable, based on operating experience, to reach the required conditions from full power in an orderly manner without challenging plant safety systems or the caerators.

The orcposed conditions and required actions are, therefore, acceptable.

They are also consistent with the conditions and actions set forth in NUREG-1430 for similar conditions related to control room cooling.

The licensee has also voposed SR 3.7.18.1 and SR 3.7.18.2 for verifying operability of the chiiled water pumps and the system heat removal capability, respectively. 'SR 3.7.18.1 will verify each chilled water pump's developed I

head at the flow test point is greater than or equal to the required developed head at a frequency that is in accordance with the IST Program. SR 3.7.18.2 will require the licensee to verify the redundant capability of the CCCS to remove the assumed heat load every 24 months.

The proposed chilled water pump i

test and test frequency are acceptable since they are consistent with other safety related pumns in the licensee's IST Program and are in accordance with the ASME Code.Section XI.

The heat removal capacity verification will consist of a combination of testing and calculations has been accepted by the staff as an adequate method of verifying the control room heat removal systems at other plants. The 24 month frequen is appropriate, as significant degradation of these systems is usuali slow and not expected to occur over this tir= period. The proposed survei lanct requirements are, therefore, acceptable. They are also consistent with the recommendations of NUREG-1430.

Sased on the above. the proposed new TS 3.7.18. and its Bases, are acceptable and they are also consistent with NUREG 1430 (or NUREG-1402 where applicable) to the extent practical.

3.3.9 Chances to TSB oniv The licensee has also made several changes to TSB 3.3.5 (Engineered Safeguards Actuation System), and TSB 3.3.17 (Post Accident Monitoring System (PAM)

Instrumentation). There were no changes required to the actual TS however.

TSB 3.3.5 was revised to reflect the manual bypass capability of the low pressure EFP-1 trip, and TSB 3.3.17 was revised to reflect the installation of the EFW cavitating venturis by coleting a reference to runout protection by operator action.

These Bases shanges will more accurately reflect the actual design of the plant and are therefore, acceptable.

3.4 EDG Unorade The licensee has implemented several hardware modifications to the EDGs to upgrade their ratings. As discussed above, these changes provide measures related to the electrical systems that are required to mitigate the consequences of certain SBLOCAs with concurrent LOOP and certain single failures; This evaluation addresses the electrical system related modifications.

lU

24 3.4.1 EDG Modifications The CR 3 Gass IE onsite electrical power system is divided into two redundant trains (Train "A" and Train "B") and includes two dedicated EDGs. Only Train "A" contains a motor driven EFW pump.

Certain SBLOCA scenarios re uire EFW to maintain OTSG cooling until core decay heat can be removed solely y ECCS cooling. With EFP 2 or associated flow path inoperable: EDGs. AC lectrical power distribution subsystems and AC vital bus subsystems are required to be operable.

With ASV-204. EFV-12 or EFV 13 inoperable: Train "B" EDG "B."

and Train "B" AC vital bus subsystems are required to be "0PERABLE."

EDG *A" lack of capacity prohibits concurrent o>eration of the motor drive EFW pump (EFP-1) with the operation of either the dip-1A or the *A" train CK4E.

when the RB BSP 1A is operating. In addition. due to the load capacity limits on EDG "A." the length of time that EFP 1 would be available is also limited.

In order to ensure adequate EFW system flow, other actions would have to be initiated.

This includes extending the time EFP 1. would be available by managing the load connected to the EDG "A* and/or by t king action to provide EFW flow via EFP 2 by opening the crosstie valve (EFV-12).

3.4.2 Prooosed TS Chanaes The licensee proposed changes to TS 3.8.1 AC Sources - Operating, and TS 3.B.3 Diesel Fuel 011. and Starting Air and associated SR to support operation with i

upgraded EDGs.

They are discussed below.

3,4.2.1 TS 3.8.1 AC Sources - Doeratina The licensee is proposin Train "A" and Train "B".g to specify the operability of each EDG separately as This is necessary due to the differing operability requirements.

In the condition that Train "A" EDG is inoperable, the proposed TS changes require verification that EFP 2 and associated flow path are OPERABLL with a comp'.etion time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The licensee also )roposed new SR actions.

In the condition that Train "B" EDG is ino>erable, tiese actions require verification that offsite circui.(s) are OPEMBLE with a completion time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter, and EFP-2 and associated flow path. ASV-204. EFV-12. and EFV-13 are OPERABLE with a completion time of I hour.

Additionally. the required feature (s), suoported by the inoperable EDG, are required to be declared INOPERABLE. with a completion time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of Condition B concurrent with inowrability of redundant required EDG Teature(s) and determination that OPERABLE EDG is not inoperable due to common cause failure with completion time of 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s: OR performing SR 3.8.1.2 for OPERABLE EDG with completion time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and restoring EDG to OPERABLE status with completion time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months within 6 days from discovery of failure to meet the applicable LCO. Similarly, when one of the required offsite circuits and Train "B" EDG are inoperable, the licensee proposed actions require verification that EFP-2 and associated flow path are OPERABLE with completion time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , and entry into applicable Conditions and Required Actions of LCO 3.8.9. " Distribution Systems Operating." when Condition.F is entered with no AC )ower source to one train and restoring required offsite circuit to OPERAB.E status with a completion time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR restoring EDG to OPERABLE status with a completion time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Additional editorial changes are made to accomodate the proposed TS changes.

25 If EFP 2 and associated flow path are inoperable; the EDGs, AC Electrical Power Distribution Subsystems. AC Vital Bus Subsystems are required to be OPERABLE.

With ASV-204. EFV-12 or EFV-13, inoperable. Train *6* EDG, Train

~B* AC Electrical Power Distribution Subsystems and Train *B* AC Vital Bus Subsystem are required to be OPERABLE, If the required equipment is not available, the capability for core decay heat removal has not been assured thus Condition H is 'aplicable (shutdown). The above technical specifications implements these requirements and are therefore acceptable.

The licensee is proposing to verify the operability of the turbine driven EFP and associated flow path, ASV 204 EFV-12 and EFV-13 with a completion time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Due to the severity of f '

isequences should a small break LOCA cccur, the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months completion time ares that a 3rompt action will be taken to confirm core decay heat removal capability. T1e completion time minimizes the time the plant is potentially exposed to unacceptable consequences from certain SBLOCAs and is therefore acceptable.

3.4.2.2 TS Sk 3.8.1.4 Minimum EDG Day Tank Fuel Volume The minimum contained volume for each EDG day tank is being increased from 245 gallons to 280 gallons. The associated Bases will also be revised to reflect that the minimum required day tank level represents the minimum " usable" volume, and that this volume will ensure a minimum of I hour of EDG operation 4

at a loading which bounds the postulated worst accident.

The proposed changes require a larger (more restrictive) volume of fuel oil in the day tank and still provides at least I hour of EM operation.

The proposed minimum usable volume for each day tank is based on 1 minute of operation at the 30 minute rating (3500 kW) and 59 minutes of operation at the upper limit of 200-hour rating (3400 kW).

This will provide a minimum requirement that bounds the current basis for stored volume of 1-hour operation at full load plus 10 percent, as well as the postulated worst-case accident EDG load profile.

Because change is necessary to su) port the new EDG loading / upgrade and it maintains at least the minimum 1 lour storage capability, the proposed changes are acceptable.

3.4.2.3 TS 3.8.3 and SR 3.8.3.1 - H1,rtimum Fuel Storace Tank Volumes The lower (3 day) volume limit of stored fuel for each EDG is being increased from 15,933 to 19,643 gallons, and the upper volume (3.5 days) limit is being increased from 18.589 to 22,917 gallons.

In addition, the minimum required co'nbined stored volume (7 days) of fuel oil for both EDG storage tanks is being increased from 37.177 to 45,834 gallons. The SR will be revised to require a minimum of 22,917 gallons for a single tank and 45,834 gallons for combined fuel oil storage. The Background, LCO. Action A.1, and SR sections of the Bases for TS 0.3.3 will be revised to indicate the minimum EDG stored fuel oil volumes are based on operation at the upper limit of the 200 hour0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months rating, rather than the continuous load rating.

The Bases for Action A.1 and the surveillance requirements will also be clarified to indicate that the storage requirements are based on usable volumes.

The current basis for Actions A and B of TS 3.8.3. and SR 3.8.3.1, and SR 3.8.3.2 requires sufficient fuel and lobe oil for EDG at the continuous load rating.

However, the postulated worst-case post-accident loading is not

26 bounded by o>eration at the continuous load rating (2850 kW) of one EDG, Therefore, tie minimum fuel and lube oil storage requirements are being increased to support o>eration of one EDG at the upper limit of the revised 203 hour0.00235 days 0.0564 hours 3.356481e-4 weeks 7.72415e-5 months rating (3400 (W). This will ensure a conservative inventory that will bound the postulated post accident loads.

A new Action A.1 will be added to verify within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months that a combined stored volume of fuel oil is greater than 7 days (new 45.834 gallons combinea minimum volume) if either of the EDG storage tanks is less than a 3.5 day volume (new minimum 22,917 gallons). This proposed new Action is acceptable since it ensures that a 7-day minimum combined storage capacity will be maintained and at least a 5 day storage capacity will be maintained in each storage tank.

The proposed increases in fuel oil storage limits and resultant changes to the associated SR are also ac:eptable since they are more restrictive and maintain the overall safety design basis of the fuel oil storage system to maintain a 7 day supply for at least on EDG.

Therefore, the proposed TS changes are acceptable.

3.4.2.4 Chances to TS 3.8.3 and SR 3.8.3.2 - Minimum Lube Oil Volume The licensee has pro)osed to increase the total volume of stored lube oil (Action B) for the EXis from 233 gallons to 280 gallons.

The associated SR 3.8.3.2 is, therefore, also being revised to reflect this new limit.

Similar to Action A, the Background. LCO, Action B.l. and SR sections of the Bases are also being revised to indicate the minimum EDG stored lube oil inventory requirements are based on EDG operation at the upper limit of the 200 hour0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months rating, rather than full load operation. As evaluated above for changes to the fuel oil storage requirements, these changes are more restrictive than the existing requirements and are necessary to assure a 7-day lube oil supply for at least one EDG, The proposed changes are also necessary to clarify and more accurately reflect the actual design which consists of a single shared lube oil storage tank that supplements the lube oil storage sump of each E0G.

Both the current and proposed limits are based on a 7 day supply for the operation of one EDG, The proposed changes are consistent with those proposed for fuc1 oil storage and are acceptable on the same basis.

This section is rev1 sed to increase the ca>acities of the shared fuel oil and the lube oil to meet the requirements of tie new ratings of the EDGs.

The proposed revisions in the diesel fuel oil and lube oil are necessary to match the increases in the EDG kW capacities and are therefore acceptable.

Also TS SR 3.8.3.1 and SR 3.8.3.2 are appropriately revised to reflect the new requirements of the fuel oil storage and the lube oil inventcry. The postulated post-accident worst-case EDG loading is not the continuous 2850 kW rating on one EDG. The minimum fuel oil and tube oil capacities requirements are increased to meet the requirements of the EDGs 200 hour0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months rating of 3400 kW.

This is conservative and acceptable.

3.a.2.5 TS 3.8.9 - Distribution Systems - Ooeratina The proposed " ACTIONS" are revised to establish the required actions to be based on TrP "A" and on Train "B" instead of on "One AC" electrical power subsystem ? : to the different train operability requirements.

These actions require erification that EFP-2 and associated flow path are OPERABLE, and

27 restoring AC electrical power dir+.rlbution subsystem to OPERABLE status. The proposed TS are similar to those specified in TS 3.8.1 and are acceptable as discussed in Section 3.4.2.1.

If Train *A* AC electrical power distribution system or Train *A* AC vital bus is that inoperable, the action is to verify (within-1 hour) the turbine EFW pump and associated flow path are operable for steam generator cooling, If-Train *B" electrical power distribution subsystem or Train *B* AC vital bus is inoperable, the action is to verify (within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ) the turbine driven emergency feed water pump and associated flow path as well as ASV-204, EFV 12 and EFV 13 are operable for steam generator cooling.

Due to the severity of the consequences should a small break LOCA occur, the i

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months completion time ensures that a 3rompt action will be taken to confirm the electrical support for core decay leat capability, The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months action time minimizes the time the plant is potentially exposed to unacceptable-consequences from certain SBLOCAs and is therefore acceptable.

3,5 Load Reiection Test & Steady State loads FPC is upgrading both EDGs to increase the 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months and 200 hour0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months ratings from 3000 kW to 3200 kW and from 3250 kW to 3400 kW respectively.

The continuous rating of the EDGs remains ;.t. 2850 kW.

Additional modifications will reduce the loeds on the EDGS. This will allow operations of the motor-driven pump EFP 1 to meet the requirements of a SBLOCA, To increase the rating, the major modifications of the EDG are the installation of new turbochargers, intercoolers and radiators.

Based on its review, the staff finds that the replacement turbochargers, intercoolers and radiators have been appropriately selected to meet the increased demand of the new ratings.

The new ratings will be as follows:

Duration Old Ratina New Ratina

_coer limit Chance Continuous 0 to 2,850 kW 0 to 2,850 kW

.nchanged 2.000 hours0 days 0 hours 0 weeks 0 months 2,851 to 3,000 kW 2.851 tu 3.200 kW Increased 200 hours0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months 3.001 to 3,250 kW 3.201 to 3,400 kW Increased 30 minutes 3,251 to 3,500 kW 3.401 to 3.500 kW Unchanged The upgrade program includes testing of the EDGs to demonstrate that they are qualified to perform at their new service ratings prior to entering Mode 4 from the present outage.

1.

FPC adopted the RG 1.9. Revision 3 dated July 1993

(" Selection. Design, Qualification and Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Pcwer Plants.").

-Sections 2.2.1 and 2.2.2 definitions of " Start Test" and " Load Test."

4 J

-The ? Start Test" will demonstrate proper stcrtup and verify that the EDG achieves the re The

Load Test" quired design voltage and frequency in a specified time.

will demonstrate the-EDG capability to carry the recuired load for a specified duration.

The EDG will be loaded above 2600 kk (greater than 9% of continuous rating.:f 2850 kW) with a typical load of 2700 kW,

i 28 2.

FPC successfully completed 22 start and load runs tests (13 on "A" EDG and 9 on "B" EDG) after completion of the installation of the new turbochargers. intercoolers and radiators before MODE 4 entry from the current outage.

3.

In addition. FPC testing of the upgraded EDGs will include fast start, combined ES ar'otion with simulated LOOP single load rejection, full load rejective, endurance and margin test (22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months @ 2800 kW and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

@ 3135 kW), and hot restart.

The tests will allow the licensee to 4

declare the EDGs as OPCRABLE and the staff finds it acceptable.

The staff agrees with FPC that the " Start Test

and

Load Test' as per RG 1.9.

Revision 3. July 1993 are satisfactory to demonstrate the capacity and the capability of EDGs *A* and *B".

Also the number of tests a

mentioned above to demonstrate EDG operability is acceptable.

Current SR 3.8.1.11 to "[V]erify each EDG operates for =60 minutes at a load

=3100 kW" and 53250 kW is changed to " Verify each EDG operates for =60 minutes at a load a3300 kW and 53400 kW."

The change of the EDG surveillance of the 200 hour0.00231 days 0.0556 hours 3.306878e-4 weeks 7.61e-5 months rating is to confirm that the EDGs are capable of accepting a load greater than or equal to the maximum expected steady state accident loads.

The kW test band is to avoid overloading of the EDG, This change corresponds to the new rating and is therefore acceptable.

3.6 Attachment D - Framatome Document FTI 51-1266138-01 An analysis was performed to show that acceptable results are obtained with the proposed actions and equipment modifications.

The analysis was also performed to establish timing issues associated with the operator actions and the required equipment service times. The anal RELAP5/ MOD 2, described in BAW 10192 P-A " Loss ysis was performed using of-Coolant Accident Evaluation i

Model For Once-Through Steam Generator Plants."

This evaluation methodology has been re.lewed and approved by the NRC for LOCA applications.

The licensee is adding BAW 10192-P.A to CR-3's licensing basis reference documentation.

~

The staff finds the addition of BAW-10192 P-A acceptable because CR-3 is in 4

the class of riants for which the use of BAW-10192-P A has been approved and.

therefore, use of this methodology is acceptable.

The current analysis of record for SBLOCA for CR3 was performed in 1996 using l-CRAFT 2 also an NRC ap) roved methodology.

The RELAP analyses and scenarios, presented to support tie license amendment predicted less limiting results than the existing licensing basis CRAFT 2 analysis so that the existing CRAFT 2 analysis remains the analysis of record for_ SBLOCA.

The RELAP analysis predicts no core uncovery.

From the standpoint of calculating the PCT, the scenarios analyzed are not the limiting SBLOCA. The existing CRAFT 2 analysis of record for the limiting SBLOCA calculated

--predicted core uncovery and a PCT excursion of 18597.

None of the event analyses used to evaluate the single failures identified in this amendment request predicted core uncovery and no temperature excursions were predicted.

As a result, the analysis presented assures that the limiting PCT calculated with CRAFT 2 remains the limiting analysis of record.

29 Additionally, the RELAP analysis was used tu support timing issues associated with equipment service times and required operator actions.

The calculations were performed using both the 10 CFR Part 50. Appendix K decay heat and a realistic decay heat.

The RELAP analyses conservatively used either the Appendix K or the realistic decay heat values.

and the realistic decay heat calculations presented and used wereThe results for the Append conservative.

Because the RELAP methodology used is approved by the NRC and the assumptions used are conservative the staff finds this analysis acceptable.

3 The licensee indicated that the procedure and plant modifications presented in this license amendment request and evaluated in Section 3.8 of this SE did not affect the analysis of record.

The changes that are beina made to the plant and to the operating procedures are to assure that the plant will oaerate within the bounds of the accident analysis. The licensee stated that tie existing analysis remains bounding. The limiting small break, where core uncovery occurs is larger than the breaks addressed in this amendment and that the peak temperature and core uncovery occur very early in the event, prior to the credited operator actions.

The staff finds these actions acceptable.

3.7 et.tachment E - Assessment of Limited Use of RELAP5 The use of RELAP5 described in BAW-10192 was used in accordance with the methodology limitations and restrictions (11 conditions identified in the staff letter dated February 18, 1997) with two exceptions as described in Attachment E.

The licensee is adding BAW-10192-P A to CR 3's licensing basis reference documentaticq. The staff finds this acce) table because CR-3 is in the class of plants for which the use of BAW 10192-) A has been ap3 roved.

The time steps were expanded when the calculations were extended well aeyond the initial temperature excursions and the heated core control volumes were selected as non equilibrium volumes rather than equilibrium volumes.

The staff reviewed these changes and determined tha criteria established require no core uncovery (t because the acceptance i.e., no significant PCT excursion) the exceptions to the conditions for this approved methodology are acceptable for this individual 3pplication.

3.8 Attachment F - Suncortina Information The licensee is addressing the issues related to SBLOCA mitigation through a combination of TS changes. E0P revisions, and plant modifications.

The staff's evaluation of the TS revisions and E0P revisions are arovided in appropriate sections of this SE.

The staft's evaluatioq of tie related plant modifications are discussed throughout this evaluation and are suunarized in this section along with the staff s conclusion regarding the specific modification.

Summaries of the staff's review and aaproval of any related US0s and new o)erator actions are also provided in tais section.

_To support the proposed c1anges and aid the staff in its review, the licensee provided in Attacnment F. in tabular form, a listing and brief summary for the following tcpics:

/

v Jh 6W

l 30 Table 1 - NRC Identified Unreviewed Safety Questions (US0s)

Table 2 - Modifications (updated by September 25, 1997 submittal) 1 Table 3 - Operator Actions (u> dated by September 25,1997 submittal) i Table 4 Summary of Planned SAR Changes Table 5 - Related Licensee Event Reports (LERs)

Table 1 lists six issues (US01 through US0 6) that have been previously identified by the staff as involving a US0. The table also provides a brief i

description of the US0 and identification of the proposed resolution which i

generally includes specific modifications and pro >osed TS/ Bases changes 050s 1. -4. and 5 relate to EDG loading. EFW NPSi, and the reduction of EFP-2 reliability, respectively. The i

automatic open signal from ASV y all basically involve the removal of the EFIC 204 and have been resolved via the reconnecting of EFIC A to o>en ASV-204.

This reconnection will be made possible as a result of the EFW system modifications and proposed TS and Bases changes, revised E0Ps and operator actions for EDG load management.

i US0 2 and US0 3 both involve EDG loading problems resulting from E0P and OP chanPs, respectively.

E0P 13 was changed to direct operators to take manual contiul and increase EFW flow which increased the EFP 1 post accident load to beyond that supported by analysis.

OP 402 was changed to allow operators to i

ES select the swing HPI p mp to either EDG resulting in exceeding the TS Bases l

value of the largest sing e post-accident load. These EDG load issues have been resolved via the mod fications to increase EDG load capacity and modifications to allow EDG load management, and proposed changes to the associated TS ano Bases.

US0 6 involves certain operator actions associated with the mitigation of SBLOCAs. The associated operator actions have been reviewed by the staff during its review of TSCRN-210 and found acceptable as described in the evaluation described below for Table 3.

All six of these US0s are considered resolved by the staffs review and evaluation of the proposed TS changes, associated plant modifications, and the licensee's overall EDG load management strategy as discussed herein.

Table 2 of the licensee's June 14, 1997 submittal identified 12 modifications related to the resolution of the SBLOCA concerns and associated US0s.

In its September 25, 1997 submittal this table wu updated to include 18 related modifications (HODS 1 through 18).

These modifications are described below.

MOD 1 Restores the automatic opening of ASV-204 on an EFIC-A actuation signal. This will restore the load sharing capability of the EFW system for the SBLOCA/ LOOP and a loss of EDG 1B in order to reduce the load on EDG-1A.

It will also increase the reliability of EFP-2.

H0D 2 Installs passive flow restricting devices (cavitating venturis) on the discharge side of both EFP-1 and EFP-2.

This will prevent excessive pump flow that could result in possible failure mechanisms of runout or inadequate NPSH available.

This modification also increases the availability of both EFW pumps.

31 MOD 3 Replaces manual operated gate valve EFV 12, in the cross tie piping between EFW Train A and Train B with a motor o>erated gate valve.

This will facilitate operator action to open t11s valve remotely and route the discharge of EFP 2 through the cross tie piping to the DTSGs.

This will allow OTSG level control and EDG load management when EFP-1 is unavailable, MOD 4 Installs flow indication from the cavitating venturi installed at the discharge of EFP-2. This control room indication will be powered from the opposite train (Train A) to provide flow indication l

should a failure disable the normal flow rate indication. This will provide feedback to the operator of flow from EFP 2 when EFP-1 needs to be secured for EDG load management.

MOD 5 Installs a control switch to allow operator action to defeat the automatic trip of EFP 1 (500 psig RCS pressure).

Defeating this trip will allow continued EFP-1 operation during certain SBLOCA scenarios by permitting EFP 1 operation when DHP 1A starts on a 500 psig actuation signal.

This switch would be used after EDG 1A load management by operator action.

MOD 6 Replaces existing control switches for RWPs 2A and -2B, and SWPs-1A and -1B with pull-to-lock (PTL) switches. 1his will prevent automatic restart of these pumps on subsequent ES actuation signrls after they have been secured for load management. These switches r

will thereby facilitate EDG-1A load management.

MOD 7 Removes auto-start function from both nonsafety control circuits of.

the flush water pumps. This will prevent these pum)s from auto-loading onto the EDCs.

The flush water of bearing flush water (domestic water) pumps are tie normal supply to the nuclear services and decay heat seawater pumps.

An earlier modification (circa 1985) provided automatic bearing flush water from the discharge of the seawater pumps themselves assuring bearing cooling when the flush water pumps are not available.

MOD 8 Implements modifications to increase the service retings of the EDGs including, (1) the combustion air flow rate will be increased by replacing nozzle rings in the turbochargers with larger ones, and (2) combustion air intercoolers will be replaced with a dual pass intercooler.

MOD 9 Installs more accurate power meters (kW indication) for EDGs.

EDGs will be able to be loaded higher because of the improved instrument accuracy.

MOD 10 Installs windup reset on integral controller of the EFIC system.

This will provide for faster response of EFW for control of flow to the OTSGs. This reduces EFW flow and consequential EDG-1A loading --

from EFP-1 upon EFW initiation.

32 MOD 11-Installs a new diesel generator (not safety related) to provide an alternate backup power supply for FWP 7.

Although not taken credit for, this will potentially alleviate EDG loading concerns when it is available during SBLOCAs providing defense-in depth for OTSG cooling.

MOD 12 Changes the ES automatic actuation logic for the normal makeup supply valve MUV 27 to add automatic closure upon receipt of a diverse containment isolation signal (which also initiates HPI).

This will aid in HPI flow balancing cctions in the event of a broken l

HPl line.

MUV-27 must be closed to help ensure accurate HPI flow l

indication.

MOD 13 Provides circuit changes to allow the operator to bypass the ES l

signal and obtain manual control of the ES systems.

By)assing the 1

ES signal is necessary to take manual control over the iPI injection valves when implementing the HPI isolation criteria 1400 14 Reroutes and protects cables for the EDG room cooling fans and adds switches for the fans to the remote shutdown panel.

MOD 15 Provides conduits and supports for the rerouted / protected control cables for the EDG room cooling fans.

MODS 14 and 15 are part of EDG upgrade which now requires the operation of both room cooling fans.

MOD 16 Replaces the ED3 radiators, including the fans to increase air flow rate for the radiators. Modifies the radiator fan drive to allow higher fan horsepower for cold weather operation.

MOD 17 Adds registers to the engine room supply air duct work to reduce pressure loss in the ductwork, rebalances the system to redistribute the air in the engine room, and replaces the ventilation systerr filters with ones that have a lower pressure drop.

MOD 18 Modifications to the EDG building to minimize recirculation of radiator discharge air. MODS 16.17.- and 18 are intended to improve diesel generator efficiency (operate at lower temperature) allowing for a larger load handling capacity.

In its September 25, 1997 submittal the licensee identified that MOD 8 was the only modification that was considered by the licensee to involve a USQ.

As a result of that determination the licensee submitted (August 26. 1997) a separate License Amendment Request (LAR-216) associated with that modification.

The staff safety evaluation for LAR-216 will be provided in a separate document.

The staff has not performed a detailed review to determine if any changes associated with the remaining modifications would involve a US0 although it believes that most of the changes could be made without involving a U50.

Such a review and determination are-not necessary as the identified modifications are part of the proposed TS changes and safety assessment for which the licensee has requested approval by TSCRN 210.

The staff considers the proposed modifications to be an integral part of the TSCRN 210 review package and could not otherwise approve the proposed TS changes and supporting analyses without approving at least the bases for the proposed modifications, b

33 The proposed modifications and their base:, are discussed within this evaluation as they relate to the SBLOCA analyses and proposed TS changes.

Some of the modifications also are necessary to resolve, or are a direct i

result of the resolution for a number of existing US0s.

Based on its review.

1 the staff concluded that the licensee has provided acceptable baces for the proposed modifications, that the modifications should result in safety improvements, and that they are necessary to respond to certain SBLOCA scenarios identified by the licensee.

However, except for MOD 8 (see staff evaluation for CR-3 License Amendment Request 216), the staff has not performed a detailed review of the design changes associated with the modifications because the licensee has not identified 6ny resultant US0s.

Thus, the staff's acceptance is for the justification and bases for the modifications, but does not include the actual implementation of the modifications.

It is the responsibility of the licensee to ensure that the implementation of the modifications does not involve a US0 and is in accordance with the current licensing and design basis.

Table 3 consists of twc tables. Table 3A and Table 38. Table 3A identifies operator actions that are assumed to be taken in less than 20 minutes (following loss of subcooling margin) for the SBLOCA scenarios of concern, while Table 3B identifies only the new operator actions that may be required Afle,t 20 minutes (following loss of subcooling margin) for these scenarios, f

in its September 25, 1997 submittal, the licensee updated these tables and expanded Table 3B to include a complete list of operator actions after 20 minutes, not just the new actions.

In its November 12. 1997 submittal. the licensee provided a second update to Tables 3A and 3B to include changes to the corresponding E0P steps for the operator actions required for mitigating the SBLOCA scenarios.

In its September 25, 1997 submittal, the licensee also identified which of the actions in both tables have been previously reviewed

. by the staff.

However, the licensee also requested the staff review the complete list of operator actions as an integral part of TSCRN-210 in order to achieve a comprehensive review of the SBLOCA mitigation strategy.

The staff has reviewed these actions to evaluate the plant design for coping with a SBLOCA and the licensee's overall SBLOCA mitigation strategy.

However, the staff has not re-reviewed or re evaluated the bases for acceptance of those actions that were previously reviewed by the staff, but instead, evaluated them only from the standpoint of their overall effect on the ability of the operators to perform all of the required actions within the time limits required for each of the three SBLOCA events.

That evaluatico is described below in Section 3.9 The staff has reviewed and evaluited the acceptability of the new operator actions that have been identified including the bases for these actions. The staff's evaluation of the technical basis for the new operator actions is provided immediately following in this section of the SE.

Tables 3A and 38 list 17 operator actions (OAs) identified as OA-1 through 0A-17.

0A-1 through 0A-6 are included in Table 3A as actions required in less than 20 minutes, while OA-7 through 0A-17 are included in Table 3B as 6ctions required to be taken after 20 minutes.

0As-1. -3. -6. -8. -13 and -16 have previously been reviewed by the staff and have only been addressed for this evaluation in Section 3.9 below.

0 OA 2 requires within 10 minutes that if subcooiing margin is lost (identified by B&W as a SBLOCA symptom) and ES has not actuated, initiate manual HPI and RBIC.

Both of these ections are accomplished via push buttons in the control room.

These actions will isolate letdown, initiate HPI flow, isolate normal makeup (contingency action in 0A 4 if no power), isolate RCP seal control bleedoff valves, actuate EFIC and initiate emergency reactor building (RB) cooling. This OA is required only in the event that a loss of subcooling

. margin precedes automatic initiation of these functions.

The manual initiation of RBIC within 10 minutes for loss of subcoolin action that has not been previously reviewed by the staff.g margin.s e new The isolation of letdown and normal makeup are operator actions associated with 050 6.

The initiation of RBIC for SBLOCA mitigation does not result in any new functions or attirns for SBLOCAs since automatic initiation was always assumed.

However, for some SBLOCAs automatic initiation may not immediately occur and some of the RBIC functions need to be assured to support other o>erator actions.

For example, RCP seal control bleedoff valves need to >e closed before (or within 90 seconds after) seal injection is isolated (OA 4), and normal makeup needs to be isolated to adequately isolate a broken HPI line (OA 5). Therefore, to ensure the effectiveness of other post-SBLOCA actions this function must be assured beforehand.

Because these actions (0A 2) are prerequisites to other actions and only result in equipment functions or configuration changes that would have occurred automatically, the staff concludes that they are acceptable.

0A 4 is one of the operator actions associated with US0 6, and requires isolating RCP seal injection within 20 minutes. Also, as a contingency action if power is lost to MUV-27 (normal makeup) and MUV-18 (RCP seal injection),

power is transferred to an energized bus and the valves are then closed. The purpose of this action is to maximize HPI flow to the reactor.

The basis for this action is that seal injection flow instrumentation relieu on to determine HPI runout flow limits is not qualified and the worst case instrument error may result in inadequate HPI flow. With seal injection isolated, adequate RCP seal cooling will still be provideo by thermal barrier coolin coolers) frorr the nuclear services closed cycle cooling (SW) g (seal area system Additionally, the RCP has been tripped, the controlled seal return header has been isolat.ed, and the vendor states that the seals are designed to function without seal injection flow.

The contingency actions are necessary in the event power for MUV-27 and MUV-18 was lined up to a bus lost due to a LCBA or LOBB scenario.

Because these actions will increase HPI flow ca) ability and RCP seal cooling via the area seal coolers will still be availa)le, the staff concludes that they are acceptable.

0A-5 involves actions intended to ensure adequate HPI flow (US0-6) will exist by isolating a broken injection line using an isolation criterion. The licensee has established an isolation criterion that takes into account the expected flows through the four injection aaths, the instrumentation uncertainties, and the worst-case HPI breat causing the lowest break flow in order to be able to ioentify and isolate a potential failed injection line.

The worst-case break causes 175 gpm to be discherged out the break. This breck, with the instrument uncertainty, would be isolated. Any break that causes less than 175 gpm does not need to be isolated to keep the core covered. The isolation criterion. lf the highest flow path is injecting 50

o 35 4

gpm higher than the second highest flow path, was established to maximize the potential to identify a failed injection path while not unnecessarily isolating an intact path. A failed injection line will cause the majority of the injected flow to go out of the break because the back pressure in the RCS is much higher than the back pressure in containment. As a result, there may not be sufficient flow directed to the core. The staff finds this action would allow the operators to identify the broken injection path, and isolate it to ensure sufficient flow to the core.

Therefore, the staff finds this action acceptable.

0A 7 involves starting control complex ventilation fans in the emergency mode

~

within 30 minutes if the fans are not already running. Operation of control complex ventilation (without chilled water cooling) is necessary to ensure control room o>erator dose is not exceeded and to provide cooling air flow to areas within t1e control complex fcr operator and equipment protection (full cooling with chilled water to the control complex heat exchangers will occur within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 0A-12).

This. action (and 0A-12) specifies 30 minutes as an acceptable time to initiate the actions: previous analyses assumed that the fans were started within 10 minutes.

There have been no proposed modifications to these systems for TSCRN-210 which eliminated any automatic functions of these systems, and therefore, manual initiation has been relied upon under the same conditions in the past.

The staff has determined that the licensee has adequately justified these start times (see Section 3.2 above).

0A 9 specifies o>erator action to cross tie EFP-2 to the Train A. (EFP-1) discharge path. )y opening EFV-12 and securing EFP-1 if Train B DC power is lost (LOBB). This action must be performed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months in order to allow loading of the Train A chilled water components.

These actions are discussed in more detail in Section 3.2 of this evaluation and have been determined to be necessary to compensate for certain single failures which could occur following a SBLOCA during Cycle 11.

Since EFW will be maintained throughout the EFW mission time by either EFP-1 or EFP-2, the proposed action is acceptable.

0A-10 is a followup to 0A-9 and requires placing EFIC in manual permissive and closing the Train B EFW block valves to prevent block valve cycling allowing 0TSG 1evel control via the Train A EFW discharge path. These actions are necessary for Cycle 11 to ensure EFW mission time and EDG load management following a LOBB. This action also is discussed further in Section 3.2 above, and is acceptable on the same basis as 0A-9.

0A-11 is another operator action identified for Cycle 11 and is intended to manage EDG loading in order to extend EFP-1 o>eration. This action would secure SWP-1A and RWP-2A (via new pull-to-loct switches) after verifying that the corresponding Train B pumps are running, and would place the new EFP-1 trip defeat switch in the defeat position to prevent automatic tripping of EFP-1 at 500 psig RCS pressure.

These actions, discussed previously in Section 3.2 are supplemental defense-in depth measures in the event of a failure of EFP-2.

Because the SW and RW pumps supply common headers in their respective system securing these pumps does not result in loss of cooling to

36 any cooled components (provided the Train B pumps are running).

This proposed i

action would also provide a more controlled and manageable post-SBLOCA response by extending EFW operation and is, therefore, acceptable.

0A 12 would complete the actions for control complex cooling by starting a control complex chiller if not already running. This action is required within I hour based on the licensee's calculations which show that limits will i

not be exceeded for at least 80 minutes. This action is necessary to complete the safety function of control c lex cooling and has no auto-start features.

Thus, it has always been a manuall initiated function and is acceptable as discussed for 0A 7 and in Section

.2 of this evaluation.

0A-14 provides for managing the operation of EFP-2 if it is the only pump 3roviding feedwater flow :or OTSG cooling (LOBA or LOBB scenario). This will

>e accomplished by stopping RCS cooldown before an EFP-2 operational limit is reached and closing / reopening of ASV 5/204 as OTSG pressure cycles below 200 psig. This will maintain EFP 2 as an available source of water and operate the pump within analyzed regions, if FWP 7 1s operating (considered for defense in-depth only) via the new diesel power supply, this action will be limited or unnecessary.

Tne operation of FWP 7 would eliminate the need to perform many of the actions discussed herein since FWP-7 could re) lace the operation of either EFW puma.

In that case, these actions would secome backup actions in the event of subsequent FWP-7 failure. As discussed above in Section 3.2. this action is acceptable based on the licensee's analysis of EFP-2 capability.

0A 15 provides a general instruction for Cycle 11. to limit RCS cooldown orior to reaching 500 psig if EFP 2 is not operating..In this case (loss of EF) 2) operators are instructed to take steps to casure that EFP-1 operates as long as necessary.

This action is acceptable because it further ensures EDG load management strategies and maintains adequate EFW/ECCS capability to mitigate the event.

0A-17 provides for the periodic re evaluation of the HPI line break isolation criterion on RCS repressurization.

This is essentially the same action 0A 5.

however, the operators are instructed to periodically revisit the criterion.

Under some circumstances, the RCS gpm criterion is not met, however, pressure may start low enough that the 50 as RCS pressure increases more flow goes out the break.

0A-17 instructs the operators to determine if one of the injection paths needs to be isolated later in the event.

The staff finds this action conservative and therefore, acceptable.

3.9 Human Factors Assessment of Procosed Doerator Actions 3.9.1 Discussion of Ooerator Actions As discussed above, the licensee's proposed SBLOCA mitigation strategy involves several plant changes and operator actions.

Following is the staff's

^

evaluation of the proposed operator actions.

A review of the Standard Review Plan. (NUREG 0800. 1993). Chapter 15.

" Accident Analysis". indicates that operator actions for steam generator tube

=

o 37 rupture; boron dilution: antici)ated transient without scram; and transier.ts requiring manual tripping of RC)s, were anticipated as part of the design

. bases analyses.

For a boron dilution event, steam system and feedwater failures which require a RCP trip, there are explicit limits on the timing of operator responses to cope with these transients.

For other analyzed accidents and conditions, the NRC has not set specific time limitations on crediting operator action for mitigating DBAs.

In those instances where licensees consider temporary or permanent changes to the facility which credit o>erator actions for previously automated system or component actuations, tie staff has relied on the guidance provided in Generic Letter (GL) 91-18. *Information To Licensees Regarding Two NRC Inspection Manual Sections On Resolution of Degraded and Nonconforming Conditions and on Operability" (1991), and ANSI /ANS Standard 58.8. " Time Response Design Criteria for Safety-Related Operator Actions" (1994).

Though ANSI /ANS 58.8 provides a methodology for estimating reasonable response times for operator actions, it permits licensees to use time intervals derived from independent sources, provided that they are based on task analyses with consioeration given to human )erformance.

The staff expects licensee's task analyses to include, but not >e limited to:

1) the specific operator actions required.

2) potentially harsh or inhospitable environmental conditions expected.

3) a general discussion of the ingress / egress paths used by plant stcff to accomplish required functions.

4) procedural guidance for required actions.

5) specific operator training necessary to carry out actions, including any special operator qualifications required to perform required actions.

6) any additional support personnel and/or equipment required by operators to perform required actions, 7) description of information required by the control room staff to determine such operator action is required including qualified instrumentation used to diagnose the situation and to verify that the required action has been successfully taken.

(As described in RG 1.97.

" Instrumentation for Light Water Cooled Nuclear Power 7 to Assess Plant and Environs Conditions During and Following an As Ment." revision 3,1983, qualification of the instrumentation relied upon by the operators may be an important review issue.

RG 1.97 defines Type A variables as: "those variables to be monitored that provide the primary information required to permit the control room operator to take specific manually controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their functions for design basis accident events. ) and, 8) ability to recover from credible errors in performance of manual actions and the expected time required to make such a recovery.

l l

o 1

38 Characterization cT these items, through detailed analysis including the use of the plant specific simulator, 3rovide a means for the licensee to assess tho likelihood of accomplishing t1e required actions and the consequences of delayed or missed opportunities to complete such actions.

The analyses should also provide the licensee with insights to help determine if the 3roposed change constitutes an US0.

(The staff.onsiders all situations w1ere licensees substitute operator actions for previously analyzed automatic safety related actions to be potential US0s because of the possibility of the operator taking actions which could result in the increase of the consequences of an accident, cause a new or different type of accident than previously analyzed, or reduce the margin of safety as defined in the plant's design basis.

j Therefore, when a licensee proposes such changes to the plant, justification for why the pro)osed changes do not constitute a US0 per 10 CFR 50.59 must be )rovided or seet an amendment as appropriate.)

Finally, in accordance witi GL 91 18 gu1A nce, the licensee is expected to have approved procedures in place and oper.Jor training completed prior to implementing such changes.

3 9.2 EVALUATION 1....s June 14.-1997 TSCRN-letter. FPC provided the NRC with draft lists t

Tables (3A and 38) of operator actions required to mitigate an initiating SBLOCA event with concurrent LOOP and the three identified limiting single failure conditions.

One (Table A) list provided actions required to be taken within the first 20 minutes of the event, the second (Table B) a list of actions required after the first 20 minutes of the SBLOCA event.

It is noted that not all of the operator actions listed in the tables are required for all SBLOCAs.

i Some of the actions are required for each of the three single failure conditions; some are not required to mitigate consequences of the SBLOCA, and some are defense in depth actions and are not considered in the design basis mitigation strategy.

As part of its June 14,1997-submittal, FPC summarized the o)erator actions that are needed to mitigate the SBLOCA accidents involving tie three single failure conditions:

In response to a reactor trip, operators perform several immediate actions contained in E0P-02 (Vital System Status Verification) to ensure that the reactor is shutdown and the turbine is tripped.

Operators then would scan the control board to determine if any) signs of upsets in heat transfer ex'ist, with inadequate subcooling margin (ISM being the highest heat transfer related symptom (the SBLOCA event analyzed by the licensee results in a loss of adequate subcooling margin). Rec nizing an ISM condition exists, operators then would perform actions in (Inadequate Subcooling Margin). EDP_-3 1

actions focus on assuring core co ing by tripping Reactor Coolant pumps, maximizing HPI, and establishing OTSG levels at the loss of subcooling margin setpoint usin the licensee.g EFW. These actions are common to all the SBLOCA analyzed by 4

4 y-v-

- w w

-m

-.r,--

.---w--

-.en

-,e..

,y-y-,

w...------yr.,

w 39 For a LOBA. Emergency Diesel Generator (EDG)-1B is the active emergency power source. Using E0P 3. operators restore control complex (e.g. main control room) ventilation by starting AHF 18B and AHF-19B (emergency recirculation and supply fans).

With a loss of adequate subcooling margin, operators branch from EQP_-3 to f P-(LOCA Cooldown) to establish control complex cooling by starting the

rain chiller, Under this accident condition, there is a potential challenge to the long term operation of emergency feedwater pump (EFP-2) because of low steam supply pressure.

However, to prevent this challenge from occurring, operators will secure the turbine (by closing ASV-5)

If the OTSG aressure reaches 200 psig. When OTSG aressure recovers, operators place EFP 2 Jack in service. As a defense in dept 1 measure FWP-7 is available to supply OTSG with feedwater to continue plant cooldown to the initiation of low pressure injection (LPI).

For a LOBB, the most challenging of three single failure accidents. EDG 1A is i

the emergency power supply. Using E0P 3. operators restore control complex (e.g. main control room) ventilation by starting /HF 18A and AHF-19A (emergency recirculation and supply fans).

Operators would then secure EFP-1 before loading the "A" control complex chiller, which will occur 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the initiation of the event. Operators will cross-connect EFW using fE-3 enabling EFP 2 to supply EFW to both OTSGs.

Operators then transition from

[QP:-3 to EQP 8 to start the "A" Train control complex chiller.

Cross-P 2

connecting the EFW is accomplished from the control complex and will occur within the time needed to reestablish control complex cooling (approximately 80 minutes after event initiation). As a defense in-depth measure, feedwater pump (FWP 7) is available to su) cooldown to the initiation of L) ply OTSG with feedwater to continue plant I.

For the loss of EFP 2, both EDGs start and provide emergency power to their respective ES busses. Using E0P-3. Operators restore control complex (e.g.,

main control room) ventilation Dy starting AHF-188 and AHF-19B (emer ency recirculation and supply fans). 0)erators branch Yrom E0P-3 to to establish control complex cooling )y starting the ~B" Train chil er.

Before reaching an EFP 1 o erating limit, operators will start decay heat pump 1 A (to establish ECCS iggyback): stop SWP-1A and RWP-2A: and place their respective pull to ocE switches in the " lock" position: and defeat the EFP-1 auto tri As a defense p function, all steps being accomplished from the control room.

in depth measure, FWP-7 is available to su continue plant cooldown to the initiation of LPI. pply OTSG with feedwater to The specific actions required by the operators to accomplish their functions are taken from the main control room and require individual switch manipulation and mor'.oring instrumentation located primarily on the main control board or r the back of it, with exception of two actions that are taken locally (i.e.. starting the control complex chiller and cross-tying emergency feedwater).

Required control room indications and instrumentation necessary for the operators to perform the actions required to mitigate the SBLOCA conditions are in accordance aith RG 1.97 and the important subcooling monitors are highly visible, digital display instruments which do not require interpolation by the operators.

The licensee stated that since all actions required are taken from the control complex. primarily the main control room, inhospitable environments are not problematic.

Ingress and egress paths

40 required to perform the local actions are lighted with emergency lighting and also pose no environmental problems.

In addition to the operator actions contained in Tables 3A and 3B of their June 14, 1997 submittal, the licensee also provided revisions to the tables in letters dated September 17, 1997: September 25: 1997: November 19,1997: and in Attachment D of their December 24, 1997 letter. Also, in response to the staff's request of June 24, 1997, the licensee submitted copies of draft E0Ps relevant to the SBLOCA events on August 4,1997 and " proposed final" E0Ps on November 19, 1997.

In their September 25. 1997 letter, the licensee also submitted results of several E0P validation exercises conducted using the licensee's plant simulator, draft E0Ps, and normal and minimum crew staffing for nine scenarios involving the SBLOC, e vents.

(In letters dated Decenber 3,1997 and December 11, 1997. FPC proviaed supporting information to confirm that the draft E0Ps that were used during the validation exercises were not "significantly different" (e.g., did not contain substantive, technical changes] from the proposed final E0Ps, This statement was confirmed during NRC LOP 1aspections conducted in December and January 1998).

Results from additional simulator validations of E0Ps were submitted to the staff on November 19. 1997. for two scenarios involving the LOBB single failure condition. Also, as part of the E0P inspection conducted at the site during the week of December 8.1997, a simulation of the LOBB event, using a minimum shift crew, was observed by an NRC inspector.

The inspector confirmed that the in plant action of starting the control complex chiller was accomplished (simulated) within the required time. Additional feedback on the ability of operators to perform certain actions was provided by the E0P inspection team during the followup inspection of January 5-9. 1998, which confirmed the successful completion of certain o>erator actions (e.g., cycling the EFP 2 during a LOBA).

In addition, the E0P inspection team identified a concern involving the potential need to swap over the control complex chillers. This swapover could be required if the operating chiller were inadvertently triaped.

Tripping the o>erating chiller would result in significantly reducing tie time margin availa)le for having an o)erable chiller within the 80 minute time frame required. According to the NRC inmector, the licensee has modified the E0P involved with chiller startup (i.e.

E0P-14 Enclosures 17 (control complex ventilation) and 18 (Control Complex Chiller Startup) so that the swapover would not be needed and.

comitted to train all operators on the use of the procedure change.

In their December 24, 1997 submittal, the licensee supplemented their September 25 and November 19, 1997 results of simulator validations of E0Ps for a total of 12 simulator validations using eleven different LOCA/ Loss of Subcooling Margin (LSCM) scenarios. The results from the twelve simulator validations reported by the licensee, which represents performance by three of the six active CR-3 operating crews, indicate that successful performance of operator actions required to mitigate each of the three SBLOCA events was consistently achieved by operations personnel under normal and minimum crew staffing levels.

(Timed results of successful performance during simulator validations were not provided by the licensee of operator action #14. " Cycle EFP-2", an action required to be taken after 20 minutes in the mitigation of a LOBA failure. Acceptable performance of this step however, was confirmed by

o 41 an NRC inspector during the E0P inspection conducted sanuary 5 9. 1993.) The l

two actions that are required to be taken locally (i.e., starting the control complex chiller and cross tying emergency feedwater) were simulated during the E0P validation trials and were reported by the licensee to have been performed successfully within the times required.

While the majority of E0P simulator exercises were conducted as unannounced casualties to " functional crews" (i.e., no mixing of crew members) instructor intervention occurred to answer questions or provide additional information as necessary.

In their December 24, 1997 submittal, the licensee reported that all o crews, including backup licensed operators. have been " fully trained

perating in mitigating an SBLOCA concurrent with a LOOP and each of the three limiting single failure conditions.

Further. FPC indicated in their December 24, 1997 submittal that "each operating crew (including backup licensed operators) participated in an unannounced cLualty training effectiveness exercise at the end of their training week *...using a scenario similar to a LOBA condition.

This exercise involved no instructor intervention.

" Performance of all crews was satisfactory."

Also. as discussed in Sectirn 2.6 of this SE. the licensee has estimated the effect of failure to perform requirect manual operator actions on the core damage frequency and concluded that the risk would be significantly. low. The licensee further stated in their December 24, 1997 submittal that seven operator actions may be eliminated as a result of certain hardware modifications being considered prior to Cycle 12 to increase the capacity margins of the EDG beyond the margins proposed by TSCRN 210. thereby eliminating the nperator actions required by TSCRN 210 for load management.

Based on reviewing the results provided by the licensee as described above, and re!.ults of the NRC's E0P inspection team, the staff concludes that the licensee has satisfactorily demonstrated that operating crews are capable of successfully serforming the actions necessary to mitigate conditions of an initiating SB.0CA event with concurrent LOOP and the three limiting single failure conditions, of: (1) L0BA or associated main distribution panel: (2)

LOBB or its associated main distribution panel:

(3) Loss of EFP 2.

The staff finds the )reviously discussed information to be consistent with the review guidance of AiSI/ANS 58.8 (1994) and Generic Letter (GL) 91-18. (1991) and. therefore, acceptable.

The staff further em with GL 91-18 and Information Notice 97-78 (1997)phasizes that, in accordance

" Crediting of Operator Actions In Place Of Automatic Actions And Modification Of Operator Actions.

Including Response Times ' crediting the manual actions identified by the licensee to mitigate the three SBLOCA events is expected to be a temporary, compensatory measure and, as such, is approved through Cycle 11 only. Prior to entering Cycle 12. the licensee is expected to correct the automatic actions in accordance with 10 CFR Part 50 Appendix B. Criterion XVI.

' Corrective Action" and as a minimum eliminate the seven manual operator actious (Nos. 3.4.5.9.11.15 and 17) as discussed in their December 24. 1997 submittal.

42 4.0

SUMMARY

Based on its review of licensee's analyses of the three limiting EDG capacity-related single failures involving LOBA. LOBB and loss of EFP 2. the staff concludes that the licensee's proposed plant and operational modifications are adequate for mitigating SBLOCA.

The proposed changes are consistent with applicable regulations and meet relevant review criteria, and are therefore, acceptable.

In its determination, the staff consiaered that some of the pro)osed changes are applicable only for one cycle. Fuel Cycle 11. and prior to uel Cycle 12. the licensee plans to assess and implement appropriate r

permanent actions. The staff will review these permanent actions and associated TS change request.

5.0 STATE CONSULTATION

Based upon written notice of the proposed amendment, the Florida State official had no coments.

6.0 EN"lRONMENTAL CONSIDERATIONS The amendment changes requirements with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that this amendment involves no significant hazards consideration and there has been no public comment on such finding (62 FR 52581). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuant to 10 CFR 51.22(b) no environmental im)act statement or environmental assessment need be prepared in connection witr the issuance of the amendment.

7.0 CONCLUSION

The Commission has concluded based on the considerations discussed above, that:

(1) there is reasonable assurance that the health and safet public will not be endangered by operation in the proposed manner.y of the (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of these amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors:

W. LeFave. SPLB/NRR C. Jackson SRXB/NRR J. Bongarra. HHFB/NRR F. Orr..SRXB/NRR Saba Saba. EELB/NRR S. Lee, SPSB/NRR L. Raghavan. DRPE/NRR Date: January 24, 1998

. _ = _ _ _,

TABLE 1 Page 1 of 2 LIST OF ACRONYMS AND ABBREVIATIONS USED i."

..... Alternating Current

/

...... Atmospheric Dump Valves A.

...... Auxiliary Feedwater AD1

..... Allowed Ou..,. Time AS

...... Auxiliary Steam ASME

..... American Society of Hechanical Engineers AT0G

..... Abnormal Transient Operating Guidelines BSP...... Building Spray Pump B&W...... Babcock and Wilcox BWOG

,.... Babcock and Wilcox Owners Group BWST

..... Borated Water Storage Tank CAL...... Confirmatory Action Letter CCCS

..... Control Com) lex Cooling System CE....... Combustion Engineering CFR,..... Code of Federal Regulations i

CHHE

,.... Control Complex Chiller CHP...... Chilled Water Pump CLPD

..... Cold Leg Pump Discharge CR 3

..... Crystal River Unit 3 CREVS

.... Control Room Emergency Ventilation System CST...... condensate storage tank DBA...... Design Basis Accidents DC

.-..... Direct Current Electrical DHCCC,,... Decay Heat Closed Cycle Cooling Water System DHP...... Decay Heat Pump DHR...... Decay Heat Removal DHSW

..... Decay Heat Seawater ECCS

..... Emergency Core Cooling System EDG,..... Emergency Diesel Generator EDG 1A

..,. Emergency Diesel Generator Train A EDG 1B

.... Emergency Diesel Generator Train B -

EFIL

..... Emergency Feedwater Initiation and Control System EFP...... Emergency Feedwater Pum)

EFP-1..... Motor driven Emergency reedwater Pump EFP-2

.... Turbine driven Emergency Feedwater Pump EFV...... Eme-cency Feedwater Valve EFW...... Emt, gency Feedwater E0P,..... Emergency Operating Procedure ES

...... Engineered Safeguards ESAS

..... Engineered Safeguards Actuation System F....... Fahrenheit FPC...... Florida Power Corporation FSAR

..... Final Safety Analysis Report FTI...... Framatome Technologies Incorporated (formerly B&W)

FWP 7..... Nonsafety motor-driven Auxiliary Feedwater Pump

TABLE 1 Page 2 of 2 gal...... gallon g)m...... gallons per minute H)!...... High Prese,ure Injection

. 0R.

.... Ingersoll Dresser l iT.

.... Inservice Testing

?i

...... kilowatts Lt,u...... Limiting Condition for Operation LER...... Licensee Event Report LOBA

..... Loss of Battery A LOBB

..... Loss of Battery B LOCA

..... Loss of Coolant Accident LOOP

..... Loss of Offsite Power LPI...... Low Pressure Injection MOV...... Motor Operated Valve MSSV

..... Main Steam Safety Valve MVP...... Makeup Pump MWt...

,. Megawatt (Thermal)

NPSH

...., Net Positive Suction Head NRC...... Nuclear Regulatory Comission OA

..,... Operator Action OTSG

..... Once Through Steam Generator PCT,

.... Peak Clad Temperature psi...... pounds per square inch psig

)ounds per square inch gauge PSV,....,

pressurizer Safety Valve PTL...... Pull to lock rpm..,... Revolutions Per Minute RB

...... Reactor Building RBCU

..... Reactor Building Cooling Units RBIC

..... Reactor Building Isolation and Cooling RCP...... Reactor Coolant Pump RCS...... Reactor Coolant System RG

,..... Regulatory Guide RW

...... Nuclear Services Seawater System RWP...... Nuclear Services Seawater Pump SBLOCA

.... Small Break Loss of Coolant Accident SER,..... Safety Evaluation Report STS...... Standard Technical Specifications SR

,..... Surveillance Requirement SW

...... Nuclear Services Closed Cycle Cooling System SWP...... Nuclear Services Closed Cycle Cooling Pump TBD...... Technical Bases Document TEV...... Turbine Bypass Valves TMI

..... Three Mile Island

-TS

...... Technical S cification TSB...... Technical S ecification Bases TSCRN..... Technical S cification Change Request Notice USQ...... Unreviewed afety Question l

_.-,.,m,.--

O TABLE 2 LIST OF TS CHANGES TS SECTION DESCRIPTION PERMANENT OR ONE-4 OFLCHANGE 4

' CYCLE 3.5.2, Action A.1 Added verification of One Cycle (Until turbine driven EFP pump and Cycle 12) flow path 3.5.2, Action A.2 Revised number assigned to One Cycle (Until Action Cycle 12) 3.7.5, Delete Applicability Note Permanent Applicability Note 3.7.5, Action B New Action One Cycle (Until Cycle 12) 3.7.5, Action C New Action One Cycle (Until Cycle 12) 3.7.5, Action D New Action One Cycle (Until Cycle 12) 3.7.5. Action E Changed scope of action to One Cycle (Until motor driven EFW pump and Cycle 12) flow path 3.7.5, Action F Revised numbers assigned to One Cycle (Until

~

Action Cycle 12) 3.7.5, Action G Revised numbers assigned to One Cycle (Until Action SR 3.7.5.2 Cycle 17)

Revised note to not require Permanent performance of SR 3.7.5.2 until 24 after entering Mode 3.

SR 3.7.5.3 Revised note to not require Permanent performance of SR 3.7.5.3 until 24 after entering Mode 3.

SR 3.7.5.4 Revised note to not require Permanent performance of SR 3.7.5.4 until 24 after entering Mode 3.

3.7.7, Action A New Action applicable to One Cycle (Until SWP-1B Cycle 12) 3.7.7, Action B Changed scope to SWP-1A one Cycle (Until Cycle 12) 3.7.7, Action C Revised numbers assigned to One Cycle (Until Action Cycle 12) 3.7.8, Action A.1 Added verification of One Cycle (Until turbine driven EFW pump and Cycle 12) flow path 3.7.9, Action A New action for "B"

train of One Cycle (Until Nuclear Services Seawater Cycle 12)

System 3.7.9, Action B Revised scope of Action to One Cycle (Until

'A" train of Nuclear Cycle 12)

Services Seawater System I

l

TABLE 2 L ST OF TS CHANGES

.TS SECTIO [;.

y, DESCRIPTION:

.ramMAnany OR uns; OF-CHANGE CYCLE-3.7.9, Action C Revised numbers assigned to One Cycle (Until Action Cycle 12) 3.7.10, Action A.1 Added verification of One Cycle (Until 4

turbine driven EFW pump and Cycle 12) flow path 3.7.18, LCO New Specification for Permanent Control Complex Cooling 3.7.18, New Specification for Permanent Applicability Control Complex Cooling 3.7.18, Action A Scope applicable to CHHE-1B One Cycle (Until and CHP-1B Cycle 12) 3.7.18, Action B Scope applicable to CHHE-One Cycle (Until 1A, CHP-1A and heat Cycle 12) exchangers 3.7.18, Actions C, New Actions for Control Permanent D,

E,

&F Complex Cooling SRs. 3.7.18.1 and New SRs for Control Complex Permanent 3.7.18.2 Cooling 3.8.1, Action B Revised scope to "A"

One Cycle (Until train EDG Cycle 12)

Added verification of turbine driven EFW pump and flow path Revised numbers assigned to Actions 3.8.1, Action C New Action for "B"

train One Cycle (Until EDG Cycle 12) 3.8.1, Action D Revised numbers assignec to One Cycle (Until Actions Cycle 12) 3.8.1, Action E Revised scope to "A" One Cycle (Until train EDG Cycle 12)

Added verification of turbine driven EFW pump and flow path Revised numbers assigned to Actions 3.8.1, Action F New Action for "B"

train One Cycle (Until EDG Cycle 12) 3.8.1, Actions G, Revised numbers assigned to One Cycle (Until H&I Actions Cycle 12)

SR 3.8.1.4 Revised required volume Permanent SR 3.8.1.11 Revised EDG load band Permanent 3.8.3, Action A New Action to verify Permanent combined stored fuel oil volume

_ _. _. ~. _ _ - - _ _

o TABLE 2 LIST OF TS CHANGES n

. TS. SEC'rION -

DESCKIFTION-

_ PERMANswr - OR. ONE v.

OF-CHANGR-

+ CYCLE' 3.8.3, Action B Revised stored fuel oil Permanent volume 3.8.3 Action C Revised stored lube oil Permanent volumes and clarify stored lube oil applies to both EDGs

~

3.8.3, Actions D, Revised numbers assigned to Permanent E,

F,

&G Actions SR 3.8.3.1 Revised stored fuel oil Permanent volumes SR 3.8.3.2 Revised stored lube oil Permanent volume and clarify scope to both EDGs 3.8.9, Action A Revised scope to *A" One Cycle (Until train AC electrical Cycle 12) power distribution subsystem Added verification of turbine driven EFH pump and flow path Revised numbers assigned to Actions 3.8.9, Action B New Action for "B" AC One Cycle (Until electrical power Cycle 12) distribution subsystem 3.8.9, Action C.1 Revised scope to "A" One Cycle (Until train AC vital bus Cycle 12) subsystem Added verification of turbine driven EFW pump and flow path Revised numbers assigned to Actions 3.8.9, Action D New Action for "B"AC vital One Cycle (Until bus subsystem Cycle 12) 3.8.9, Actions E, Revised numbers assigned to One Cycle (Until F&G Actions Cycle 12)

O O

TABLE 2 LIST OF TS CHANGES

< TSB. PAGE AND.

i=5CRIrnON.OF : umaanas,

ransmanena: .OR - QWE -

iSECTICW.

+

CYCLEa B 3.3.5, Add EFW/LPl trip defeat One Cycle (Until

Background

Cycle 12)

B 3.3.17, LCO, Delete d: Scussion of EFW Permanent Item 19 runout B 3.5.2, Add discussion of need of One Cycle (Until

Background

EFW for certain SBLOCAs Cycle 12)

B 3.5.2, LCO Clarification regarding Permanent number of HPI pumps and injection legs B 3.5.2, Action New Action for verification One Cycle (Until A.1 of turbie driven EFP pump Cycle 12) and flow path B 3.5.2, Action Revised numbers assigned to One Cycle (Until A.2 Action Cycle 12)

B 3.5.2, Reference Added reference to One Cycle (Until 5

calculation Cycle 12)

B 3.7.5, Added discussion of EFW Permanent

Background

cavitating venturis B 3. *i. 5, Add discussion of One Cycle (Until

Background

mission for EFW Cycle 12)

Add discussion of need of EFW for certain SBLOCAs B 3.7.5, Add discussion of mission One Cycle (Until Applicable Safety for EFW Analysis Cycle 12)

B 3.7.5, LCO, 1st Revise} discussion one Cycle (Until Paragraph regarding ASV-5 and ASV-204 Cycle 12)

B 3.7.5, LCO, 2nd Defined valves in steam Permanent Paragraph supply flow paths B 3.7.5, LCO, 3rd Add discussion of need of One Cfcle (Until Paragraph EFW for certain SBLOCAs Cycle 12)

B 3.7.5, LCO, Last Deleted discussion of Permanent Paragraph operability of turbine driven EFW pump below 200 ps19 B 3.7.5, Action Revised numbers assigned to One Cycle (Until A.1 referenced Conditions Cycle 12)

B 3.7.5, Action New action for ASV-5 One Cycle (Until B.1 Cycle 12)

B 3.7.5, Actions New Actions for ASV-204, One Cycle (Until C.1 & C.2 EFV-12, and EFV-13 Cycle 12)

B 3.7.5, Actions New Actions for turbine One Cycle (Until D.1, D.2,

& D.3 driven EFP pump Cycle 12)

I l

. _ _ ~

_ _ - _ _ _ - ~ _. _ --

TABLE 2 LIST OF TS CHANGES

+res.FA"

?""

955"E1 m CBI3 OF m =

'rumannmar.OR w m-

> gECTICOI

- ( b CYCLE:

B 3.7.5, Action Changed 3 cope of action to One Cycle (Until E.1 motor driven EFP pump and Cycle 12) flow path B 3.7.5, Actions Revised numbers assigned to One Cycle (Until E.1, F.1, F.2, Actions and referenced Cycla 12) 0.1 Actions B 3.7.5, Reference Added references to One Cycle (Until 6

calculation specific to Cycle 22)

TSCRN 210 B 3.7.5, Reference Added references to Permanent 7

calculation B 3.7.7, Add discussion of need of One Cycle (Until

Background

EFW fer certain SBLOCAs Cycle 12)

B 3.7.7, Actions New Action applicable to One Cycle (Until A.1 & A.2 SNP-1B Cycle 12)

B 3.7.7, Action Changed scope to SWP-1A One Cycle (Until B.1 Cycle 12)

B 3.7.7, Actions Revised numbers assigned to Or.e Cycle (Until C.1 & C.2 Action Cycle _12)

B 3.7.8, Add discussion of need of One Cycle (Until

Background

EFW for certain SBLOCAs Cycle 12)

B 3.7.8, Actions Added verification of One Cycle (Until A.1 & A.2 turbine driven EFP pump and Cycle 12) flow path B 3.7.9, Add discussion of need of One Cycle (Until

Background

EFL for certain SBLOCAs Cycle 12)

B 3.7.9, LCO Clarified Operability-Permanent requires each valve in flow path B 3.7.9. Actions New actions for "B" traill One Cycle (Until A.1 & A.2 of Nuclear Services Cycle 12)

Seawater System B 3.7.9, Action Revised scope of Action to One Cycle (Until B.1 "A" train of Nuclear Cycle 12)

Services Seawater System B 3.7.9, Actions Revised numbers assigned to One Cycle (Until C.1 & C.2 Actions Cycle 12)

T 3.7.10, Add discussion o'f need of One Cycle (Until

Background

EFW for certain SBLOCAs Cycle 12)

B 3.7.10, Actions Added verification of One Cycle (Until A.1 & A.2 turbine driven EFP pump and Cycle 12) flow path B 3.7.12, LCO Added reference to new Permanent Specification 3.7.18

i TABLE 2 LIST OF TS CHANC?.S

Tus FAGE AND.

/ T4iECRIrnON - OFJ cauusus PERNAmani OR'ONE

-SECTION'

~

CY M B 3.7.18, New Specification for Permanent Background, First Control Complex Cooling 3 Paragraphs B 3.7.18, Add discussion of use of One Cycle (Until Background, Last "B" train chiller and pump Cycle 12)

Paragraph for certain SBLOCAs B 3.7.18, New Specification for Permanent i

Applicable Safety control Complex Cooling Analysis B 3.7.18, LCO &

New Specification for Permanent Applicability Control Complex Cooling B 3.7.18, Actions Scope applicable to CHHE-1B One Cycle (Until A.1 & A.2 and CHP-1B Cycle 12)

B 3.7.18, Action Scope applicable to CHHE-One Cycle (Until B.1 1A, CHP-1A, and heat cycle 12) exchangers B 3.7.18, Actions New Specification for Permanent C.1, C.2, D.1, Control Complax Cooling D.2, E.1,

& F.1 B SRs 3.7.18.1 &

New Specification for Permanent l

3.7.18.2 Control Complex Cooling B 3.7.18, New Specification for Permanent Reference 1 Control Complex Cooling B 3.7.18, Added references to One Cycle (Until Reference 2 calculation specific to Cycle 12)

TSCRN 210 B 3.7.18, New Specification f6r Permanent Reference 3 Control Complex Cooling B 3.8.1, Add discussion of need of One Cycle (Until

Background

EFW for certain SBLOCAs Cycle 12)

B 3.8.1, Increased EDG service Permanent

Background

ratings B 3.8.1, Last Added discussion of steady Permanent Paragraph state loads B 3.8.1, Actions Revised scope to "A" One Cycle (Until B.2 & B.3 train EDG Cycle 12)

Added verification of turbine driven EFW pump and flew path Revised numbers assigned to Actions B 3.8.1, Actions Revised numbers assigned to One Cycle (Until B.4'1, B.4.2,

&B Actions Cycle 12) 5 B 3.8.1, Actions New Action for "B"

train One Cycle (Until C.1 thru C.5 EDG Cycle 12)

t

,v TABLE 2 LIST OF TS CHANGES omTSB: PAGE A%

.. DESCRIPTION OF.CHAnus;

) PERMANENT;OR ONE..

SECTION:

? CYCLE!

s B 3. 8.1, Actions Revised numbers assigned to One Cycle (Until D.1 & D.2 Actions Cycle 12)

B 3. 8.1, F.ctions Revised scope to *A" One Cycle (Until i_-

E.1, E.2 & E.3 train EDG Cycle 12)

Added verification of turbine driven EFW pump and flow path Revised numbers assigned to Actions

]lk B 3.8.1, Actions New Action for "B"

train One Cycle (Until F.1, F.2 & F.3 EDG Cycle 12)

B 3.18.1, Actions Revised numbers assigned to One Cycle (Until G.1, H.1, H.2, Actions I.1 Cycle 12)

B 5R 3.8.1.4 Clarified that level is Permanent expressed as useable volume Revised basis for fuel oil volume B SR 3.8.1.8 Revised largest rejectable Permanent load B SR 3.8.1.11 Revised to reflect the Permanent accident loads and modified EDG service ratings B 3.8.3, Revised basis for fuel oil Permanent Background, 1st volume Change 13 3. 8.3, Revised to describe EDG One Cycle (Until Background, 2nd requirements in certain Cycle 12)

Change SBLOCAs B 3.8.3, Revised basis for fuel oil Permanent Background, 2nd to volume Last Paragraph, 3rd to last complete sentence B 3.8.3, Revised to describe EDG One Cycle (Until Background, 2nd to requirements in certain Cycle 12)

Last Paragraph, SBLOCAs 2nd to last E

complete sentence B 3.8.3, LCO, 1st Revised basis for fuel oil Permanent paragraph, 1st volume change B 3.8.3, LCO, 1st Revised to describe EDG One Cycle (Until

~~

paragraph, 2nd requirements in certain Cycle 12) change SBLOCAs I

b

l~;.4 TABLE 2 LIST OF TS CHANGES TSB'PAGE-AND:.

e.= DESCRIPTION:OF CHANGE-2 PERMANENT OR ONE-

. SECTION -

1CYCLEL B 3.8.3, LCO, 2nd Revised basis for fuel oil Permanent paragraph, 1st volu.ne sentence B 3.8.3, LCO, 2nd Revised to describe EDG One Cycle (Until paragraph, 2nd requirements in certain Cycle 12) sentence SBLOCAs B 3.B.3, Action New Action to verify Permanent A.1 combined stored fuel oil volume B 3.8.3, Action Revised number assigned Permanent B.1 to Action Clarified that level is expressed as useable volume Revised fuel oil storage requirement Revised basis for fuel oil volume B 3.B.3, Action Revised lube oil storage Permanent C.1 requirement Revised basis for lube oil volume Clarified stored lube oil applies to both EDGs B 3.8.3, Actions Revised numbers assigned to Permanent D.1, E.1,

& F.1 Actions B 3.8.3, Action Revised numbers assigned Permanent G.1 to Actions Clarified stored lube oil applies to both EDGa B SR 3.8.3.1 Clarified that level is Permanent expressed as useable volume Revised basis for fuel oil volume B SR 3.8.3.2

Revised lube oil storage Perms.ent requirement Revised basis for lube oil volume B 3.8.9, Revised to describe EFW dne Cycle (Until

Background

requirements in certain Cycle 12)

SBLOCAs

"Dd)L./ h

)

TABLE 2 LIST OF TS CHANGES

-o Tum PAGE JJED.

c DESCR1ruCN OFJ CMAmss

,y--n u n T OR:-055--

m M-SECTIOtt-

~

CYCLE:

fd

^

1.-

~

e B 3.8.9, Actions Added revised scope for One Cycle (Until A.1, A.2, B.1,

A" train AC electrical Cycle 12)

B.2, 1st Paragraph power distribution suosystem Added verification of turbine driven EFW pump, flow path, ASV-204, EFV-12 & EFV-13 B 3.8.9, Actions Addud basis for Allowable One Cycle (Until A.1, A.2, B.1, Completion Time Cycle 12)

B.2, nd Paragraph B 3.8.9, Actions Revised numbers assigned to One Cycle (Until A.1, A.2, B.1, referenced Actions Cycle 12)

B.2, Remaining changes B 3.8.9, Actions Revised scope to "A"

One Cycle (Until C.1, C.2, D.1, train AC vital bus Cycle 12)

D.2 subsystem Added verification of

)

turbine driven EFW pump, flow path, ASV-204, EFV-12, & EFV-13 Revised numbers assigned to Actions B 3.8.9, Actions Revised number assigned to One Cycle (Until E.1, F.1, F.2, Action and referenced Cycle 12)

G.1 Conditions l

1

_ _ - _ _ -

ML20199J306

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2.0 BACKGROUND

SUMMARY

5.0 STATE CONSULTATION

7.0 CONCLUSION

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ML20199J306

Text

2.0 BACKGROUND

SUMMARY

5.0 STATE CONSULTATION

7.0 CONCLUSION

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