ML072110364

Region III SDP Training, Wednesday, June 12, 2002

ML072110364
Person / Time
Site:	Point Beach
Issue date:	06/12/2002
From:	- No Known Affiliation
To:	Office of Nuclear Reactor Regulation
References
FOIA/PA-2007-0180
Download: ML072110364 (33)

Text

at.

Region III SDP Training Wednesday, June 12, 2002 On February 20, 2002, at 1:00 a.m., the Unit 2 2P-15B Sl pump was started as part of a monthly preventive maintenance bearing lubrication activity. The control room operators noted that when the pump was started, motor current increased normally, but then decayed to less than 10 amps. The normal Sl pump running current was 30 amps. Additionally, the pump developed no discharge pressure. The auxiliary operator stationed locally in the vicinity of the SI pump noted a loud noise near the end of the pump coastdown, observed excessive seal leakage, and reported the presence of an acrid smell to the control room. The Duty Shift Superintendent arrived in the pump area shortly thereafter, observed the excessive seal leakage, and perceived the acrid smell. Through follow-up discussion and observation it was concluded that the acrid smell was emanating from the inboard pump seal area. The Duty Shift Superintendent directed the isolation of the pump to secure the excessive seal leakage. The 2P-15B Sl pump was declared inoperable and TS Action Condition 3.5.2.A.1 entered at 1:00 a.m. on February 20, 2002. Technical Specification Action Condition 3.5.2.A.1 required an inoperable ECCS train to be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the affected Unit to be placed in Mode 3 (Hot Standby) within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 4 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Subsequent inspection of the pump revealed damage to the rotating element, the coupling and shaft keys between the pump and the motor, the pump internal wearing rings, and other components. Licensee investigation revealed that the cause of the equipment damage was pump gas binding as the result of back-leakage of nitrogen-saturated fluid from the Sl 'A' accumulator through at least two check valves, 2SI-845E, "Unit 2 2P-15B Sl Pump To Reactor Coolant Loop 'A' Cold Leg Sl Check Valve" and 2Sl-889B, "Unit 2 2P-15B Sl Pump Discharge Check Valve," to the 2P-15B pump discharge side. When the nitrogen-saturated water pressure was reduced from the accumulator pressure (750 pounds per square inch gauge) to the SI pump suction pressure (-30 pounds per square inch gauge), the nitrogen came out of solution causing the 2P-15B gas binding.

The licensee proceeded with the repair of 2P-1 5B with the expectation that the pump would be repaired, tested, and returned to service prior to the expiration of 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS Action Statement 3.5.2.A.1. At approximately 2:00 p.m. on February 22, 2002, the licensee determined pump repairs and testing could not be completed before the expiration of the TS action statement.

Accordingly, shutdown of Unit 2 began at 2:48 p.m. on February 22, 2002. Mode 3 was reached at 7:26 p.m. on February 22, and Mode 4 at 1:38 a.m. on February 23, 2002. During the time that the Unit 2 'B' ECCS train was inoperable, the 'A' ECCS train remained in standby service and was capable of performing the intended safety function.

The performance deficiency existed in that, on multiple occasions, the licensee failed to promptly identify and correct a significant condition adverse to quality regarding leakage from the 2T-34A safety injection accumulator. Specifically, on February 12, 2001, (CR 01-0454) and January 15, 2002, (AR 1862) licensed control room operators identified decreasing 2T-34A safety injection accumulator level trends but the license failed to determine the root cause of the leakage and prevent reoccurrence. In addition, NRC Information Notices97-040 and 88-023, Supplements 1 through 5, provided at least six other corrective action program opportunities between 1989 and 1999 to cause the licensee to consider the effects of Sl accumulator leakage on equipment operability. Failure of the licensee to critically evaluate and correct the cause of the accumulator leakage resulted in failure of the 2P-15B safety injection

pump, due to gas binding caused by back-leakage of nitrogen-saturated water from the accumulator to the pump casing, on February 20, 2002, during monthly lubrication activities.

Because of the unpredictable and variable behaviors of the past leakage data, valve packing leakage, pump mechanical seal leakage, and parallel leakage paths, the inspectors concluded that an exact duration in which the 2P-1 5B pump had become inoperable could not reasonably be determined.

The last successful quarterly surveillance test of 2P-15B was performed on December 29, 2001, in accordance with inservice test procedure IT 02, "High Head Safety Injection Pumps and Valves (Quarterly) Unit 2," Revision 48. During this inservice test, 2P-15B was operated at 200, 400, 600, and 800 gallons per minute (gpm) discharge flow, met all acceptance criteria, and exhibited no abnormalities. Subsequent to the inservice test, a short monthly run of 2P-1 5B for bearing lubrication preventative maintenance was performed on January 24, 2002. No abnormalities were noted during the 2P-1 5B January 24 run.

Since the failure of the 2P-1 5B SI pump occurred within seconds of the pump start on February 20, 2002, the inspectors considered the last successful demonstration of the 2P-15B SI pump to have occurred on January 24, 2002, at 3:33 a.m. when the pump had run for approximately 30 seconds.

Surveillance Test and Monthly Lubrication Run Characteristics Test Characteristic Monthly Run Brief run for bearing lubrication purposes. Vendor recommended OE for motor sleeve bearing configuration to minimize shaft chemical etching and remove oxidation deposits resulting from moisture absorption into the oil film. Control room operators run the SI pump until normal running current is developed and the local operator reports no abnormalities. Typically, the SI pump is run for less than 30 seconds.

Quarterly Required by TS surveillance requirement 3.5.2.2 in accordance Surveillance with Inservice Testing Program specified in Section XI of the ASME Boiler and Pressure Vessel Code and Applicable Addenda.

Required to be performed at least once per 92 days. Functional test of the SI pump includes flow and differential pressure measurements at 200, 400, 600, and 800 gpm. Design flow rate of SI pump is 700 gpm.

Concerns for voiding of common ECCS piping were eliminated due to: (1) elevation differences between the SI pump casings and other ECCS pump common suction lines (the SI pump casings were 3.5 ft above the common ECCS suction line), and (2) the A train SI pumps had been run frequently to refill SI accumulators and had effectively swept any nitrogen-saturated water or gas voids back into the accumulators (the A train pumps exhibited no symptoms of gas binding).

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I SDP PHASE 1 SCREENING WORKSHEET FOR IE, MS, and B CORNERSTONES Reference/Title (LER #, Inspection Report #, etc): Pt Be.achi5rep. 50-,266/. -1/202-.00**3 Performance Deficiency (concise statement clearly stating the deficient licensee performance): .l.akage fom quaiity regarding License* efailed to critically evaluate and correct. *significant'condition '"aaverse-.to a,. RC injection safety sixN (SI) accumula-to.r. thatb ad been identified in.two licensed reactor operator condition reports: and gerfe:nreýi6mmunicatioi'n.s. Failure of.the licensee to critically ev.aluate,.nd correct . the cause of the accumulator leakage:.,resulted. infailure%.of the 2.P:-15B S .pump, due to gas binding caused by back-leakageof.

nitr6gen-saturated .water ftifm.n.he. accumulator tothe pump casing, on February: 20, 2002, during a.monthly

.u,,

. .r . .i,,:a............

surve~iffllnce.:

Factual Description of Identified Condition (statement of facts known about the finding, without hypothetical failures included):

SU-2"!B."train SI puo Pi5B aldn j/O~2-du ring riathly actvites

• 21P-15B3 failed within. .... seconds

............ ... of starting...g .°... . .;....

• inspection revealed dam.age'to rotating element of pump, coupling and shaft keys between pump and motor, the.internal wearing rings, and inboard pump..mechanical seal.

6 gas binding in the 2P-1 5B pump 1casing caused the pumpurotatingielement to.seize. the internal pump we~ring rings whi**caused damage to other cor*ponents.

SU2..'A" train SI purip,: 2.:-1 5A, was .not affected:!by the gas bind ing that caused.the failure of 2P1i 5B.

System(s) and train(s) degraded by identified condition: UT,,train h.igh-he*a*f.ety!,njectio-n.

Licensing Basis Function of System(s) or Train(s) (as applicable):

The primary purpose f the safety. injection. system is to automatically.deliver cooling water to.the reactor core in the event.of, L*.CA. In the[.FSAR, the.safety: injection pumps are relied:upon,.to mitigate the consequences of the: LBLOCA ;SGTR, SB LOCA, :ad MS LB.. accidents. Relevant safetY-reiated FSAR and otherdesign basis functions include,

• deliver bdrated,,. cooling w*aterto the reactoricooling ...=j ......

system (RCS) du.ri.nghe.ii.njection. phfase .of SAto support core cooling

increase....the *,!.. boron... ., .concentation"inftie

-. . :..... -- ion! - ...

RCS.. during thinectin..,

- . .. . .. . . ... a s of o .

.SI:to ensureeadequate reactor shutdown margin. in the eyent of.a secondary pipe break

. recirculate.and cool the water that is collected in the containrment:s:um p,and return it dtot*ueRSduring the' "recculaii6n phase of Si to support long .

• preciude contain ment leakage ,rogh.theSI'sy=sem piig h~treti..S followinga lossof coolant accident to support the overall Contain m.entfunction of lIimit ing the r.lease of p".t..entialiy radio.a-tctive.materials to the enVironment

'provide sufficient boronnmainta.n o an ade quatep.ost-LO.CA sup mean .boron concentrati on to ensure' shutdown of the core with *ll control rods out i the.SI system shall de.liveirbora-ted water.tolthe RCOSiwas necessary, to :.copenie for.Xenon decayto maintain hot shutdow0 mrgin Other Safety Function of System(s) or Train(s) (as applicable):

Maintenance Rule category (check one): X risk-significant non-risk-significant Time that identified condition existed or is assumed to have existed: 1/2 ti m'perio-dp -' between 1/24/02- *icit 0333 a-n-d*l 2/20/2002 at 0100(o 00 6.o97 d .1ays 7.days)

Issue Date: 03/18/02 A-1 0609, App A

I I Functions and Cornerstones degraded as a result of this identified condition (check /)

INITIATING EVENT CORNERSTONE Transient initiator contributor (e.g., reactor/turbine trip, loss offsite power)

___ Primary or Secondary system LOCA initiator contributor (e.g., RCS or main steam/feedwater pipe degradations and leaks)

MITIGATION SYSTEMS CORNERSTONE BARRIERS CORNERSTONE

___ Core Decay Heat Removal Degraded RCS LOCA Mitigation Boundary Degraded (e.g., PORV block valve, PTS issue)

_X Initial Injection Heat Removal Degraded

___ Primary (e.g., Safety Inj) Containment Barrier Degraded Low Pressure Reactor Containment Degraded X High Pressure Actual Breach or Bypass Secondary - PWR only (e.g., AFW) Heat Removal, Hydrogen or Pressure Control Degraded

___ Long Term Heat Removal Degraded (e.g.,

ECCS sump recirculation, suppression pool Control Room, Aux Bldg, or Spent cooling) Fuel Bldg Barrier Degraded

___ Reactivity Control Degraded ___ Fuel Cladding Barrier Degraded

___ Fire/Flood/Seismic/Weather Protection Degraded Page 1 0609, App A A-2 Issue Date: 03/18/02

I 0 SDP PHASE I SCREENING WORKSHEET FOR IE, MS, and B CORNERSTONES Check the appropriate boxes V If the finding is assumed to degrade:

1. fire protection defense in depth (DID), detection, suppression, barriers, fire brigade. STOP. Go to IMC 0609, Appendix F

2. the safety of a shutdown reactor. STOP. Go to IMC 0609, Appendix G

3. the safety of an operating reactor, identify the degraded areas:

o Initiating Event XX Mitigation Systems o RCS Barrier c Fuel Barrier o Containment Barriers

4. Two or more of the above areas degraded -- STOP. Go to Phase 2

5. If only one of the above areas is degraded, continue only in the appropriate column below.

Initiating Event Mitiqation Systems RCS Containment Barriers

1. Does the finding contribute to 1. Is the finding a design or Barrier or 1. Does the finding only represent the likelihood of a Primary or qualification deficiency confirmed not Fuel a degradation of the radiological Secondary system LOCA to result in loss of function per Barrier barrier function provided for the initiator? GL 91-18 (rev 1)? control room, or auxiliary building, or spent fuel pool, or SBGT El If YES-'-Stop. Go to Phase 2 El IfYES -- screen as Green 1. RCS system (BWR)?

Barrier

[]If NO, continue El IfNO, continue E If YES -- screen as Green Stop.

2. Does the finding contribute to 2. Does the finding represent an Go to Eif NO, continue both the likelihood of a reactor actual loss of safety function of a Phase 2 trip AND the likelihood that System? 2. Does the finding represent a mitigation equipment or degradation of the barrier function functions will not be available? El If YES -- Stop. Go to Phase 2 of the control room against smoke or a toxic atmosphere?

El IfYES--Stop. Go to Phase 2 El IfNO, continue 2. Fuel Barrier El If YES -,- Stop. Go to Phase ElIf NO, continue 3. Does the finding represent an 3 actual loss of safety function of a screen as

3. Does the finding increase the single Train, for > its Tech Spec Green El IfNO, continue likelihood of a fire or Allowed Outage Time?

internal/external flood? 3. Does the finding represent an X lf YES - Stop. Go to Phase 2 actual open pathway in the El If YES -- Use the IPEEE or physical integrity of reactor other existing plant-specific El IfNO, continue containment or an actual analyses to identify core reduction of the atmospheric damage scenarios of concern 4. Does the finding represent an pressure control function of the and factors that increase the actual loss of safety function of one reactor containment?

frequency. Provide this input for or more non-Tech Spec Trains of Phase 3 analysis. equipment designated as risk- -If YES - Stop. Go to significant per 10CFR50.65, for >24 Appendix H of IMC 0609 El IfNO, screen as Green hrs?

El IfNO, screen as Green E-If YES - Stop. Go to Phase 2 El IfNO, continue

5. Does the finding screen as potentially risk significant due to a seismic, fire, flooding, or severe weather initiating event, using the criteria on page 3 of this Worksheet?

ElIf YES -- Use the IPEEE or other existing plant-specific analyses to identify core damage scenarios of concern and provide this input for Phase 3 analysis.

E]If NO, screen as Green Page 2 of 3 Issue Date: 03/18/02 A-3 0609, App A

Pt Beach "B" SI Pump issue SDP/ENFORCEMENT PANEL WORKSHEET Phase 2 SDP Risk Evaluation:

The inspectors and SRA evaluated the risk significance of the inspection finding in terms of the contribution from internal, external, and LERF events. Consistent with the guidance for the Significance Determination Process (SDP), the change in core damage frequency (ACDF) was evaluated considering the Unit 2 B Sl pump unavailable from one half the time period from the last successful demonstration of pump performance to the time of pump failure. External initiating events, seismic, fire, and tornado/high winds were individually considered.

Based on the Point Beach SDP Phase 2 worksheets, which have been benchmarked, the dominant accident sequence occurs with a medium break LOCA (MLOCA). The licensee submitted an LER on April 18, 2002, documenting the Unit 2 TS required shutdown on February 22, 2002. The LER focused on the TS required shutdown and did not offer any new information concerning risk arguments as to when the Sl pump became unavailable or details of the root cause evaluation. The following summarizes the inspector's Phase 2 risk assessment.

Phase 2 Evaluation Internal Initiating Events Assumptions

1. The inspectors did not consider the ability to recover the 2P-1 5B Sl pump following the start on February 20, 2002, since the pump seized, the shaft keys between the motor and pump were sheared, and the pump coupling was damaged. The failure on February 20 occurred within seconds of the pump start.

2. Based on the licensee's PRA, the 2P-1 5B Sl pump had a risk achievement worth (RAW) value of 1.61 and the plant had a baseline core damage frequency (CDF) of 4.46E-5 per reactor year.

3. The last successful quarterly surveillance test of 2P-1 5 was performed on December 29, 2001, in accordance with inservice test procedure IT 02, "High Head Safety Injection Pumps and Valves (Quarterly) Unit 2," Revision 48.

During this inservice test, 2P-15B was operated at 200, 400, 600, and 800 gallons per minute (gpm) discharge flow, met all acceptance criteria, and exhibited no abnormalities. Subsequent to the inservice test, a short monthly run of 2P-15B for bearing lubrication preventative maintenance was performed on January 24, 2002. No abnormalities were noted during the 2P-15B January 24 run.

Since the failure of the 2P-1 5B Sl pump occurred within seconds of the pump start on February 20, 2002, the inspectors considered the last successful demonstration of the 2P-15B Sl pump to have occurred on January 24, 2002, at 3:33 a.m. when the pump had run for approximately 30 seconds.

I

4. The inspectors correlated Unit 2 A accumulator level and pressure history with 2P-15B line volumes. Using direct mass balance methods, the inspectors determined that sufficient accumulator leakage existed between December 29, 2001, and January 24, 2002, to fill the line volume between the accumulator check valve, 2SI-845E, and the 2P-15B SI pump discharge check valve, 2SI-889B, with nitrogen-saturated water by a factor of four. In addition, the inspectors determined that sufficient accumulator leakage existed between January 24, 2002, and February 20, 2002, to fill the 2P-15B SI pump casing with nitrogen gas by a factor of 2.5. Direct mass balance methods predicted SI pump failure due to gas binding within 24 to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> following the last pump run with the leak rates historically observed. The inspectors noted that no failures had occurred during the 13 month interval prior to February 20, 2002, even though 2P-1 5B was operated once per approximately 30 days. This 2P-15B performance history indicated the presence of other difficult-to-quantify variables including;

• leakage of nitrogen-saturated gas from SI pump mechanical seals

• diffusion of nitrogen gas through SI system valve packing to atmosphere

• the presence of parallel leakage paths from the 2T-34A accumulator back to the 2P-15B pump casing.

Licensee performance of Point Beach Test Procedure 113, "2T-34A SI Accumulator Leakage Test," on March 29, 2002, and 01-171, "T-34A/B Safety Injection Accumulator leakage troubleshooting," on April 5, 2002 confirmed that parallel leakage paths between the accumulator and the pump casing existed.

The inspectors also reviewed integrated 2T-34A accumulator leakage data between 2P-1 5B pump runs for the time period between March 2001 and February 2002. When failure of 2P-15B occurred on February 20, 2002, approximately 700 gallons of nitrogen-saturated water had leaked from the 2T-34A accumulator. Because of the unpredictable and variable behaviors of the past leakage data, valve packing leakage, pump mechanical seal leakage, and parallel leakage paths, the inspectors concluded that a threshold above which 2P-15B SI pump failure was certain to have occurred could not be established and a time period at which the 2P-1 5B SI pump had become inoperable could not reasonably be determined. Therefore, in accordance with Inspection Manual Chapter 0609, "Significance Determination Process,"

Attachment A, Step 1.1, Revision dated March 18, 2002, an exposure time of one-half of the time period since the last successful demonstration of the 2P-15B pump was used.

In this case, the exposure time for risk analysis purposes existed for one-half the time period from January 24, 2002, at 3:33 a.m. to February 20, 2002, at 1:00 a.m. (13.95 days) plus the time to reach a condition in which the SI pump was no longer required to be operable (Mode 4). Unit 2 reached Mode 4 at 1:35 a.m. on February 23, 2002, (3.02 days), providing a total exposure time of (13.95 + 3.02

= 16.97) or 17.0 days.

4. Concerns for voiding of common ECCS piping were eliminated due to: (1) elevation differences between the SI pump casings and other ECCS pump common suction lines (the SI pump casings were 3.5 ft above the common ECCS suction line), and (2) the A train SI pumps had been run frequently to refill SI accumulators and had effectively swept any nitrogen-saturated water or gas voids back into the accumulators (the A train pumps exhibited no symptoms of gas binding).

Work Sheet Results Using Table 1, "Categories of Initiating Events for Point Beach Nuclear Plant," from the "Risk-Informed Inspection Notebook for Point Beach Nuclear Plant Unit 1 and 2," the exposure time for the degraded condition (gas binding of the SI pump) was considered to be between 3 and 30 days. Table 2, "Initiators and System Dependency for Point Beach Units 1 and 2," determined that loss of one SI pump affected the following initiating events;

1. TRANS = Transients (Reactor Trip)

2. TPCS = Transients Without Power Conversion System

3. LDC1 = Loss of Single 125 VDC Bus 01

4. LDC2 = Loss of Single 125 VDC Bus 02

5. SLOCA = Small LOCA

6. SORV = Stuck Open PORV

7. MLOCA =Medium LOCA

8. LOOP = Loss of Offsite Power

9. LEAC = LOOP Plus Loss of Gas Turbine with 1 EAC Available

10. SGTR = Steam Generator tube Rupture

11. MSLB = Main Steam Line Break Each initiating event and relevant accident sequence is provided below.

1. Transients (Reactor Trip)

TRANS = Row I. Estimated Likelihood Rating based on 17 days condition existed = "2". Applicable sequences:

1. 1 TRANS(2) + AFW (4) + PCS (3) + HPR (2) = 11

1. 3 TRANS(2) + AFW (4) + PCS (3) + EIHP (2) = 11

2. Transients Without Power Conversion System TPCS = Row I. Estimated Likelihood Rating based on 17 days condition existed

= "2". Applicable sequences:

1. 1 TPCS(2) + AFW(4) + HPR(2) = 8

1. 3 TPCS(2) + AFW(4) + EIHP(2) = 8

3. LDC1 = Loss of Single 125 VDC Bus 01 LDC1 = Row II1. Estimated Likelihood Rating based on 17 days condition existed = "4". Assumption is that single loss of 125 VDC occurs on 'A' train of engineering safeguards equipment. Applicable sequences:

1. 1 LDCI(4) + AFW(3) + HPR(0) = 7

1. 3 LDCI(4) + AFW(3) + EIHP(0) = 7

4. LDC2 = Loss of Sinqle 125 VDC Bus 02 LDC2 = Row I1. Estimated Likelihood Rating based on 17 days condition existed = "4". Assumption is that single loss of 125 VDC occurs on 'B' train of engineering safeguards equipment. Applicable sequences:

1. 1 LDC2 (4) + AFW (3) +PCS (2) + HPR (2) = 11

1. 3 LDC2 (4) + AFW (3) + PCS(2) + EIHP (2) = 11

5. SLOCA = Small LOCA SLOCA = Row I1. Estimated Likelihood Rating based on 17 days condition existed = "4". Applicable sequences:

1. 2 SLOCA(4) + RCSDEP(2) + HPR(2) = 8

1. 3 SLOCA(4) + AFW(4) + HPR(2) = 10

1. 5 SLOCA(4) + EIHP(2) + LPI(3) = 9

1. 6 SLOCA(4) + EIHP(2) + ACC(3) = 9

1. 7 SLOCA(4) + EIHP(2) + RCSDEP(2) = 8

1. 8 SLOCA(4) + EIHP(2) + AFW(4) = 10

6. SORV = Stuck Open PORV SLOCA = Row I1. Estimated Likelihood Rating based on 17 days condition existed = "4". Applicable sequences:

1. 2 SORV(4) + BLK(2) + RCSDEP(2) + HPR(2)= 10

1. 3 SORV(4) + BLK(2) + AFW(4) + HPR(2) = 12

1. 5 SORV(4) + BLK(2) + EIHP(2) + LPI(3) = 11

1. 6 SORV(4) + BLK(2) + EIHP(2) + ACC(3) = 11

1. 7 SORV(4) + BLK(2) + EIHP(2) + RCSDEP(2) = 10

1. 8 SORV(4) + BLK(2) + EIHP(2) + AFW(4) = 12

7. MLOCA = Medium LOCA MLOCA = Row I1. Estimated Likelihood Rating based on 17 days condition existed = "4". Applicable sequences:

1. 1 MLOCA(4) + HPR(2) = 6

1. 3 MLOCA(4) + EIHP(2) + LPR(2) = 8

1. 4 MLOCA(4) + EIHP(2) + LPI(3) = 9

1. 5 MLOCA(4) + EIHP(2) + DEP(2) = 8

1. 6 MLOCA(4) + EIHP(2) + AFW(4) = 10

8. LOOP = Loss of Offsite Power

TPCS = Row II. Estimated Likelihood Rating based on 17 days condition existed

= "3". Note that accident sequence #4 assumes AC Power is recovered.

Applicable sequences:

1. 1 LOOP(3) + AFW(4) + HPR(2) = 9

1. 3 LOOP(3) + AFW(4) + EIHP(2) =9

1. 4 LOOP(3) + EAC(5) + HPR(2) = 10

1. 5 LOOP(3) + EAC(5) + EIHP(2) =10

9. LEAC = Loss of Offsite Power Plus Loss of Gas Turbine With EAC Available LEAC = Row V. Estimated Likelihood Rating based on 17 days condition existed

= "6". Assumption is that emergency AC power is not available on the 'A' engineered safeguards feature train. Applicable sequences:

1. 2 LEAC(6) + SORV(2) + RCSDEP(2) + HPR(0) = 10

1. 3 LEAC(6) + SORV(2) + EIHP(0) =8

10. SGTR = Steam Generator Tube Rupture SGTR = Row I1. Estimated Likelihood Rating based on 17 days condition existed = "4". Assumption is that emergency AC power is not available on the 'A' engineered safeguards feature train. Applicable sequences:

1. 3 SGTR(4) + EIHP(2) + EQ(2) = 8

1. 4 SGTR(4) + EIHP(2) + SGI(2) = 8

1. 7 SGTR(4) + AFW(4) + EIHP(2) = 10

11. MSLB = Main Steam Line Break Accident MSLB = Row I1l. Estimated Likelihood Rating based on 17 days condition existed = "4". Applicable sequences:

1. 1 MSLB(4) + AFW(4) + HPR(2) = 10

1. 3 MSLB(4) + ISOL(2) + HPR(2) = 8

1. 6 MSLB(4) + EIHP(2) + AFW(4) = 10

1. 7 MSLB(4) + EIHP(2) + ISOL(2) = 8 Application of SDP Counting Rule Based on the counting rules of the SDP discussed in Inspection Manual Chapter 0609, Appendix A, Attachment 2, paragraph 3.2; every 3 affected accident sequences that have the same order of magnitude of risk, as determined by the addition of the initiating event likelihood and the remaining mitigation capability, constitute one equivalent sequence which is more risk significant by one order of magnitude. This rule is applied in a cascading fashion.

The results of the counting rule yields a YELLOW finding; however, based on Pt Beach's SDP worksheets, Table 2, note 6, findings with one HPSI train was identified as being 1 order of magnitude conservative, i.e., the color obtained using the notebook is one color higher compared to that obtained using the plant PRA. Based on this the risk

significance of this issue is more appropriately characterized as WHITE. This WHITE risk characterization is further verified through NRC SPAR analysis and a licensee's analysis as discussed below.

Phase 3 analysis Consideration of other risk tools to confirm SDP notebook benchmarking results RAW calculation Based on the licensee's PRA, the "B" SI pump had a risk achievement worth (RAW) value of 1.61 and the plant has a baseline core damage frequency (CDF) of 4.46E-5 per reactor year.

ACDF [(RAW x CDF) - CDF] x duration (years)

= [(1.61) x 4.46E-5) - 4.46E-5] x 408 hrs/8760 hrs

= 1.3E-6 SPAR Using the same pump unavailability duration the CCDP = 4.1 E-6.

N!

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2. Table 2 Initiators and System Dependehcy for Point Beach Nuclear Plant, Units 1 and 2 17)

CD CD 0

Affected Systems Major Compoinents Support Systems Initiating Event Scenarios C

2.,

Accumulators"' 2 Accumulators None LLOCA, MLOCA, SLOCA, SORV 90 AC Power System AC Power Distribution & DC All AC Instrument Power (1)

AFW Two MDPs (both shared between 480V AC, DC, 3 SW 12), ESFAS, All except LLOCA, LOSW two units) Fire Water( )

One TDP DC, SW (2), ESFAS, Fire Water(3 ) All except LLOCA CCW Two pumps for each unit, one 480V AC, DC, ESFAS, SW LCCW dedicated and two common Heat Exchangers Condensate I MFW Two Condensate pumps 4.16 kV AC, DC, SW, IA, Circ. TRANS, LCCW, LDC2, SGTR Two MFW pumps Water

[ o SI pumps-. 4.16 kV AC, DC, CCW (during TRANS, TPCS, LDC1, LDC2, recirc.), SW, ESFAS SLOCA, SORV, MLOCA, LOOP, rI

____________L__.AC,____P__,__SLB.._________.._______JECSGR SB CVCS / Charging pumps, Three charging pumps 480V AC, DC ATWS, LCCW, LOSW boric acid transfer pumps Two boric acid transfer (BAT) 480V AC, DC ATWS pumps DC Power Buses, battery chargers and Battery Chargers (4) All batteries (four station batteries CD and six battery chargers)

EDG (5) Four EDGs shared by both units DC, SW, Fuel Oil LOOP, LEAC Gas Turbine 1 Gas Turbine Own batteries and atomizing LOOP, LEAC r%)

and control air compressors C)

Table I Categories of Initiating Events for Point Beach Nuclear Plant, Units I and 2 0a CD Row Approximate Example Event Type Initiating Event Likelihood (IEL) 0)

Frequency I > 1 per 1-10 yr Reactor Trip S Loss of Power Conversion System 1 3 II 1 per 10_102 yr Loss of Offsite Power( 23 4 0)

III 1 per 102 103' yr Steam Generatorrube Rupture__._., Stuck-open 3 5 PIR.VSRV.(P'lYJ0 Small LOCA-irjucling RCP seal failures

(-OCAI) Main-Steam Line Break(ýS (outside contatrnment), Loss of Instrument Air(tOA), Loss of Compon*n*I-Q(olino.Water (LCCW) L of*ingle 125V DC

-S

.. ,oW -CW te

• LC.

- , Loss.

Bu ~C1-orf-iD- Medium LOCAMEC IV 1 per 10' - 10' yr Large LOCA (LLOCA) 4 5 6 V 1 per 104 _ 105 yr Loss of Service Water.(LOSW), LOOP with Loss of One 5 r6) 7 Emergency AC Bus ! .

VI less than 1 per 10i yr ATWS, ISLOCA 6 7 8

> 30 days 3-30 days < 3 days Exposure Time for Degraded Condition Notes:

CD

1. The SDP worksheets for ATWS core damage sequences assume that the ATWS is not recoverable by manual actuation of the reactor trip function. Thus, the ATWS frequency to be used by these worksheets must represent the ATWS condition that can only be mitigated by the systems shown in the worksheet (e.g., boration). Any inspection finding that represents a loss of manual reactor trip capability for a postulated ATWS scenario should be evaluated by a risk analyst for consideration of the probability of a successful manual trip.

2. The initiating event frequency for loss of a 125V DC bus is 9.4E-04/yr., which is the high end of Row IV. It is assigned to Row Ill, based on the C)

C) benchmarking results.

-0 Table 3.1 SDP WQrksheet for Point Beach Nuclear Plant, Units I and 2 ý Transients (Reactor trip) (TRANS)

CO 0) 0 Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

('3 Power Conversion System (PCS) 1/2 Main Feedwater trains with 1/2 condensate trains (operator action = 3)

Secondary Heat Removal (AFW) .- .._ 1/2 MDAFW trains (1 multiktrain system) oY 1/1 TQAFW train (1 ASD train)

Early Inventory, High Pressure Injectionf .- H2.PRSI.trains (1 multi-train system Primary Heat Removal, FeedlpIqed, (FB) .. lY2POR~ s and block valves open for Feed/Bleed (operator action = 2) ')

High Pressure Recirculation (HPR) 1/2 HP$1 trains with 1/2 RHR trains and 1/2 RHR heat exchangers with operator action frswit~lhover (operator action = 2) ( 7__

CA Circle Affected Functions lEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit 1 TRANS -AFW -PCS~t (4) c 2 TRANS - AFW - PCS - FB (5) 1 + 4 + 3 +2 10 3 TRANS -AFW -PCS' c-) .J- nf

+ 31 +4 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient CD time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

0)

IQ

-0 0

Table 3.2 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 - Transients without PCS (TPCS)

CD 0)

C) Safety Functions Needed: Full Creditable Mitigation Capabilit for Each Safety Function:

Secondary Heat Removal (AFW) 1/2 MDAFW trains (1 multi-train system) or 1/1 TDAFW train (1 ASD train) with 1/2 SGs and associated 1/1 ADV or 1/4 SSVs gO Early Inventory, High Pressure Injection 1/2 HPSI trains (1 multi-train system) QQc*

Primary Heat Removal, Feed/Bleqd (F1) 172POR(/Vs and block valves open for Fe6d/Bleed (operator action = 2) (1)

High Pressure Recirculation '(HPR). 1/2 HPSI trains with 1/2 RHR trains and 1/2 RHR Heat Exchangers with operator action f**r4wtchover (operator action = 2) (2) Q f 2/n Circle Affected Functions IE_.L R emaining Mitig~ation Cap~ability Ra~ting for Each Affected Sequence 1 TPCS -AFW QHP' (3) 4 ~

2 TPCS - AFW - FB (4) 1 + 4 +2 7 3 TPCS AFW'IIII(5 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient CD time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

C)

N)

K C.,

Table 3.4 SOP Workshee~for Point Beach Nuclear Plant, Units I and 2 - Los, of Single 125V DC Bus 01 (LDC1oMa Dz ('

Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

Secondary Heat Removal (AFW) 1/1 MDAFW train (1 train) or 1/1 TDAFW train (1 ASD train) to 1/1 SG with corresponding 1/1 ADV or 1/4 SSVs Early Inventory, High Pressure Injection (HPj 1/1 HPSI train (1 train) L//;, )

Primary Heat Removal, Feed/B1.1w (FB) 'O-*' 'PORV' and block valves open for Feed/Bleed (operator action = 2)

High Pressure Recirculation 1/1 HPSI train with 1/1 RHR train and 1 RHR Heat Exchanger with operator action for or (operator action *t = 2)

Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit 1 LDC1 - AFW (-HPR3) D 2 LDC1 - AFW - FB (4) 3 + 3+2 8 3 LDC1 AFW (5) 8 _EIH,_P,)-'.

Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

"O a Notes:

S1. Loss of single 125V DC bus results in loss of control power to one set of emergency safety function equipment (i.e., 1 HPSI pump, 1 MDAFW

-~ pump, 1 RHR pump, etc.). Also, control power to 1 PORV is lost. Loss of DC Bus 01 results in loss of control power for the main feedwater of the unit. The IE frequency is estimated at --9.3E-04/yr.

o 2. The human error probability (HEP) assessed in the IPE for establishing bleed and feed is approximately 2.OE-2.

3. No separate event tree is drawn. Please refer to the Transients without PCS event tree.

CD 0

0 ri

Z.0 C3

-U 0

Table 3.5 SDP Worksheet for Point Beach Nuclear Plant, Units Iland 2 -Loss of Single 125VDC CD Bus 02 (LDC2) (1 . 3 ( -

0) 0 AD~

Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

Secondary Heat Removal (AFW) 1/1 MDAFW train (1 train) or 1/1 TDAFW train (1 ASD train) with 1/1 SG with 90 corresponding 1/1 ADV or 1/4 SSVs Power Conversion System (PCS) . ' 1/2 main feedwater trains with 1/2 condensate trains (operator action = 2)

Early Inventory, High Pressure Injectio(EIHP 1/ HPSI train (1 train)

Primary Heat Removal, Feed/Bleed (FO)' 1/1 PORV and block valves open for Feed/BIeed (operator action= 2) (2)

High Pressure Recirculation ((HPR)j 1/1 HPSI train with 1/1 RHR trains an!1/1 RHR Heat Exchanger with operator action for switchover (operator action - 2)

Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit 1LDC2 -AFW -PCsj (4) 2 LDC2 - AFW - PCS - FB (5) 3 + 3 + 2+2 10 3 LDC2 - AFW - PCS /

I(EIHJ)(6) 3 + 3+ 2 +o 1 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

CD

1) sufficient If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met:

time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

N)

C)

Tv 0

Table 3.8 SDP Worksheet for Point Beach Nuclear Plant, Units 1 and 2 - Small LOCA (SLOCA) a.

03 CD Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

C: Early Inventory, High Pressure Injection 1/2 HPSI trains (1 multidrain system) T Do

['Secondary Heat Removal (AFW) 1/2 MDAFW trains (1. multi-train system) or 1/1 TDAFW train (1 ASD train)

RCS Cooldown/Depressurization (RCSDEP) Operator depressurizes RCS using (pressurizer spray or 1/2 PORVs) and 1/2 atmospheric steam dump valves (operator action = 2) (2)

Primary Heat Removal, Feed/Bleed (FB) 1/2 PORVs and block valves open for Feed/Bleed (operator action = 2)(1)

Accumulators (ACC) 1/2 Accumulators (1 multi-train system)

Low Pressure Injection (LPI) 1/2 RHR trains (1 multi-train system)

Low Pressure Recirculation (LPR)-.)* 1/2 RHR trains taking suction from sump (operator action = 2)

High Pressure Recirculation(ijLPiý3 1/2 HPSI trains with 1/2 RHR trains and 1/2 RHR Heat Exchangers with operator action for sWitcdh0Ver (operator action = 2) ON Circle Affected Functions IEL Remaining Mitigation Capability Rating for Each Affected Sequence

-41 1 SLOCA - LPR (2,9) 2 SLOCA - RCSDEP( 2 ) -ýrF4)'I4) 3 SLOCA - AFW+t (6) 3 + 4W~ +79 6 4 SLOCA - AFW - FB (7) 3 + 4 + 2 9 CD 5 SLOCA El'-1-33 (10) 6 SLOCA \ýHP ACC (11)

C, N)

-0 7SLOCA\' IW2 E~p~~RCSDEp(2)

RCD (12) 8 6j CD 90 PJ 8 SLOCA iýEHRP- AFW (13) 7:

3 ý4- 10 U-Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

P" Notes:

co

1. The human error probability assessed in the IPE for establishing bleed and feed cooling is approximately 2.0E-2.

2. Worksheet Sequence 2 is a controlled cooldown and Worksheet Sequence 7 is a rapid depressurization. PBNP estimates that the error probability for operator failure to cooldown following SLOCA is 2.7E-3, and the operator failure to depressurize for LPI injection is 1.2E-2. Here, this function is assigned a credit of 2.

0 CD CD)

-D 0)

Table 3.9 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 - Stuck-Open PORV (SORV) 0, Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

C Early Inventory, High Pressure Injection 1/2 HPSI trains (1 multi-train system) 90 K) Isotation of Small LOCA (BLK) The closure of the block valve associated with stuck-open PORV (1 train)

Secondary Heat Removal (AFW) 1/2 MDAFW trains (1 multi-train system) or 1/1 TDAFW train (1 ASD train)

RCS Cooldown/Depressurization (RCSDEP) Operator depressurizes RCS using (pressurizer sprays or 1/1 remaining PORV) and 1/2 atmospheric dump valves (operator action - 2)

Primary Heat Removal, Feed/Bleed (FB) Operator action using the remaining 1/1 PORV (operator action = 2) (

Accumulators (ACC) 1/2 Accumulators (1 multi-train system)

Low Pressure Injection (LPI)--.--. 1/2 RHR trains (1 multiktrain system)

High Pressure Recirculatio ow(HPR)' 1J2.HPSltrains with 1/2 RHR trains and 1/2 RHR Heat exchangers with operator action for switchover (operator action = 2)

Low Pressure Recirculation (LPR) 1/2 RHR trains taking suction from the sump (operator action = 2)

Circle Affected Functions _L_ Remaininq Mitigation Capability Rating Recovery Results for Each Affected Seqguence Credit 1 SORV - BLK - LPR (2,9) 2 SORV - BLK - RCSDEP P R, '(4) / ) 2Q) 23 .6 COV-BK-AF 4 SORV - BLK - AFW - FB (7) 3 + 2+ 4 +2 11 CD 5 SORV -BLK " !ýHP LPI (10)1 3 + 2 + + 3 1__0 CD ri

-ED 0) 6 SQRV -BLK -'EHP ACC (11) (

0, 3- + -2 3.-'+ 3 11 l C

.. . W .. . . .. . . .. . . ._... . . . . .. . . -

7SORV- BLK-IHP, RCSDEP(2) (12) 10CJ' '

• 3 + 2 + S3-+ 42'EIHJ** 10 , -)--J U-*

N,)

8 SQRV - D4K -(IElIH% AFW (13) C2 3 2 3 12 j u U Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

0 Oý If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient CD time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

Notes:

1. The human error probability assessed in the IPE for establishing bleed and feed cooling is approximately 2.OE-2.

2. Sequence 2 is a controlled cooldown and Sequence 8 is a rapid depressurization. PBNP estimates that the error probability for operator failure to cooldown following SLOCA is 2.7E-3, and the operator failure to depressurize for LPI injection is 1.2E-2. Here, this function is assigned a credit of 2.

3. No separate event tree is provided. Please refer to the SLOCA tree.

CD 0) 0 N)

CD 0)

Table 3.10 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 - Medium LOCA (MLOCA) 0 Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

U) Early. Inventory, High Pressure Injection 1/2<HPSI trains-. (11multi-train

. system) s

-*(4HP),

QO Auxiflary Feedwater (AFW) 1/2 MDAFW trains (1 multi-train system) or 1/1 TDAFW train (1 ASD train)

RCS De pressturization (PEP) Operator depressurizes using 1/2 atmospheric dump valves (operator action = 2)

Accumulators (ACC) 1/1 ACC injection to 1 intact loop (1 train)(')

Low Pressure Injection (LPI) 1/2 RHR trains (1 multi-train system)

High Pressure Recircula..o... 1/2 HPSI trains taking suction from 1/2 RHR trains with operator action for switchover oera.t.action - 2) 0p. .

Low Pressure Recirculation (LPR) 1/2 RHR trains with operatdr switchover from injection to recirculation (operator action = 2)

Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Seguence Credit 1 MiLOCAý" ,.PR}(),,

U 2 MLOCA - ACC (3,7) 3 + 2 5 3 MLOCA VHP, LPR (5) ()s 3 2 8 4 MVLOCA ~EJH.- LPI (6) 3 A

1" 9 _

3 2(8 CD 6 MLOCA \ IHO AFW (9) 10 .2 AD~

C)

0)

Table 3.12 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 --- Loss of Offsite Power (LOOP) 0 Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

Emergency AC Power (9EAC) 1/2 dedicated Emergency Diesel Generators (I)(1 multi-train system) or crosstie opposite unit EDG (operator action = 1) or 1/1 Gas Turbine (operator action 1) (1.2) 4 Turbine-driven AFW Train (TDAFW) 1/1 TDP train of AFW (1 ASD train)( )

Secondary Heat Removal (AFW) 1/2 MDAFW trains (1 multi-train system) or 1/1 TDAFW train (1 ASD train)

Recovery of AC Power in < 1 hr (REC1) Recovery within 1 hr (operator action = 1) (3)

Recovery of AC Power in 4 hrs (REC4) Recovery within 4 hrs (operator action =1) (3)

.Esiylnventory, High Pressure Injection 1/2 HPSI trains (1 multi-train system)

(EIHP))

"'Artmary Heat Removal, Feed/Bloed (FB) Operator uses 1/2 PORVs and block valves (operator action = 2)

High Pressure Recirculationt' (HPR)' 112 HP-Sl trains with 1/2 RHR trains and with operator action for switchover (operator CD Circle Affected Functions IEL Remaining- Mitigation Capability Rating for Each Affected Sequence 1 LOOP- AFW.HPR,"(3)

C) 2 + 4 (3 8 2 LOOP - AFW - FB (4) 2 + 4 +2 8 3 LOOP -AFW'ýElHP (5)

CA) 2(Cr-+ 4 + 9 4 LOOP - EAC I P 7,11) C (AC recovered K & *)

2 + 5 + 9 5 LOOP -EAC -EIHP>(8,13) "

(AC recovered)ý 2 +5 +3 10 N)

- C o)

Q/:Q 0

~ u\,'1/2~~' W, ac,ý3 Table 3.13 SDP Worksheet for Point B9ach Nuclear Plant, Units 1 and 2 ý LOOP with Loss of One ,AJUJA CD Emergency AC Bus (LEAC)(1)

C Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

Relief Valves Reclosing (SORV) . All relief valves reclose (1 tra-)

Early Inventory, High Pressure Injection 1/1 HPSI train (1 train) 0 K)

Primary Heat Removal, Feed/Bleed (FB) 171-PORV and block valve open for Feed/Bleed (operator action = 2)

RCS Cooldown/Depressurization (RCSOEP) Operator depressprizes RCS using pressurizer sprays and 1/1 PORV and block valve or atmospheric dump valves (operator action = 2)

Low Pressure Recirculation (LPR). 1/1 RHR train taking suction from the sump (operator action = 2)

High Pressure Recirculation (HPR)) 1/1 HPSI*train with 1/1RHR train (requires operator action for switchover; operator actIbfi2 OIL/( w______ ____

Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit CA 1 LEAC - SORV - LPR (3) 5 + 2 + 2 9 2 LEAC - SORV - RCSDEP HP2 (5) 5 +2 + 2 11~)5 Li 3 LEAC - SORVr 5)lH6 R.

5+2 + ;n2ý'

IA HP__6__ _____

0 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

CD 0)

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient N). time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

0 0

Table 3.14 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 - Steam Generator Tube Rupture (SGTR) 90 Safety Functions Needed: Full Creditable Mitigation Capability for Each Safety Function:

Secondary Heat Removal (AFW) 1/2 MDAFW trains (1 multi-train system) or 111 TD AFW train (1 ASD Train)

Earlnventory, High Pressure Injection 1/2 HPSI trains (1 multi~train system)

'lan~-edwater (MFW) 1/2 MFW trains with 1/2 condensate trains (1)(operator action 2)

SG Isolation (SGI) Operator isolates the ruptured SQ (operator action = 2) (ý)

Pressure Equalization (EQ) Operator cools down RCS using 1/1 SQ ADV (on the unaffected SG) or 1/2 RCS pressurizer PORVs to less than setpoint of relief valves of SG (operator action = 2) (3)

Decay Heat Removal (DHR) Cooldown and depressurize primary and align 1/2 RHR trains (operator action = 2)

Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit CD 1 SGTR - EQ - DHR (3) 0 C) 2 SGTR- SGI - DHR (5) 3 + 2+2 7 3 SGTR EIHP EQ (7) ~~~>____

4 SGTR EIHPý 49I(8 5 SGTR - AFW - EQ (10) 3 + 4 +2 9 6 SGTR - AFW - SGI (11) 3 + 4 + 2 9 N)

7 SGTR -AFW ~EIHPP,k(12) 16(4 _ __ _)_ _ _

CD 0

8 SGTR-AFW- MFW (13) 3 + 4 +2 9 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

Notes:

1. Point Beach SGTR analysis credits the recovery of main feedwater if auxiliary feedwater fails, but does not credit the use of feed and bleed if all feedwater fails.

2. Failure to identify and isolate a ruptured SG is assigned an error probability of 4.8E-3. Failure to isolate ruptured SG and stop TDAFW flow is assigned an error probability of 8.5E-03 in the IPE.

3. Failure to cooldown and depressurize for SGTR is assigned a failure probability of 2.OE-02.

CD

"'3 C)

CD N)

-0 Table 3.15 SDP Worksheet for Point Beach Nuclear Plant, Units I and 2 - Main Steam CD Line Break (MSLB) 0)

0 Safety Functions Needed: Full Creditable Mitigation Capability for Each Safely Function:

Ea~y~Lnventory, High Pressure Injection 1/2 HPSI trains (1 multi-train system)

• Secondary Heat Removal (AFW) 1/2 MDAFW trains (1 multi-train system) or 1/1 TDAFW train (1 ASD Train)

Main Steam Isolation (ISOL) Automatic signal for MSIV closure and operator verification (1 train)

Feedwater Isolation and Control of $1 (FWIC) Operator isolates feed to SGs and controls SI flow (operator action = 2)

Primary Heat Removal, Feed/Bleed (FB) 1/2 PORVs with block valves open (operator action - 2)

High Pressure Recirculation (Pf) 1/2 HPS trains taking sucton from 1/2 RHR trains with operator action for switchover

~prator action =2) /7 Circle Affected Functions IEL Remaining Mitigation Capability Rating Recovery Results for Each Affected Sequence Credit 1 MSLB -AFW /LRI 3)

3) Q' 2 MSLB - AFW - FB (4) 3 + 4 +2 9 3 MSLB - ISOL -rLHPPR (6) '/

4 MSLB - ISOL - FB (7) 3 + 2 +2 7 CD

5. MSLB - ISOL - FWIC (8) 7 3 +2 +2 6 MSLBy,'*H-3 -P----+

AFW (10) 10(*

("

j Q-j_____ ___

C)

CD 0 7 MSLB (EIHP ".-7tSOL (11)

Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:

Q0 N3 Ifoperator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) sufficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.

Note:

a CD C)

,L1 I Questions for June 12, 2002 training

1. For this finding, which initiating event worksheets need to be evaluated?

TRANS SLOCA LEAC TPCS SORV SGTR LDC1 MLOCA MSLB LDC2 LOOP

2. What is the deficient condition duration?

17 days.

The inspectors could not establish an exact start of the pump unavailability. In this case, the exposure time for risk analysis purposes existed for one-half the time period from January 24, 2002 to February 20, 2002 (13.5 days) plus the time to reach a condition in which the "B" Sl pump was no :longer required to be operable (Mode 4). Unit 2 reached mode 4 at 1:35am on February 23, 2002 (3 days), providing a total exposure time of 16.5 days (17 days).

3. For the finding, should operator credit be applied?

No, pump was clearly unavailable with broken components that made up the pump shaft.

4. What is the initiating event likelihood that should be used for the MSLB worksheet?

4 ,(104)

5. What safety functions (i.e. AFW, EIHP, etc) are affected in Table 3.4 "Loss of Single 125Vdc Bus 01 (LDC1) for this finding?

EIHP and jHPR

6. For Table 3.5, "Loss of 125Vdc Bus 02" (LDC2), what credit ;(failure probability) is assigned ,for HPR?

2 (10-2)

7. After completing all of the worksheets, what is the dominant accident sequence?

MLOCA-HPR

8. After performing the Phase 2 risk assessment, what is the risk significance of this finding due to internal events?

YELLOW

.3, g* !

1ý , ,

Sonia's Counting Rule 8 7 6 5 4 Ill III III I II III Ill II three - 9's = one - 8 four sets of 3-8's = four - 7's two sets of 3-7's = two - 6's one set of 3-6's = one - 5 one - 5 = YELLOW; however, note (6) from Table 2 identifies to the inspector that SDP results (color) will be higher than actual risk. SRA performs Phase 3 using NRC computer tools and licensee's risk analysis to confirm that WHITE is the proper risk characterization.

Al d& .

U Type of Remaining Mitigation Capability Remaining U Mitigation Capability Credit U

X = -logl(failure prob)

Recovery of Failed Train I Operator action to recover failed equipment that is capable of being recovered after an initiating event occurs. Action may take place either in the control room or outside the control room and is assumed to have a failure probability of approximately 0.1 when credited as "Remaining Mitigation Capability." Credit should be given only if the I

following criteria are satisfied: (1) sufficient time is available; (2) environmental conditions allow access, where needed; (3) procedures describing the appropriate operator actions exist; (4) training is conducted on the existing procedures under similar conditions; and (5) any equipment needed to ;perform these actions is available I

and ready for use.

1 Automatic Steam-Driven (ASD) Train I A collection of associated equipment that includes a single turbine-driven component to provide 100% of a specified safety function. The probability of such a train being unavailable due to failure, test, or maintenance is assumed to be approximately 0.1 when credited as "Remaining Mitigation Capability."

U 1 Train A collection of associated equipment (e.g., pumps, valves, breakers, etc.) that together 2 I

can provide 100% of a specified safety function. The probability of this equipment being unavailable due to failure, test, or maintenance is approximately 1E-2 when credited as "Remaining Mitigation Capability." I 1 Multi-Train System A system comprised of two or more trains (as defined above) that are considered susceptible to common cause failure modes. The probability of this equipment being 3 I

unavailable due to failure, test, or maintenance is approximately 1E-3 when credited as "Remaining 'Mitigation Capability," regardless of how many trains comprise the system. I 2 Diverse Trains A system comprised of two trains (as defined above) that are not considered to be susceptible to common cause failure modes. The probability of this equipment being 4 (=2+2) I unavailable due to failure, test, or maintenance is approximately 1E-4 when credited as "Remaining Mitigation Capability."

Operator Action Credit I

Major actions performed by operators during accident scenarios (e.g., ,primary heat removal using bleed and feed, etc.). These actions are credited using three categories of human error probabilities (HEPs). These categories are Operator Action = 1 which represents a failure probability between 5E-2 and 0.5, Operator Action = 2 which 1 2, or 3 I

represents a failure probability between 5E-3 and 5E-2, and Operator Action = 3 which represents a failure probability between 5E-4 and 5E-3.

I Table 5 - Remaining Mitigation Capability Credit I

I 0609, App A, Att 1 A1-14 Issue Date: 03/18/02 1.. r-V I