ML11216A118

Submittal of Reference Documents Related to EA-11-018 for Browns Ferry Nuclear Plant Unit 1

ML11216A118
Person / Time
Site:	Browns Ferry
Issue date:	08/04/2011
From:	Eugene Guthrie Reactor Projects Region 2 Branch 6
To:
References
EA-11-018
Download: ML11216A118 (209)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257 August 4, 2011 MEMORANDUM TO: Memo To File FROM: Eugene F. Guthrie, Chief /RA/

Reactor Projects Branch 6

SUBJECT:

SUBMITTAL OF REFERENCE DOCUMENTS RELATED TO EA-11-018 FOR BROWNS FERRY NUCLEAR PLANT UNIT 1, DOCKET 50-259 This memo submits reference documents reviewed by the NRC that are to be made available for public viewing. The enclosed documents are as follows: : TVA response to NRC questions regarding the general characteristics of valve 1-FCV-074-066 (no date) : TVA response to NRC questions of April 29, 2011 regarding in service testing of 1-FCV-074-066 : TVA response dated April 5, 2011 to NRC questions of March 31, 2011 regarding 1-FCV-074-66 : TVA response to NRC questions from the April 4, 2011 Regulatory Conference : TVA response to NRC follow-up questions of March 31, 2011 : TVA response to NRC follow-up questions of April 18, 2011 : TVA response to NRC question during a site meeting on April 22, 2011 : TVA response to Independent Team questions June 29, 2011 : TVA response to Independent Team questions July 7, 2011 0: TVA response to Independent Team questions July 8, 2011 1: TVA response to Independent Team questions (telecon) July 11, 2011 2: TVA response to Independent Team questions (telecon) July 8, 2011 3: TVA response to Independent Team questions (telecon) July 11, 2011 4: TVA response to Independent Team questions July 11, 2011 Docket No.: 50-259 License No.: DPR-33

Enclosures:

As Stated

_________________________ G SUNSI REVIEW COMPLETE G FORM 665 ATTACHED OFFICE RII:DRP RII:DRP SIGNATURE JDH /RA/ EFG /RA/

NAME JHamman EGuthrie DATE 08/04/2011 08/04/2011 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO Responses to NRC Questions Regarding Valve 1-FCV-74-066 Is the Valve N stamped?

Review of the valve data sheet 1-47BD452-99 for the valve (TVA mark # 47W 452-3563),(UNID; 1MVOP-074-0066) indicates that the valve is a 24, 600# class type, Pressure Seal Angle valve by Walworth and is not N stamped. (ref Caic 3-MD-Q3074-920438).

Under what classification was the valve purchased?

ASME B31.1 (ref. Caic 3-MD-Q3074-920438).

Are there markings on the valve guides from the free floating disc?

There is no evidence of galling and no markings on the valve guides that would result from interferences as a result of a cocked disc. The internal configuration of the valve includes a linear trim of sufficient length to provide stability to the valve disc and not allow cocking of the disc inside the valve body.

Are the valve guides stellite?

The valve guides are not stellite. Typically Walworth uses stellite for the valve disc, seat, and back seat only.

What NDE methods were used on the welds?

There is no record of any NDE being performed on the welds. Tack welds, being non-structural, are generally not subject to NDE.

What is the overall actuator ratio?

Review of the valve data sheet 1-47BD452-99 for the valve (TVA mark # 47W 452-3563),

(UNID 1 MVOP-074-0066) indicates that the overall actuator ratio is 109.78:1.

What amount of disc lift is needed for the required flow?

The amount of disc lift needed for the required flow is approximately 19 (18 15/16 lift from drawing 3-A-12337-M3A) for the design basis flow of 20,000 gpm. The amount of lift needed for one pump flow is minimal.

When FCV-74-66 is nearly closed, more than the minimum injection flow can be achieved. The large DP across the valve demonstrates that the disk will be lifted well off the valve seat, so much more than the analysis minimum injection flow rate of 3600 gpm will occur.

(ref. Free Floating Disc Analysis)

Can we provide stroke time data?

Recorded stroke time data indicate that for a four year period (10/2006 to 08/20 10) the quarterly stroke time for 1-FCV-74-066 is approximately 33 seconds (ranging from 33.1 to 33.9 seconds).

(ref. Unit 11 -FCV-74-66 stroke time data)

Enclosure 1

What were the thrust values of the as left torque switch setting and the as left pull out thrust from the last static test?

Review of MOVATS data indicates that the as left torque switch trip thrust is 85,364 lb. The as left pullout thrust is 54,351 lb. (ref. MOVATS test results (11/12/2010)

What is the rate of friction change versus size?

See Tab XI Performance Improvement International Report What is the confidence factor of scaling (model to actual)?

See Tab XI Performance Improvement International Report If the valve disc did break free as hypothesized, what kind of mechanical shock/water hammer would be incurred by suddenly releasing the 850# valve disc with the maximum possible 1W being supplied from a very large capacity pump?

Analysis was performed on the effect of a wedged disc releasing due to vibrations induced by pump flow and pressure. In order for there to be a waterhammer, there needs to be a sudden decrease in fluid velocity. When FCV-74-66 opens, the water in the pipe upstream of the valve initially has no velocity and flow will increase through the open valve and into the reactor vessel.

The water in the valve above the disk will also be pushed into the reactor vessel as the disk is pushed out of the way.

Neither of these flows will experience a sudden decrease in fluid velocity on their way to the RV so there is no potential for a waterhammer to occur when FCV-74-66 suddenly opens.

(ref. Free Floating Disc Analysis)

Is a Part 21 Report being considered?

The Part 21 report is in the approval process.

References

• Valve Operator Data Sheet 1-47BD452-99

• P11 Report

• U-3 Caic MD-Q3074-920438

• U-2 CaIc MD-Q2074-910124 (not reviewed by me but referenced on U3 calc cover sheet)

• Walworth company drawing 3-A-i 2337-M-3A

• Functional Evaluation 42538 for PER 141380

• MOVATs test results (1 0/2006 to 08/2010)

• Unit 11 -FCV-74-66 stroke time data

• MOVATS test results (11/12/2010)

• Unit 11 -FCV-74-66 stroke time data

• Free Floating Disc Analysis Enclosure 1

Inservice Testing (IST) of FCV-74-52 and FCV-74-66 Question:

On the afternoon of Friday 04/29/2011, the NRC questioned Browns Ferry Nuclear Plant (BFN) Inservice Testing (IST) Program compliance with American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) Code, Subsection ISTC 4.1 (reference SR 362156). This document was written to establish the basis for compliance.

TVA Response:

During the Unit 1 Cycle 8 refueling outage on October 23, 2010, 1-FCV-74-66 did not open while attempting to place RHR Loop 2 in service. Lights indicated open but pump discharge pressure was at maximum and no flow was indicated in the loop. This condition and the root cause are documented in PER 271338.

The BFN IST Program is implemented in accordance with ASME OM Code 1995 Edition with 1996 Addenda (1995 OMa 1996). 1995 OMa 1996, Subsection ISTC 4.1, specifies the requirements for valve position verification as follows:

Valves with remote position indicators shall be observed locally at least once every 2 years to verify that valve operation is accurately indicated. Where practicable, this local observation should be supplemented by other indications such as use of flowmeters or other suitable instrumentation to verify obturator position. These observations need not be concurrent. Where local observation is not possible, other indications shall be used for verification of valve operation.

The BFN IST Program is described in BFN Technical Instruction (TI) 0-TI-362, Inservice Testing of Pumps and Valves. This TI lists in tabular form the ASME Class, Category, Normal and Safety Position, Surveillance Procedures, and Surveillance Frequencies.

The configuration and testing of valves 1-FCV-74-52 and 1-FCV-74-66 (FCV-74-52/66) is typical for all three Units. These valves are classified as Category B valves with an active safety function. FCV-74-52/66 are normally open valves with an open safety position; however, these valves may be throttled and are therefore considered active in the IST Program. In accordance with the Code ISTC Table 3.6-1, Category B, active valves require exercising, stroke timing, and position indication verification. Exercising and stroke timing is conducted quarterly and position indication verification is conducted once per 2 years. In addition, remote position indication verification includes direct observation of stem movement.

NUREG-1482, Revision 1, Guideline for Inservice Testing at Nuclear Power Plants, was used to develop the BFN IST Program. No specific additional guidance is provided for verification of remote position indication other than Section 4.2.7, Verification of Remote Position Indication for Valves by Methods Other Direct Observation. NRC recommendations related to this section contain some guidance applicable to FCV-74-52/66:

Page 1 of 5 Enclosure 2

Inservice Testing (IST) of FCV-74-52 and FCV-74-66 For certain types of valves that can be observed locally, but for which stem travel does not ensure that the stem is attached to the disk, the local observation should be supplemented by observing an operating parameter as required by Subsections ISTC 4.1, 4.2, and 4.5.

Note that ISTC Subsections 4.2 and 4.5 are not applicable to remote position indication as described by Subsection 4.1.

Neither the OM Code nor NUREG-1482 requires the use of supplemental parameters in conjunction with position verification. ASME OM Code Interpretation 99-9 confirms that it is not the intent of the ASME OM Code to require observation of stem movement to be supplemented by other indications to verify obturator position regardless of practicability.

Interpretation: 99-9

Subject:

ASME/ANSI OMa-1988, Part 10, para. 4.1 and equivalent subsequent editions and addenda Date Issued: December 23, 1998 File: OMI-98-20 Question: If it is practicable, is it a requirement of OMa-1988, Part 10, para. 4.1 that local observation of stem movement be supplemented by other indication to verify obturator position?

Reply: No.

Contact with an OM Code committee member identified that the committee did not intend supplemental verification be performed on all IST valves during position indication testing. This position is consistent with OM Code and NUREG guidance.

Therefore, supplemental verification of the position of valves FCV-74-52 and FCV-74-66 has not been required for implementation of the OM Code at BFN, based on the OM Code itself, NUREG-1482, and Code Interpretation 99-9.

However, even though supplemental verification is not a Code requirement, it should be noted that exercise of CKV-74-68 and CKV-74-54 during performance of the surveillance procedures identified in Table 3 (see References below) provides indication that FCV 52 and FCV-74-66 are in the open position and passing flow. If flow was not observed during performance of these surveillance procedures, the surveillance acceptance criteria would not be met and investigation would determine any blockage of FCV-74-52 or FCV-74-66.

The requirements of the ASME OM Code are fulfilled through 0-TI-362 and the surveillance procedures listed in Appendices H, I, and J of 0-TI-362. In accordance with ISTC Table 3.6-1, Category B, active valves require exercising and position indication verification.

Page 2 of 5 Enclosure 2

Inservice Testing (IST) of FCV-74-52 and FCV-74-66 Exercising of FCV-74-52/66 is conducted quarterly in accordance with the surveillance procedures listed in Table 1 (see References below). Position indication is conducted once every two years in accordance with the procedures listed in Table 2 (see References below).

Recirc. Loop "A" CKV-74-68 SHV-74-69 X-13B FCV-74-67 FCV-74-66 Drywell Access Room CKV-74-68 El. 565' Figure 1 The configuration for RHR Loop II shown in Figure 1above illustrates the location of FCV-74-66 in relation to other IST Program valves (FCV-74-67 and CKV-74-68). RHR Loop I containing FCV-74-52 is similarly configured as shown in Figure 2 below.

SHV-74-55 Recirc. Loop "B" CKV-74-54 X-13A FCV-74-53 FCV-74-52 Drywell Access Room El. 565' CKV-74-54 Figure 2 Page 3 of 5 Enclosure 2

Inservice Testing (IST) of FCV-74-52 and FCV-74-66 FCV-74-66 is normally open and is required to be open to provide flow to the reactor vessel.

IST Program implementing procedures, shown in Table 3, exercise CKV-74-68 to the open position using Shutdown Cooling flow of greater than or equal to 9000 gpm at a frequency of once per operating cycle in accordance with the BFN Condition Monitoring Program as described in 0-TI-443, Condition Monitoring of Check Valves. This check valve test provides supplemental indication that FCV-74-66 is in the open position.

Although not specifically documented in the check valve exercise test, supplemental indication that FCV-74-66 is open is provided when the check valve exercise test is performed.

1-SI-3.2.21(II) was scheduled to be performed at Cold Shutdown during U1R8.

However, upon initiation of Shutdown Cooling, no flow was observed and the issue with 1-FCV-74-66 was identified, which precluded performance of the surveillance procedure.

==

Conclusion:==

The BFN IST Program testing specified for FCV-74-52 and FCV-74-66 is in compliance with ASME OM Code, Code Interpretation 99-9, and the guidance provided in NUREG-1482, including verification of position indication. Although supplemental position indication verification is not required by the Code or NUREG-1482 for all IST valves subject to position verification requirements, verification of flow through CKV-74-54/CKV-74-68 at BFN does provide the recommended supplemental indication as discussed in the ASME OM Code and NUREG-1482.

Page 4 of 5 Enclosure 2

Inservice Testing (IST) of FCV-74-52 and FCV-74-66

References:

• ASME OM Code 1995 Edition 1996 Addenda

• 0-TI-362, Inservice Testing of Pumps and Valves

• NUREG-1482, Revision 1, Guideline for Inservice Testing at Nuclear Power Plants

• ASME OM Code Interpretation 99-9, Dated December 23, 1998 (OMI-98-20)

• BFN Surveillance Procedures:

Table 1: Quarterly Exercise of FCV-74-52/66 1-SR-3.6.1.3.5(RHR I) 2-SR-3.6.1.3.5(RHR I) 3-SR-3.6.1.3.5(RHR I) 1-SR-3.6.1.3.5(RHR II) 2-SR-3.6.1.3.5(RHR II) 3-SR-3.6.1.3.5(RHR II)

Table 2: Position Indication of FCV-74-52/66 1-SI-3.6.1.3.5(H I) 2-SI-3.6.1.3.5(H I) 3-SI-3.6.1.3.5(H I) 1-SI-3.6.1.3.5(H II) 2-SI-3.6.1.3.5(HII) 3-SI-3.6.1.3.5(H II)

Table 3: Exercise of CKV-74-68 1-SI-3.2.21(I) 2-SI-3.2.21(I) 3-SI-3.2.21(I) 1-SI-3.2.21(II) 2-SI-3.2.21(II) 3-SI-3.2.21(II)

Page 5 of 5 Enclosure 2

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 After performing an initial, preliminary review of the root cause analysis (RCA) for PER 271338, 1*FCV-074-066 RHR Outboard (Loop 2) Valve Failure, Revision 1, approved March 16, 2011, and associated analytical and test reports, the NRC staff identified the following questions and/or concerns:

1) The root cause analysis report states that the damaged skirt with the undersized threads was compared with a new, in stock spare. The comparison noted that the new spare had undersized threads as well. However, the report failed to quantify how much the spare was undersized. Also, how would the spare thread size correlate to its strength to resist failure?

TVA Response:

The in-stock spare was reworked by work order (WO) 11162030; thread measurements were taken to be 6.340 (major). This was compared to the dimension taken by the Westinghouse laboratory of the 1-FCV-074-66 valve skirt where the average thread dimension major was 6.33. The difference in the dimensions was concluded to be due to rolling of the thread tips as depicted in the Westinghouse report from damage caused from pullout. Thus, the spare was considered to be similar in dimension. Structural Integrity analysis of the threads bounded the condition between the as-design value of 6.3638 (major) and limiting thread dimension on the as-found disc skirt. The spare, having similar thread sizing, would have had similar strength.

2) An evaluation was completed to determine how much force it would take for the undersized skirt threads to fail. The evaluation used the smallest measured value which was found only at one location on the skirt. This location was at the .25 inch from the bottom of the skirt which translates to the third thread on the skirt. The remaining threads were fairly consistent in their diameter although they were still undersized. The force evaluation assumed a thread engagement of 1.5 inches. Why wasn't the evaluation completed for the average diameter covering the 1.5 inches? Why weren't the values of the disc thread conditions included in the report?

TVA Response:

Structural Integrity (SI) analysis included a comparison of the as-designed thread and the limiting case thread engagement as bounding cases. Table 2 in the Thread Static Shear Strength Calculation provides the as-found thread dimensions and Table 7 in the Weld Fracture Mechanics and Stress Analysis Calculation provides the stress intensity along the threads. The as-found limiting thread dimension is appropriate to use because this would provide a maximum capacity based on the limiting thread providing conservatism. The 1.5-inch thread length was used for conservatism in the calculation. Thread measurements were taken from 0.25 inches to 1.75 inches along the threaded surface to provide a good representative sampling as described in the Westinghouse Report STD-MCE-10-198, Table 3.1 on page 22. It should also be noted that even though small variations in thread size existed, the smallest threads would be expected to fail first with load shifting to the remaining threads leading to a domino effect. The values of the disc thread conditions were within manufacturers tolerance (see page 12 of the Root Cause Analysis).

1 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

3) The RCA report noted that the broken tack welds had a possible rotational aspect to the failure. The report had noted that the failed valve was reworked in 2006. A new stem was installed. It was also noted that shortly after the rework, the valve was unable to close.

Investigation found a failed torque arm or anti rotational device. If the torque arm was not installed properly on the new stem, this could lead to the possible rotational aspect of the failure. Was this investigated and reviewed?

TVA Response:

The anti-rotation device issue was thoroughly reviewed. Westinghouse provided an analysis of the weld fracture indicating the failure was in the axial direction. Regarding the rework in 2006, the failed anti-rotational device would not create additional stress on the weld or threaded connection. There is a small clearance between the disc/washer and disc skirt. This clearance allows the fit-up between the disc and disc skirt for welding and provides a separation to allow the stem to rotate independently of the disc and disc skirt. In the closed position, the valve stem would still be free to rotate (spin). Thus, no additional stresses on the weld or threads would occur because the stem was free to rotate. In the open position, the valve stem would again be free to rotate with no torsional force between the skirt and the stem since no obstruction is present. If back seating occurred, which is likely based on markings observed on the back seat, the torsional forces would be located at the contact area between the stem offset and the valve body back seat. No load would be transferred to the disc skirt weld or disc skirt threads from either torsional or axial loading. Any impact forces due to such event would not be significant based on the velocity (approximately 19 inches in 33 seconds) and associated changes in momentum while cycling of the valve open.

4) Was the spare skirt examined under a microscope as well to determine overall health?

TVA Response:

The spare skirt was not examined under a microscope. However, the spare skirt threads were visually inspected and measured using the three-wire thread measuring method at TVAs Power Service Shop during the weld build-up and rework of threads (Reference Work order (WO) 111620630). Measurements are provided in the answer to question 1 above.

5) Static analysis of the thread engagement of the disc/skirt assembly determined that the measured engagement would be sufficient for loading greater than normal unseating forces.

A comparison of MOVATS test data for unseating forces was completed and documented in Attachment 3 of the RCA. The data compiled in attachment 3 has no values. What assurance is there that the data supports the theory of COF being a constant and its contribution to the unseating force?

TVA Response:

As depicted in the weak link analysis (CVNO Report No. SR-128, Rev. 2 by Crane Nuclear, Inc. Rims R27 950913008) the normal opening thrust limit for this valve is 274,000 lbs with a required of 162,906 lbs. The Structural Integrity analysis Thread Static Shear Strength Calculation provides for a conservative capacity of as-found threaded connection of 313,000 2

4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 lbs based on the limiting thread dimension. MPR-2524-A, Joint Owners Group (JOG) Motor Operated Valve Periodic Verification Program Summary is approved by the NRC. MPR-2524-A provides guidance that new and rebuilt valves COF and VF are on a slope until it plateaus over a period of time and remains constant unless disturbed by stroking. The INEEL report demonstrates this concept by testing and natural aging. The MOVATs data determined in 2010 provides sufficient assurance that the design values COFs are within the design basis for the MOV.

6) The valve that failed (1-FCV-074-066) was reworked in 2006 and had no unseating force.

The valve was tested again in 2008 and had no unseating force. However, the valve was rebuilt in 2010 and now has an unseating value of 51,893 #. How does this agree with the theory of COF starting out low on a new installation and/or rework and gradually increasing in value until it plateaus out?

TVA Response:

TVA concurs with the principle of coefficient of friction (COF) starting out low on a new installation and/or rework and gradually increasing in value until it plateaus out. Because of the effective seat cleaning capability from the high contact stresses associated with stroking globe valves (see answer to question 22) the COF may be reduced below the tangent of the seat angle (0.268 for 15 degrees) and not show any unseating force.

Although the cleaning affect from stroking globe valves may reduce the COF below that which would show unseating like 3-FCV-74-52, all other current unseating traces on the four remaining valves showed unseating consistent with the aged stellite INEEL report. The 2010 full MOVATs trace performed on the 1-FCV-74-66 aged stellite seats demonstrates that it will show unseating similar to the other four valves after stroking.

7) There is conflicting data with respect to the history predictive monitoring data table on page 67 of the RCA report and the supplied MOVATS test data traces. For the failed valve 1-FCV-074-066 test on November 2008, it is reported in the history data as no unseating force seen. However, the MOVATS test data supplied with the overall Browns Ferry evaluation indicates otherwise. There is an open stroke spring pack deflection overlay of test data curve noted for valve 1-FCV-074-066 and valve 1-FCV-074-052. Both spring packs have a deflection thus indicating unseating force. 1-FCV-074-066 spring pack has a greater deflection than 1-FCV-074-052. Estimated force for pullout for valve 1-FCV-074-066 is well over 150,000 Ibs of thrust based on Limitorque spring pack curve for the lightest pack available. The MOVATS curve date is 10/31/2008. There is also a MOVATS overlay comparison of current values for valves 1-FCV-074-052 and 1-FCV*074-066 on the same date. The current value for 1-FCV-074-052 has a spike representing the unseating but there is no spike on current trace for valve 1-FCV-074-066. Was the spring pack data taken the same stroke as the current data? If the current data was obtained after the spring pack data, it is possible that this was the point of separation. What is the measured stem factor for this valve? (MOVATS test traces show that an ETT transducer was used so torque and thrust data should be available to determine stem factor). Also, what model spring packs were installed in the actuators for 1-FCV-074-066 and 1-FCV-074-052?

3 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 TVA Response:

The spike (maximum deflection) on the 10/31/2008 spring pack curve is an indication of hammer blow and not unseating. Refer to the supplied overlay of test data that compared the spring pack curves between the 2008 and 2010 tests as well as the thrust curve of the 2010 test. Although the vertical axis is not the same (spring pack deflection vs. thrust), the horizontal axis is time for both curves. One can observe that the unseating is much later (well after stem nut transition) than the hammer blow event. The spring pack deflection is such a coarse measurement that one would not expect to observe unseating event. The estimated force of 150,000 lbs of thrust is associated with the hammer blow and not unseating. Therefore, this value is not expected to increase as the COF increases to a plateau over time.

Yes, the spring pack data was taken on the same stroke as the thrust data dated October 31, 2008.

Due to the location of the Easy Torque Thrust (ETT) transducer (below the anti-rotation device) the test cannot obtain the torque value. Therefore, the stem factor was not determined.

The spring pack model is Limitorque 1501-125 for both the 1-FCV-074-066 and 1-FCV-074-052 actuators.

4 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 5

4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

8) Were the static unseating values on the other five RHR outboard injection valves consistent as compared to the total seating thrust applied? Were the unseating values on the other five valves consistent from test to test?

TVA Response:

At this time the only accurate thrust data is the single point MOVATS data (from Table A5.2, page 68 of the Root Cause Analysis). It is supported by the current traces (qualitative data from all six valves) and other inspection technique results as identified by the Root Cause Analysis.

The valves were not previously in the MOV program because they were passive valves as determined by the TVA evaluations performed for NRC Generic Letter 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance. As an enhancement these valves have been incorporated into the MOV program to improve performance monitoring.

9) Page 18 of the RCA report has a discussion attempting to quantify the strain normal force of the body seat that exerts on the disc. The force is estimated utilizing MOVATS calculated closing and opening thrust and static load balances. What does this mean? The discussion also attempted to correlate COF to be .33 which is close to published data for aged stellite after two strokes. A nominal value of .4 for COF is used to reflect actual conditions. This appears to be non conservative. Explain. Other studies (EPRI, INEL, JOG) involving stellite on stellite friction testing yielded higher values of COF. A nominal value of COF for materials at a 15 degree angle would be .68. Another unknown is the condition of the seat and disc edges. Were they sharp or chamfered? EPRI testing concluded that disc and seat with sharp edges can yield inconsistent friction results and be unpredictable in their performance as it relates to friction. Published data was used for justifying a nominal .4 COF value. This does not appear to be consistently applied. The published report dealt with sliding surfaces in contact simulating a gate valve. The failed valve was a globe and would not experience the same sliding action on the surface area. How were these apparent inconsistencies resolved or reconciled to achieve credible results?

TVA Response:

The sum of the total forces acting in the vertical direction has to equal zero during seating and unseating. The two equations (seating and unseating) have two unknowns (COF and normal force). These unknowns can be solved to determine the valve body normal force and the COF (0.33) conservatively assuming the kinematic (closing) COF is 80% of the static (opening) COF.

Strain gages applied to the stem were used during the October 2010 refueling outage to accurately measure the closing force and the opening force. A value of 0.4 was chosen based on the INEEL report for aged satellite (see answer to question 22) and 2010 stain gage results rather than selecting a bounding number provided by other references and was used consistently. This globe valve disc seat does not have sharp edges since it is chamfered.

6 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

10) On page 20 of the RCS report. nonconforming conditions were identified as:

1) Disc skirt thread diameter undersized

2) Lower keyway disc locking key not installed

3) Disc washer missing

4) Damaged internal disk threads Why weren't the undersized skirt to disc tack welds on this list? On page 26 of the RCA report, it specifically stated that the welds were identified as a nonconforming condition because they were "undersized and of poor quality". Provide a detailed explanation of why the undersized welds were not related, or contributed, to the 74-66 valve failure, or explain why the welds were not a nonconforming condition.

TVA Response:

This was an oversight; however, it is discussed on page 26 of the RCA. The undersized tack welds were considered a non-conforming condition on 1-FCV-074-0066, which was returned to the proper design configuration during the U1R8 refueling outage in November 2010. As depicted in the weak link analysis the tack weld is not credited for having any structural capacity thus was not considered as being a contributor to the failure in the RCA. The modeling of the weld fracture was important to understand the failure mechanisms and ultimate capacities combined (Weld and Threads) to bound the condition and make determinations for a failure mechanism (i.e. reactor back pressure).

The undersized welds were not considered a contributing cause since they are not credited in the design to handle axial loads. The full sized threads are designed to handle the full reactor backpressure. Additionally, threads on the other valves have not been validated to be undersized. It should also be noted that no other force can stress the undersized threads and the weld to the point of failure and the metallurgical analysis clearly demonstrates that the full length of threads were deformed and fractured due to a force in the pullout direction.

From the Structural Integrity report, the cases with thread engagement show that, if the threads and welds are assumed to share the load, the weld stresses are reduced by about a factor of 4 because the threads take the bulk of the load. However, the thread displacement at maximum weld stress was found to be on the order of 0.005 inches, while the possible thread clearance is seen from Figure 2 to be on the order of 1/2 the thread pitch, or 0.042 inches. So, if the threaded joint was not preloaded, or lost preload due to thread deformation, then primarily the weld would take the load, as in the zero thread engagement cases, until the weld failed, irrespective of the weld size being 0.2 or 0.5 inches. Once the weld failed, then exclusively the threads would take the load. To address this condition, and to independently check the thread shear strength calculations, finite element analyses were also performed for the case of thread engagement but no weld, with the entire load being taken by the undersized threads.

7 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

11) Page 28 of the RCA report - MOVATS data reviewed from 1996 - 2010. A statement was made that new or refurbished stellite is not expected to show an unseating force due to low COF (< .268). This statement conflicts with the failed valve post static test. After the valve had been reworked, the data showed an unseating force of 51,893 #. Explain.

TVA Response:

It is true that we observed unseating in the MOVATS trace of November 12, 2010. The reason we did not observe the unseating in the past (2006) is that the stellite surface was relatively new and the COF is lower. With the additional time, the stellite surface has aged and the COF is high enough to observe the unseating. It would be anticipated that the unseating forces would be observed in 2008 however, the stem and disc were already separated. The seats were not machined in 2010 when the valve was repaired and therefore the aging stellite surfaces were not disturbed.

12) Page 28 of the RCA report - Weakness identified in the acceptance of MOVATS test data where no detection of unseating was considered. The acceptance was based on limited knowledge of aging stellite and the effects on the COF. This limited knowledge was used to provide a basis for not establishing further investigation, which could have identified the separation. Although based on industry knowledge of globe valves for a lack of unseating being shown, the justification basis for not seeing unseating was deemed to have been justified at the time. Why is this conclusion not in conflict with the maintenance data being shown in Attachment 3. If test personnel were knowledgeable on stellite aging and saw no unseating force, a questioning attitude should have challenged this test. Explain why not.

Also, what has the licensee done with respect to the test data on 3-FCV-074-052?

Maintenance history shows that the valve was modified in 1995. MOVATS test data show unseating in tests completed in 1998 and 2000 but has no unseating on the next tests in 2002 and 2004, but again shows unseating in 2006 and 2008 but not in 2010. The maintenance history assessment in Attachment 3 only addresses the inconsistency by stating that there was a "potential that unseating may not be observed on a globe valve trace." What assurance is there in the reliability of unseating being a constant with respect to COF?

TVA Response:

The old maintenance data shown in Attachment 3 (Table A5.1) of the RCA, indicated that unseating events were observed for 3-FCV-074-52. However, such observations were not supported with thrust traces, rather by current traces (partial MOVATS). The Table A5.1 information was developed with the available partial MOVATS data from the past. No thrust values were available. Since these passive valves were not part of the MOV program, detailed analysis is not expected to be performed. Additionally, unseating forces are not significant for a normally open valve.

Because of the effective seat cleaning capability from the high contact stresses associated with stroking globe valves (see answer to question 22) the COF may be reduced below the tangent of the seat angle (0.268 for 15 degrees) and not show any unseating force. This valve was inspected and the results indicated the stem-disc is intact. Going forward, these valves will be maintained by the MOV Program. The program requires thrust and current data to be collected.

8 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 Additionally, operational constraints were instituted to restrict pressure differential across the valve until it can be returned to design.

MPR-2524-A, Joint Owners Group (JOG) Motor Operated Valve Periodic Verification Program Summary is approved by the NRC. MPR-2524-A provides guidance that new and rebuilt valves COF and VF are on a slope until it plateaus over a period of time and remains constant unless disturbed by stroking. The INEEL report demonstrates this concept by testing and natural aging. The MOVATs data determined in the 2010 provides sufficient assurance that the design values COFs is within the design basis for the MOV.

13) Page 29 of the RCA report - Discussion states that performance monitoring program has a weakness in that it does not provide enough criteria for establishing anomalies with respect to aging stellite. The conclusion states "Enhancement of program knowledge should include the effects of aging stellite on the COF to establish when unseating should be seen for globe valves." What is the explanation for the inconsistent performance of 3-FCV-074-052 unseating going back and forth (seen and unseen)? How will this be addressed in the future?

TVA Response:

Refer to question 12 for additional information regarding 3-FCV-074-52. As we transition the responsibility of this group of MOVs to the MOV Program, the performance will be monitored and trended by the MOV Program. Furthermore, due to the past history of stem separation, the thrust trace evaluation will be supplemented by the current trace evaluation. The safety function for these valves is to open. The program actions will be to ensure that they are open as required. The lessons learned from this Root Cause Analysis Report will be incorporated into those program actions.

14) Was any attempt made by the licensee to calculate the actual force it took to "pop" the 1FCV- 74-66 valve disc loose? Did the licensee evaluate the actual force used to pull out the stuck 74-66 to validate or bound the assumptions and results of their analysis and testing? If this evaluation was accomplished what were the conclusions? If this evaluation was not accomplished, then why not? Also, provide a complete description of the lift calculations, equipment, set-up, and any additional actions (e.g., thermal stress relief) that would allow the NRC to analyze the actual lift forces used to break free the stuck 74-66 valve disc?

TVA Response:

It should be noted that the mass of the valve internals and the actuator capability would be expected to lodge the disc into the seat. The lifting rig used to disassemble the valve was not instrumented to record the force required and therefore no evaluation was performed.

Recording this data would not have been feasible because of the uncertainty related to suddenness of releasing the disc and inability to accurately control metal temperatures without installing thermocouples.

9 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

15) Describe any internal or external industry operating experience (OE) regarding this phenomenon of separated valve disks that were stuck in their seats which subsequently vibrated loose after a period of time?

TVA Response:

A similar experience provided by Performance Improvement International (PII) was at San Onofre Unit 1, 1987-1988. Dr. Chong Chiu was the Assistant Technical Manager of San Onofre Station at that time, when a temporary loss of water flow issue in the heater drain pump that caused temporary water level changes in the drain tank occurred. After a few minutes, the flow resumed. Later, the control valve stem-disc was found separated and the disc was temporarily stuck in the seat (as the only possible explanation of temporary loss of flow). This case is similar to the Browns Ferry valve stuck-and-release case experienced. However, the San Onofre event was apparently not reported as OE generally available to the industry.

16) The root cause (i.e., under-sized upper skirt threads) would imply a 10 CFR 21 notification would be warranted. Has the vendor/supplier been notified or involved with the root cause determination? Does the vendor/supplier agree with the root cause?

TVA Response:

TVA concurs that the undersized threads condition is 10 CFR 21 reportable and for this reason made this report via a Licensee Event Report revision.

The vendor (Crane Nuclear, current owner of Walworth Valve) was consulted during the investigation to determine specific attributes of the valve, vendor drawings, and available documentation. The Crane representative concurred with the root cause and also that the measurement of thread diameter would not be expected to be performed by the customer.

The supplier (GE) was notified of the findings of the root cause and (based upon our notification to them) entered this issue in their corrective action program for evaluation as a potential 10 CFR 21 finding.

17) What is the technical basis and empirical evidence that back-pressure conditions actually existed on the 1-FCV-74-66 valve following periodic stroke testing of the inboard RHR injection valve (1-FCV-74-67)? What is the technical basis and empirical evidence that similar back-pressure conditions did not exist to the same degree or worse for the other inboard/outboard RHR injection valves (i.e., 1/2/3-FCV-74-52/66)? What is the technical basis and empirical evidence that would explain why all the other inboard/outboard RHR injection valves were sufficiently different in design, maintenance, operation, or physical condition to not experience similar back-pressure conditions resulting in valve failure?

TVA Response:

Note: TVA will provide the response to this question separately.

10 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66

18) In determining the maximum pressure differential of 251 psid across the closed separated FCV-74-66 valve disc (see page 16 of the RCA), the licensee assumed the associated RHR pump was started 10 minutes earlier per the safe shutdown instructions (SSI). How is this consistent with the SSI caution not to run an RHR pump greater than seven minutes without flow?

TVA Response:

The Safe Shutdown Analysis (SSA) assumes for conservatism that the Residual Heat Removal (RHR) pump is started and rapid depressurization is initiated at 30 minutes resulting in LPCI injection at 35 minutes with peak clad temperature (PCT) remaining below 1500 degrees F for the limiting case. The Safe Shutdown Instructions (SSIs) ensure that the RHR pump is started and rapid depressurization is initiated no later than 20 minutes, which results in LPCI injection at 25 minutes. The SSI initiation is 10 minutes sooner than the SSA assumption of 30 minutes.

The results of testing and analyses indicate that 1-FCV-74-66 would have opened and injection from the RHR pump would have initiated within no more than seven minutes of starting the RHR pump. Assuming it takes the seven minutes for the valve to open, injection would occur at 27 minutes, which is well within the limiting case value of 35 minutes from the SSA. The seven-minute time period is also within the time period specified in the SSI caution note for running the RHR pump without flow. The SSI caution note states, RHR pump should NOT exceed 7 and 1/2 minutes in service without a viable flow path to prevent exceeding pump design limits.

Therefore, assurance is provided that the Appendix R peak clad temperature would have been satisfied.

19) What is the reason for assuming the undersized threads of FCV-74-66 could not be preloaded when the upper skirt was threaded onto the valve disc? Even if the full anticipated pre-load could not be established, what is the basis for assuming the threads were not in contact and load bearing when the tack welds were made?

TVA Response:

The models generated by Structural Integrity have assumed the skirt was in contact with the disc. The analysis considers both a pre-load and no pre-load as a method to bound the condition. The relative thread displacement was determined using the maximum load for determining the maximum stress in the weld under a no pre-load condition whether it was assembled incorrectly or due to thread deformation due to undersized threads.

20) What is the basis for assuming the tack welds, and the undersized welds, were loaded sequentially and not concurrently? Was it possible that the FCV-74-66 tack welds and undersized threads were actually sharing the pull out load? What is the difference in the pullout load carrying capacity between FCV-74-66 (with undersized threads and undersized welds sharing the load), and another valve (e.g., 1-FCV-74-52) with undersized threads but with properly sized welds sharing the load? Would FCV-74-66, with both the undersized threads and welds sharing the load, be capable of carrying the calculated pull out load assumed during maximum back pressure conditions? What about FCV-74-52?

TVA Response:

11 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 The potential for load sharing between the threads and the tack weld was addressed as follows. The Structural Integrity analysis concluded that the threads take the bulk of the load under that condition, and would deform under a single application of the opening thrust load with full backpressure (similar to the deformed condition observed in the threads). Once this deformation occurred; the weld would take the bulk of the load upon subsequent applications, and the undersized weld in valve 1-FCV-74-66 is predicted to fail.

From the Structural Integrity report, the cases with thread engagement show that, if the threads and welds are assumed to share the load, the weld stresses are reduced by about a factor of 4 because the threads take the bulk of the load. However, the thread displacement at maximum weld stress was found to be on the order of 0.005 inches, while the possible thread clearance is on the order of 1/2 the thread pitch, or 0.042 inches. So, if the threaded joint was not preloaded, or lost preload due to thread deformation, then primarily the weld would take the load, as in the zero thread engagement cases, until the weld failed, or excessively exceeds design irrespective of the weld size being 0.2 or 0.5 inches. Once the weld failed, then exclusively the threads would take the load. To address this condition, and to independently check the thread shear strength calculations, finite element analyses were also performed for the case of thread engagement but no weld, with the entire load being taken by the undersized threads.

21) Why are single point MOVATS data comparisons sufficient to support the conclusion statements made in the RCA? Explain using the data from testing of all six valves from all three test cycles for comparison.

TVA Response:

Not seeing unseating force during the November 2008 current trace was consistent with the metallurgical forensics analysis that determined the fractured weld existed in an oxygenated environment for a significant amount of time. Although the cleaning affect from stroking globe valves may reduce the COF below that which would show unseating like 3-FCV-74-52, all other current unseating traces on the four remaining valves showed unseating consistent with the aged stellite INEEL report. The 2010 full MOVATs trace performed on the 1-FCV-74-66 aged stellite seats demonstrates that it will show unseating similar to the other four valves after stroking.

22) Is the determination that valve seating surfaces COF are analogous to "second stoke" COF a reasonable assumption based on the following?

• Without being able to identify when the valve failure occurred, what is the basis to assume with any confidence that the valve was cycled just prior to the last closing event before it failed?

• The reduction in COF shown during subsequent strokes in the INEEL report is attributed in part to the sustained relative surface motion between the samples causing plastic deformation and fracture of granular surfaces of the corrosion products. Globe valve seats do not go undergo a sustained period of relative motion between the seating surfaces.

TVA Response:

12 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 The 1-FCV-74-66 valve disc successfully lifted when shutdown cooling began in March of 2009 effectively releasing the captured oxidation particles. The valve was then closed in accordance with the procedure after securing from shutdown cooling. Although globe valves have a shorter sliding distance on the seat, relative contact stresses are much higher based on the smaller contact surface areas offsetting the sustained relative motion. This can be seen by the relatively low industry MOVATS globe valve unseating forces. During the mockup, testing surfaces were roughened to increase the COF. Significant reductions in the COF was observed after each high compression stroke; greater change from the first stroke then getting less with each subsequent stroke moving closer to the un-roughened surface. The observed changes were much greater than those published in the INEEL report. The maximum sustained static (at the beginning of the stroke) COF before any strokes in the INEEL is 0.5 and 0.38 after one stroke.

The evaluation of 1-FCV-074-66 conservatively assumes a static COF of 0.4.

23) In 2008, the licensee attempted to vent FCV-74-66 using the bonnet vent line, but was unsuccessful. Instead of a solid stream of water, only two cups of water came out. WO 08-723813-000 was then initiated to perform the necessary maintenance to clear the presumed vent line plugging. However, subsequent maintenance during U1R8 refueling outage, did not identify any plugging (i.e., the line was determined to be clear). What opportunity did the licensee have, or miss, in recognizing that the valve bonnet vent line was not plugged but rather the FCV-74-66 valve disc was stuck in its seat preventing any flow through the vent line?

TVA Response:

Work Order (WO) 08-723813-000 was initiated to perform the necessary maintenance to clear the vent line. The WO required the vent valves to be cut out and then verification that the vent line was clear was made back to the 1-FCV-074-066 as part of WO verification process prior to reinstalling the vent valves to ensure reliability. The obstruction was removed as previously reported in WO 08-723810-000 and corrected non-conformances identified by PER 156971.

Since plugging of the vent line was the obvious cause and there was no reason to suspect the disc was lodged into the valve body, an acceptable ultrasonic (UT) method (procedure SR 3.5.1.1) was used to validate the piping to be full of water. It should also be noted that the lack of reliability to vent RHR Loop I was reported on October 3, 2008 and RHR Loop II on November 11, 2008.

24) What's the basis for assuming operators would be successful in executing the SSl's given the degraded condition of the FCV-74-66 valve? Does past training and operating experience suggest operators would have waited up to seven minutes before securing the Loop II RHR due to no observed flow, especially considering operators secured RHR after less than two minutes on October 23, 2010 when procedure instructions allowed three minutes? During operation of Loop II RHR in alternate safe shutdown per the SSIs, with a degraded FCV 74-66 valve (i.e., detached from the stem), would the 120 to 215 psig pressure band for controlling reactor pressure still be appropriate for ensuring adequate RHR flow? Was this verified by analysis or testing?

TVA Response:

13 4/5/11 Enclosure 3

TVA Response to NRC Questions Dated 3/31/11 on 1-FCV-074-66 The circumstances are considerably different for placing RHR in shutdown cooling versus entry into the Safe Shutdown Instructions (SSIs) due to a significant fire event. The circumstances when the valve failure was identified on October 23, 2010, involved placing RHR in shutdown cooling after a planned shutdown for a refueling outage. Under these conditions, RHR flow is expected to occur immediately upon starting of the RHR pump since reactor pressure would already be below the shutoff head of the RHR pump. The plant was not experiencing any accident, transient or external/internal event. The operators secured the pump after a reasonable amount of time and successfully placed RHR Loop I in shutdown cooling. The circumstances associated with placing RHR in alternate shutdown cooling in accordance with the SSIs during an Appendix R event are considerably different.

Entry into the SSIs places the plant in a unique alignment that ensures one train is free of fire damage. The operator starts the RHR pump well before reactor pressure is below the shutoff head of the pump. The operator is trained and knows that injection flow will not be seen until reactor pressure drops to a sufficient value (e.g., below the shutoff head of the RHR pump). The typical time between RHR pump start and flow initiation is approximately 5 minutes per the Safe Shutdown Analysis. Additionally, in this situation, the operators priority is protection of the reactor core. Therefore, the operator would not secure the running RHR pump. Instead, another operator would be dispatched to the field to determine the reason for lack of flow. It is reasonable to assume the operator would allow the RHR pump to run for the full seven and a half minutes per the caution note in the SSIs.

With respect to the pressure band for controlling reactor pressure to ensure adequate RHR flow; the pressure band for controlling reactor pressure would still be appropriate for ensuring adequate RHR flow. Based on analysis, the differential pressure required to lift the disk is small (i.e., 2.45 psi) compared to the differential pressure across the disk (i.e., a minimum of 60 psi) when the minimum required RHR injection flow is being supplied in accordance with SSI alternate shutdown cooling.

25) Was it possible for operators to exceed the SSI timelines while they attempted to execute the SSIs given that the degraded FCV-74-66 valve would have caused an unexpected delay in the initiation of RHR flow?

TVA Response:

The results of testing and analyses indicate that 1-FCV-74-66 would have opened and injection from the RHR pump would have been initiated within no more than seven minutes. Initiating flow within the seven-minute time period fully complies with 10 CFR 50 Appendix R Safe Shutdown Analysis and the Safe Shutdown Instructions. As discussed in the response to question 18, even with the potential delay in the opening of valve 1-FCV-74-66, RHR flow would have been established within 27 minutes versus the analyzed time of 35 minutes contained in the SSA.

14 4/5/11 Enclosure 3

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

During the TVA/NRC Regulatory Conference in Atlanta, GA on April 4, 2011, the NRC staff requested TVA to address the following questions and/or provide additional information regarding their presentation and the root cause analysis (RCA) for PER 271338, 1-FCV-074-066 RHR Outboard (Loop 2) Valve Failure:

1) Provide detailed fire modeling information (e.g., ignition frequencies, fire propagation, severity factors, suppression, etc.) from the licensee's NFPA-805 transition work for the scenarios identified in NRC's Phase 3 Significance Determination Process issued March 2, 2011. Also, provide cable routing information on the post-fire availability of alternate systems (e.g., core spray, the opposite loop of RHR/LPCI, HPCI, RCIC, etc.)?

TVA Response The work on the Browns Ferry Nuclear Plant (BFN) Fire Probabilistic Risk Assessment (PRA) to support transition to NFPA-805 is still ongoing. The detailed fire modeling of BFN plant-specific configurations for fire scenarios considered in the NRC Significance Determination Process (SOP) evaluation has not yet started. However, as part of the transition to 10 CFR 50.48(c), the NRC has communicated to the industry that its expectations are very high for justifications of treatment outside of the methods provided in NUREG/CR-6850, "EPRIINRC-RES Fire PRA Methodology for Nuclear Power Facilities," dated September 2005. As an example, the FAQ process demonstrated that even strong technical work done by the Electric Power Research Institute (EPRI) was insufficient to convince the staff to allow relaxation of conservative assumptions documented in NUREG/CR-6850 in favor of more realistic assumptions. As a result, the Browns Ferry Fire pRA is being performed using the guidance provided in NUREG/CR-6850 and related FAQs. In addition, fire modeling performed to support the BFN transition to NFPA-805 will be in accordance with NRC guidance. Therefore, the conservatism inherent in the NUREG/CR~6850 methodology and related FAQs will bias the calculated results.

The complexity of the Fire PRA (FPRA) process is addressed in NUREG/CR-6850 by establishing a structured set of 17 technical tasks that comprise the systematic evaluation of the fire hazards and risks. Due to practical difficulties, no integrated pilot was ever performed for the process addressed in NUREG/CR-6850. Instead, the pilots tested only individual tasks.

Despite the incremental enhancements documented in the FAQ resolutions, the simplifications and bounding assumptions of the methods and data in NUREG/CR-6850 remain obstacles to the goal of plant specific Fire PRAs that realistically reflect fire risks; therefore, it is difficult to use FPRAs in risk-informed decision-making. Following the completion of several FPRAs using the NUREG/CR-6850 methodology, the calculated risk numbers appear to be much higher than those associated with internal events. The Nuclear Energy Institute (NEI), experienced industry fire PRA practitioners, NRC staff, and NRC FPRA contractors met with the NRC Advisory Committee on Reactor Safeguards (ACRS) Reliability and PRA Subcommittee to discuss concerns associated with FPRAs on November 16,2010, and again on December 13 and 14, 2010. On December 6, 2010, NEI submitted an NEI report, lIRoadmap to Attaining Realism in Fire PRAs - December 2010," to the ACRS. The NEI report documents the industry's basis for concern that FPRAs are not providing results that comport with plant operating experience, and provides a roadmap for areas of FPRA requiring further improvement in order to achieve enhanced realism in FPRA methods.

Page 1 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

The NEI report provides evidence based on results from current FPRAs that support the observation that the results of the FPRAs are conservative with respect to operating experience.

The primary source of the conservatisms is the simplified approach taken in defining fire hazards and the bounding assumptions made in characterizing fire events. The net result is that FPRAs (and Fire SOPs) based on NUREG/CR-6850 are not realistic. The NEI report provides evidence that supports the following:

• Fire characterization does not conform with operating experience o Over-prediction of number of severe fires o Assumed rate of fire growth and severity, e.g., 12 minutes in electrical cabinets, oil fire severity o No credit for control of fires

• The level of risk is overstated o Fire PRAs based on NUREG/CR-6850 predict high frequency of fires, but NRC's Accident Sequence Precursor (ASP) has not demonstrated this result o Predicted frequency of spurious operations not consistent with operating experience

• Uneven level of conservatism can mask key risk insights and lead to inappropriate decision-making o Simplifications result in bounding treatment o Assumes plant challenge for all fires, e.g., plant trip o No credit for administrative controls Many of the current FPRAs have used detailed fire modeling, cable and circuit analysis and Human Reliability Analyses (HRA) to improve the calculated results. However, even with such detailed analyses, the calculated results are estimated to be conservative by a factor in the range of 5 to 10 (or perhaps higher) overall (taken from "Achieving Realism in Fire PRA, Insights and Challenges based on Damage States and Associated Frequencies," presented by J. R. Chapman at PSA-2011 - International Topical Meeting on Probabilistic Safety Assessment and Analysis). This estimation is based on comparison of calculated results, such as the frequency of fire damage states to operating experience, as provided by the NRC's ASP program (e.g., based on calculated results, more significant fires should be occurring in the industry than are actually being experienced). The current fire PRA methods would predict that a fire designated as a "significant precursor" would be expected to occur every one to ten years across the industry. However, there has not been a significant precursor involving a fire since implementation of fire protection programs across the industry.

Identified areas of conservatism in current FPRA methodology include the following.

• Fire event data characterization

• Fire severity characterization

• Credit for incipient detection

• Credit for suppression and detection

• Switchgear zone of influence, fire growth assumptions (e.g., incipient fire growth in electrical cabinets)

• Ignition frequency treatment of standby components

• Fire growth assumptions Page 2 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

• Peak heat release rates

• Damage assessment

• Fire modeling

• Treatment of hot shorts

• Human reliability The degree of conservatism for each of the above areas is not readily quantifiable until EPRI/NRC research is completed and applied.

However, as an example of the degree of conservatism that may be expected for an electrical cabinet fire, the TVA PRA group has performed a sensitivity study of refined heat release rate distribution and fire growth assumptions based on ideas discussed with the ACRS Reliability and PRA Subcommittee during the meeting in December 2010. The results indicate that the fire non-suppression probability may be reduced by a factor of 10 or more if more realistic characterization of an electrical cabinet fire is applied in fire risk estimates.

Other conservatisms exist as a result of BFN plant-specific non-quantifiable factors. Defense-in-depth measures and compensatory actions (such as the dedicated On-Site Fire Department and the roving fire watches) are not currently explicitly quantified in the FPRA methodology addressed in NUREG/CR-6850. Other non-quantifiable factors, under the current FPRA methodology, that will reduce the fire risk include the existence of fire retardant on the cable, the presence of cable tray covers, and the fact that almost 100°A>> of BFN power cables have thermoset material jackets (currently self-ignited cable fires are required to be assumed for plant configurations with partial thermoplastic cables). Thermoset cables use a cross link polymer chain material that does not melt and is much more resistant to fire damage.

In conclusion, current FPRA and SOP methodology using NUREG/CR-6850 and related FAQs contain significant conservatism. As a result, the quantification of fire risk using this methodology can bias the SOP results substantially and result in over-prediction of fire risk associated with a finding for which the significance is dominated by fire. As such, TVA considers that it is more appropriate to use Inspection Manual Chapter 0609, Appendix M to evaluate the significance associated with the failure of valve 1-FCV-74-66.

With respect to cable routing information on the post-fire availability of alternate fire safe shutdown systems, the current level of cable routing and associated data entry being performed for the BFN NFPA-805 transition does not support providing, in a timely manner, more detailed information than the information that was gathered and provided to the NRC during the Appendix R Operator Manual Action SOP evaluation. The follOWing information on the post-fire availability of alternate fire safe shutdown systems is provided consistent with the approach taken during the Appendix R Operator Manual Action SOP evaluation.

• To better understand the scenarios that had been proposed for the previous Appendix R Operator Manual Action SOP, detailed evaluations of individual scenarios were undertaken at BFN by Site Engineering and Operations. Initially, the individual scenarios were walked down to determine target sets and begin data analysis. Electrical Design personnel evaluated each target set to determine what equipment is impacted by the fire ignition source and assumed damage. Complete detailed circuit review was not completed. Many Page 3 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) cables that are included in the analysis may not cause failure of the associated equipment.

However, further evaluation was not performed for every cable. For these cables, the associated equipment was assumed to be impacted by the fire and made unavailable.

Therefore this approach is conservative.

• The list of equipment impacted for each scenario was then reviewed by licensed individuals in the BFN Operations organization. An initial assessment was completed to determine if any normal equipment used to achieve and maintain fire safe shutdown was impacted. The results are provided in the Attachment 1 tables for each applicable scenario/fire area. Only those results applicable to the proposed SDP for the valve 1-FCV-74-66 failure have been provided. Components in the tables highlighted in red are impacted and therefore considered to be unavailable due to the fire.

Page 4 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

NRC Scenario from Appendix R Operator Manual Action SOP (Highlighted in orange in Tables) Heading/Description in Tables Fire Area 7&8 SCENARIO 8 & 9 lAHU Above 4KV SDBD RM) 1-3 2 SCENARIO 2 & 3 l480V RMOV BD 1C) 1-1 41 SCENARIO 33 & 34 l480V RMOV BO 1A) 5 1 SCENARIO 1 l250V RMOV SO 1C) 1-1 19 SCENARIO 24 l3-FCV-74-67) 3-1 21 SCENARIO 26 & 27 l480V RMOV BO 3D) 3-3 22 SCENARIO 28 l3-ACU-031-7205) 3-3 42 SCENARIO 35 l250V RMOV SO 1A) 5 43 SCENARIO 36 & 37 (4KV SO SO A) 5 106A SCENARIO 115A (Cable Tunnel Intake) 25 44,45,46 SCENARIO 38,39 & 40 l480V SO BD 1A) 6 9& 10 SCENARIO 10 & 11 l1-XFA-231-TS1A) 1-5 11 SCENARIO 12 & 13 lRPT 1-BDAA-068-0001-JI) 1-5 23 SCENARIO 29 lRWCU cabinet) 3-4 24 SCENARIO 30 & 31 l3-BOAA-068-00031) 3-4 25 SCENARIO 32 (0-XFA-266-0THS) 3-4 69 SCENARIO 82 lU1 GEN SKR AIR COMPRESSOR 1-CMP-35-460B) 25 73 SCENARIO 84 (U2 EXCITER CUBICLE) 25 76 SCENARIO 87 l4160V UNIT SO 2C) 25 77 SCENARIO 88 l4160V COMMON SO B) 25 95 SCENARIO 106 (Cable Travs - 480V TB MOV SO 1C) 25 101 SCENARIO 111 (4KV UNIT SO 3B) 25 102 SCENARIO 112 l480V TMOV SO 3C) 25 103 SCENARIO 113A (North TB U1 & U2 (Bus Duct>> 25 103 SCENARIO 113B (North Turbine Buildina U3) 25 104 SCENARIO 114A (North TS U1 & U2 (Cable Trav>> 25 104 SCENARIO 114B lNorth TB U3 lCable Trav>> 25 105 SCENARIO 116 lCable Tunnel to XFMR Yard) 25 106 & 106C SCENARIO 115B ITB Cable Tunnel Trav Horizontal and Vertical) 25 61 & 62 SCENARIO 74 & 75 (4160 UNIT BD 1A) 25 63&64 SCENARIO 76 & 77 (4Kv RECIRC BD 1) 25 67&68 SCENARIO 80 & 81 (480V LTG BD 1) 25 70,71,72 SCENARIO 83 (480V COMMON BD 2) 25 74&75 SCENARIO 85 & 86 (4160 UNIT SO 2A) 25 79,80,81 SCENARIO 90, 91 & 92 l480V UNIT SO 2B) 25 84&85 SCENARIO 95 & 96 l4KV RECIRC SO 3) 25 86&87 SCENARIO 97 & 98 l4KV Unit SO 3A) 25 93&94 SCENARIO 104 & 105 l480V Common Bd 3) 25 96&97 SCENARIO 107 & 108 l4160V UNIT BD 2B) 25

99. 100 SCENARIO 109 & 110 l480V TMOV BO 2C) 25 Page 5 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

2) The Structural Integrity Associates report on the strength of the threaded joint was calculated for shear strength. This calculation was used as the basis for the postulated event that caused the failure. However, actual thread conditions from the Westinghouse report show the following:

• The failure mechanism was a yielding failure causing plastic deformation (beaking) and not thread shearing.

• Only a minority of the threads are documented as having plastic deformation.

• The top thread and most of the second thread (which would have the most thread engagement) do not indicate any deformation.

• There is virtually no deformation to two complete vertical axes of the threads.

The actual analysis of the failed joint appears to contradict the assumption that it took a force greater than the joints calculated shear strength to fail the joint. How does this affect the RCA, postulated failure scenario, and other report conclusions?

TVA Response:

As listed in bullet #1 above regarding the failure mechanism, the stress results illustrated in Figure 1 below are based on membrane stress averaged through critical paths in the threads, not shear stress, and are therefore consistent with the deformation pattern observed (beaking).

The evidence strongly supports the predominant failure mechanism as pullout. Beaking (plastic deformation) damage to the threads was clearly caused from a shear loading condition because they were undersized, resulting in the pullout. The Westinghouse report (Ref. 1) indicates that a significant number of the threads exhibited plastic deformation, and that the most significant deformation was at the top of the threaded joint (bottom of the figures since they are upside down). Measurements were taken at the 20 degree, 110 degree, 200 degree and 290 degree azimuth locations around the skirt over a total of twenty threads. The beaking phenomenon was most notably observed at the 290 degree location starting at thread number 3 and extending over the next nine threads. Little or no evidence of beaking was observed at the other azimuth locations. Due to the undersized threads, loading would not expect to be uniformly distributed.

This observation is very consistent with, and would be expected from undersized threads subjected to asymmetrical or "ratcheting" type loading conditions. This also accounts for no deformation being observed on two completed vertical axes of the threads. Because the threads were undersized leading to asymmetrical loading, this evidence pattern occurred.

Dr. Pete Riccardella (one of the founders of Structural Integrity) reviewed Structural Integrity's supporting analysis regarding this NRC question. His response is provided below.

Response from Structural Integrity (also see original reports (Refs. 2, 3, and 4>>

"We disagree with observations (bullets) #2 and #3 above. Figures 2 and 3 below, taken from the Westinghouse Failure Analysis Report, indicate that a significant number of the threads exhibited plastic deformation, and that the most significant deformation was at the top of the threaded joint (bottom of the figures since they are upside down). This is consistent with the loading distribution predicted in Figure 1 below.

Page 6 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) 01 o 10000 20000 70000 I-----------~"'IF=-----

c.

~E I - - - - - - - - - - - - - - - - = < ;

o "C

_ _ Inside Path

~

1 - - - - - - - - - - - - - - -.-Outside Path I--------------,~~ =----

Axial Membrane Stress (psi)

Figure 1 - Finite Element Thread Stress Results at 314 kip Axial Load The inside path and outside path as well as axial membrane are discussed in Reference 3.

Page 7 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

Figure 2 Close-up Macrograph of Skirt Threads, Showing Thread Damage (Fig. 3.3 from Ref. 1)

Page 8 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

Figure 3 - Optical Comparator Image of Damaged Threads (Fig. 3-10 from Ref. 1)

As listed in bullet #1 above regarding the failure mechanism, the stress results illustrated in Figure 1 above are based on membrane stress averaged through critical paths in the threads, not shear stress, and are therefore consistent with the deformation pattern observed (beaking).

Clearly the deformation in Figure 3 is more severe in the threads near the bottom of the figure (top of the joint), although all of the threads appear to be significantly deformed, which is easily visualized if one were to superimpose a symmetrical thread pattern over the thread pattern in the figure. Also, while there might be some undamaged thread regions, it must be recognized that significant clearances (slop) existed in the threaded joint due to the undersized thread condition, such that there may have been a departure from concentric alignment between the skirt and the disc, and thus some amount of rocking may have helped dislodge the two parts.

On the basis of the above, we do not believe that the metallurgical observations of the failed joint contradict the assumptions in our analysis. To the contrary, our analysis is consistent with one of the main conclusions in the Westinghouse Failure Analysis Report, that "The mixed damage forms suggest that the threads were probably not unscrewed but rather were removed by an asymmetrical force or were the result of an inconsistent mating surface in the base."

Page 9 of 29 4/13/11 .

Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

3) No quantitative value was presented for the licensee's tlhigh confidence" level of assurance that the 1-FCV-74-66 valve would have performed its safety function for alternate safe shutdown. What is this value? Provide an explanation of the results and methodology of the uncertainty analysis used to justify the licensee's "high confidence" that within seven minutes of RHR pump operation the 1-FCV-74-66 valve would have opened? How ma[n]y scale model tests were actually performed to demonstrate the repeatability of the two initial scale model tests? What were the results?

TVA Response:

The TVA investigation of the valve skirt/disc separation (Le., as-found condition) included additional literature reviews which show that friction reduction due to pressure pulsations produced from a running Residual Heat Removal (RHR) pump would have been capable of releasing the lodged disc from the seat. Rather than reach a conclusion based solely upon application of industry research, a highly recognized expert team (Performance Improvement International (PI I>> was consulted to design a laboratory mock-up and perform extensive testing to determine if the valve would have functioned in the as-found condition. Actual plant data was collected from RHR Loop II with one RHR pump running to support realistic modeling of pressure pulsation amplitude and frequency. Extensive calibration testing of the laboratory mockup was performed to minimize uncertainties and improve repeatability (over 30 tests) prior to the performance of the actual vibration test using the mock-up.

Section 6.2 in the PII report, "Analysis of the October 23, 2010 BFN-1-FCV-074-066 Shut-Down Cooling Event," dated March 22, 2011, discusses experiment uncertainty. The following calculations provide the design-stage uncertainty associated with the experiment.

Design-8tage Uncertainty Substituting values from Table 6.9 into Equation 6.3 (both in the PII report), the design-stage uncertainty of strain gauges 1 and 2 and the hydraulic press are 12 ~E, 20 ~E, and 0.02 kip respectively. The combined design-stage uncertainty of the strain gauges is (1) where uuS1 and Ud.Bg2 are the design-stage uncertainty of strain gauges 1 and 2, respectively.

Therefore, U Ug was 23 ~E throughout calibration testing. Valve body strain throughout calibration testing with the 83 degree set remained at values of 219-277 ~E both immediately after loading and before being pUlled out (open the valve). Strain measurement error was, at most, 8.3-10.5% during these tests. Valve body strain throughout calibration testing with the 75 degree valve set ranged between 353-393 ~E and 241-268 ~E immediately after loading and before being pulled out, respectively. Valve body strain measurement errors were, at most, 5.9-6.5% and 8.6-9.5°k, respectively after loading and before pUllout, during these tests.

Page 10 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

University of California San Diego (UCSD), where the tests were performed, laboratory personnel suggested that strain gauge deviation is often much greater ("'100 IJE) than resultant values for ud.sg during testing with similar loading patterns. Section 6.3 of the PII report discusses the time-dependent relationship between friction reduction and valve body release.

The 75 degree valve disc was released from its wedged position almost immediately after surface abrasion was reduced significantly at the contacting surface.

Propagation of Error During Vibration Testing Equation 6.4 of the PII report conveys the interdependence of strain and force variation within the testing sample set and predicts the lower bound of strain measurement error during vibration testing. PII considers that valve body oscillation during testing may have caused strain readings to be significantly lower than their true values. Therefore, only the lower bound of error propagation is of interest. The OE limit is believed to have been -50 to -80 IJE throughout testing.

Variation in ud.sg may have approached this range of values.

Statistical Analysis of Uncertainty PII is confident in the validity of its test results based on the following. Statistical analysis was performed to verify the likelihood that the 74-66 valve disc would have liberated from its wedged position in less than seven minutes. The percent change in static COF and time required to liberate the valve disc were determined by vibration experiments with the 83 degree and 75 degree valve sets, respectively. Therefore, the accuracy of both parameters was evaluated.

Three vibration tests were performed with the 83 degree valve set. The sample size is very small and no population mean or variance exists for the set. It is therefore appropriate to use a one-sample t-interval procedure. This test evaluates the likelihood that the valve disc would have been freed of its wedged position with a static COF change greater than or equal to 18.2%

(required under Appendix R operating conditions). A t-value is established to determine the probability that disc liberation at this value would not have been possible j- Jl o (2) s where X, J.lo' S, and n are the sample mean, value of interest (limiting case), sample standard deviation, and sample size, respectively (Ref. 5, 381-2). The t-value is an 0/2 quantity since only outliers lower than Jl o are of interest. The sample standard deviation is s = Je x n-l

%)2 (3)

Page 11 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) where x and i are sample values and the sample mean, respectively (Ref. 5, 109). The mean of the three test values provided in Table 6.4 of the PII report is 26.3°k. Therefore, sand t a / 2 are 1.11 and 12.6, respectively. A t-table is used to determine the confidence interval associated with the t a / 2 value. The sample set has df = n-l (4) degrees of freedom. Therefore, df equals 2. Evaluating df in the standard t-table and extrapolating yields an a/2 value of 0.003 (Ref. 5, A-10). The probability that the maximum change in the 74-66 valve could have overcome normal forces associated with an 18.2°k reduction in the static COF is (5)

Thus, P equals 99.7% and there is very reasonable assurance that the valve disc would have liberated with at least an 18.2% reduction in the static COF.

Two tests were also conducted with the 75 degree valve set to determine the amount of time required to fully abrade the seating surfaces. The 75 degree valve disc was liberated in less than seven minutes in both vibration tests. PI! observed no evidence suggesting disc liberation would have required additional time.

Therefore, the laboratory mock-up testing is very credible and provides high confidence (99.7%)

that the valve would have provided functional flow within seven minutes.

PII's conclusion is quoted verbatim below:

II *** Therefore, PII has assurance that the valve disc would have been released from its wedged position within seven minutes.....A number of conservative measures were applied in both the calculations and the experiment conducted. As a result, PII has a very high confidence in the credibility of its findings. PII has found no safety concerns associated with the October 23, 2010 SDCE [shutdown cooling event]."

4) The significant force needed to release the stuck FCV-74'66 valve disc from the valve seat indicated that the disc might have been in a thermally bound condition, which was not addressed by the mock-up tests. What was the technical basis that thermal binding was not a factor in the 74-66 disc being stuck in its seat?

TVA Response:

The outboard injection valve (1-FCV-074-66) is normally open and is in a line maintained full of ambient temperature <<100°F) water by the plant keep-fill system. In the event of excessive leakage past the interlocked closed inboard valve, the water temperature could rise (experience on Unit 2 shows water temperature can get as high as 250°F). However, the normally open Page 12 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) outboard valve would only be closed for a short period of time during quarterly operability stroking. The developed temperature gradient across the valve while the valve is being stroked is expected to be minimal since steady state conditions have already been developed while the valve is open and the amount of time during stroking is minimal. Additionally, the history of periodic temperature recording (see table below) demonstrates a negligible amount of heating from leakage past the closed inboard valve. The inboard valve is also stroked while aligning for shutdown cooling at relatively low Reactor Pressure Vessel (RPV) coolant saturation conditions

(-80 psig and 325 OF). The thermal gradient developed during this shutdown cooling stroke would also be minimal because of the short stroke duration and the much longer amount of time needed to heat the keep-fill water and the valve. Heating from the bottom was not possible since it was found to not pass flow as soon as the pump was started and secured within 110 seconds. Therefore, thermal binding does not contribute to the disc being lodged in to the seat.

See the following paragraph concerning higher temperature gradients from the reactor pressure vessel.

In the hypothetical event that the outlet of the valve is exposed to high temperatures while the valve is closed (or the disc is separated and resting in the valve body seat) the temperature gradient would tend to relieve the body strain rather than increase it. In this event. the inlet disc surface area and large disc trim mass, approximately equal to the disc itself, would be exposed to cool keep-full water including just a small portion of the valve surface area. The top of the disc and the majority of the valve surface area would be exposed to the higher temperature water with a lower density and associated thermal conductivity. Therefore, the insulated valve body would thermally expand more than the disc and relieve the body seating strain; both are carbon steel with the same thermal expansion coefficient. A temperature gradient event from higher inlet temperatures is not considered feasible because of the large volume of cool keep-full water required to be heated during the short time the valve is in the closed position.

The pressure suppression chamber (PSC), keep-fill system is designed to maintain a hydrostatic overpressure on the RHR discharge lines. The RHR system discharge lines are maintained full at all times to prevent the possibility of water-hammer. The RHR System is filled from the PSC head tank, which has ties to the PSC water-transfer pumps for pumping power, or from the condensate transfer system. The PSC head tank pump(s) will start and stop automatically to control the tank level. Both PSC head tank pumps take suction indirectly from the suppression pool via a connection to a Core Spray (CS) pump suction line from the PSC upstream of the pump suction isolation valve. The PSC head tank pump suction line contains two normally open isolation valves. The closed loop (PSC head tank to Emergency Core Cooling System (ECCS) to suppression pool to the PSC transfer pumps back to PSC head tank) assures that the proper suppression pool water level is maintained. Two check valves exist between the ECCS and the PSC head tank and between the ECCS and the Condensate Storage and Supply System to prevent loss of ECCS flow. The PSC transfer pumps are redundant and have separate power supplies. The instrumentation associated with the PSC keep-fill system is redundant. Also, the discharge piping of the RHR system is periodically vented from the high point of the system and water flow determined in accordance with Technical Specifications Surveillance Requirements. Verification that the systems are vented and filled is also required by plant procedures following periods of inoperability or maintenance on these systems as required demonstrating system operability. Temperature of the keep-fill system varies depending on source (Suppression Pool or Condensate). The PSC keep-fill Page 13 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) system temperature when the source is the suppression pool is consistent with the temperature of the suppression pooll while the PSC keep-fill system temperature when the source is condensate is more dependent on the ambient temperatures of the environment. Typical temperatures of the keep-fill system are provided below which are taken in proximity to the valve. As can be seen clearly from the discussion and the temperature profiles of the keep-fill system l thermal binding was not was an issue with the 1-FCV-074-66 valve.

Date Date Pipe temp Reviewed/Calibration Pipe temp Reviewed/Ca Ii bration Pipe (F) Date Pipe (F) Date RHR Loop I 88.7 10/22/2008 RHR Loop <100 11/12/2008 RHR Loop I <100 11/20/2008 RHR Loop <100 12/09/2008 RHR Loop I <100 12/29/2008 RHR Loop <100 01/02/2009 RHR Loop I 84.7 01/26/2009 RHR Loop 74 01/30/2009 RHR Loop 102.3 02/26/2009 RHR Loop 87.3 03/02/2009 RHR Loop 89.7 03/09/2009 RHR Loop 90.5 03/09/2009 RHR Loop 92.4 03/10/2009 RHR Loop 72.5 03/24/2009 RHR Loop 71.2 03/20/2009 RHR Loop 79.3 04/24/2009 RHR Loop 73.4 04/20/2009 RHR Loop 91.1 06/29/2009 RHR Loop 74.4 05/14/2009 RHR Loop <100 10/16/2009 RHR Loop 90.3 06/15/2009 RHR Loop <100 11/13/2009 RHR Loop 93.2 07/14/2009 RHR Loop <100 12/08/2009 RHR Loop 92.4 08/06/2009 RHR Loop <100 01/15/2010 RHR Loop <100 09/18/2009 RHR Loop <100 02/12/2010 RHR Loop <100 10/08/2009 RHR Loop <100 02/13/2010 RHR Loop <100 11/06/2009 RHR Loop <100 04/16/2010 RHR Loop <100 12/04/2009 RHR Loop <100 05/14/2010 RHR Loop <100 12/23/2009 RHR Loop <100 06/11/2010 RHR Loop <100 01/09/2010 RHR Loop I <100 07/16/2010 RHR Loop <100 02/04/2010 RHR Loop <100 08/15/2010 RHR Loop <100 03/05/2010 RHR Loop <100 09/10/2010 RHR Loop <100 04/10/2010 RHR Loop <100 10/15/2010 RHR Loop <100 05/07/2010 RHR Loop <100 11/14/2010 RHR Loop <100 06/04/2010 RHR Loop <100 11/14/2010 RHR Loop <100 07/11/2010 RHR Loop <100 12/10/2010 RHR Loop <100 08/06/2010 RHR Loop <100 01/11/2011 RHR Loop <100 09/03/2010 RHR Loop <100 02/11/2011 RHR Loop <100 10/08/2010 RHR Loop <100 11/08/2010 RHR Loop <100 11/09/2010 RHR Loop <100 12/03/2010 RHR Loop <100 01/07/2011 RHR Loop <100 02/04/2011 RHR Loop <100 03/04/2011 Page 14 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

5) Did the licensee conduct any licensed operator training (e.g., simulator) specifically involving implementation of the safe shutdown instructions (881) in which the operators were trained to seek and pursue alternate sources of coolant injection to compensate for the loss of RHR? If so, describe and provide the applicable simulator exercise guides and/or lesson guides? Did the licensee provide any licensed operator training that involved implementation of the 881s in which the RHR pump would run for up to seven minutes without any indication of flow? If so, describe provide the applicable simulator exercise guides and/or lesson guides?

TVA Response:

Browns Ferry Nuclear Plant (BFN) Operators are trained in the skills, knowledge and behaviors required to execute Emergency Operating Instructions (EOls), Severe Accident Management Guidelines (SAMG), Radiological Emergency Plan (REP), and Safe Shutdown Instructions (SSls). As discussed below, operators are also trained on recognition and decision making processes necessary to address a scenario which is outside the bounds of rule-based procedure compliance.

SSI training scenarios include fires in plant locations and the associated equipment failures that require operators to respond in order to maintain the plant in a safe condition and to complete the SSI actions. Once in the SSls, operators are taught that the SSI actions are the only credible path for success and operators are trained to complete them accordingly. Specific technical training regarding alternate path solutions within SSI is not provided due to the design of the SSls. Consistent with the SSls and the BFN licensing basis, additional malfunctions after SSI entry are not part of the training since additional equipment malfunctions would remove the success path once in the SSI.

To ensure operator awareness and expectations when confronted with issues outside of rule-based procedure guidance, applicable behavioral training is provided to operators. The cumulative effect of the behavioral training ensures operator understanding of the expectations for maintaining the reactor in a safe condition and ensuring the safety and welfare of the public during all plant conditions. These expectations apply regardless of whether the operator actions are driven by rule-based response within established procedure guidelines or knowledge-based response when outside of established procedure guidelines.

Operators are trained to recognize conditions that are outside the procedure bounds. Success paths in these circumstances rely on application of behaviors supported by teamwork, collaboration and other organizational actions.

Examples of approved training materials in place at BFN to address behavioral aspects of plant operation include:

• Procedure OPDP-1, "Conduct of Operations," training to emphasize role and responsibilities for core and public safety

• Multiple complex casualties during EOI training to drive "a protect the core" mind-set

• Multiple complex scenarios leading to execution of SAMG strategies

• Multiple complex scenarios requiring REP guideline execution to protect core and the public.

Page 15 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

When plant conditions or events are outside the bounds of applicable procedures, the operators are able, based on the combined technical and behavioral aspects of the operating training program, to recognize that they are in knowledge-based mode. They will use all means possible to ensure nuclear and public safety.

Additional training details are noted below.

• As part of the licensed operator initial and continuing training programs, TVA provides simulator scenarios which contain complex casualties with multiple system failures. One example of this is OPL 1711029 (initial training), which combines High Pressure Coolant Injection (HPCI) System out of service with a loss of off-site power and failure of one diesel generator to start with a failure of the Reactor Core Isolation Cooling (RCIC) injection valve to open, which results in emergency depressurization as required by the EOls. To further complicate this event, three Safety Relief Valves (SRVs) fail to open, which will result in the operator having to use alternate SRVs to attain six SRVs open.

• Shift Manager and Shift Technical Advisor (STA) programs include training on roles and responsibilities for core and public safety commensurate with the position as follows.

o Shift Manager Responsibilities (from OPDP-1, Duties and Responsibilities of the Shift Manager (Rev. 19, Page 35 of 69>>

Duties and responsibilities of the Shift Manager (SM) related to maintaining adequate core cooling include the following:

• As the senior management representative on shift, the SM is in direct charge of plant operations and is responsible through the Operations Superintendent and Operations Manager to the Plant Manager for safe and reliable operation of the nuclear plant.

• The SM is responsible for on shift management and oversight in the control room and all plant group activities.

• The SM has the authority to take action necessary to ensure compliance with Technical Specifications, operating license requirements, and approved plant procedures to protect the health and safety of employees and the public. to ensure adequate security, and to protect the plant from damage.

Page 16 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) o Shift Manager Training Trainina Material Purpose Relevant Objective(s)

The purpose of this module 1. Describe the authority and responsibility of the Shift OPL199.LM4 is to instill TVA's operating Manager.

philosophy to the Shift OPERATING Manager candidate. The PHILOSOPHY Shift Manager is the first and 2. In a variety of circumstances, advocate the foremost example of the operating philosophy of TVA in accordance with operating philosophy in all plant policies and procedures and the operators' situations. As such, it is code of professionalism. This may include the critical that the Shift following:

Manager be fully cognizant of TVA's and plant management's attitudes a. Enforcing standards of operating performance.

towards operation of the plant b. Advocating an overriding attitude of conservatism for reactor core safety, particularly in regard to reactivity control, reactor coolant inventory, core cooling, heat sink availability, primary system integrity, and containment integrity.

c. Applying prudent jUdgment based on training, experience, and management expectations.

3. When presented with a scenario or a plant situation that requires corrective actions by operators, explain how the operating philosophy of TVA governs actions in response to the scenario/situation.

4. Given an operating condition that is not addressed in procedures, direct conservative actions designed to protect the plant and public health and safety.

5. Given an action or condition that reduces the reliability of safety-related equipment, develop a plan to mitigate the situation and restore the equipment to full reliability in a timely manner.

6. Given a choice of two or more alternatives for a given plant operational situation, select the one that provides the greater margin of reactor safety consistent with operating requirements.

7. Using the operational situations as examples, explain how foregoing a short-term benefit to prevent sacrificing long-term component integrity is apPlied to manaaina plant operations.

Page 17 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

Trainina Material Purpose Relevant Obiective(s)

The purpose of this module 1. Given a set of accident data, evaluate parameters to OPL199.AC1 is to reinforce the determine if natural circulation is occurring following a loss of knowledge the individual forced coolant flow prior to equipment or core damage.

TRANSIENT AND ACCIDENT has gained with their ANALYSIS experience as a Unit 2. During simulated conditions, demonstrate a thorough SupervisorlSRO. The understanding of, and the skills needed to maintain and focus of this module should restore, the following safety functions:

be on how this knowledge can be used to predict the Reactivity control consequences of actions, Reactor coolant inventory both positive and negative.

Core cooling Heat sink availability Primary system integrity Containment integrity

3. For a given plant operational condition and the plant probabilistic risk assessment, identify and discuss failure mechanisms, human or equipment, that would provide risk of core damage.

4. List the parameters used and identify the indications of a degraded core.

5. State the potential problems of cooling a degraded core and discuss policies and procedures that are used to diagnose and mitigate the situation.

The purpose of this module Apply the bases of the EOls to accident events that may require OPL199.AC2 is to ensure that the deviation from the instructions.

candidate has a full EMERGENCY OPERATING understanding of the bases Enabling Learning Objectives INSTRUCTIONS for the Emergency (EOls) Operating Instructions. As 1. Explain the methods of verifying proper implementation of the a Shift Manager. the EOls in accordance with plant operating philosophy.

individual may face situations which require 2. Given an accident scenario, predict the plant response to the deviation from the recommended actions by applying knowledge of EOI bases.

instructions. To recognize these situations and 3. Describe and discuss example situations that allow for respond appropriately, the deviation from EOls in accordance with plant individual must be fully administrative procedures.

cognizant of the bases and assumptions used to 4. Given situations that allow for deviation from EOls, develop the Emergency discuss the benefits of the deviation and potential Operating Instructions. problems if improperly applied.

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Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

Training Material Purpose Relevant Objective(s}

The purpose of this module Enabling Learning Objectives OPL199.EP1 is to ensure that the candidate has a full 1. Describe the responsibilities of the shift manager to manage EMERGENCY PLANS understanding of the bases an emergency event while implementing the emergency plan.

for the Emergency Plans.

As a Shift Manager, the 2. Given an emergency event condition, describe the typical individual may face decisions with priorities that a shift manager must make in situations which require transitioning from normal operations to coping with an implementation of the site emergency event and implementation of the emergency plan.

Emergency Plans. To recognize these situations 3. Given an emergency event condition, assign priorities to and respond appropriately, activities to ensure resources are appropriately directed to the individual must be fully manage the plant condition and implement the emergency cognizant of the bases and plan in accordance with plant procedures.

assumptions used to develop the Emergency 4. Describe conservative protective action recommendations Plans. based on core/containment status or unverified radioactive release information.

5. Given emergency conditions, identify constraints or impediments that may adversely impact timely protection of the general public.

6. Identify organizations available to offer equipment or assistance for mitigating an emergency.

7. Given emergency conditions, determine additional resources needed for mitiQatinQ the event.

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Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

Training Material Purpose Relevant Objective{s)

The purpose of this module 1. Given various plant conditions, determine if operation is OPL199.TE1 is to provide the Shift outside plant design bases.

Manager candidate with an APPLYING DESIGN BASES understanding of how the 2. In the presence of conditions outside the normal operating TO design bases apply to limits, identify any safety concerns associated with plant OPERATIONS operational situations. operations.

3. In the presence of conditions outside the design bases, identify the safety concerns associated with plant operations.

4. Given a situation where the plant is known to be outside the design bases, determine the appropriate course of action to return the plant to within design limits.

5. Explain the design basis for environmental qualification of instrumentation.

6. Given a plant-specific event that has the potential for putting the plant outside the design bases (such as a loss of the residual heat removal system while in mid-loop operations, and improper surveillance or maintenance), evaluate the effect of the event on plant safety using appropriate design bases.

7. Given a specific plant condition coupled with an on-line maintenance request, determine the effects on PSA and if the request should be approved and work allowed to proceed.

8. Given a plant condition and information on planned activities, determine the plant parameters that define the basis of the operating envelope and how they might be affected by the planned activities.

9. Explain factors considered in determining availability and operability of structures, components, and systems important to plant safety.

Page 20 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) a STA Responsibilities (from OPDP-1, Duties and Responsibilities of the STA (Rev. 19, Page 37 of 69>>

Duties and responsibilities of the STA related to maintaining adequate core cooling include the following:

a Assists in oversight providing an independent perspective of critical safety functions, using redundant and diverse plant indications during transients and emergencies.

a Immediately reporting any abnormalities or plant condition that may represent a challenge to the critical safety functions or that could result in a degradation of the safety level.

a Assessing plant parameters during and following an accident in order to ascertain whether core damage has occurred or appears imminent.

a Providing recommendations on appropriate corrective actions to restore plant parameters to acceptable values.

a Investigating the causes of abnormal or unusual events that occur and assess any adverse effects.

a Evaluating the effectiveness of procedures in terms of terminating or mitigating accidents and make recommendations when changes are needed.

a STA Training

• This material is trained as part of OPL175.001, Duties and Responsibilities of the STA, as part of initial STA training. The goal of the training is as follows:

"Upon completion of this lesson, the STA will demonstrate satisfactory knowledge of the duties and responsibilities assigned to the on-shift STA" a Tasks associated with this training material include the following

• Verify critical safety functions during transients by using redundant and diverse indication.

• Assess plant parameters during and following an accident to ascertain whether or not core damage has occurred.

• Recommend appropriate corrective action to restore plant parameters to acceptable values.

• Recognize and report to the Shift Manager events which may affect plant safety.

• Recommend appropriate corrective actions to terminate or mitigate an accident.

Page 21 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2) o The training material also addresses the importance of during transients and accidents, comparing existing critical parameters to plant-specific critical safety function limiting values, and providing an independent verification of critical safety functions to the shift supervisor. The training material defines a critical safety function as a "function needed to control reactivity, remove core heat, provide an ultimate heat sink, or contain radioactivity. "

With respect to licensed operator training that involved implementation of the SSls in which the RHR pump would run up to seven minutes without any indication of flow, the following information is provided.

The circumstances associated with placing the RHR System in alternate shutdown cooling in accordance with the SSls during a 10 CFR 50 Appendix R event support keeping the RHR pump running. Entry into the SSls places the plant in a unique alignment that ensures one train is free of fire damage. The operator starts the RHR pump well before reactor pressure is below the shutoff head of the pump. The minimum flow valves are normally open such that there is a flow path available when the RHR pumps are started. The operator is trained and knows that injection flow will not be seen until reactor pressure drops to a sufficient value (e.g., below the shutoff head of the RHR pump). The typical time between RHR pump start and flow initiation is approximately five minutes per the Safe Shutdown Analysis. Additionally, in this situation, the operator's priority is protection of the reactor core. Therefore, the operator would not secure the running RHR pump during an emergency situation if there was no indication of RHR flow.

Instead, another operator would be dispatched to the field to determine the reason for lack of flow and take appropriate action to attempt to establish flow locally. It is reasonable to assume the operator would allow the RHR pump to run at least for the full seven and a half minutes per the caution note in the 8Sls.

TVA has found evidence that supports this position. Operators ran RHR Loop I and Loop II pumps for approximately 110 minutes and approximately 55 minutes, respectively, during a simulator exercise performed to support the development of an REP scenario in 2010. The RHR pumps automatically started in response to an accident signal and the operators were unable to perform rapid depressurization due to loss of drywell control air. The operators were unaware at the time that drywell control air would be lost and that the rapid depressurization would not function. Operators were in the EOls at this point in the scenario. While the EOls do not contain a caution note relative to running an RHR pump without a flow path, the operators are trained and aware of the cautionary note relative to running an RHR pump without a flow path in the Operating Instruction for the RHR System. The RHR minimum flow valves are normally open and provide a flow path upon the starting of the RHR pump. RHR Loop II flow was established at approximately 55 minutes after the pumps started. The RHR Loop I pumps were secured at approximately 110 minutes after starting and no flow path was available and RHR Loop II flow had been established. Allowing the RHR pumps to run for these periods of time would be not considered a deficiency during the actual REP drill.

Page 22 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

6) Does the NSSS vendor agree with the licensee's Part 21 report regarding under-sized threads? What kind of feedback has the vendor provided to substantiate or unsubstantiate[d] the conclusions in the licensee's Part 21 report dated April 1, 2011?

TVA Response:

General Electric (GE), the Nuclear Steam Supply System (NSSS) vendor, agrees that there is merit to the notification report and has entered it into their corrective action program and is evaluating the failure of the 24" globe valve at Browns Ferry per the attached GE corrective action document. The final Part 21 determination will be contained in a document identified as PRe 11-21. At this time, General Electric is investigating and has provided no additional feedback on the TVA conclusions.

Additionally, the valve vendor (Crane Nuclear, current owner of Walworth Valve) was consulted during the investigation to determine specific attributes of the valve, vendor drawings, and available documentation. The Crane representative concurred with the root cause and also that the critical measurements of valve components would not be expected to be performed by the customer (TVA). The representative (David Dwyer, Manager of Engineering) stated "There are no maintenance based requirements to verify critical dimensions of parts. That being said, during any refurbishment the goal is to bring wear surfaces within spec limits." The skirt threads are not considered a "wear surface. II Page 23 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

CT5- Qllick CAR Report ReslIJr

_ Commitment Tracking Welcome: Schwall, System James Quick CAR Report

{ Pnnt 1 CAR Information CAR: 54578 CAR Type: External Entry Dale: I.larch 27, 2011 Priority: B

• CondltlOI\ Adverse to Quality Generated By: Customer Complaint Internal Audit #:

(usl. CAR #: None Identrfled

("stollier Site: BROWNS FERRY 1-3 SUPI)1ier I Vendor:

Supplier /Vendo.'

Contact:

Initiator: Porter, Dale Process Owner: Watford, Glen Resl)Qtlsihle Persoll: Schwan. James CAR Status: Pending Response Completion Problem

-External Contact Name: RIchard Steed -Phone Number: 256'729-2552 -Email:

rwsteed@lva.gov Failed Valve - General Electric (GE) provIded the valve as the Nuclear Steam SupplV System Supplier via TVA/GE Contract No. 66C60*90744 (Units 1 and 2) and 67C60-91750 (Unit 3) as meeting all requirements ofGE Co.

SpecIfication No. 21AI047 and GE Purchase SpecificatIon 21AI047AS, Rev. 5 - Globe Valves - I-Iotor Operated (GE Parts list ~jo.10-154). This valve Is the RHR Loop II LPCl flow control valve, I-FCV-074-066, and was manufactured bv the Walworth Company as Part No. 531,543 (FIgure 5509). Drawing Nos. O-A-12337--lE, C-Problem

Description:

12337-3A. C-12337-8-1, and a \lendor-provided sketCh. The valve is a 24-inch No.

5297PS, 600-1b r*lss SP-66 Rating cast carbon steel, butt welded. pressure-seal angle globe valve operaled by a Umitorque Sr.1B*5T-350 motor operator. The root cause analysis Identified the failure mechanism was due to opening thrust exceeding the threaded connection between the disc skirt and dIsc due to a manufactUle's defect In which the threads were undersized. Comparisons of the as-found disc skirt (TIlC :: AEJ982E) and the In-stock dIsc skirt (TIIC :: BWF455P) were made by the Root Cause team and similar thread dImensions were found.

Evaluate original documentation (desIgn and manufacturing records) and evaluate Proposed Resolutioll: Impact of ldentified failure on plant safety performance. Potentlallv Reportable Condition will be Issued with supplemental customer Informatlon.

Keywords: Original Design; Orlglnall.1anufacture; Hardware Page 24 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

CTS- Quick CAR Repol1 Result Page 2 01'2 Response Analysis Callsal factors:

Cause Analysis:

Effec.ls and Extents:

Action(s)

Response Acceptance Responsihle Acceptance:

Original Acceptance Date:

Acceptance Date:

Process Owner Acceptance:

Origin'll Acceptance Datc:

Acceptance Date:

Initiator Acceptance:

Original Acceptance Date:

Acceptance Date:

Closure Responsible Closure:

Original Closure Date:

Closure Date:

Process Owner Closure:

Original Closure Date:

Closure Date:

Initiator Closure:

Original Closure Date:

Closure Date:

Effectiveness Review Effectiveness Reviewer:

E/R Due Date:

E/R Completion Date:

E/R Notes:

CAR Critique Review CAR Critique Actions:

CAR Criti(IUe Notes:

Trend Codes Severity:

Trend Codes:

Page 25 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

7) How many periodic surveillance tests of the Loop /I LPGI inboard injection valve occurred on Unit 1 between May 2007 and November 2008 that could have resulted in back-pressure conditions on the Loop /I LPGI outboard injection valves? Also how many times and when has similar surveillance testing been accomplished that could have created back-pressure conditions on the other five Unit 1, 2, and 3 LPGI outboard injection valves?

17) (question from March 31,2011) What is the technical basis and empirical evidence that back-pressure conditions actually existed on the 1-FGV-74-66 valve following periodic stroke testing of the inboard RHR injection valve (1-FGV-74-67)? What is the technical basis and empirical evidence that similar back-pressure conditions did not exist to the same degree or worse for the other inboard/outboard RHR injection valves (i.e., 1/213-FGV 52166)? What is the technical basis and empirical evidence that would explain why all the other inboard/outboard RHR injection valves were sufficiently different in design, maintenance, operation, or physical condition to not experience similar back-pressure conditions resulting in valve failure?

TVA Response:

The original Question 17 from the NRC Questions dated March 31,2011 , and Question 7 received at the Regulatory Conference on April 4, 2011 , are similar, with respect to additional information requested. We have included the response to both as a combined answer below.

The table below provides the data associated with the periodic surveillance tests of the valves in question during this time frame.

Strokes at Pressure between May 2007 and November 2008 l-FCV-74-S3 l-FCV-74-67 2-FCV-74-S3 2-FCV-74-67 3-FCV-74-53 3-FCV-74-67 (impacts 1- (impacts 1- (impacts 2- (impacts 2- (impacts 3- (impacts 3-FCV-74-S2) FCV-74-66) FCV-74-52) FCV-74-66) FCV-74-S2) FCV-74-66) 5 4 7 6 5 5 06/13/2008 03/28/2008 07/03/2008 04/26/2008 07/13/2008 06/27/2008 03/21/2008 01/04/2008 04/11/2008 02/01/2008 01/25/2008 02/08/2008 12/27/2007 10/12/2007 01/17/2008 11/09/2007 11/02/2007 10/19/2007 09/28/2007 07/19/2007 10/26/2007 08/21/2007 08/10/2007 07/27/2007 07/11/2007 08/03/2007 09/11/2007 05/18/2007 05/04/2007 07/31/2007 OS/25/2007 05/11/2007 Page 26 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

The backpressure force can vary based on the leak tightness of the FCV-74-66 and 52 flow control valves (FCVs). The figure below demonstrates the effect of leakage either into the volume above the disc (i.e., between the inboard and outboard valves) (raising the pressure) or out of the volume (reducing the pressure). This figure charts the change in specific volume as the pressure in a controlled volume is changed converting the change in mass to gallons. All the outboard valves are the same 24" angled globe valve manufactured by Walworth.

leakage to or from Captured Volum" between Inboard and Outboard 0.5 E

0 0.4 0.3 1

• ~

0.2

~ *

~

0.1 a

1000 900 800 700 600 500 400 300 200 100 Backpressure (psi)

The applied backpressure could be significantly different depending on the relative leak tightness of the three in-line valves (injection check, inboard, and FCV). If the FCV is relatively leak tight, pressure would build-up during the cycling of the inboard valve. All the Units 2 and 3 available as-found leak rate results from 1993 until current for the injection check valve (36 tests) and the inboard injection gate valve (38 tests) were collected to determine the mean leakage (1.15 and 0.29, SCFH respectively) and standard deviation (1.36 and 1.08, respectively). The as-found October 28, 2008, leak rate results for the Unit 1 RHR Loop II injection check valve and the inboard injection gate valve were 13.5 (9 standard deviations above the mean) and 12.46 (11 standard deviations above the mean) SCFH respectively. The leakage rate past the check valve is more than enough to pressurize the volume of 21.2 fl3 (fJ. of

-0.06 fl3) needed to pressurize to reactor pressure) during stroking of the inboard injection valve as long as leakage past the FCV (74-66) is relatively lower. This backpressure will not decrease if leakage past the inboard valve is higher than the FCV afler the inboard valve is closed and the FCV (74-66) is given a signal to open as is done during logic surveillance testing. The leak tightness of the Unit 1 FCV-74-66 valve was demonstrated while troubleshooting the October 23, 2010 separated disc. A pressure gage was placed between the closed inboard injection valve and closed FCV. The FCV was given an open signal and while the stem moved open the pressure decreased well below atmospheric pressure indicating leak tightness. Therefore the backpressure on the Unit 1 74-66 valve had the potential to be significantly higher than that experienced the comparable Unit 2 and 3 valves. The Unit 1 RHR Loop I injection check valve and inboard injection gate valve also exhibited high leakage similar to RHR Loop II. However, based on the results of inspection of the 1-FCV-74-52 valve (i.e., disc and skirt not separated and welds intact), it is concluded that either relative leakage past the outboard valve (1-FCV Page 27 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

52) was high not allowing backpressure to build or the threads on 1-FCV-74-52 were not undersized to the extent found on 1-FCV-74-66.

The 1 FCV-74-66 tack welds between the skirt and disc were not considered to be a contributing cause since they are not credited in the design to handle axial loads. The properly sized threads are designed to handle the full reactor backpressure. However, threads on the other valves have not been validated to be undersized. Inspections of all similar nonconforming valves on Units 1, 2, and 3 have been completed and found to have the discs attached and the welds intact. It should also be noted that no force (other than that resulting from applied backpressure) can stress the undersized threads and the weld to the point of failure and the metallurgical analysis clearly demonstrates that the full length of threads on the 1-FCV-74-66 valve were deformed and fractured due to a force in the pullout direction. A force in the seating direction would simply push the disc further into the body without any stress on the threads and the welds since the threads and welds move with the disc. Excessive force on the backseat would also have a negligible effect on the thread and weld stresses since the stem velocity and associated change in momentum is relatively low.

As discussed in the Crane weak link analysis (Ref. 6), the axial loading comes from testing the 1-FCV-074-67 downstream valve with the 1-FCV-074-66 in the closed position. The corresponding valves in the other loop (Loop I) would be pressurized due to testing the FCV-074-53 valve with the FCV-074-52 valve closed. By removing the FCV-074-67 (and FCV-074-

53) from testing except under refueling conditions when the backpressure does not exist, the axial loading mechanism has been minimized. Additionally, operational constraints have been put in place to limit the backpressure on all remaining valves that have not been modified or returned to design configuration.

In addition, the Unit 2 RHR valves (2-FCV-74-66 and 2-FCV-74-52) have been repaired by applying 8 structural gussets between the skirt and the disc capable of resisting maximum backpressure and rotational forces.

In summary, based on plastic deformation of the threads, the tack welds of 1-FCV-74-66 took the full load resulting from backpressure and failed. The magnitude of the force would fail a full size %" thick weld after the threads plastically deformed. The threads of valve 1-FCV-74-66 were significantly damaged after one event (backpressure applying axial force) and continued to degrade with each subsequent event until failure. The threads were so damaged by the first event that each subsequent event would continue to damage the threads until failure with a much lesser force such as normal unseating. A common cause failure mechanism does did not exist for the following reasons: 1) since the welds are the first to fail, inspection of the tack welds demonstrated that all other valves were not subjected to forces of this magnitude or that the threads are not undersized, 2) relative leakage rates between the injection check, inboard, and flow control (FCV-74-66 or 52) valves played a dominant role in the magnitude of force applied,

3) the FCV-74-66 and 52 valves are normally open and remain open during a design basis event, including shutdown during an Appendix R fire event, and 4) backpressures and corresponding stresses on the threads and welds during a design basis event are well within the capability of undersized threads and welds in the hypothetical event that it is required to open after being closed given the historical leakage record of the other similar valves.

Page 28 of 29 4/13/11 Enclosure 4

Browns Ferry Unit 1 FCV-074-066 RHR Outboard Injection Valve Failure NRC Questions (#2)

8) Was a root cause determination conducted for an event involving failure of the 2-FCV-74-66 valve in December 1974 as reported by Abnormal Occurrence Report BFAO-50-260fl432W? If so what was the results?

TVA Response:

A review of BFN historical data revealed the Abnormal Occurrence Report BFAO 260n432W was documented in Abnormal Occurrence Report (AOR) 2607432W. No cause investigation was documented in the TVA system for this occurrence. A TVA trouble ticket was identified for tack welds being broken and the disc being rotated partially counterclockwise for both the 1-FCV-74-66 valve and 1-FCV-74-52 valve. However, with respect to the AOR and valve 2-FCV-74-66, the AOR indicated that the disc and skirt came unscrewed and separated, with the disc lodged in the seat. Repairs were made per MMI 15.3.1.5-N- 2/8/1975 (Welding Instruction for FCV-74-52 and FCV-74-66 Disc to Disc Skirt). The welding instruction was included in the work procedure (WP3896 R1 - 1977 timeframe) for Engineering Change Notice (ECN) L1473 which installed the V-Notch Disc Trim.

It would have been normal for investigations of this nature to be performed by the Supplier (GE) as an FDDR (Field Deviation Disposition Report) and thus TVA has requested GE to investigate their Design Record Files (DRF). Subsequent to this event ECN L1473 (1975) was initiated for the incorporation of the V-Notch Disc Trim modifications to the FCV-074-052/066 valves correcting rotational issues due to flow induced vibration.

References

1. Westinghouse Report No. STD-MCE-10-198, "Browns Ferry 1 RHR Angle Valve Destructive Evaluation," Westinghouse Proprietary Information, December 2010.

2. Structural Integrity Associates Letter Report 1001572.401 ,"Browns Ferry LPCI Injection Valve Evaluation", Revision 0, January 2011.

3. Structural Integrity Associates Calculation No. 1001572.302, Revision 0, "Weld Fracture Mechanics and Stress Analysis of LPCllnjection Valve (1-FCV-74-66)," February 2011.

4. Structural Integrity Associates Calculation No. 1001572.301, Revision 0, uLPCI Injection Valve (1-FCV-74-66) Thread Static Shear Strength Calculation," February 2011.

5. "Introductory Statistics," N. A. Weiss, 7th Edition, Peason Educacion, 2005.

6. CVNO Report No. SR-128, Revision 2, lISeismic Weak Link Report," Crane Nuclear, Inc.,

August 1995.

Page 29 of 29 4/13/11 Enclosure 4

Attachment 1 BFN Scenario Equipment Availability Results Tables Enclosure 4

SCENARIO 1(250V RMOV BD 1C)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 1 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 2 & 3(480V RMOV BD 1C)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 2 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 8 & 9(AHU Above 4KV SDBD RM)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 7&8 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 10 & 11 (1-XFA-231-TS1A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 9 & 10 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 12&13(RPT 1-BDAA-068-0001-II)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 11 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 24(3-FCV-74-67)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 19 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 26 & 27(480V RMOV BD 3D)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 21 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 28(3-ACU-031-7205)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 22 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 29(RWCU cabinet)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 23 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 30 & 31(3-BDAA-068-0003I)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 24 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 32(0-XFA-266-0THB)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 25 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 33 & 34 (480V RMOV BD 1A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 41 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 35(250V RMOV BD 1A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 42 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 36 & 37 (4KV SD BD A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 43 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 38, 39 & 40 (480V SD BD 1A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 44, UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 45, 46 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 74 & 75 (4160 UNIT BD 1A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 61 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 62 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 76 & 77 (4Kv RECIRC BD 1)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 63 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 64 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 80 & 81 (480V LTG BD 1)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 67 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 68 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 82 (U1 GEN BKR AIR COMPRESSOR 1-CMP-35-460B)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 69 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 83 (480V COMMON BD 2)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 70, 71, UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 72 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 84 (U2 EXCITER CUBICLE)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 73 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 85 & 86 (4160 UNIT BD 2A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 74 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 75 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 87 (4160V UNIT BD 2C)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 76 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 88 (4160V COMMON BD B)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 77 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 90, 91 & 92(480V UNIT BD 2B)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 79, UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 80, 81 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 95 & 96(4KV RECIRC BD 3)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 84 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 85 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 97 & 98(4KV Unit BD 3A)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 104 & 105(480V Common Bd 3)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 93 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 94 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 106 Cable Trays - 480V TB MOV BD 1C DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 95 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 107 & 108(4160V UNIT BD 2B)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 96 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 97 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 109 & 110(480V TMOV BD 2C)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 99, UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 100 B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 111(4KV UNIT BD 3B)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 101 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 112(480V TMOV BD 3C)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 102 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 113A North TB U1 & U2 (Bus Duct)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 103 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 113B North Turbine Building U3 DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 103 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 114A North TB U1 & U2 (Cable Tray)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 104 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 114B North TB U3 (Cable Tray)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 104 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 115A Cable Tunnel Intake DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 106A 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 115B TB Cable Tunnel Tray Horizontal and Vertical DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D 106 &

UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW 106C B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4

SCENARIO 116(Cable Tunnel to XFMR Yard)

DIVISION I DIVISION II DG A DG B DG C DG D 4KV SD BD A 4KV SD BD B 4KV SD BD C 4KV SD BD D DG 3A DG 3B DG 3C DG 3D UNIT 0 4KV SD BD 3EA 4KV SD BD 3EB 105 4KV SD BD 3EC 4KV SD BD 3ED A1 RHRSW C1 RHRSW B1 RHRSW D1 RHRSW A2 RHRSW C2 RHRSW B2 RHRSW D2 RHRSW A3 RHRSW C3 RHRSW B3 RHRSW D3 RHRSW CS 1A CS 1C CS 1B CS 1D RHR 1A LPCI RHR 1C LPCI U1 HPCI RHR 1B LPCI RHR 1D LPCI RHR 1A HX RHR 1C HX RHR 1B HX RHR 1D HX UNIT 1 480V SD BD 1A 480V SD BD 1B 480V RMOV BD 1A U1 RCIC 480V RMOV BD 1B U1 UNIT PREFERRED 480V RMOV BD 1C 250V RMOV BD 1B 250V RMOV BD 1A U1 SRVs U1 DIV I ECCS INV U1 DIV II ECCS INV CS 2A CS 2C CS 2B CS 2D RHR 2A LPCI RHR 2C LPCI U2 HPCI RHR 2B LPCI RHR 2D LPCI RHR 2A HX RHR 2C HX RHR 2B HX RHR 2D HX UNIT 2 480V SD BD 2A 480V SD BD 2B 480V RMOV BD 2A U2 RCIC 480V RMOV BD 2B U2 UNIT PREFERRED 480V RMOV BD 2C 250V RMOV BD 2B 250V RMOV BD 2A U2 SRVs U2 DIV I ECCS INV U2 DIV II ECCS INV CS 3A CS 3C CS 3B CS 3D RHR 3A LPCI RHR 3C LPCI U3 HPCI RHR 3B LPCI RHR 3D LPCI RHR 3A HX RHR3C HX RHR 3B HX RHR 3D HX UNIT 3 480V SD BD 3A 480V SD BD 3B 480V RMOV BD 3A U3 RCIC 480V RMOV BD 3B U3 UNIT PREFERRED 480V RMOV BD 3C 250V RMOV BD 3B 250V RMOV BD 3A U3 SRVs U3 DIV I ECCS INV U3 DIV II ECCS INV Enclosure 4 Wrought Products Technical Data - Stellite 6B (AMS 5894) - Stellite 6K Page 1 of 5 Search GO Home Products & Services Industrial Applications Technical About Deloro Stellite Locations Latest News Contact Us Home Products & Services Wrought Products Technical Data Download Page as PDF Coating Services Components Investment Casting Sand Casting Resin Shell Casting Centrifugal Casting Powder Metallurgy Machinery Wrought Products Wrought Product Certified Mechanical Properties.

Capacities Covers Stellite6B in the form of sheet and plate up to 1 inch thickness and round bar up to 3.5 Is This Process For diameter.

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Wrought Products Minimum Properties of Wrought Stellite 6B Materials Property Value Wrought Products 130 ksi (896 Typical Components Tensile Strength MIN MPa)

Process Demo Yield Strength at 0.2% offset 70 ksi (483 MPa) MIN Wrought Products Elongation in 4D 5% MIN Technical Data Reduction in Area 7% MIN Hardness 33-43 HRC Equipment Hardfacing Alloys Solution Services Industrial Applications Properties Data Technical The properties listed in this booklet are typical or average values based on laboratory tests conducted by the manufacturer. They are indicative only of the results obtained in such tests About Deloro Stellite and should not be considered as guaranteed maximums or minimums. Materials must be Locations tested under actual service conditions to determine their suitability for a particular purpose.

Latest News All data represent the average of four or less tests unless otherwise noted. The secondary Contact Us units (metric) used in this booklet are those of the SI system.

Chemical Composition, Percent Stellite Cobalt Nickel Silicon Iron Manganese Chromium Molybdenum Tungsten Carbon 6B Bal. 3.00* 2.00* 3.00* 2.00* 28.00-32.00 1.50* 3.50-5.50 0.90-1.40 6K Bal. 3.00* 2.00* 3.00* 2.00* 28.00-32.00 1.50* 3.50-5.50 1.40-1.90

• Maximum Average Physical Properties Metric Units British Units Stellite Stellite Physical Properties Temp., degrees C Temp., degrees F 6B 6B 6K 6K Hardness Limits 33-43 RC 40-42* RC 33-43 RC 40-42* RC 22 72 Typical 36-40 RC 43-47 RC 36-40 RC 43-47 RC Density Kg/m3 lb/in.3 22 72 8387 8387 0.303 0.303 Melting Range 1265 to 1354C 2310 to 2470 deg. F microhm-m microhm-m Electrical Resistivity 22 0.91 72 36 watt-cm/sq. cm-deg. C Btu-in/sq.ft.hr.-deg. F 103 Thermal Conductivity 22 72 -

0.147 - (546 ohms per cil. mil. ft.)

x 10-6/m/m.K microinches/in.-deg. F 13.9 7.7 0-100 32-212 13.8 7.7 7.8 0-200 14.1 13.8 32-392 7.7 14.5 8.0 0-300 32-572 13.8 7.7 14.7 8.2 0-400 32-752 13.8 7.7 Mean Coefficient of 15.0 8.3 0-500 32-932 13.8 7.7 Thermal Expansion 0-600 15.3 32-1112 8.5 14.0 7.8 15.8 8.8 0-700 32-1292 14.2 7.9 16.3 9.1 0-800 32-1472 14.5 8.1 16.9 9.4 0-900 32-1 652 14.9 8.3 17.4 9.7 0-1000 32-1832 15.5 8.6 Electrical Conductivity Enclosure 5 http://www.stellite.com/ProductsServices/Components/WroughtProducts/WroughtProduc... 29/01/2011

Wrought Products Technical Data - Stellite 6B (AMS 5894) - Stellite 6K Page 2 of 5 Compared to 22 1.90 72 1.90 Copper, percent - -

J/kg*K Btu/lb-deg. F Room Specific Heat Room 423 0.101 (calculated) - -

Magnetic Permeability at 200 <1.2 <1.2 Oersteds (15.900 22 <1.2 72 <1.2 A/m)

Reflecting Power, 57-70 57-70 percent

• Minimum depending on gauge Average Hot Hardness Test Temp., Brinell Hardness at Temperature, Stellite deg. F Mutual Indentation Method (deg. C) 1000 (538) 226 1200 (649) 203 6B 1400 (760) 167 1600 (871) 102 Average Compressive Strength Average Compressive Stellite Form Test Temp. Strength Ksi (MPa) 6B 1/2-in. (12.7 mm), Plate 1 Room 347 (2392) 6K Sheet 1 Room 325 (2241)

Average Modulus of Rupture Average Modulus of Stellite Form Test Temp. Rupture Ksi (MPa) 6B Sheet 1 Room 338 (2360)

Average Modulus of Elasticity Average Modulus of Elasticity Stellite Form Test Temp.

psi x 106 (MPa) 6B Sheet 1 Room 30.4 (210,000) 6B 5/8-in. (15.9 mm), Bar Room 31.1 (214,000)

Average Izod Impact Strength (un-notched)

Average Izod Impact Strength (un-Stellite Form Test Temp. notched) ft.

lbs. J 1/2-in (12.7 mm),

6B Room 62 84 Plate 1 Average Charpy Impact Strength Test Temp., Average Charpy Impact Strength, ft.

deg. F (deg. C) lbs. (J)

Stellite Type of Test Longitudinal Transverse Un-notched 72 (98) 65 (88)

Room notched 6 (8) -

1000 (538) Un-notched 81 (110) -

6B notched 15 (20) -

1/2-in. (12.7 mm), Plate 1 Un-notched 116 (157) -

1250 (677) notched 15 (20) -

Un-notched 126 (171) -

1500 (816) notched 15 (20) -

1 Solution heat-treated at 2250 deg. F (1232 deg. C), air cooled Average Room Temperature Data - Stellite 6B Ultimate Yield Strength Tensile at 0.2%

Strength, Elongation in 2 in. Hardness, FORM Condition offset Ksi (MPa) 50.8 mm, percent Rockwell C Ksi (MPa)

Sheet, Solution Heat-0.040 in. (1.0 145.0 (1000)a 90.1 (621)a 12a 36a treated*

mm), thick Sheet, Solution Heat-0.065 in. (1.7 140.8 (971)a 86.7 (598)a 11a 36a treated*

mm), thick Sheet, Solution Heat-Enclosure 5 http://www.stellite.com/ProductsServices/Components/WroughtProducts/WroughtProduc... 29/01/2011

Wrought Products Technical Data - Stellite 6B (AMS 5894) - Stellite 6K Page 3 of 5 0.125 in. (3.2 treated*

144.7 (998)a 89.8 (619)a 11a 37a mm), thick Sheet, Solution Heat-0.187 in. (4.8 144.5 (996)a 89.3 (616)a 10a 37a treated*

mm), thick Solution heat-treated at 2250 deg. F (1232 deg. C), air cooled a Average of 27-31 tests Average Tensile Data 1 Ultimate Tensile Yield Strength Test Temp.,

Strength at 0.2% offset, Elongation in 2 in.

Stellite Form deg. F (deg. 50.8 mm, percent Ksi (MPa) Ksi (MPa)

C)

Room 146.0 (1007) 91.6 (632) 11 1500 (816) 73.9 (509) 45.4 (313) 17 0.063 in. (1.6 1600 (871) 55.8 (385) 39.2 (270) 18 mm),

Sheet 1800 (982) 32.6 (225) 19.8 (137) 36 2000 (1093) 19.5 (134) 10.9 (75) 44 2100 (1149) 13.3 (92) 7.7 (53) 22 Room 148.0 (1020) 88.0 (607) 7 6B 1/2 in. (12.7 mm), 1000 (538) 133.0 (917) 58.5 (403) 9 Plate 1250 (677) 115.0 (793) 60.6 (418) 9 Room 154.1 (1063) 92.6 (638) 17*

600 (316) 147.8 (1019) 74.5 (514) 30*

5/8 in. (15.9 mm), 1000 (538) 129.1 (890) 67.3 (464) 28*

Bar 1500 (816) 75.4 (520) 46.5 (321) 28 1600 (871) 58.3 (402) 37.9 (261) 34*

Room 176.5 (1217) 102.7 (708) 4 1200 (649) 146.0 (1007) - - 8 0.063 in. (1.6 6K 1500 (816) 70.2 (484) 44.5 (307) 17 mm),

Sheet 1800 (982) 34.1 (235) 19.3 (133) 28 2000 (1093) 17.4 (120) 8.6 (59) 53 1 Solution heat-treated at 2250 deg. F (1232 deg. C), air cooled.

• Elongation, percent in 1 in. (25.4 mm).

Average Cavitation-Erosion Data Alloy Test Duration, hrs. Weight loss, mg.

Stellite 6B 100 42.3 Type 304 Stainless Steel 7 39.9 Average Abrasive Wear Data Volume Loss, Hardness, Wear Alloy Condition mm3 Rockwell Coefficient1 Stellite 6B Mill annealed 8.2 C-38 0.471 x 10-3 Stellite 6K Mill annealed 13.3 C-46 0.946 x 10-3 Stellite 25 Mill annealed 53.0 C-24 2.00 x 10-3 1 hr. at 1600 deg.

F (871 deg. C) 1090 Steel water quenched + 37.2 C-55 8.00 x 10-3 4 min, at 900 deg.

F (482 deg. C)

Type 316 Stainless Steel As received sheet 81.4 B-86 2.0 x 10-3 Type 304 Stainless Steel As received sheet 102.1 B-92 3.00 x 1 0-3 Average Adhesive Wear Data*

Alloy Condition Ring Alloy Volume Loss, Wear mm3 Coefficient1 Stellite 6B Mill annealed 4620 Steel 0.293 3.70 x 10-5 Stellite 6K Mill annealed 4620 Steel 0.561 8.73 x 10-5 Stellite 25 Mill annealed 4620 Steel 0.285 2.50 x 10-5 1 hr. at 1600 deg.

F (871 deg. C) 1090 Steel water quenched + 4620 Steel 0.293 6.00 x 10-5 4 min, at 900 deg.

F (482 deg. C)

Average Coefficients Of Static Friction For Some Common Materials Material Against Stellite 6B Cast Iron Bronze Aluminium Lead Stellite 6B 0.119 0.123 0.125 0.138 0.119 Cast Iron 0.123 0.199 0.245 0.213 0.225 Enclosure 5 http://www.stellite.com/ProductsServices/Components/WroughtProducts/WroughtProduc... 29/01/2011

Wrought Products Technical Data - Stellite 6B (AMS 5894) - Stellite 6K Page 4 of 5 Bronze 0.125 0.245 0.231 0.257 0.249 Aluminium 0.138 0.213 0.257 0.213 0.328 Lead 0.119 0.225 0.249 0.328 0.290 Coefficient represents tangent of angle of repose. Tests made on dry surface having better than 120 grit finishes. All values based on averages and are to be used comparatively and not as absolute values.

• Average of two or more tests against a case-hardened SAE 4620 steel ring (Rockwell C-63).

1 The wear coefficient (K) was calculated using the equation where V = Wear volume (mm3)

P = Load (kg)

L = Sliding distance (mm) h = Diamond pyramid hardness A combination of a low wear coefficient and a high hardness is desirable for good wear resistance.

Average Corrosion Data - Stellite 6B*

Concentration, Test Temp., Average Penetration Rate per Media percent by Weight deg F (deg. C) Year**

mils mm Acetic Acid 10 Boiling 0.08 0.002 Acetic Acid 30 Boiling 0.04 0.001 Acetic Acid 50 Boiling 0.02 <0.001 Acetic Acid 70 Boiling 0.06 <0.002 Acetic Acid 99 Boiling 0.03 <0.001 Chromic Acid 10 150 (66) 95 2.41 Formic Acid 10 Boiling 20 0.51 Formic Acid 30 Boiling 26 0.66 Formic Acid 50 Boiling 47 1.19 Formic Acid 70 Boiling 50 1.27 Formic Acid 88 Boiling 23 0.58 Hydrochloric Acid 2 Room 0.1 <0.003 Hydrochloric Acid 5 Room 63 1.60 Hydrochloric Acid 10 Room 108 2.74 Hydrochloric Acid 20 Room 93 2.36 Hydrochloric Acid 2 150 (66) 0.1 <0.003 Hydrochloric Acid 5 150 (66) >1000 >25.4 Hydrochloric Acid 10 150 (66) >1000 >25.4 Hydrochloric Acid 20 150 (66) >1000 >25.4 Nitric Acid 10 Boiling 0.15 <0.004 Nitric Acid 30 Boiling 6 0.15 Nitric Acid 50 Boiling >1000 >25.4 Nitric Acid 70 Boiling >1000 >25.4 Phosphoric Acid 10 Boiling Nil Nil Phosphoric Acid 30 Boiling 2 0.05 Phosphoric Acid 50 Boiling 19 0.48 Phosphoric Acid 70 Boiling 23 0.58 Phosphoric Acid 85 Boiling 611 15.5 Sodium Hydroxide 30 Boiling 13 0.33 Sulfuric Acid 10 Room 0.02 <0.001 Sulfuric Acid 30 Room Nil Nil Sulfuric Acid 50 Room 0.4 0.01 Sulfuric Acid 77 Room 0.7 0.02 Sulfuric Acid 10 150 (66) 0.02 <0.001 Sulfuric Acid 30 150 (66) 0.09 <0.003 Sulfuric Acid 50 150 (66) >1000 >25.4 Sulfuric Acid 77 150 (66) 176 4.5 Sulfuric Acid 2 Boiling 31 0.79 Sulfuric Acid 5 Boiling 91 2.31 Sulfuric Acid 10 Boiling 157 3.99 Sulfuric Acid 20 Boiling 360 9.14 Sulfuric Acid 50 Boiling >1000 >25.4 Sulfuric Acid 30 Boiling >1000 >25.4 Sulfuric Acid 77 Boiling >1000 >25.4 Ferric Chloride 10 Room 13 0.33***

(10 days without crevice)

Ferric Chloride 10 Room 9** 0.23***

(10 days with crevice bolt)

Ferric Chloride + 5 Room 18 0.46***

Sodium Chloride (10 days) 10 Potassium Permanganate + 2 194 (90) 8 0 .20 sodium Chloride (120 hrs) 2

• Determined in laboratory tests. It is recommended that samples be tested under actual plant conditions.

• • Corrosion rates for all duplicate samples based on an average of 4-24 hour test periods.

• • • Samples pitted during test.

Average Stress Rupture and Creep Data Initial Time in hours Elongation Test Temp., Stress Elongation, for total Elongation, % at Rupture, Stellite deg. F (deg. Ksi Life, hrs. of:

percent percent C) (MPa) 0.5 1.0 2.0 1000 (538) 60 (414) 0.70 192.81 - - - 0.8 1200 (649) 50 (345) 0.45 361.4 0.5 113.8 - 3.0 6B 1400 (760) 35 (241) 0.35 59.3 0.4 3.8 16.3 5.1 0.063 in. (1.6 1500 (816) 25 (172) 0.35 70.6 0.2 4.3 19.9 4.7 mm), 1600 (871) 19 (131) 0.10 57.9 0.5 2.2 11.1 4.3 Sheet2 1700 (927) 12 (83) 0.19 104.0 1.8 20.9 89.9 2.6 1800 (982) 8 (55) 0.05 113.4 5.1 22.7 57.6 5.5 2000 (1093) 2 (14) 0.004 116.7 4.4 - - 13.3 1 Test discontinued before rupture.

2 Specimens were solution heat-treated at 2250 deg. F (1232 deg. C) and air cooled prior to testing.

Enclosure 5 http://www.stellite.com/ProductsServices/Components/WroughtProducts/WroughtProduc... 29/01/2011

Wrought Products Technical Data - Stellite 6B (AMS 5894) - Stellite 6K Page 5 of 5 Fusion Welding Stellite 6B (AMS 5894) and Stellite 6K can be welded by gas tungsten-arc (TIG) with an argon flow of 25 CFH, gas metal-arc (MIG), shielded metal-arc (coated electrode), and oxy-acetylene in this order of preference. The oxy-acetylene method should be used with discretion and care in that Stellite will boil during welding which may cause porosity. Use a 3x reducing flame to minimize oxidation, penetration, and inter-alloying.

Stellite 6B (AMS 5894) and Stellite 6K should be preheated and maintained at 1000°F (35 8°C) to prevent cracking during welding and then still air cooled.

Fixturing which would chill the weld rapidly should not be used. Standard weld joints are recommended. Inconel 82, 92, or 625 filler metals are recommended for joining Stellite 6B (AMS 5894) to softer materials such as carbon steel or stainless steel, while the harder cobalt- base filler metals such as Stellite 6 and Stellite 21 are recommended for joining Stellite 6B (AMS 5894) to itself, especially if wear resistance is required in the weld areas. In the latter case, Inconel 82, 92, or 625 may be used for root passes and then be overlayed with the harder materials. Gas shielding of the root side of the gas tungsten-arc weldments is not mandatory but is recommended in order to improve weld penetration.

Adequate ventilation is required to control exposure to airborne dust, fumes, and particulate when machining, grinding or welding Stellite alloys. MSDS sheets are available.

Brazing Stellite 6B (AMS 5894) and Stellite 6K are readily joined to other materials by brazing. All forms of surface dirt such as paint, ink, oil, chemical residues, etc.,

must be removed from the mating parts by etching, solvent scrubbing, degreasing, or other means. In addition, fluxing will be required during torch brazing operations when using silver brazing filler metal to help clean the joint and allow the filler metal to flow more freely over the mating surfaces. Brush joining areas generously with brazing flux prior to heating. When torch or induction brazing, as soon as the brazing filler metal melts, the source of heat should be removed and the parts positioned. The assembly should then be pressed together to squeeze out the excess flux and still air cooled. The parts should not be quenched.

Other brazing filler metals (i.e., gold, palladium, or nickel-based alloys) are satisfactory for joining Stellite 6B (AMS 5894) and Stellite 6K. Brazing filler metal selection depends on the service conditions expected.

A close fit of the mating surfaces is recommended. The finished joints will have greater strength if the filler metal is very thin, generally 0.001 - 0.005 (0.03 -

0.13 mm) thick.

Brazing with high-temperature filler materials is generally performed in a furnace. Induction and resistance heating with salt-bath and metal-bath dip brazing have limited application. Vacuum furnaces held at less than one micron pressure or controlled atmosphere furnaces, having adequate moisture control at brazing temperatures (less than 60° F ( 15°C) dew point), produce the most satisfactory results. Controlled atmospheres such as hydrogen or cracked ammonia are suitable for brazing Stellite 6B (AMS 5894) and Stellite 6K base materials.

Home Products & Services Industrial Applications Technical About Deloro Stellite Locations Latest News Contact Us Sitemap Privacy Policy Terms of Use Contact Stellite Feedback Employee Login Administration Copyright 2011 Deloro Stellite Group Enclosure 5 http://www.stellite.com/ProductsServices/Components/WroughtProducts/WroughtProduc... 29/01/2011 Analysis Print 04/11/2011 1:57:27 PM Valve ID 1FCV7452 Test Desc. TSS 1.0 OCO 1-FCV-74-52 UNSEATING 250 200 150 100 50 0

-2.0 -1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 55.31 A 0.8600 Sec TSS 1.0 OCO 10/06/2006 6:49:23 AM S:\...\1FCV7452\S2.NOR Enclosure 5

Analysis Print 04/11/2011 2:00:33 PM Valve ID 1FCV7452 Test Desc. AFFS/LS 1-FCV-74-52 UNSEATING s4 100 75 50 25 0

-2.0 -1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 41.29 A 0.8720 Sec AFFS/LS 11/16/2008 10:21:31 AM S:\...\1FCV7452\S4.NOR Enclosure 5

Analysis Print 11/18/2010 1:34:56 PM Valve ID 1FCV7466 1-FCV-74-52 UNSEATING EVENT 80 60 40 20

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 4 -------- Ia RMS 43.56 A 0.8280 Sec AL/FS/Part/@6024/TSS1 11/01/2010 1:35:59 AM S:\...\1FCV7452\C5.NOR Enclosure 5

Analysis Print 11/18/2010 11:41:26 AM Valve ID 1FCV7466 1-FCV-74-66 UNSEATING 100 75 50 25 0

-2.0 -1.0 0 1.0 2.0 3.0 4.0 Trace Signal Name Value at Cursor Test Title Test Date NOR File 1 -------- Ia RMS 0.02 A 0.0000 Sec AF TSS 2 OCO 10/09/2006 6:39:15 AM S:\...\1FCV7466\C2.NOR Enclosure 5

Analysis Print 11/18/2010 1:38:17 PM Valve ID 1FCV7466 1-FCV-74-66 UNSEATING EVENT 2008 60 40 20 0

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 2 -------- Ia RMS 30.76 A 1.0910 Sec affs 10/31/2008 11:08:44 AM S:\...\1FCV7466\C4.NOR Enclosure 5

Analysis Print 11/18/2010 1:41:15 PM Valve ID 1FCV7466 Test Desc. ALFS/TSS1.0625 1-FCV-74-66 UNSEATING EVENT 2010 0

-100000

-200000

-300000

-400000 40 35 30 25 32.75 33.00 33.25 33.50 33.75 34.00 34.25 34.50 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 ETT Thrust 4606 lbs 33.4070 Sec ALFS/TSS1.0625 11/12/2010 11:08:31 PM S:\...\1FCV7466\S6.NOR 2 Ia RMS 31.99 A 33.4070 Sec ALFS/TSS1.0625 11/12/2010 11:08:31 PM S:\...\1FCV7466\S6.NOR Enclosure 5

Analysis Print 04/11/2011 2:50:42 PM Valve ID 2FCV7452 Test Desc. ALLS/TSS3#2 2-FCV-74-52 UNSEATING 100 75 50 25 0

-2.0 -1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 51.01 A 1.0540 Sec ALLS/TSS3#2 03/03/2007 11:33:46 AM S:\...\2FCV7452\S21.NOR Enclosure 5

Analysis Print 11/18/2010 1:35:33 PM Valve ID 1FCV7466 2-FCV-74-52 UNSEATING EVENT 80 60 40 20

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 5 -------- Ia RMS 52.67 A 1.0500 Sec AF/ALFS LS 05/25/2009 3:13:54 PM S:\...\2FCV7452\C25.NOR Enclosure 5

Analysis Print 11/18/2010 1:36:07 PM Valve ID 1FCV7466 2-FCV-74-66 UNSEATING EVENT 80 60 40 20

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 6 -------- Ia RMS 53.43 A 0.7890 Sec AL SPRING PACK 03/30/2007 9:41:45 AM S:\...\2FCV7466\C14.NOR Enclosure 5

Analysis Print 04/11/2011 2:03:19 PM Valve ID 2FCV7466 Test Desc. ALFS/BS 2-FCV-74-66 UNSEATING 60 40 20 0

-1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 52.80 A 0.8030 Sec ALFS/BS 05/11/2009 2:36:33 PM S:\...\2FCV7466\S15.NOR Enclosure 5

Analysis Print 04/11/2011 2:07:35 PM Valve ID 3FCV7452 Test Desc.

3-FCV-74-52 UNSEATING 100 75 50 25 0

-1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 49.07 A 1.2310 Sec 03/06/2006 10:04:10 PM S:\...\3FCV7452\S8.NOR Enclosure 5

Analysis Print 04/11/2011 2:09:08 PM Valve ID 3FCV7452 Test Desc. affs ls 3-FCV-74-52 UNSEATING 100 75 50 25 0

-1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 52.64 A 1.2340 Sec affs ls 04/16/2008 11:03:30 AM S:\...\3FCV7452\S10.NOR Enclosure 5

Analysis Print 11/18/2010 1:32:55 PM Valve ID 1FCV7466 3-FCV-74-52 UNSEATING EVENT 80 60 40 20 0

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 7 -------- Ia RMS 48.00 A 0.7970 Sec ALFS #3 03/10/2010 10:42:37 PM S:\...\3FCV7452\C16.NOR Enclosure 5

Analysis Print 04/11/2011 2:10:41 PM Valve ID 3FCV7466 Test Desc. affs/ls 3-FCV-74-66 UNSEATING 60 50 40 30 20 10 0

-1.0 0 1.0 2.0 3.0 4.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 37.28 A 1.1330 Sec affs/ls 03/14/2006 12:45:47 PM S:\...\3FCV7466\S7.NOR Enclosure 5

Analysis Print 04/11/2011 2:12:02 PM Valve ID 3FCV7466 Test Desc. AF @MCC 3-FCV-74-66 UNSEATING 50 40 30 20 10 0

-1.0 0 1.0 2.0 3.0 4.0 5.0 Graph Signal Name Value at Cursor Test Title Test Date NOR File 1 Ia RMS 34.81 A 1.1650 Sec AF @MCC 03/24/2008 11:32:03 AM S:\...\3FCV7466\S9.NOR Enclosure 5

Analysis Print 11/18/2010 1:36:43 PM Valve ID 1FCV7466 3-FCV-74-66 UNSEATING EVENT 80 60 40 20

-0.25 0 0.25 0.50 0.75 1.00 1.25 1.50 1.75 Trace Signal Name Value at Cursor Test Title Test Date NOR File 8 -------- Ia RMS 52.91 A 1.0910 Sec AL PARTIAL @ VLV 03/22/2010 4:59:33 AM S:\...\3FCV7466\C14.NOR Enclosure 5 BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011

1. The seat on Browns Ferry Nuclear Plant (BFN) valve 1-FCV-74-66 was refurbished during the BFN Unit 1 restart efforts. When were the seats of the other FCV-74-52/66 valves refurbished?

TVA Response:

The information related to valve seat refurbishment is as follows:

Valve # Seat refurbishment/clean Work order #

date 1-FCV-74-52 06/08/2006 Seat cleaned, polished and blue checked under WO 03-005591-010 (Page 118).

1-FCV-74-66 09/06/2006 Seat cleaned, polished and blue checked under WO 03004964-000 (Page 90) 2-FCV-74-52 No seat refurbishment No record of refurbishment since 1995 after 1995 2-FCV-74-66 No seat refurbishment No record of refurbishment since 1998 after 1998 3-FCV-74-52 No seat refurbishment No record of refurbishment since 1998.

after 1998 3-FCV-74-66 5/12/95 Seat cleaned, polished and blue checked under WO94002626-000 (page 26).

This table was developed based on the review of all maintenance records on these valves since 1995.

2. The Structural Integrity report appears to indicate that the disc skirt may have become partially unscrewed and then the threads pulled out (fatigue and ductile overload were potential failure mechanisms). Explain why were the undersized welds on 1-FCV-74-66 not considered to be critical contributors to the failure.

TVA Response:

For BFN valve 1-FCV-74-66, the stem was replaced by WO 03-004964-000 in 2006 and required the disassembly of the valve internals. The tack welds associated with the disc/disc skirt connection of 1-FCV-74-66 were replaced and QC verified the new welds during this process. An excerpt from WO 03-004964-000 is provided in Attachment 1.

The original vendor drawings for the FCV-74-52/66 valves do not specify tack weld size.

During Unit 1 restart when the stem was replaced and the tack welds needed to be installed, guidance was absent on the weld size. The applicable TVA drawing 0-A-12337-M-1E was modified by DCN 51199 S2 for Unit 1 only. PIC #67379 (dated 6/10/06) was generated for a field change to add guidance for the tack weld for valve 1-FCV-74-66 on the design drawing A-12337-M-1E and approved on 6/12/06. The Unit 3 drawing (A-12337-M-3A) contained tack weld sizes which states Field replacement of disc to be attached to disc skirt with four tack welds - 1/2 fillet weld, 1/2 long, 90 degrees apart, or two 7 long (MIN) 9 long (MAX) welds, 180 degrees apart. The PIC requested that this Unit 3 guidance be added to the Unit 1 drawing.

1 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 The final drawing change which also added in a fillet size to the 7 to 9 weld wording (contrary to the PIC request) was completed 9/09/06. However, in recent discussion with Crane Nuclear, they stated that the tack welds are only for anti-rotation and that they are only concerned with ensuring weld fusion to prevent rotation since the tack welds are not considered to be load bearing.

The weld data sheet (performed 6/23/06) associated with WO 03-004964-000 indicated the length requirement (7 to 9 inches long) of each tack weld and that the two welds be 180 degrees apart, which is typical for tack welds. The QC inspector verified (dated 6/25/06) that the requirements on the weld data sheet were satisfied. QC appropriately sign-off on the welds because the 1/2 fillet guidance had not yet been added to the drawing.

Therefore, our review design requirements associated with the tack weld thickness has determined that the 1-FCV-074-66 valve tack welds did not have a thickness requirement when these welds were applied in 2006. The Root Cause Analysis report will be revised to reflect this additional information.

The Structural Integrity report (provided in Attachment 2) states with respect to these tack welds, It is noteworthy that the design purpose of fillet welds such as these is generally not to provide additional axial load support, but rather as locking devices to keep the threaded joint from unscrewing. Crane Nuclear indicated that the differential rotation forces between the skirt and the disc to be small (e.g., the unpinned skirt would tend to rotate with the disc) and as long as there is some weld fusion resisting high cycle rotational fatigue the size of the weld is not important. The metallurgical results (References 1 and 2) indicate that there was sufficient fusion to serve the function adequately as a tack weld to prevent rotation.

Crane Nuclear also noted that all loading is transmitted through the disc and disc skirt thread connection. Appropriately, the design did not consider axial stress because the weld cannot be stressed by axial loading with proper preloading of threads within manufacturers size tolerance and because of the large difference between the stiffness of the full sized threads and the weld. Undersized threads would significantly, if not altogether, reduce the preload and stiffness of the threads subjecting the weld to axial loading. Crane Nuclear further stated that the weld failure by axial forces would begin at the ends of the weld and propagate which is consistent with the results of the analysis performed by Southwest Research.

After the failure of valve 1-FCV-74-66, Southwest Research was retained to perform an on-site evaluation of the overall condition of the disc skirt paying particular attention to the broken tack welds and to make replicas of the fracture surface. Analysis of the replicas from the usable portions of the fracture surface indicated features consistent with fatigue (striations) and ductile tensile overload (dimpling). These features are fully consistent with initiation and initial propagation of the fracture along and across the weld cross-section due to fatigue with final failure occurring due to tensile overload (axial loading). Given the predominate crack propagation direction of the welds as discussed in the Southwest Research report (Reference 2), it is reasonable to conclude that the welds failed by axial overload or axial fatigue as discussed on page 10 of the report and evidenced in Figures 10, 29, 30 and 32.

2 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 Weld separation Weld separation from from axial fatigue axial overload Figure 10 Dimples shown in Figure 29 are a strong indication that the failure caused in this area was caused by overload.

3 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 Figure 30 clearly indicates fatigue striation. The clearly establishes cyclic loading and fracture progression across the fracture surface consistent with loading in the axial direction.

4 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 Figure 32 shows the locations where failure modes were identified in the replicas. In the areas where axial fatigue modes were identified as the failure mode, an arrow with a blue outline and a light-yellow fill is shown on the fracture surface. These arrows also show the propagation directions which are consistent with Crane Nuclear statement that the axial failure would start at the weld endpoint and propagate along the weld cross section. Where axial overload was the failure mode, a labeled arrow points to the location on the fracture surface.

Due to the difficulties of obtaining replicate samples, laboratory analysis of replicates, and uncertainties of the field analysis, it was decided that further metallurgical evaluations were necessary in order to provide more detailed analysis of the failure. Therefore, the assembly (upper portion of the angle valve including the stainless steel stem and cast steel skirt) was shipped to the Westinghouse Materials Center for destructive examination.

The resulting Westinghouse report (Reference 1) determined that the threads were undersized and showed mechanical damage starting with the first thread. Further detailed analysis indicated significant plastic deformation (beaking) of the threads beginning on the second thread (refer to Figure 3.10). With respect to question of the disc skirt becoming partially unscrewed, the formation of beaks is inconsistent with the threads unscrewing.

5 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 BOTTOM Damaging Motion Beaking Damage TOP Figure 3.10 Optical Comparator Image of Damaged Threads (Location Not Specified)

The beaking is more pronounced at 290 degrees and 20 degrees which agree with the asymmetrical loading model for the undersized threads. This is further corroborated by the evidence of flattened thread crests predominately at 110 degrees, where insufficient or limited contact does not allow for a sufficient force to be applied to create plastic deformation (beaking). Additionally, because of the asymmetric loading, no damage is visible at 200 degrees, indicating little to no contact with the threads in this location. The Structural Integrity analysis (Attachment 2) also showed that the threads are subject to significant axial forces under axial loads, consistent with the observations of severe damage (beaking) in some threads in the Westinghouse metallurgical report (Reference 1).

6 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 At the completion of the metallurgical examinations by both Southwest Research and Westinghouse, an independent metallurgical review (Reference 3) was conducted by a Burns and Roe metallurgist. This review concluded that the Westinghouse examination of the skirt threads showed primarily two types of damage. One form was a phenomenon which is referred to as "beaking" whereby deformation of the thread tips is aligned in the direction opposite of the applied load. This type damage was the predominant mechanism observed and is associated with pullout by an axial load rather than unscrewing. It was also noted that beaking was not observed around the entire circumference of the threads which indicates some type of asymmetrical loading. The second form of damage observed was flattened thread crests.

Finally, the Burns and Roe metallurgist concluded the combined metallurgical analyses provided evidence which suggest that the valve skirt to disc tack weld failed as a result of fatigue and tensile overload due to axial loading. The metallurgist also concluded that damage to the skirt threads resulting from undersizing shows that stem disengagement from the disc most likely occurred as a result of pullout after the weld failure rather than unscrewing. Although porosity and other anomalies were observed in the weld region, the metallurgist did not believe they were major contributors to the weld failure. The metallurgist also stated that a review of design documentation shows that proper procedures were employed for making the weld, and skill of the craft was the most likely cause for these anomalies.

Based on discussions with Crane Nuclear, the size of the tack weld whether 0.2or 0.5, makes no difference for axial loading as they are not intended to be load bearing. All loading is transmitted through the disc and disc skirt thread connection. The welds are strictly for anti-rotation and as long as there is fusion to some degree, combined with the v-notch trim, the anti-rotation design requirements are met. Crane Nuclear also stated that the 0.5 weld was significantly heavier than they would typically recommend and there had been no other design features associated with these valves, updated since the v-notch trim addition. The v-notch trim effectively eliminates the flow-induced vibration causing rotational loads.

With respect to non-axial fatigue failure of the welds, no evidence of high cycle fatigue, which would be indicative of flow induced vibration during operation (and the potential for the disc skirt to have become unscrewed), was found to be present in any of the metallurgical examinations (References 1, 2, and 3).

In addition, since the skirt is free to rotate on the stem (because no key is installed on the stem), there is no force that would cause relative rotation between the disc and skirt.

Rotation of the disc is limited by the v-notch trim settling in the flow stream. This is further substantiated by damage on the first thread and the beginning of beaking on the second thread. Additionally, based on discussions with Crane Nuclear, pre-load on the thread is only hand tight, and with the undersized threads minimum contact and asymmetrical loading can be expected. The threads that are damaged, but not beaked, are indicative of minimum contact bending the tips, while not producing enough stress at the crest to cause beaking.

7 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 BOTTOM Damage TOP Close-up Macrograph of Skirt Threads, Showing Thread Damage, 12 Threads per Inch Spacing (0 Degree View)

Although the tack welds are not designed as a load bearing feature, more weld metal would improve the axial load carrying capability of the disc skirt connection. The Structural Integrity report (Reference 4) did not reduce the capability of the 0.2 weld based on the porosity and de-lamination discussed in the Westinghouse report. The Structural Integrity report only considered the load that a 0.2 weld would be able to support in the event of the undersized threads. The threads are the axial load bearing component. As such, Structural Integrity did not consider the porosity and de-lamination of the welds. The Burns and Role independent metallurgist also evaluated the porosity and de-lamination of the welds and considered them to not be contributors to weld failure (Reference 3). The Structural Integrity report (Reference 4) stated that even a perfect 0.5 fillet weld would not be capable of withstanding the design backpressure when thread contact is reduced by undersized threads or plastically deformed threads (as it was in the case of the 1-FCV-74-66 failure).

From a structural design standpoint, a fillet weld has an inherent flaw at the root of the weld 8

4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 which provides a stress riser for fatigue initiation when subjected to axial loading. This further supports why a tack weld is not considered for structural support.

Based on the variability in the load carrying capability of undersized threads and the variability associated with backpressure buildup, it is reasonably possible that the combination of 0.5 weld and undersized threads could resist higher axial loads than a 0.2 weld with undersized threads, although it is calculated to fail well below design backpressure. TVA reported that this additional work was in progress in a previous response. As a result of this possibility, Structural Integrity recently performed elastic-plastic analyses. These analyses and additional information are provided in Attachment 2. With respect to differences between valve 1-FCV-74-66 and the other FCV-74-52/66 valves, based on the review of Structural Integrity analyses and information, it is concluded that the difference is most likely due to some combination of the following variables.

• Differential pressure across the valve disc. The relative leak-tightness of the valves of the inboard (reactor pressure vessel) and outboard (residual heat removal system) side of FCV-74-52/66 valves during surveillance testing determines the magnitude of differential pressure the associated valve disc experiences. Since the leakage rate through large valves can vary, the actual pressure differential can also vary significantly from valve to valve.

• The condition of the disc threads. Variation in disc thread diameter due to manufacturing tolerances has a direct influence on the amount of thread engagement and the load required to cause failure.

• The extent of any asymmetries. As the asymmetry between mating threads increases, a lower force would be expected to thread damage and failure.

The results of these analyses further support the conclusions provided previously in response to this question.

Based on the above information, it is concluded that the tack welds of the disc/disc skirt connection of valve 1-FCV-74-66 failed due to axial loading causing fatigue or overload.

Failure of the weld was directly related to the undersized threads. There was no thickness requirement for the tack welds installed in 2006, and the tack welds fully met their design function of preventing rotation. Therefore the tack welds were not a design or performance deficiency. If the condition of undersized threads on valve 1-FCV-74-66 had been eliminated prior to the valve failure, the anti-rotation tack welds would not have failed.

Independent analysis by Structural Integrity clearly demonstrates that even a 0.5 fillet size would fail under axial loads resulting from design backpressure conditions (Reference 4).

The tack welds on 1-FCV-74-66 are clearly not the cause of the failure and therefore are not considered to be critical contributors to the valve failure.

3. For the refurbishment of 1-FCV-74-66 in 2006, were there any Quality Control (QC) hold points for the tack welds in the associated Work Order or the weld traveler?

TVA Response:

For BFN valve 1-FCV-74-66, the stem was replaced by WO 03-004964-000 in 2006 and required the disassembly of the valve internals. The tack welds associated with the 9

4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 disc/disc skirt connection of 1-FCV-74-66 were replaced and QC verified the new welds during this process. An excerpt from WO 03-004964-000 is provided in Attachment 1.

The original vendor drawings for the FCV-74-52/66 valves do not specify tack weld size.

During Unit 1 restart when the stem was replaced and the tack welds needed to be installed, guidance was absent on the weld size. The applicable TVA drawing 0-A-12337-M-1E was modified by DCN 51199 S2 for Unit 1 only. PIC #67379 (dated 6/10/06) was generated for a field change to add guidance for the tack weld for valve 1-FCV-74-66 on the design drawing A-12337-M-1E and approved on 6/12/06. The Unit 3 drawing (A-12337-M-3A) contained tack weld sizes which states Field replacement of disc to be attached to disc skirt with four tack welds - 1/2 fillet weld, 1/2 long, 90 degrees apart, or two 7 long (MIN) 9 long (MAX) welds, 180 degrees apart. The PIC requested that this Unit 3 guidance be added to the Unit 1 drawing.

The final drawing change which also added in a fillet size to the 7 to 9 weld wording (contrary to the PIC request) was completed 9/09/06. However, in recent discussion with Crane Nuclear, they stated that the tack welds are only for anti-rotation and that they are only concerned with ensuring weld fusion to prevent rotation since the tack welds are not considered to be load bearing.

The weld data sheet (performed 6/23/06) associated with WO 03-004964-000 indicated the length requirement (7 to 9 inches long) of each tack weld and that the two welds be 180 degrees apart, which is typical for tack welds. The QC inspector verified (dated 6/25/06) that the requirements on the weld data sheet were satisfied. QC appropriately sign-off on the welds because the 1/2 fillet guidance had not yet been added to the drawing.

Therefore, our review design requirements associated with the tack weld thickness has determined that the 1-FCV-074-66 valve tack welds did not have a thickness requirement when these welds were applied in 2006. The Root Cause Analysis report will be revised to reflect this additional information.

4. Discuss the effect of a negative dp, e.g., reactor pressure greater than the RHR shutoff head, across the valve disc and then increasing over time on the coefficient of friction (and the resulting impact on valve opening time) determined by the mock-up testing, since a positive dp across the valve disc (as existed during the mock-up testing) would not exist prior to the reactor pressure reaching the pressure associated with the RHR shutoff head.

TVA Response:

Vibration reduces the coefficient of friction (COF) independent of pressure differential across the disc. The factors causing friction reduction by vibration are 1) superposition of the inertia force due to vibration acceleration on the friction force, 2) leveling or cancellation of alternate friction force due to the change in frictional directions, 3) increase of relative sliding velocity (kinematic affect), 4) surface flattening due to the progress of wear, and 5) material softening from the heat due to friction. Forces on the disc from differential pressure do not affect any of the above factors as long as the force does not cause the disc to move, in which case the disc would be liberated from the body. The assumed total closing thrust load from the motor actuator is greater than the load applied by the pressure differential associated with total normal operating reactor pressure (1030 psig). This thrust load approaches a limiting sudden load of twice the gradually applied load after approximately 10 4/21/11 Enclosure 6

BFN 1-FCV-74-66 Valve Failure NRC Follow-up Questions - April 18, 2011 four strokes. Differential pressure with the high side being downstream (reactor side) is gradually applied as the inboard valve is opened. Since the pressure differential is gradually applied and less than the normal motor operator thrust it is not expected to further lodge the disc into the seat. Even if the differential pressure was assumed to be suddenly applied it would have a negligible effect on the deflection of the disc into the valve body since the deflection is approaching its limit after already being impacted by the actual maximum of 13 times (i.e., strokes) by a higher stem force. Therefore, the disc will release as soon as the differential pressure across the disc gets high enough to overcome the product of the body strain normal force caused by seating and the reduced COF. In other words the change in COF is independent of the differential pressure and the time to release the disc is when the differential pressure force exceeds the remaining frictional force. Applying a constant differential pressure for a period of time will have the same effect as applying a forcing function starting with a negative differential pressure and ending with a positive differential pressure of the same value for the same period of time. The reactor pressure is expected to be ~200 psia (see Attachment 3) with a containment pressure of 16.5 psia after the RHR pump is running for 7.5 minutes (P = 372 + 16.5 - 200 = 188 psi). The resulting differential pressure is well within the mock-up limiting differential pressure of 100 psi based on a reduction in the COF of 27.3% within 7 minutes.

5. Provide any documentation for the root cause and corrective action taken in response to the 1974 event discussed in Abnormal Occurrence Report BFAO-50-260/7432W.

TVA Response:

No additional information, from that provided in response to NRC Round 3 Question 8 dated 4/13/11, is available at this time. TVA is continuing to research this issue.

References

1. Westinghouse Report No. STD-MCE-10-198, Browns Ferry 1 RHR Angle Valve Destructive Evaluation.

2. Southwest Research Institute Project 18.18074.11.101, On-Site Evaluation of Browns Ferry 1 FCV-74-066 RHR Disc Skirt.

3. Burns and Roe Enterprises, Inc., Metallurgical Failure Analysis of Browns Ferry Nuclear Plant - Unit 1 Residual Heat Removal Valve 1-FCV-74-066.

4. SI Calculation No. 1001572.302, Revision 0, Weld Fracture Mechanics and Stress Analysis of LPCI Injection Valve (1-FCV-74-66).

11 4/21/11 Enclosure 6

Attachment 1 QC Report on 1-FCV-074-66 Weld Inspection Enclosure 6 Attachment 2 Structural Integrity Associates Elastic-Plastic Stress Analysis of LPCI Injection Valve (1-FCV-74-66)

Enclosure 6

Additional Considerations Regarding Browns Ferry LPCI Injection Valve Failure April 19, 2011 This document summarizes additional analyses and discussion regarding the failure of LPCI injection valve 1FCV7466 at Browns Ferry Nuclear Unit 1 (BFN1). It attempts to address a number of questions regarding our earlier analyses and report [1, 2, 3] and poses additional theories regarding the cause of the failure. Overall conclusions of the study are:

1. The predicted pullout load of the threaded joint was significantly smaller than that of the as designed joint due to undersized thread conditions.

2. Pullout of the threaded joint was clearly possible at the opening thrust load predicted to occur in a test condition in which the valve is opened against essentially reactor pressure on the back side of the disc (429 kips).

3. The tack welds were installed to prevent unscrewing of the threaded joint, and offered little additional resistance to pullout of the threaded joint.

4. The metallurgical failure analysis of the skirt threads showed evidence of asymmetric loading of the threaded joint, which is consistent with the excess clearance created by the undersized thread conditions. Such asymmetry would further reduce the pullout loads relative to those predicted by the axisymmetric analyses discussed herein.

Thread Pullout Calculation Our earlier calculation [1] utilized the minimum measured major skirt diameter of 6.311 in order to derive a conservative, lower bound pullout load, and thus the maximum possible effect of the undersized thread condition. (See Figure 1) The actual skirt diameter measurements, as reported in [4]

were:

Enclosure 6

The thread pullout calculations of [1] were thus repeated under a number of assumptions regarding thread diameters and engagement length [6], the results of which are summarized in Table 1 below.

Figure 1 - Illustration of Thread Undersize Condition with Minimum Measured Skirt Diameter Enclosure 6

Table 1 - Summary of Revised Thread Pullout Calculations from [6]

Knmax Esmin Dsmin Dsave ATS Shear n Le (in) F (kips)

(in) (in) (in) (in) (in2) Strength (ksi)

AsDesigned Thread 6.3097 16.839 884.056 AsFound Thread with Min Major Dia. of 6.2630 7.168 376.313 Skirt (using Eq. 2)

AsFound Thread with 1.500 Min Major Dia. of 6.311 5.974 313.611 Skirt (using Eq. 3)

AsFound Thread with Ave Major Dia. of 6.331 9.999 524.952 Skirt (using Eq. 3) 12 6.300 52.50 AsFound Thread with Ave Major Dia. of Skirt and Designed 1.922 6.331 12.812 672.638 Thread Engagement Length (using Eq. 3)

AsFound Thread with Ave Major Dia. of Skirt and Estimated 1.172 6.334(1) 8.364 439.090 Thread Engagement Length (using Eq. 3)

It is seen from this table that a range of pullout loads is predicted, ranging from the predicted load for the asdesigned thread (884 kips) down to the conservatively low value of 314 kips predicted previously

[1]. If the average measured skirt major diameter is used over the entire thread engagement length, the pullout load is 525 kips. If a reduced engagement length is assumed, the predicted pullout load is 439 kips.

A noteworthy uncertainty in the above calculations is the minor diameter assumed for the disc threads.

A value of 6.3 was provided by TVA, but there were no asbuilt measurements taken, and a design drawing was not available indicating what the tolerances were on this dimension. Bickfords book on Design and Behavior of Bolted Joints [5] states: If the bolt is undersized or the nut oversized, thread Enclosure 6

contact areas will be less than those planned by the designer, and substantial deformation may occur.

The metallurgical failure analysis report [4] identified substantial deformation in many of the skirt threads from the failed valve, consistent with an undersized skirt thread (bolt) and/or oversized disc thread (nut). Two types of deformation were observed as summarized in Figure 2 and Table 2 below.

Figure 2 Optical Comparator Image of Damaged Threads (Fig. 310 from [4])

Beaking damage consisted of deformation in which part of the threads were extruded towards the bottom of the skirt, which is consistent with the skirt being pulled out of the disc by an overload in the upward direction. A second form of damage was manifested as flat thread peaks, which is consistent with very small thread contact such that the skirt could pull through the disc threads without major (beaking) deformation. Also observed in [4]: Some threads had no apparent damage. The mixed damage forms suggest that the threads were probably not unscrewed but rather were removed by an asymmetrical force or were the result of an inconsistent mating surface in the base.

Given the observed thread damage, and the fact that the skirt was evidently separated from the disc with little or no damage to some threads, it is considered highly likely that there was minimal thread engagement and that the pullout loads were on the lower end of the range presented in Table 1 above.

Enclosure 6

Table 2 - Reported Extent of Thread Damage from [4]

ElasticPlastic Analysis To shed further light on the above study, elasticplastic calculations were performed [7] using the axisymmetric model developed in [2], but modifying the thread sizes to the averages of the measured thread diameters rather than the minimum. The model and thread diameters used are summarized in Figure 3. Two elasticplastic cases were run. In Case 1, the larger diameter 6.334 (top 14) threads engaged first, followed by engagement of the 6.322 (bottom 8) threads once sufficient deformation occurred. In Case 2, the bottom eight threads were assumed to not engage, which would be consistent with slightly oversized disc threads and little or no damage to those threads during pullout. This was judged to be a reasonably conservative approximation in the axisymmetric model, based on the relative damage reported in Table 2. The results of the two analyses are presented in Figure 4, in the form of load versus displacement curves of the skirt relative to the disc.

Enclosure 6

Contact Elements Between Threads Skirt Major Diameter = 6.334 Skirt Major Diameter = 6.322 Figure 1: Elastic-Plastic FEM Details Enclosure 6

Average Axial Displacement of Skirt 500,000 450,000 400,000 350,000 Applied Force (lbs) 300,000 250,000 Case 2 200,000 Case 1 150,000 100,000 50,000 0

0.000 0.002 0.004 0.006 0.008 0.010 0.012 Displacement (in)

Figure 4 - Results of ElasticPlastic Analysis It is seen from this figure that the two cases track identically up to a load of ~300 kips, at which point, the threads have undergone ~0.005 inches displacement. At that point, in Case 1, the remaining bottom threads engage, and the joint is able to sustain additional load up to the max load applied to the model, 430 kips. In Case 2, on the other hand, the bottom threads dont engage, and the curve flattens out at a maximum load of ~360 kips (the analyses failed to converge beyond that point, indicative of a limit load failure or pullout). In summary, the elasticplastic analysis [7] yielded similar results to the previously discussed thread pullout calculation. Depending on the thread diameters and engagement length assumed, pullout failure of the joint is predicted at loads on the order of 350 to 500 kips, well short of the load capacity of the asdesigned joint (884 kips). The analysis also showed that the threads are subject to significant plastic deformation under these loads, consistent with the observations of severe damage (beaking) in some threads in the metallurgical report [4]. Also note, from Table 2, that the beaking is more prevalent in the top threads, and at certain azimuths (especially 290 degrees). This is consistent with the above assumption of upper thread only engagement in Case 2, and also indicative that the thread engagement was not perfectly concentric.

Enclosure 6

Effect of Fillet Welds The above elasticplastic analyses [7] do not include the effect of the fillet welds on the pullout load. It is noteworthy that the design purpose of fillet welds such as these is generally not to provide additional axial load support, but rather as locking devices to keep the threaded joint from unscrewing.

Prior elastic analyses [2] considered the effect of the welds, and predicted that the weld would share a small portion of the loading in the elastic regime (25% weld versus 75% threads). Elastic stresses in the welds were as listed in Table 3 below, depending on the weld size and whether the threads are assumed to be engaged or not. It was also noted that the weld picked up maximum load at a thread displacement of 0.005 inches. Given the amount of plastic displacement of the threads predicted in Figure 4, the threads would be expected to pick up maximum stress under either Case 1 or Case 2, and that either weld size would likely fail under the opening thrust load with full reactor back pressure (429 kips).

Table 3 - Calculated Weld Stresses at 314 kips [4]

Thread Membrane Engagement Stress (ksi) 0.5 inch No 53.88 weld Yes 13.36 0.2 inch No 122.55 weld Yes 29.92 Asymmetric Loading Effects It appears likely from the nature of the thread damage in Table 2 that the loads were not applied in a concentric fashion around the threaded joint. One axis (200°) showed no thread damage over the entire length of the threads, while another (290°) exhibited severe damage (beaking) in the top ten or so threads, plus minor damage to all threads. Bickford [5] comments that If the threads on either (bolt or nut) are slightly out of round, they will not be fully engaged during a portion of each turn. . . . These problems may cause significant loss of strength in the threads. The undersized skirt threads (and possible oversized disc threads) create significant clearance (slop) in the threaded joint. If, for example, the joint was assembled and preloaded in a horizontal position, then the disc threads would be offset due to gravity towards the side that was down during assembly, which would result in asymmetric thread engagement. The likely consequence of such asymmetry would be further reduction in pullout loads relative to the predictions of our axisymmetric analyses. Such a condition would be consistent with the observations, in Table 2 above, of significantly different thread damage in different azimuths.

Enclosure 6

Variables that contribute to the likelihood of failure The following variables are sources of uncertainty in the estimated force required to result in a separation of the valve skirt and disc. The actual value of these variables is unknown, which makes it difficult to predict their exact contribution to the failure of 1FCV7466.

Differential pressure across the valve disc. The relative leaktightness of the LPCI valves on the inboard (RPV) and outboard (RHR) sides of valve 1FCV7466 during surveillance testing will determine the magnitude of the differential pressure the valve disc experiences. Since the leakage rate through large valves lacks a high degree of repeatability, the actual pressure differential can also vary significantly from valve to valve.

The condition of the disc threads. Variation in the disc thread diameter due to manufacturing tolerances will have a direct influence on the amount of thread engagement and the load required to cause failure.

The extent of any asymmetries. As the asymmetry between mating threads increases, a lower force would be expected to cause thread damage and failure.

Since only 1FCV7466 failed and skirt threads from a spare component compared closely to the failed skirt, a reasonable conclusion is that the difference is most likely due to some combination of the variables listed above.

References

1. SI Calculation No. 1001572.301, Revision 0, LPCI Injection Valve (1FCV7466) Thread Static Shear Strength Calculation.

2. SI Calculation No. 1001572.302, Revision 0, Weld Fracture Mechanics and Stress Analysis of LPCI Injection Valve (1FCV7466)

3. SI Letter Report 1001572.401, Revision 0, BFN Valve Failure Evaluation

4. Westinghouse Report No. STDMCE10198, Browns Ferry 1 RHR Angle Valve Destructive Evaluation, Westinghouse Proprietary Information, SI File No. 1001572.206P

5. J. H. Bickford, An Introduction to the Design and Behavior of Bolted Joints, 3rd Edition, Taylor

& Francis Group, 1995.

6. SI Calculation No. 1001572.301, Revision 1A, LPCI Injection Valve (1FCV7466) Thread Static Shear Strength Calculation.

7. SI Calculation No. 1001572.304, Revision A, ElasticPlastic Stress Analysis of LPCI Injection Valve (1FCV7466).

Enclosure 6

Attachment 3 Browns Ferry Nuclear Plant Appendix R Depressurization Curve Enclosure 6

1500 Core Temperature (F) 1400 1300 RV Pressure (psia) 1200 1100 1000 Depressurization at 20 minutes 900 800 700 600 500 Injection at 30 minutes 400 RV press <140 psia WW pres. > 16.5 300 RV pressure below the shutoff head of the RHR pump at 25 minutes 200 RHR Pump running for 7.5 minutes 100 0.00E+00 1.00E01 2.00E01 3.00E01 4.00E01 5.00E01 6.00E01 Time (hours)

Enclosure 6

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1

1. Could the 1-FCV-74-66 valve disc rotate relative to the skirt based on the tack weld condition at the time of discovery?

TVA Response:

1-FCV-74-66 failure occurred due to an axial pull out instead of a torsional failure. This is identified by the weld segments left on the disc and disc skirt. The remaining weld segments condition at the time of discovery are not consistent with a rotational event, because any significant rotation would have knocked them off. Typically the valve disk and disc skirt are snug tight prior to welding as discussed in the General Electric Field Deviation Instruction (see the attachment). The thread dimensions according to drawing C-12337 3A are 6 3/8 -12 NS-3, which is a pitch of 12 threads per inch which is what was observed, which means in one rotation the linear movement of the skirt away from the disc is 1/12 inch, or 0.08333. Based on the height and orientation of the protruding portions of weld left on the skirt and disc (greater than 1/12), the protruding weld segments would act as a stop to the rotational motion of the skirt versus the disc. The locations of these protruding weld segments would prevent even one full rotation of the skirt away from the disc. See the pictures below. Therefore, the valve disc could not have rotated relative to the skirt based on the condition of the tack weld at the time of discovery.

DISC WELD WELD View from top of 1-FCV-74-66 with extraction device installed Page 1 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1 Weld separation from axial overload Weld separation from axial fatigue Figure 10 from Southwest Research Report DISC SKIRT WELD Thread side of skirt with protruding weld Page 2 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1 DISC WELD WELD Top of disc WELD Protrusions WELD Protrusions Bottom of skirt with stem installed Page 3 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1

2. Why did the station not recognize the disc to stem separation during venting in November 2008?

TVA Response:

(Note: TVA recognizes that the response to Question #23 (dated April 5, 2011) in the Round 1 questions and responses did not include sufficient detail. A similar request (Question #1) was included in the Round 3 set of questions from the NRC dated April 7, 2011. TVA provided a response dated April 14, 2011. The original version of the response below was provided to and discussed with the NRC on April 25, 2011. As a result of that discussion and in order to provide completeness and historical clarity, TVA has revised the April 25th response to include elements of the April 14th response and address the deficiencies in the April 5th response.)

It was not reasonable for plant personnel to recognize disc to stem separation on the 1-FCV-74-66 valve during venting in November 2008. This conclusion is supported by the following discussion.

Technical Specification (TS) surveillance requirement SR 3.5.1.1 states, Verify, for each ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve. Because there were no high point vents on the RHR Loops, the procedural guidance in place in 2008 called for venting from the 1-FCV-74-52 body vent for Loop I and 1-FCV-74-66 body vent for Loop II. Venting was performed monthly per procedure 1/2/3-SR-3.5.1.1 (RHR I and RHR II) to ensure that the lines were full of water in accordance with the requirements specified in SR 3.5.1.1 and SR 3.5.2.2 (water hammer prevention). The TS requirement and its implementing procedure were not intended to detect a separated disc. Each valve body vent consists of a horizontal 1/2 diameter line directly off the top of the valve body (~4 down from the pressure seal), an elbow down, and two vertically oriented globe vent valves configured lower than the vent line off the valve body. The vent valves have internal seat orifices ~1/4 wide when the valves are fully open.

Unit 1 at BFN was in lay-up condition for several years prior to restart, and the vent lines were not refurbished or tested as a part of restart. Therefore, each line was susceptible to clogging by debris both before and during flow through the line.

Venting of Loop I was attempted on October 3, 2008 and Loop II on November 11, 2008.

Successful venting would entail a large quantity of water with a relatively steady flow rate.

This venting was unsuccessful on both Loop I and Loop II. For example, during the venting of Loop II, a small amount (approximately two cups) of water was collected with a gradually diminishing flow rate, both of which were symptoms of line blockage; therefore, the vent line was assumed to be plugged. Depending on the amount, size, and type of restriction the observed flow of liquid from blockage can appear similar to depressurizing an enclosed volume (e.g., volume between the inboard and outboard valves). The restricted flow of liquid through the vent pipe as a result of blockage can be so small that the pipe does not fill completely, and the gradually fills until liquid flows out of the end of the pipe similar to depressurizing an enclosed volume. Additional debris can then dislodge and build up in the pipe, causing complete blockage, also similar to depressurizing an enclosed volume.

Page 4 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1 Work Order (WO) 08-723810-000 was initiated to perform the necessary maintenance to clear the Loop II vent line. WO 08-723810-000 throttled 1-FCV-74-66 to a mid-travel position and attempted to vent to verify there was no flow blockage in the bonnet (caused by change in position of the disc skirt) with the valve in the full open position. This attempt to vent was unsuccessful, so it was assumed the blockage was in the vent line/vent valves.

Since WO 08-723810-000 had no further instructions that could be conducted, Problem Evaluation Report (PER) 156971 was written to specifically create actions necessary address the insufficient venting of the bonnet vent lines. The PER response created WO 08-723813-000 which was written to perform troubleshooting and venting of the line, or to replace the valve and line to re-establish the vent path if troubleshooting was unsuccessful.

In the interim, an alternate methodology (ultrasonic testing) was used to meet the TS requirements. Functional Evaluation (FE) 42924 and FE 43012 provided the technical justification for the non-conforming condition associated with venting and required a revision to 1-SR-3.5.1.1 (RHR I and RHR II) to perform ultrasonic testing monthly until such a time as these obstructions were cleared via WO 08-723813-000. The revised procedure was successfully performed.

At that time there was no reason to assume that the disc for valve 1-FCV-72-66 had separated from the skirt/stem because flow was established through the valve three days later. In addition, the disc was later found to be not separated from the disc skirt on valve 1-FCV-74-52, even though it exhibited the same unsuccessful venting symptoms as valve 1-FCV-72-66.

In order to reduce dose to workers as low as reasonably achievable, the vent lines including vent valves were replaced with new prefabricated assemblies in 2010 under WO 08-723813-000. Further examination was not considered necessary at the time since the obstructed vent lines were replaced. This WO was tied to PER 156971. With the completion of the activities of the WO, all corrective actions have been completed and are either closed or in waiting for approval status. PER corrective action 156971-002 states This condition was corrected by the completion of WO 08-723813-000 during the U1R8 RFO.

In summary, it was not reasonable to expect station personnel to make a correlation between the lack of vent capability and the separation of the disc and skirt on valve 1-FCV-74-66 because:

• The venting configuration was highly susceptible to blockage;

• Attempted venting on Loop I failed one month prior;

• Vented water quantity and flow rate were characteristic of blockage;

• 1-FCV-74-66 passed flow three days later when loop II was successfully placed in shutdown cooling; and

• The disc was not later found to be separated from the skirt/stem on valve 1-FCV-74-52, even though it exhibited the same unsuccessful venting symptoms as valve 1-FCV 66.

Page 5 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1

3. Why were the threads not recognized as contributing to the disc to stem separation that occurred in 1974?

TVA Response:

The 1974 event involving Browns Ferry Nuclear Plant (BFN) Unit 2 valve 2-FCV-74-66 was determined to be a rotational event with separation of the disc and skirt clearly caused by unscrewing from the skirt threads due to broken tack welds (note that the V-Notch Disc Trim had not yet been installed on any of the FCV 52/66 valves), and not a pull-out event (i.e., caused by undersized threads) that was discovered in October 2010. It was also noted that partial unscrewing existed on two other valves (i.e., BFN Unit 1 valves 1-FCV-74-66 and 1-FCV-74-52). In none of the cases was there any notation of visible damage to the threads. The Tennessee Valley Authority Abnormal Occurrence Report (AOR BFA0 260/7432W), which reported this event to the NRC stated the following.

The valve was disassembled and the disc found separated from the stem. The disc was removed from the valve body and seating surfaces were visually inspected; the mating threads on the disc and disc guide were cleaned, inspected, and found satisfactory. The tack welds preventing rotation of the disc on the disk guide were found broken, and all parts were cleaned and inspected. Repair was made by cutting a weld bevel on the disc guide, reassembling the disc and guide, and applying a larger, stronger retaining weld to prevent separation of the parts.

The valve was reassembled and functionally tested satisfactorily.

Valves in similar positions on both units 1 and 2 will be disassembled and inspected, and an additional weld will be added to the disc and guide during unit outages when conditions permit.

During cleaning and inspection of the 2-FCV-74-66 mating threads of the disc and disc guide (i.e., disc skirt) in 1974, if vertical damage (axial pullout) of the threads had existed, it would have been observed. During the visual inspections of the 1-FCV-74-66 mating threads of the disc and disc skirt in October 2010, thread damage was easily observed ,

which was subsequently confirmed by the metallurgical examination conducted at Westinghouse.

In 1974, it would have been normal for investigations of this nature to be performed by the Supplier (GE) as an FDDR (Field Deviation Disposition Report) and thus TVA has requested GE to investigate their Design Record Files (DRF). Subsequent to this event Engineering Change Notice (ECN) L1473 (1975) was initiated for the incorporation of the V-Notch Disc Trim modifications to the FCV-74-52/66 valves correcting rotational issues due to flow induced vibration.

Recent investigations found General Electric (GE) Field Deviation Instruction (FDI) 190 dated December 26, 1977 (see the attachment), which in response to the AOR, established additional requirements for the tack weld. The GE FDI stated Entire length of both flatted areas should be welded with a generous weld. Note that no weld thickness specification was provided. TVA fully complied with this vendor recommendation by completion of a 7 to Page 6 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1 9 weld along the flatted surface. The GE FDI 190 requirement was later implemented through TVA Mechanical Maintenance Instruction 15.3.5.1.N, RHR Angle Valve FCV-74-52 FCV-74-66 Disassembly, Repair, Reassembly, and Testing Unit 1, 2, and 3.

Page 7 of 8 4/26/11 Enclosure 7

NRC 1-FCV-74-66 Questions from BFN Site Meeting 4/22/11 Revision 1 Attachment GE FDI 190 Page 8 of 8 4/26/11 Enclosure 7 BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 Question 1. - Provide the basis for why 1-FCV-74-66 is not part of the GL 89-10 program.

TVA Response:

Regulatory Requirements All MOVs in safety-related piping systems were considered to be within the scope of Generic Letter (GL) 89-10. However, MOVs that were not required to change positions during design basis events or in plant emergency procedures could be eliminated from the GL 89-10 program per Supplement 1 to GL 89-10. In addition, GL 89-10 originally required the inclusion of passive-position changeable valves where the MOV was not blocked to prevent inadvertent operation; however, Supplement 4 to GL 89-10 eliminated this requirement for BWRs. Therefore, it is permissible to exclude from the GL 89-10 program an MOV that is not required to change positions during design basis events or in plant emergency procedures. This position was accepted by the NRC in its letter dated March 18, 1997 as described below.

Discussion In a letter from T. E. Abney to the NRC dated January 6, 1997 (Attachment 1), TVA provided a response to the NRC letter dated October 7, 1996 (Attachment 2) for re-evaluation of the safety functions of certain MOVs removed from, or not included in, the BFN GL 89-10 program. In of the January 6, 1997 letter, Page E1-10 of the submitted letter, both FCV-74-52 and FCV-74-66 were identified as not required by plant procedures to operate the RHR system in the suppression pool cooling mode. Therefore, these valves have no redundant safety function and will not be included in the GL 89-10 program. Both the 1-FCV- 74-52 and 1-FCV-74-66 valves have a safety function to remain in the open position to support LPCI injection.

They are required to be open and remain open during normal plant operation. Therefore, they are classified as Passive MOVs by the MOV Program and are not included in the BFN GL 89-10 MOV Program.

In a letter from NRC to TVA dated March 18, 1997 (Attachment 3), NRC stated that the changes committed to in Mr. Abneys January 6, 1997 letter (Attachment 1) are considered adequate to address our (NRCs) concerns on this subject (reduced scope of valves in GL 89-10 Program). Accordingly, the NRC accepted TVAs justification for excluding the FCV-74-52 and FCV-74-66 valves for the BFN GL 89-10 program.

In addition, TVA has previously stated that the disc to stem separation occurred in 2008 and the valve passed flow in March 2009. Further independent testing was conducted by Performance Improvement International and concluded that the valve was capable of passing flow with the stem to disc separation.

Question 2. - Provide WO package and all supporting information that documents the partial MOVATs performed in 2006 and 2008 for 1-FCV-74-66.

TVA Response:

The following WO packages are applicable and were provided by BFN Licensing to the NRC.

WO #04-716746 was performed in 2006 (Attachment 4)

WO 2008-714852-000 was performed in 2008 (Attachment 5)

Page 1 of 16 Revision 1 - 07/07/11 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 Question 3. - Explain why the 3-FCV-74-52 and the 1-FCV-74-52 valve unseating forces are not consistent from test to test.

TVA Response:

Table A5.1 (Attachment 6) of the Root Cause Analysis (RCA) report provides a qualitative assessment of whether unseating is visible from the partial MOVATs data. Tabular results for 3-FCV-74-52 show that unseating was visible for some tests and not visible for other tests. The inconsistency in qualitative unseating results for 3-FCV-74-52 was explained in the TVA response to question 6 in our March 31, 2011 submittal as variation in disc-to-seat COF. Table A5.1, however, does not show inconsistent unseating results for 1-FCV-74-52.

Question 4. - Provide the actual unseating forces for 1-FCV-74-52 in 2008 and 2010.

Provide the actual unseating forces for the other valves as well.

TVA Response:

Prior to the discovery of the 1-FCV-74-66 stem-disc separation event in October, 2010, direct stem thrust measurements were not taken for the six RHR outboard LPCI angle globe valves (FCV-74-52, FCV-74-66) since they were not in the BFN GL 89-10 program as discussed in response to Question 1 above. However, the partial MOVATS data that we did take does not allow for the determination of actual unseating forces. Data acquired consisted of motor current, and, more recently, spring pack displacement. Although spring pack displacement is proportional to drive sleeve torque, the spring pack displacement was not calibrated and only approximate torque values can be obtained using Limitorque generic spring pack curves. In addition, only loading events that exceed the spring pack preload can be seen. As was shown in the figure (shown below) for Question 7 in our response dated March 31, 2011, the first open valve stroke loading event seen in the spring pack displacement represents the actuator hammerblow. A second loading event approximately 0.75 seconds later would be an indication of unseating, but only if unseating exceeds the spring pack preload.

Therefore, based on the information provided above, we are unable to provide the actual unseating forces. Quantification of unseating forces will not be possible until direct stem thrust measurements are obtained beginning at the next RFO on each unit.

Page 2 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 Question 5. - Provide the date when the WO was initiated and date when the WO was worked to address the plugged bonnet vents for 1-FCV-74-52 and -66 (Thierry provided WO 08-723813-000 as a reference).

TVA Response:

The plugged bonnet vents were described in PER 156971 dated 11/11/2008 and Work Order (WO) 08-723813-000 was initiated as the PER response to address the condition by replacing the vent valves. TVA concluded that these bonnet vents were in fact plugged based on recurrent and recent experience with similar vents that were confirmed to be plugged with foreign material. WO 08-723813-000 was signed off completed and accepted by Operations on 11/19/2010.

As discussed in response to question 2 of the NRC questions dated 4/22/11 an alternate methodology (ultrasonic testing) was used to meet the Technical Specification (TS) surveillance requirement SR 3.5.1.1 which states, Verify, for each ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve. Functional Evaluation (FE) 42924 and FE 43012 provided the technical justification for the non-conforming condition associated with the apparently plugged vent and required a revision to procedure 1-SR-3.5.1.1 (RHR I and RHR II) to perform ultrasonic testing monthly until such a time as these vent obstructions were cleared via WO 08-723813-000. The revised procedure was successfully performed.

Question 6 - MOVATs data traces provided depicts a date of October 31, 2008 while the RCA states the MOVATs data was obtained in November 2008. Was data taken both in Oct and Nov or should the RCA state Oct?

Page 3 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 TVA Response:

The data was taken only once on October 31, 2008. Table A5.1 of the Root Cause Analysis will be updated to indicate that the correct date is October 31, 2008.

Question 7. - Provide the 2010 MOVATs data taken for 1-FCV-74-66 after the valve was repaired.

TVA Response:

The 2010 MOVATS data taken for 1-FCV-74-66 after the repair are provided below and are also attached in the Root Cause Analysis.

NOTE: The X denotes the unseating of the valve disc.

Page 4 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 Question 8. - Provide the program document for the GL 89-10 program.

TVAs Response:

The program document (NETP-115) was provided by BFN Licensing to the NRC on 07/01/2011.

It is also attached to this response (Attachment 7).

Question 9. - PER 271338 RCA rev 1 Attachment 7 specifies that 1-SR-3.5.1.6 and 1-SR-3.3.5.1.6 document instances when the 1-FCV-74-66 was known to have been stroked by date performed. These SRs perform flow test and logic functional test. 1-SR-3.6.1.3.5 and 1-SR-3.3.3.1.4 would be the correct SRs that would have required stroking the valve.

Is the data in the table for valve stroke history incorrect or are the wrong SRs referenced?

TVA Response:

Valve 1-FCV-74-66 is stroked during execution of the following surveillance procedures:

Procedure Steps where 1-FCV-74-66 is stroked 1-SR-3.5.1.6 (RHR II) Quarterly Frequency Not stroked.

1-SR-3.3.5.1.6 (C II) 2-year Frequency 7.2 [20]: Close 7.2 [28]: Open 7.2 [35]: Close 7.2 [38]: Open 7.2 [40]: Close 7.2 [43]: Open 7.2 [46]: Close 7.2 [61]: Open 7.6 [1]: Close 7.6 [20]: Open 1-SR-3.6.1.3.5 (RHR II) Quarterly Frequency 7.2 [1]: Close 7.2 [2]: Open 7.2 [4.1]: Close 7.2 [4.2]: Open 7.2 [5]: Possible stroke if not in original position 1-SR-3.3.3.1.4 (H II) 2 year frequency 7.2 [4]: Close 7.2 [8]: Open 7.2 [10]: Close 7.2 [14]: Possible stroke if not in original position Therefore, the reference in Attachment 7 of the RCA to 1-SR-3.5.1.6 (RHR II) is incorrect since it does not have procedure steps that specify the stroking of 1-FCV-74-66. The reference to procedure 1-SR-3.3.5.1.6 (C II) is correct. In addition, procedures 1-SR-3.6.1.3.5 (RHR II), and 1-SR-3.3.3.1.4 (H II) also have procedure steps that specify the stroking of 1-FCV-74-66.

Therefore, the wrong SR procedures are referenced in the RCA and the data in the RCA table for the valve stroke history is incorrect. However, we estimate that the total number of valve strokes will close to that given in table A5.1 of Attachment 7 of the RCA. Therefore, the conclusions in Page 5 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 the RCA should remain valid. This attachment will be revised to include the correct surveillance procedure references and the revised stroke count.

Question 10. - Provide a copy of the entire procedure of ECI-0-000-MOV09 r20 and EPI 000-MOV001 r48. (Parts of these procedures were in the WOs and they want to see the whole procedure.)

TVA Response:

Procedures ECI-0-000-MOV09 r20 (Attachment 8) and EPI-0-000-MOV001 r48 (Attachment 9) are attached and were previously provided by BFN Licensing.

Question 11. - What is requiring the 2 year frequency for the partial MOVATs? Are they scheduled PMs?

TVA Response:

1-FCV-74-66 was maintained by the Preventive Maintenance (PM) Program. The PM program called for a partial MOVATS every 2-years for this valve, which was scheduled to be consistent with a refueling outage cycle basis for equipment reliability reasons.

Question 12. - If this valve were in the GL 89-10 program would the frequency change; would you be doing more work on the same frequency?

TVA Response:

If the 1-FCV-74-66 valve was in the BFN GL 89-10 program, a baseline for performance would be established on a once per refueling outage basis until a performance trend was established.

Once the baseline was established then the frequency would be set in accordance with the MOV program (NETP 115, Attachment 7). If this valve was incorporated into the MOV program, a full MOVATS test instead of the partial MOVATS test would be performed on the frequency set in accordance with the MOV program.

Page 6 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 1 Page 7 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 2 Page 8 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 3 Page 9 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 4 Page 10 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 5 Page 11 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 6 Page 12 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 Page 13 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 7 Page 14 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 8 Page 15 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - June 29, 2011 ATTACHMENT 9 Page 16 of 16 Enclosure 8

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 1 - Provide a copy of the PER from a few years ago on EOIs (i.e., related to using the 74-66 valve in the EOIs).

TVA Response:

TVA has been unable to locate any PERs associated with using the 74-66 valve in the EOIs.

However, the following information is provided regarding the identification of motor-operated valves (MOVs) in the Emergency Operating Instructions (EOIs).

The Updated Final Safety Analysis Report, TVA Design Criteria and EOIs have been reviewed to determine the safety-related function/position of FCV-74-52 and FCV-74-66. This review concluded that FCV-74-52 and FCV-74-66 are normally open and must remain open to perform their safety-related function of allowing injection water to enter the reactor vessel. This conclusion is consistent with the scoping review performed for the NRC Generic Letter 89-10 Program (see 6Jan1997 Letter to NRC and 18Mar1997 Letter from the NRC) that also determined FCV-74-52 and FCV-74-66 are not required to close or throttle injection flow during a Design Basis Accident (DBA). Further, some other utilities have removed valves equivalent to FCV-74-52 and FCV-74-66 from the GL 89-10 program at similarly designed plants.

The process used to identify valves that are required to be in the GL 89-10 program included a review of the EOIs; however, consistent with the rest of the industry, not all MOVs included in the EOIs are in the GL 89-10 program. This is because the EOIs consider additional equipment failures and accident scenarios that could require an MOV to have a function beyond those credited in the safety analysis. FCV-74-52 and FCV-74-66 have throttling and closure capability and the EOIs rely on this capability for controlling injection flow or other functions, but these capabilities are not required or credited in the safety analysis for mitigating DBAs, and; therefore, this supports TVAs conclusion that they are not required to be in the GL 89-10 Program.

Question 2 - Clarify/change 2009 to 2008 on answer to Question 1 dated 6/29/11.

TVA Response:

Corrected in revision 1 and sent to Browns Ferry Nuclear Plant (BFN) Licensing 7/7/2011. Also corrected the steps in Question 9 of 1-SR-3.3.5.1.6 (C II) 2-year Frequency to additional stroke performance in step 7.2[10] and 7.2[14] in revision 2. (Attachment 1)

Question 3 - When was full MOVATS done on valves during the restart of Unit 1, e.g., 74-67 and 74-53.

TVA Response:

The full MOVATS test was performed on valve 74-67 during the restart of Unit 1 on 9/16/2006.

The full MOVATS test was performed on valve74-53 during the restart of Unit 1 on 10/2/2006.

Full MOVATS testing was not performed on the 74-52 or 74-66 valves as part of the Unit 1 restart.

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 4 - Do we perform procedures ECI-0-000-MOV09 and EPI-0-000-MOV001 for valves in the Generic Letter 89-10 program on a 2 year frequency.

TVA Response:

No, the Preventive Maintenance (PM) work order for the specific MOV will specify the frequency and what specific instruction/procedures are to be performed in accordance with the GL 89-10 program requirements.

Procedure EPI-0-000-MOV001 is an electrical inspection procedure that is performed at difference frequencies for different MOVs based on the program requirements. Procedure ECI-0-000-MOV009 is a MOVATS testing procedure that is performed at different frequencies for different MOVs as well as in accordance with program requirements. Furthermore, in EPI 000-MOV001; Section 8.2, Post Maintenance Testing, Step [5.1] identifies the partial MOVATS PM requirement as specified in ECI -000-MOV009. Note that this is not GL 89-10 required testing. The partial MOVATS testing instruction is in Attachment 5 of ECI-0-000-MOV09.

Question 5 - Are there acceptance criteria for partial MOVAT testing or is partial MOVAT testing performed as a good practice and for trending purposes only.

TVA Response:

The partial MOVATS testing is performed primarily as a good practice and for trending purposes. Attachment 5 of BFN procedure ECI-0-000-MOV009 provides instructions for the partial MOVATS testing. Step 1.3[4] of this procedure calls for a verification that the acquired test data is acceptable. However, this is not referring to meeting acceptance criteria, but whether the data was successfully acquired or not.

Per the Root Cause Analysis (RCA), the GL 89-10 Program (NETP-115) will monitor (test and trend) the FCV-74-52 and FCV-74-66 periodically as a Category 2 MOV (i.e., not in the GL 89-10 commitment population) effective in January 2011. Performance data will be collected for trending purpose and acceptance criteria will be established for all six (3 units and 2 loops/unit) of the Outboard LPCI Injection MOVs as part of the MOV Program requirement. Corrective actions taken as part of PER 147628 will address these items.

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 ATTACHMENT 1 Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 1. - Provide the basis for why 1-FCV-74-66 is not part of the GL 89-10 program.

TVA Response:

Regulatory Requirements All MOVs in safety-related piping systems were considered to be within the scope of Generic Letter (GL) 89-10. However, MOVs that were not required to change positions during design basis events or in plant emergency procedures could be eliminated from the GL 89-10 program per Supplement 1 to GL 89-10. In addition, GL 89-10 originally required the inclusion of passive-position changeable valves where the MOV was not blocked to prevent inadvertent operation; however, Supplement 4 to GL 89-10 eliminated this requirement for BWRs. Therefore, it is permissible to exclude from the GL 89-10 program an MOV that is not required to change positions during design basis events or in plant emergency procedures. This position was accepted by the NRC in its letter dated March 18, 1997 as described below.

Discussion In a letter from T. E. Abney to the NRC dated January 6, 1997 (Attachment 1), TVA provided a response to the NRC letter dated October 7, 1996 (Attachment 2) for re-evaluation of the safety functions of certain MOVs removed from, or not included in, the BFN GL 89-10 program. In of the January 6, 1997 letter, Page E1-10 of the submitted letter, both FCV-74-52 and FCV-74-66 were identified as not required by plant procedures to operate the RHR system in the suppression pool cooling mode. Therefore, these valves have no redundant safety function and will not be included in the GL 89-10 program. Both the 1-FCV- 74-52 and 1-FCV-74-66 valves have a safety function to remain in the open position to support LPCI injection.

They are required to be open and remain open during normal plant operation. Therefore, they are classified as Passive MOVs by the MOV Program and are not included in the BFN GL 89-10 MOV Program.

In a letter from NRC to TVA dated March 18, 1997 (Attachment 3), NRC stated that the changes committed to in Mr. Abneys January 6, 1997 letter (Attachment 1) are considered adequate to address our (NRCs) concerns on this subject (reduced scope of valves in GL 89-10 Program). Accordingly, the NRC accepted TVAs justification for excluding the FCV-74-52 and FCV-74-66 valves for the BFN GL 89-10 program.

In addition, TVA has previously stated that the disc to stem separation occurred in 2008 and the valve passed flow in March 2009. Further independent testing was conducted by Performance Improvement International and concluded that the valve was capable of passing flow with the stem to disc separation.

Question 2. - Provide WO package and all supporting information that documents the partial MOVATs performed in 2006 and 2008 for 1-FCV-74-66.

TVA Response:

The following WO packages are applicable and were provided by BFN Licensing to the NRC.

WO #04-716746 was performed in 2006 (Attachment 4)

WO 2008-714852-000 was performed in 2008 (Attachment 5)

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 3. - Explain why the 3-FCV-74-52 and the 1-FCV-74-52 valve unseating forces are not consistent from test to test.

TVA Response:

Table A5.1 (Attachment 6) of the Root Cause Analysis (RCA) report provides a qualitative assessment of whether unseating is visible from the partial MOVATs data. Tabular results for 3-FCV-74-52 show that unseating was visible for some tests and not visible for other tests. The inconsistency in qualitative unseating results for 3-FCV-74-52 was explained in the TVA response to question 6 in our March 31, 2011 submittal as variation in disc-to-seat COF. Table A5.1, however, does not show inconsistent unseating results for 1-FCV-74-52.

Question 4. - Provide the actual unseating forces for 1-FCV-74-52 in 2008 and 2010.

Provide the actual unseating forces for the other valves as well.

TVA Response:

Prior to the discovery of the 1-FCV-74-66 stem-disc separation event in October, 2010, direct stem thrust measurements were not taken for the six RHR outboard LPCI angle globe valves (FCV-74-52, FCV-74-66) since they were not in the BFN GL 89-10 program as discussed in response to Question 1 above. However, the partial MOVATS data that we did take does not allow for the determination of actual unseating forces. Data acquired consisted of motor current, and, more recently, spring pack displacement. Although spring pack displacement is proportional to drive sleeve torque, the spring pack displacement was not calibrated and only approximate torque values can be obtained using Limitorque generic spring pack curves. In addition, only loading events that exceed the spring pack preload can be seen. As was shown in the figure (shown below) for Question 7 in our response dated March 31, 2011, the first open valve stroke loading event seen in the spring pack displacement represents the actuator hammerblow. A second loading event approximately 0.75 seconds later would be an indication of unseating, but only if unseating exceeds the spring pack preload.

Therefore, based on the information provided above, we are unable to provide the actual unseating forces. Quantification of unseating forces will not be possible until direct stem thrust measurements are obtained beginning at the next RFO on each unit.

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 5. - Provide the date when the WO was initiated and date when the WO was worked to address the plugged bonnet vents for 1-FCV-74-52 and -66 (Thierry provided WO 08-723813-000 as a reference).

TVA Response:

The plugged bonnet vents were described in PER 156971 dated 11/11/2008 and Work Order (WO) 08-723813-000 was initiated as the PER response to address the condition by replacing the vent valves. TVA concluded that these bonnet vents were in fact plugged based on recurrent and recent experience with similar vents that were confirmed to be plugged with foreign material. WO 08-723813-000 was signed off completed and accepted by Operations on 11/19/2010.

As discussed in response to question 2 of the NRC questions dated 4/22/11 an alternate methodology (ultrasonic testing) was used to meet the Technical Specification (TS) surveillance requirement SR 3.5.1.1 which states, Verify, for each ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve. Functional Evaluation (FE) 42924 and FE 43012 provided the technical justification for the non-conforming condition associated with the apparently plugged vent and required a revision to procedure 1-SR-3.5.1.1 (RHR I and RHR II) to perform ultrasonic testing monthly until such a time as these vent obstructions were cleared via WO 08-723813-000. The revised procedure was successfully performed.

Question 6 - MOVATs data traces provided depicts a date of October 31, 2008 while the RCA states the MOVATs data was obtained in November 2008. Was data taken both in Oct and Nov or should the RCA state Oct?

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 TVA Response:

The data was taken only once on October 31, 2008. Table A5.1 of the Root Cause Analysis will be updated to indicate that the correct date is October 31, 2008.

Question 7. - Provide the 2010 MOVATs data taken for 1-FCV-74-66 after the valve was repaired.

TVA Response:

The 2010 MOVATS data taken for 1-FCV-74-66 after the repair are provided below and are also attached in the Root Cause Analysis.

NOTE: The X denotes the unseating of the valve disc.

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 Question 8. - Provide the program document for the GL 89-10 program.

TVAs Response:

The program document (NETP-115) was provided by BFN Licensing to the NRC on 07/01/2011.

It is also attached to this response (Attachment 7).

Question 9. - PER 271338 RCA rev 1 Attachment 7 specifies that 1-SR-3.5.1.6 and 1-SR-3.3.5.1.6 document instances when the 1-FCV-74-66 was known to have been stroked by date performed. These SRs perform flow test and logic functional test. 1-SR-3.6.1.3.5 and 1-SR-3.3.3.1.4 would be the correct SRs that would have required stroking the valve.

Is the data in the table for valve stroke history incorrect or are the wrong SRs referenced?

TVA Response:

Valve 1-FCV-74-66 is stroked during execution of the following surveillance procedures:

Procedure Steps where 1-FCV-74-66 is stroked 1-SR-3.5.1.6 (RHR II) Quarterly Frequency Not stroked.

1-SR-3.3.5.1.6 (C II) 2-year Frequency 7.2[10]: Close 7.2[14]: Open 7.2 [20]: Close 7.2 [28]: Open 7.2 [35]: Close 7.2 [38]: Open 7.2 [40]: Close 7.2 [43]: Open 7.2 [46]: Close 7.2 [61]: Open 7.6 [1]: Close 7.6 [20]: Open 1-SR-3.6.1.3.5 (RHR II) Quarterly Frequency 7.2 [1]: Close 7.2 [2]: Open 7.2 [4.1]: Close 7.2 [4.2]: Open 7.2 [5]: Possible stroke if not in original position 1-SR-3.3.3.1.4 (H II) 2 year frequency 7.2 [4]: Close 7.2 [8]: Open 7.2 [10]: Close 7.2 [14]: Possible stroke if not in original position Therefore, the reference in Attachment 7 of the RCA to 1-SR-3.5.1.6 (RHR II) is incorrect since it does not have procedure steps that specify the stroking of 1-FCV-74-66. The reference to procedure 1-SR-3.3.5.1.6 (C II) is correct. In addition, procedures 1-SR-3.6.1.3.5 (RHR II), and 1-SR-3.3.3.1.4 (H II) also have procedure steps that specify the stroking of 1-FCV-74-66.

Therefore, the wrong SR procedures are referenced in the RCA and the data in the RCA table for the valve stroke history is incorrect. However, we estimate that the total number of valve Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 7, 2011 strokes will close to that given in table A5.1 of Attachment 7 of the RCA. Therefore, the conclusions in the RCA should remain valid. This attachment will be revised to include the correct surveillance procedure references and the revised stroke count.

Question 10. - Provide a copy of the entire procedure of ECI-0-000-MOV09 r20 and EPI-0-000-MOV001 r48. (Parts of these procedures were in the WOs and they want to see the whole procedure.)

TVA Response:

Procedures ECI-0-000-MOV09 r20 (Attachment 8) and EPI-0-000-MOV001 r48 (Attachment 9) are attached and were previously provided by BFN Licensing.

Question 11. - What is requiring the 2 year frequency for the partial MOVATs? Are they scheduled PMs?

TVA Response:

1-FCV-74-66 was maintained by the Preventive Maintenance (PM) Program. The PM program called for a partial MOVATS every 2-years for this valve, which was scheduled to be consistent with a refueling outage cycle basis for equipment reliability reasons.

Question 12. - If this valve were in the GL 89-10 program would the frequency change; would you be doing more work on the same frequency?

TVA Response:

If the 1-FCV-74-66 valve was in the BFN GL 89-10 program, a baseline for performance would be established on a once per refueling outage basis until a performance trend was established.

Once the baseline was established then the frequency would be set in accordance with the MOV program (NETP 115, Attachment 7). If this valve was incorporated into the MOV program, a full MOVATS test instead of the partial MOVATS test would be performed on the frequency set in accordance with the MOV program.

Enclosure 9

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Telecon Follow up Question - July 8, 2011 Question 1 - Were full MOVATS performed on valves 74-67, and 74-53 during the restart of Unit 1 in 2006, and were full MOVATS performed in 2008? If not, how was the frequency established?

TVA Response:

The full MOVATS test was performed on valve 74-67 during the restart of Unit 1 on 9/16/2006.

Full MOVATS was performed again in 2008 for valve 74-67 as part of the TVA program periodic verification test in accordance with the 120 month GL 89-10 program schedule. Full MOVATS was again performed as a post maintenance test (PMT) in 2010 because it was modified as part of the Joint Owners Group (JOG) upgrade. The GL 89-10 program testing frequency for this valve is 120 months.

The full MOVATS test was performed on valve 74-53 during the restart of Unit 1 on 10/2/2006.

Full MOVATS were performed again in 2007 as PMT for valve repair and not as part of the GL 89-10 program, and it was performed again in 2010 because of JOG upgrade maintenance.

The GL 89-10 program testing frequency for this valve is 120 months.

Normally, the periodic GL 89-10 program testing frequency is established for the GL 89-10 program valves based on risk (PRA risk ranking) and margin of the MOV. As an example; a high risk and low margin MOV would be tested every 2-years while a low risk and high margin MOV would be tested every 10 years. This process is described in the TVA GL 89-10 program document NETP-115.

In 2006, valve 1-FCV- 74-66 had a stem replacement. Since this valve was not in the GL 89-10 program, a full MOVATS test was not performed at that time (during the restart of Unit 1). If this valve had been in the GL 89-10 program our requirements (NETP 115) would have required a full MOVATS as part of the PMT. After successful PMT, the requirements for full MOVATS would be in accordance with the TVA program (NETP 115) based on risk and margin as previously discussed. Refer also to Question 12 of the 6/29/11 responses.

Enclosure 10

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Telecon Follow up Question - July 11, 2011 Question 1 - Were full MOVATS performed on valves 74-67, and 74-53 during the restart of Unit 1 in 2006, and were full MOVATS performed in 2008? If not, how was the frequency established?

TVA Response:

The full MOVATS test was performed on valve 74-67 during the restart of Unit 1 on 9/16/2006.

Full MOVATS was performed again in 2008 for valve 74-67 as part of the TVA program periodic verification test in accordance with the 120 month GL 89-10 program schedule. Note that the scheduling of this test was based on the 120 month program schedule and was not required for any other reason. Full MOVATS was again performed as a post maintenance test (PMT) in 2010 because it was modified as part of the Joint Owners Group (JOG) upgrade. The GL 89-10 program testing frequency for this valve is 120 months.

The full MOVATS test was performed on valve 74-53 during the restart of Unit 1 on 10/2/2006.

Full MOVATS were performed again in 2007 as PMT for valve repair and not as part of the GL 89-10 program, and it was performed again in 2010 because of JOG upgrade maintenance.

The GL 89-10 program testing frequency for this valve is 120 months.

Normally, the periodic GL 89-10 program testing frequency is established for the GL 89-10 program valves based on risk (PRA risk ranking) and margin of the MOV. As an example; a high risk and low margin MOV would be tested every 2-years while a low risk and high margin MOV would be tested every 10 years. This process is described in the TVA GL 89-10 program document NETP-115.

In 2006, valve 1-FCV- 74-66 had a stem replacement. Since this valve was not in the GL 89-10 program, a full MOVATS test was not performed at that time (during the restart of Unit 1). If this valve had been in the GL 89-10 program our requirements (NETP 115) would have required a full MOVATS as part of the PMT. After successful PMT, the requirements for full MOVATS would be in accordance with the TVA program (NETP 115) based on risk and margin as previously discussed. Review of the 1-FCV-74-66 valve indicates that upon adding the Unit 1 74-66/52 valves to the program in 2006 it would have received a follow-up confirmatory full MOVATS test at the subsequent refuel outage and then would likely have received a full MOVATS test on a 120 month frequency based on the assumption that these valves would have similar low risk and high margin as the 74-53/67 valves unless the confirmatory full MOVATS test showed results that were of concern. However, if the 74-66/52 valves were included in the GL 89-10 program in 1997 then full MOVATS testing of these valves would have been performed in 2006 during U1 restart. If these test results were comparable to those for the same valve on Units 2 and 3 then no testing other than that required by the program frequency, most likely 120 months, would have been performed. Refer also to Question 12 of the 6/29/11 responses.

Enclosure 11

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Telecon Follow up Question - July 8, 2011 As discussed in the response to Question 1 dated July 7, 2011, the EOIs consider additional equipment failures and accident scenarios that could require a MOV to have a function beyond those credited in the safety analysis.

Valve FCV-74-52 and valve FCV-74-66 are required to be closed should valves FCV-74-53 and FCV-74-67, respectively be open when initiating suppression pool cooling, drywell sprays or suppression chamber sprays (see Step 2 of EOI Appendix 17A, Step 6 of EOI Appendix 17B and Step 6 of EOI Appendix 17C, respectively). The initiation of suppression pool cooling and suppression chamber sprays is not discussed in Section 14.6.3 of the SAR as a manual action following a LOCA-DBA. The initiation of drywell sprays is explicitly described in the Section 14.6.3 as a manually initiated action, which can be taken following a LOCA-DBA. The exact words in Section 14.6.3 are: ...The containment spray would normally not be activated at all... The basis for this statement is also in Section 14.6.3 of the SAR, which reads: ...After the reactor vessel is flooded to the height of the jet pump nozzles, the excess flow discharges through the recirculation line break into the drywell. This flow offers considerable cooling to the drywell and causes a depressurization of the containment as the steam in the drywell is condensed...

In Supplement 1 to GL 89-10 states (as described on page 3 of the enclosure to NRC letter to TVA, dated 7Oct1997): ...safety-related MOVs that are always in their safety position, or would have no affect on the operation of the safety train if placed in the nonsafety position, could be removed from the GL 89-10 program...

When initiating suppression pool cooling, drywell sprays or suppression chamber sprays, clearly if FCV-74-53 and FCV-74-67 is closed, the position of FCV-74-52 and FCV-74-66, respectively, does not matter. If FCV-74-53 and FCV-74-67 is open and FCV-74-52 and FCV-74-66, respectively, is open then depending on the pressure in the reactor vessel, all RHR pump(s) flow or some portion of this flow will be directed through the desired flow path to the suppression pool, drywell sprays or suppression chamber sprays.

As discussed above, only the use of drywell sprays is discussed in Section 14.6.3 of the SAR. And as discussed above, water that is discharged from the recirculation break has a similar effect in containment cooling as water that is discharged from the drywell sprays. Based on these SAR statements, it is reasonable to conclude that the position of FCV-74-52 and FCV-74-66 has no affect on the operation of the safety train. Therefore, based on the guidance in Supplement 1 of GL 89-10, FCV-74-52 and FCV-74-66 are not required to be included in the GL 89-10 Program.

Enclosure 12

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Telecon Follow up Question - July 11, 2011 As discussed in the response to Question 1 dated July 7, 2011, the EOIs consider additional equipment failures and accident scenarios that could require a MOV to have a function beyond those credited in the safety analysis.

Valve FCV-74-52 and valve FCV-74-66 are required to be closed should valves FCV-74-53 and FCV-74-67, respectively be open when initiating suppression pool cooling, drywell sprays or suppression chamber sprays (see Step 2 of EOI Appendix 17A, Step 6 of EOI Appendix 17B and Step 6 of EOI Appendix 17C, respectively). The initiation of suppression pool cooling and suppression chamber sprays is not discussed in Section 14.6.3 of the UFSAR as a manual action following a LOCA-DBA. The initiation of drywell sprays is described in Section 14.6.3 as a manually initiated action. However, Section 14.6.3 also states that initiation of drywell sprays would normally not be taken following a LOCA-DBA.

In addition, there is discussion in Section 4.8.6.2 of the UFSAR that also indicates the initiation of suppression pool cooling, drywell sprays or suppression chamber sprays is dependent on adequate core cooling following a LOCA-DBA. That is, these alignments may not be used depending on the break size, location and equipment failures assumed.

The above described UFSAR statements indicate that not initiating drywell sprays will not significantly change the results of the containment analysis in Section 14.6.3 of the UFSAR. However, the case of no drywell spray is not explicitly evaluated in the UFSAR. General Electric Hitachi (GEH) performed the LOCA-DBA containment analysis for BFN. The need for drywell sprays to maintain containment pressure below its design limit was discussed with GEH on 11Jul2011. GEH stated that the peak containment pressure occurs early following a LOCA-DBA (<10 minutes), and concurred that the drywell spray function is not needed for a DBA-LOCA. GEH stated that the long-term containment analysis is performed assuming drywell sprays are in operation simply because that is most limiting regarding NPSH available for the ECCS pumps. This minimizes containment pressure and is conservative when determining the NPSH available to the ECCS pumps.

In Supplement 1 to GL 89-10 states (as described on page 3 of the enclosure to NRC letter to TVA, dated 7Oct1997): ...safety-related MOVs that are always in their safety position, or would have no affect on the operation of the safety train if placed in the nonsafety position, could be removed from the GL 89-10 program...

When initiating suppression pool cooling, drywell sprays or suppression chamber sprays, clearly if FCV-74-53 and FCV-74-67 is closed, the position of FCV-74-52 and FCV-74-66, respectively, does not matter. If FCV-74-53 and FCV-74-67 is Enclosure 13

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Telecon Follow up Question - July 11, 2011 open and FCV-74-52 and FCV-74-66, respectively, is open then depending on the pressure in the reactor vessel, all RHR pump(s) flow or some portion of this flow will be directed through the desired flow path to the suppression pool, drywell sprays or suppression chamber sprays with the balance of the flow being discharged to the reactor vessel.

As discussed in Section 14.6.3 of the UFSAR, water that is discharged from the recirculation break has a similar effect on containment cooling as water that is discharged from the drywell sprays so the flow split between these two paths does not significantly change the results of the containment analysis. The exact statement in Section 14.6.3 of the UFSAR reads: ...After the reactor vessel is flooded to the height of the jet pump nozzles, the excess flow discharges through the recirculation line break into the drywell. This flow offers considerable cooling to the drywell and causes a depressurization of the containment as the steam in the drywell is condensed...

For suppression pool cooling, the relevant parameter is the total flow through the RHR Heat Exchangers and this water may return to the suppression pool via any path (e.g., a break in a pipe connected to the reactor vessel, the drywell sprays, the suppression chamber sprays) so the flow split(s) does not significantly change the results of the containment analysis.

Based on these evaluations, it is reasonable to conclude that the position of FCV-74-52 and FCV-74-66 has no affect on the operation of the safety train.

Therefore, using the guidance in Supplement 1 of GL 89-10, FCV-74-52 and FCV-74-66 are not required to be included in the GL 89-10 Program.

Enclosure 13

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 11, 2011

1. Are the RHRSW outlet valves in the 89-10 program?

TVA Response:

Assuming these are the RHRSW Heat Exchanger Outlet Valves (1,2,3-FCV-23-34,40,46,52),

they are in the MOV Program. These valves were put in to the GL 89-10 program because they meet the criteria of supplement 1 to GL 89-10. The failure of these valves was detected in 2008 when the valves were disassembled and not because of MOV testing in accordance with the GL 89-10 program.

2. The 2008 W.O. for the 1-FCV-74-66 valve specifies performance of a partial MOVATS in accordance with MOV 009. Section 2.3 of MOV 009 states if a partial MOVATS is required per a W.O. then use only Att. 5. Att. 5 is not in the W.O. and it appears the W.O. used selected parts of section 7.

TVA response:

The following responses are based on Work Oder 08-714852-000 (attached).

a. Was Att. 5 used per step 2.3?

No, Page 13 of the work order file (or page 9 of MOV009), indicated that the Step 2.3 was N/A. The test performer used step 1.2 on the same page to meet his testing requirement.

b. If not why not?

Att. 5 was not used to perform the test because the testing instructions (Page 7 step 1.2 of the work order file) required the test data to include spring pack displacement which can only be obtained at the valve, as well as electrical data (normally from Partial MOVATS at the MCC; motor control center). The testing personnel used Attachment 7 (at the valve test) and collected all the needed data at one place rather than going to two places (at the valve and at the MCC).

c. What was basis for only performing parts of section 7?

The basis for only performing parts of Section 7 of MOV009 was mainly to meet the test instruction requirement as discussed in the response to b above.

3. Have the EOI Appendices been revised regarding utilization of valves 74-52 (66) since the scope of the GL 89-10 program was developed?

Enclosure 14

BFN 1-FCV-74-66 Valve Failure NRC Independent Assessment Team Questions - July 11, 2011 TVA Response:

The EOI Appendices have not changed with respect to utilization of valves 74-52 (66). The current revision of 2-EOI APPENDIX-17A directs the operator to verify closed 2-FCV 52(66) in step 2.f. and Revision 5 of 2-EOI-APPENDIX-17A which was issued 9/8/95 has the same action in the same step.

Enclosure 14