ML12093A165

Entergy Pre-Filed Hearing Exhibit ENT00130B, Calculation F10503-R-001, Rev. 2, Transformer Internal Pressure Evaluation.

ML12093A165
Person / Time
Site:	Indian Point
Issue date:	11/19/2010
From:	Zysk G Entergy Corp
To:	Atomic Safety and Licensing Board Panel
SECY/RAS
Shared Package
ML12088A508	List: ML12088A510 ML12088A511 ML12088A514 ML12088A515 ML12093A165
References
RAS 22107, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 F10503-R-001, Rev 2
Download: ML12093A165 (140)

Text

ENT00130B Submitted: March 28, 2012 Calculation Sheet ATTACHMENT A Rev. 0 Sheet No: A9 of 9 Calc No.: F10503-R-001 Title: Transformer Internal Pressure By: G. Zysk Date: 11/19/10 Evaluation Checked: L.K. Wong Date: 11/19/10

References:

1. Frank M. Clark, "Insulating Materials for Design and Engineering Practice", John Wiley and Sons, Inc. New York N.Y.

1962.

2. R.L. Bean, N. Chackan Jr., H.R. Moore, E.G. Wentz, "Transformers for the Electric Power Industry" Westinghouse Electric Corporation, Power Transformer Division, McGraw Hill Book Co. New York, N.Y., 1959.

3. R. L. Bean, H. L. Cole, "A Sudden Gas Pressure Relay for Transformer Protection," AIEE Transactions, Volume 72, 1953, pp. 480-483

4. Recorded Electrical Conditions Report

5. Randall Noon, "Engineering Analysis of Fires and Explosions", CRC Press, Boca Raton, FL. 1995.

6. Univolt 60, Material Safety Data Sheet, Date issued: 02/22/95 Supersedes date: 09/15/93 Exxon Company USA,

7. F.M. White, "Fluid Mechanics" 3rd edition, McGraw-Hill, Inc. New York, N.Y. 1994.

8 J. T. Madill, "Typical Transformer Faults and Gas Detector Relay Protection," AIEE Transactions, Volume 66, 1947, pp.

1052-1060.

APPENDIX B: FEA Analyses Report No. F10503-R-001 Page B1 Revision 2

Finite element analyses (FEA) of the transformer tank wall was performed to investigate the structural impact of instantaneous pressure pulses on the 21 Main Transformer. The computer software program ANSYS v.11 [17] was used for the analyses. Several cases of internal pressure pulse loads of 700 psi and 800 psi were evaluated to obtain the dynamic response of the transformer wall. The analysis is conservative because the pressure is assumed to reach a peak value irrespective of the large deformation experienced by the wall. The maximum deflection was calculated to be 15 to 16 inches (38 to 41 cm), and the maximum estimated pressure was determined to be between 700 psi and 800 psi for this deflection.

As shown in Fig. B.1, the model uses element Solid45 to generate an explicit and representative 3D model of the transformer wall, reinforcement plates, and welds. All welds were explicitly modelled as 0.25 in. fillet welds, as Fig. B.2 shows. In Fig. B.2, the upper stiffener and lower stiffener are welded, but the gap in between the welds open up like a fish-mouth under dynamic loading. For this reason, it was determined there was no need to add contact elements in this gap region.

A single material definition was used for the wall, reinforcement plates, and welds.

Plastic material behavior was incorporated into the analyses by using bilinear kinematic hardening plastic properties. These were defined by yield stress and tangent modulus parameters.

The boundary conditions included constraint of the X-direction displacement (UX) nodes on both sides of the wall to represent continuity. As Fig. B.1 shows, all degrees of freedom (DOF) of nodes which were 2 in. from the top-side and bottom-side regions of the wall were fixed. This constraint was included because the top and bottom horizontal plates of the transformer wall were of sufficient thickness to supply a restraint on movement in those regions.

Fig. B.3 shows the applied loading condition. A dynamic internal pressure load was selected to be applied to the inner side of the wall. Deadweight loads were applied in the first load step before application of the transient loads. The pressure pulse included a ramp-up loading time of 0.001 seconds followed by a 0.025 second hold time. The decay time of the pressure pulse was selected to be 0.027 seconds, and was also simulated as a ramp-down rather than step-down function.

Report No. F10503-R-001 Page B2 Revision 2

Damping of the structure was introduced via a stiffness matrix multiplier, and was selected at a ratio proportional to the stiffness. The stiffness matrix multiplier, , was set equal to 8.52 x 10-5 . This value was based on a damping ratio of 1% at a frequency of 37Hz, which was the first natural mode of the linear structure.

Various pressure pulse simulations at peak dynamic pressure values of 700 psi and 800 psi were analyzed. As Fig. B.4 shows, the maximum out-of-plane deflection at a peak pressure of 700 psi was found to be around 15 inches (38 cm). The residual out-of-plane deflection after the pressure pulse is around 6 in., which was approximately the deflection observed in the 21MT while on-site for the external visual inspection. For the simulation run at a peak dynamic pressure of 800 psi, the maximum out-of-plane deflection was found to be slightly greater than 16 inches (41 cm). These values are within the range of dynamic pressures calculated in Appendix A.

Report No. F10503-R-001 Page B3 Revision 2

Fixed all DOF of nodes 2 inches from top and bottom sides Restrained by UX on both sides Fig. B.1: Sketch of the representative transformer model.

Report No. F10503-R-001 Page B4 Revision 2

Welds Gap Fig. B.2: Close-up sketch of gap and weld region along transformer wall.

Report No. F10503-R-001 Page B5 Revision 2

Fig. B.3:

B Graph of the load ding conditio ons selecte ed for the analyses.

Report No.

N F10503 3-R-001 Page e B6 Revision n2

Fig. B.4: Maximum out-of-plane deflection and residual deflection for a 700 psi peak dynamic pressure.

Report No. F10503-R-001 Page B7 Revision 2

Lucius Pitkin, Inc. Consulting Engineers Advanced Analysis Fitness-For-Service Failure & Materials Evaluation Nondestructive Engineering LPI (Main office & Laboratory) 304 Hudson Street New York, NY 10013-1015 Tel: 212-233-2737 Fax: 212-406-1417 LPI (Boston Area Office) 36 Main Street Amesbury, MA 01913-2807 Tel: 978-517-3100

Attachment IV

Unit 22 Main Transformer Test Results Review Baseline/

Test Acceptance Criteria Last Test Data This Test Data Results Review Nameplate CH 0.28 0.19 CHL(UST) 0.35 0.26

<0.5% is SAT, 0.5% to 1.0%

Transformer Power Requires Engineering Review CHL 0.35 0.26 N/A SAT - all values are <0.5%.

Factor and Acceptance, >1.0% is CL 0.39 0.29 UNSAT CHL(UST) 0.35 0.26 CHL 0.34 0.26 CH 6929 6965 6938

<5% of Baseline SAT, 5% to CHL(UST) 14018 14052 14006 10% of Baseline Requires CHL 14021 14072 14013 Transformer SAT - all values are <5% of Engineering Review and Capacitance CL 43751 44086 43948 Baseline values.

Acceptance, >10% of Baseline is UNSAT CHL(UST) 14018 14048 14004 CHL 14039 14059 14016 H1 (C1) 0.27 0.24 0.30

<0.5% is SAT, 0.5% to 1.0% H1 (C2) N/A 0.22 0.27 Requires Engineering Review H2 (C1) 0.27 0.25 0.30 Bushing Power and Acceptance, >1.0% is SAT - all values are <0.5%.

Factor H2 (C2) N/A 0.23 0.26 UNSAT, 2X Nameplate is UNSAT H3 (C1) 0.27 0.25 0.31 H3 (C2) N/A 0.23 0.26 H1 (C1) 449 443 440 H1 (C2) 12314 12271 12228

<5% of Nameplate SAT, 5% to SAT - all values are <5% of 10% of Nameplate Requires H2 (C1) 450 446 445 Nameplate values. The Bushing Engineering Review and capacitance values are Capacitance Acceptance, >10% of H2 (C2) 12260 12271 12229 decreasing however they are in Nameplate is UNSAT spec.

H3 (C1) 449 448 446 H3 (C2) 12314 12270 12223

Unit 22 Main Transformer Test Results Review Baseline/

Test Acceptance Criteria Last Test Data This Test Data Results Review Nameplate X1 0.019 0.021 X2 0.021 0.022

<0.1W is SAT, 0.1W to 0.3W X3 0.018 0.020 SAT - all values are <0.1W and Bushing Hot Collar Requires Engineering Review N/A 0.018 0.017 similar to past results.

and Acceptance, >0.3W UNSAT X4 X5 0.018 0.021 X6 0.018 0.017 Currents (mA) measured should H1-H0 353.60 373.95 SAT - the currents measured follow the pattern of two similar follow the expected pattern of Excitation Current high readings (H1-H0 and H3- H2-H0 N/A 275.90 296.38 two similar high readings (H1-H0) and one lower reading (H2- H0 and H3-H0) and one lower H0). H3-H0 352.91 375.15 reading (H2-H0).

A Imp 34.457 34.451 A Reac 34.478 34.448 SAT - the change in Change in impedance and B Imp 34.619 34.603 Leakage impedance and reactance from reactance from previouss test is N/A Reactance 34.576 34.600 previous test is < 3% and

< 3% and within 2% of average. B Reac within 2% of average.

C Imp 34.779 34.634 C Reac 34.714 34.631 H1/X1 9.5668 9.558 9.5632 Transformer Turns SAT - measured ratio is within Within 5% of calculated ratio H2/X2 9.5668 9.555 9.5603 Ratio (TTR) 5% of calculated.

H3/X3 9.5668 9.561 9.5624 H1-H2 75.950 79.047 SAT - measured resistances are within 5% of each other.

H2-H3 75.860 79.277 The difference in readings from past results could be attributed Measured resistance shall not H3-H1 76.140 79.288 Winding to instruments used, the quality very by more than 5% from N/A Resistance of test equipment connections adjacent windings. X1-X0 931.0 860.4 and/or temperature correction.

X2-X0 911.0 866.5 The results from this test have been temperature corrected to X3-X0 929.0 856.0 20C.

Unit 22 Main Transformer Test Results Review Baseline/

Test Acceptance Criteria Last Test Data This Test Data Results Review Nameplate SAT - all readings are greater H to G 4200 77900

> 1500 Megohms than the acceptance criteria.

Winding Insulation The difference in readings from Resistance L to G N/A 4200 63400

> 16 Megohms past results is due to different (Megger) testing technique and

> 1500 Megohms H to L 4200 30100 equipment used.

There is no distinct acceptance criteria for this test. Comparison SAT - Review of traces by between phases and past test Performed System Engineering, Siemens SFRA N/A N/A N/A results is required. Requires in 2008 and Doble indicate the test is Engineering review and SAT.

acceptance.

There is no distinct acceptance SAT - Review of the oil criteria for this test. The results Dissolved Gas Performed analysis results by System are reviewed against past N/A N/A N/A Analysis (DGA) 10/29/10 Engineering finds the results to gassing trends, EN-EE-G-001 be acceptable.

and IEEE C57.104

Unit 2 UAT Test Results Review Test Acceptance Criteria Baseline Last Test Data This Test Data Results Review CH 0.41 0.31 SAT - all values are <0.5% with the exception of CL. The CL is CHL(UST) 0.48 0.34 acceptable at 0.51% based on

<0.5% is SAT, 0.5% to 1.0%

CHL 0.52 0.35 it being below 1.0%, historically Transformer Power Requires Engineering Review N/A being higher than the other Factor and Acceptance, >1.0% is CL 0.72 0.51 power factors, it is not trending UNSAT CHL(UST) 0.48 0.35 up and the value is similar to the other similar auxiliary CHL 0.48 0.34 transformers on site.

CH 13393 13376 13391

<5% of Baseline SAT, 5% to CHL(UST) 20070 20065 20050 10% of Baseline Requires CHL 20079 20074 20095 Transformer SAT - all values are <5% of Engineering Review and Capacitance 2455 2456 2426 Baseline values.

Acceptance, >10% of Baseline is CL UNSAT CHL(UST) 20065 20062 20049 CHL 20067 20069 20052 H1 0.018 0.016 H2 0.019 0.016 H3 0.024 0.019

<0.1W is SAT, 0.1W to 0.3W SAT - all values are <0.1W and Bushing Hot Collar Requires Engineering Review X0 N/A 0.022 0.021 similar to past results.

and Acceptance, >0.3W UNSAT X1 0.018 0.027 X2 0.028 0.026 X3 0.026 0.018 Currents (mA) measured should H1-H2 163.07 165.72 SAT - the currents measured follow the pattern of two similar follow the expected pattern of Excitation Current high readings (H2-H3 and H3- H2-H3 N/A 324.9 332.63 two similar high readings (H2-H1) and one lower reading (H1- H3 and H3-H1) and one lower H2). H3-H1 345.28 329.4 reading (H1-H2).

Unit 2 UAT Test Results Review Test Acceptance Criteria Baseline Last Test Data This Test Data Results Review 5R (H1/X1) 2.889 2.883 2.883 Transformer Turns SAT - measured ratio is within Within 5% of calculated ratio 5R (H2/X2) 2.889 2.883 2.883 Ratio (TTR) 5% of calculated.

5R (H3/X3) 2.889 2.883 2.883 H1-H2 61.750 56.838 SAT - measured resistances are within 5% of each other.

H2-H3 60.020 56.896 The difference in readings from past results could be attributed Measured resistance shall not H3-H1 60.620 56.688 Winding to instruments used, the quality very by more than 5% from N/A Resistance of test equipment connections adjacent windings. X1-X0 2.623 2.852 and/or temperature correction.

The results from this test have X2-X0 2.658 2.867 been temperature corrected to 20C.

X3-X0 2.662 2.890 SAT - all readings are greater H to G 4200 2400

> 46 Megohms than the acceptance criteria.

Winding Insulation The difference in readings from Resistance L to G N/A 4200 24200

> 16 Megohms past results is due to different (Megger) testing technique and

> 46 Megohms H to L 4200 2560 equipment used.

There is no distinct acceptance criteria for this test. Comparison SAT - Review of traces by between phases and past test Performed System Engineering and SFRA N/A N/A N/A results is required. Requires in 2008 Siemens indicate the test is Engineering review and SAT.

acceptance.

There is no distinct acceptance SAT - Review of the oil criteria for this test. The results Dissolved Gas Performed analysis results by System are reviewed against past N/A N/A N/A Analysis (DGA) 10/29/10 Engineering finds the results to gassing trends, EN-EE-G-001 be acceptable.

and IEEE C57.104

Attachment V

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 1/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer

1. Bushing Data Type: COTA - Transformer OIP (Oil Impregnated Paper Bushing)

Type of installation Oil-Air Bushing Style 1175-F020-23-AG3-02 Insulation Class 345 kV BIL 1175 kV SIL Wet 825 kV Rated Maximum Voltage 220 kV Line to Ground 1 Min Dry Voltage 520 kV Rated cont. Current 2000 A Serial Numbers 05F9080 - 01 Terminal H1 Transformer 05F9080 - 04 Terminal H2

1. 4.019.269 (Unit #21) 05F9080 - 03 Terminal H3 Year of Manufacturing 2005

2. Scope This Photographical Report contains the significant photographs taken during the inspection of the bushings of terminal H2 and H3 of the transformer Unit #21, which bushing H2 exploded on November 07, 2010, causing the outage of the power plant.

The inspection was performed on January 18, 2011, at the Bushing factory of TRENCH in Toronto/Ajax - Canada.

For a better understanding of the pictures shown in the section 4, in the sketch below the schematic structure of the investigated condenser bushing is shown. This sketch is also reproduced in the section 5. Note that in TRENCH bushings, capacitive layers of the condenser body use split-foils for the upper and lower portions of the bushing.

Condenser grading Condenser grading configuration on the Grounded layer configuration on the lower upper (air) side with the (oil) side, with the higher lower field stress; field stress; Central conductor, 100% rated potential.

No electrical Field stress on the inner foil edges Sketch 1. View of the longitudinal half section of the condenser core, showing the main elements and detail of the regions with capacitive grading.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 2/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Radial electrical stresses from the centre conductor to the outer grounded capacitive layers are kept uniform and linear throughout the active part by using capacitive voltage grading.

Since the dielectric strength of the air is low, the upper side grading of the bushing must be designed over a longer distance resulting in a low axial electric field stress compared to the oil-immersed lower end of the bushing where the axial electric fields are compressed over a smaller distance resulting in higher stresses.

3. Summarized Inspection Description On January 18, 2011, the bushing inspection and tear down took place at the Trench factory in Toronto/Ajax - Canada.

After an introductory explanation about the TRENCH bushing facility and capabilities, a brief presentation was given by TRENCH regarding the failure of 3 of Trench France 230-kV bushings occurred in 2006. These bushings were of a different design than the IPEC bushings under consideration, and their failure was attributed to insulation breakdown due to copper migration caused by a corrosive reaction initiated by polar compounds in the Shell Diala D mineral oil used in those bushings.

3.1 Inspection of Bushing of Terminal H2 (S. No. 05F9080 - 04)

The first bushing inspected was the one installed on the terminal H2 of the transformer Unit #21.

The location of the failure was determined to have occurred on the oil immersed (lower-end) side of the bushing, causing an explosion and subsequent transformer tank rupture and fire (see Technical Report ST 19/10).

For the inspection, first the condenser core was extracted from the outer shell (see Picture 3).

Then the condenser core was placed on rollers installed over a wooden box, which was intended to accommodate the unwound paper layers.

Upon unwinding of the outer paper layers, where the voltage tap foil and the ground foil are located (which are grounded during normal operation of the transformer), small brown traces were observed at the edge of the aluminum foils.

These treeing traces extended around 1 mm axially along the paper insulation and had a starting point at the upper edge of the aluminum foils installed at the upper portion of the condenser core.

Since the lower part of the H2 bushing was mostly destroyed during the failure, the major part of the aluminum foils could be inspected only on the upper part (above the bushing flange region).

These brown traces were similar to the ones shown during the TRENCH presentation on the opening meeting.

It was also observed that the traces became gradually lighter as the examination progressed from the outer layers to the innermost ones.

The innermost 18 foil layers at the lower part of the bushing were not damaged during the failure (see picture 32), allowing the inspection of the bottom portion of the condenser core. Similar treeing traces were found at these locations.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 3/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer It was noticed that the traces on the edges of the aluminum foils were observed only at the outer foil edges. This means:

9 On the bottom edge of the foils of the bottom portion of the active part; 9 And on the upper edge of the foils of the upper portion of the active part; The location of the traces suggests that their formation is related to the presence of electrical fields. The inner edges of the aluminum foils are exposed to a negligible electrical field stress and no traces were observed in these regions (refer also to Sketch 1).

The most likely failure path was identified as starting on or around the outer edge of the first layer following the layer of the potential tap, passing through the big hole and reaching the 100%

potential at the central conductor near the bottom terminal. The failure path also expanded to the bushing flange at the zero potential side (refer to the sketch 6 - section 5).

3.2 Inspection of Bushing of Terminal H3 (S. No. 05F9080 - 03)

Following the teardown sequence, the bushing of terminal H3 of the transformer Unit #21 was inspected next.

The epoxy cast insulator of the lower part of this bushing had shattered in pieces but there was no damage to the condenser core. As all the layers of the condenser core were intact, both upper and lower foil edges could be fully inspected.

Similar to the H2 terminal bushing, treeing traces were found on the first layer below the grounded layer of the voltage tap and on most the remaining foils.

The traces at the lower edge of the bottom foils were more pronounced than those found at the upper part of the H2 bushing. It was also observed at the layers of the bottom part of this bushing that the intensity of the traces decreased from the outer layers to the innermost ones.

On the upper edge of the foils of the upper portion of the condenser core also showed traces, these with similar intensity as those detected on the H2 bushing.

3.3 Inspection of Bushing of Terminal H1 (S. No. 05F9080 - 01)

Based on the similar findings on the first two inspected bushings, it was decided not to unwind the third bushing, originally installed at the terminal H1. However, according to information provided by TRENCH, this bushing was also unwound at a later date and showed similar evidence of traces as the ones that were detected on the other two bushings already inspected.

//

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 4/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer

4. Selection of the significant Photos of the Inspection Bushing H2 Bushing H3 S.No. O5F9080-04 S.No. O5F9080-03 Picture 1: General view of the bushings as received from the Indian Point site; 4.1 Inspection Photos of Bushing Terminal H2 (S. No. 05F9080 - 04)

Remaining layers of Grounded sleeve the condenser core below bushing Flange Bottom plate of copper with Remaining part of the flashover marks.

condenser core destroyed by the flashover Picture 2: General view of the H2 bushing showing the bottom part destroyed by the flashover; ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 5/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Upper part of the H2 Bushing condenser core without damage or flashover marks.

Picture 3: H2 bushing core being extracted from the porcelain body & flange.

Remaining layers of the Flange and grounded Upper part of the lower part. sleeve region condenser core without damage or flashover Picture 4: Bushing H2: Major parts of the condenser core after extraction.

Remaining layers of the bottom part of the condenser core.

Central copper tube with flashover marks on the bottom end.

Roller device for easy unwinding operation.

Picture 5: Bushing H2 installed on the device for Picture 6: Bushing H2: central conductor tube, after unwinding the condenser core. complete unwinding of the layers of the condenser core ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 6/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Big Hole in the condenser core.

Remaining layers of bottom part of the condenser core Distance from the end of the central copper tube to the Big Hole.

Picture 7: H2 bushing: identification of the major flashover path at the destroyed layers; Contact spot of the grounding tap.

Picture 8: H2 bushing: distance from the end of the central conductor to the voltage tap.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 7/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Burst paper layer surrounding the damaged contact spot of the voltage tap; Picture 9: H2 bushing: Aluminum layer between the ground tap and the voltage tap.

Not damaged Aluminum layer between voltage tap and ground tap; Burnt paper layer over the damaged contact spot of the voltage tap; Burnt contact spot of the Potential tap; Picture 10: H2 bushing: Further Aluminum layer after Test tap and the burnt voltage tap.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 8/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Not damaged Aluminum layer of the voltage tap; Burnt contact spot of the voltage tap; Reinforced contact layer of the voltage tap; Picture 11: H2 bushing: burnt contact layer of the voltage tap.

Picture 12: H2 bushing: Detail of the 2nd layer beneath Picture 13: Red arrow: Treeing traces on the upper (inwards) the voltage tap layer with treeing traces on edge of the aluminum foil; the edge.

Green circle: enlarged area on the picture aside.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 9/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 14: H2 bushing: Further detail of the 2nd layer Picture 15: Red arrow: Treeing traces on the upper beneath (inwards) the voltage tap layer with treeing edge of the aluminum foil; traces on the edge.

Green circle: enlarged area on the picture aside.

Picture 16: H2 bushing: Further detail of the 3rd layer Picture 17: Red arrow: Treeing traces on the upper after (inwards) the voltage tap layer with treeing traces edge of the aluminum foil; on the edge.

Green circle: enlarged area on the picture aside.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 10/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 18: H2 bushing: Treeing traces on the paper Picture 19: Red arrow: Treeing traces on the paper layer underneath the aluminum foil. This is the 4th layer underneath the upper edge of the aluminum foil; beneath (inwards) the voltage tap layer.

Green circle: enlarged area on the picture aside.

Picture 20: H2 bushing: Treeing traces on the edge of Picture 21: Red arrow: Treeing traces on the upper one further aluminum foil layer of the middle portion of edge of the aluminum foil; the intensity of the traces the condenser core; became lighter on the layers closer to the central Green circle: enlarged area on the picture aside. conductor.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 11/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 22: H2 bushing: Treeing traces on the edge of Picture 23: Red arrow: Treeing traces on the upper one further aluminum foil, one layer beneath the middle edge of the aluminum foil; the intensity of the traces portion of the condenser core; became gradually lighter on the layers closer to the Green circle: enlarged area on the picture aside. central conductor.

Picture 24: H2 bushing: Very light treeing traces (red Picture 25: Green circle: Upper (internal) edge of a arrows) on the edge of one aluminum foil layer situated bottom aluminum layer; the region of edge of the near to the central conductor of the condenser core; aluminum foil is completely free from treeing traces.

Similar situation was confirmed on the lower (internal) edge of the upper foil All internal edges showed similar characteristic, being free of treeing traces.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 12/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 26: Detail view of the big hole extending down until the 19th layer (red arrow) (reckoning from the inner conductor outwards); Green circle: Discharge path, beginning on the hole.

Picture 27: H2 bushing: Picture 28: H2 bushing:

Red arrow: Bottom of the big hole Green circle: discharge path; Green arrow: 21th layer (2 layers above the 19th) Red arrow: Bottom of the big hole Green arrow: 20th layer (1 layer above the 19th)

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 13/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 29: H2 bushing: Picture 30: H2 bushing:

Green circle: discharge path; Orange circle: traces on the bottom edge of the 18th Red arrow: Bottom of the big hole layer; Green arrow: remaining part of the 19th layer touched by Green arrow: 18th layer (1 layer beneath the 19th) the discharge.

Picture 31: H2 bushing: Picture 32: H2 bushing:

th th Green arrow: 18 layer; Measuring the diameter of the 18 layer; Red arrow: Bottom of the big hole Red arrow: Bottom of the big hole Green circle: discharge path also visible by mechanical Green arrow: 18th layer;

& burnt marks on the 18th layer.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 14/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 33: H2 bushing: Picture 34: H2 bushing:

th th Green arrow: 18 layer; Orange circle: lower part of the 17 layer with slight Orange circle: upper edge of the 18th layers bottom part treeing traces on the bottom edge completely free from treeing traces. Green arrow: 17th layer; Picture 35: H2 bushing: Picture 36: H2 bushing:

Green arrow: 2nd layer above the inner conductor; Green arrow: 2nd layer; nd Orange circle: enlarged region shown on picture 36, Orange circle: lower part of the 2 layer with slight with slight treeing traces made visible. treeing traces on the bottom edge.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 15/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 37: H2 bushing: Picture 38: H2 bushing:

Green arrow: 1st layer wound on the central copper Green arrow: 1st layer; st conductor after the required paper thickness is applied; Orange circle: lower part of the 1 layer with slight Orange circle: enlarged region shown on picture 38, treeing traces on the bottom edge.

with slight treeing traces made visible.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 16/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer 3.4 Inspection of Bushing of Terminal H3 (S. No. 05F9080 - 03)

Remaining part of the condenser core destroyed by the flashover Bottom plate of copper with flashover marks.

Picture 39: General view of the H3 bushing showing the bottom part; all layers of the condenser core are complete, only few external paper turns are slightly burnt when the epoxy envelope of the oil side was broken and thrown away due to the mechanical impact caused by the flashover at the bushing H2 on the central phase.

Picture 40: H3 bushing: Picture 41: H3 bushing:

Green arrow: Central copper conductor; Green arrow: Central copper conductor of bushing H3, Red arrow: Discharge mark on the central conductor, upper part.

occurred after explosion of H2 bushing; ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 17/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Outer paper layers damage during extracting the core from the bushing flange. Contact spot of the Test Tap.

Contact spot of the Potential Tap.

Picture 42: Bushing H3: detail view of the flange region, showing the contact spots of the Test

& Potential taps without damage.

After taken away the grounded layers corresponding to the voltage and ground taps, the first layer below the voltage tap layer showed intense traces at its lower edge, as shown in the pictures below:

Picture 43: H3 bushing: Picture 44: H3 bushing: enlarged detail of the 1st st

1 layer beneath the voltage tap layer; layer; Red circle: region enlarged (Green arrow) on photo Red circle: detail of treeing traces clearly shown at the

1. 44, with clear treeing traces at the bottom edge of the lower edge of the layer.

1st layer beneath the voltage tap.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 18/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 45: H3 bushing: further detail of the 1st layer Picture 46: H3 bushing: detail view of the layer beneath the voltage tap layer:; beneath the voltage tap:

Red circle: region enlarged on the photo #46 (Green Red circle: detail of treeing traces clearly shown at the arrow) with clear treeing traces at the bottom edge of lower edge of the layer.

the 1st layer beneath the voltage tap.

Picture 47: H3 bushing: detail of the 1st layer beneath Picture 48: H3 bushing: detail view of the upper edge the voltage tap layer, upper edge of the upper foil: of the upper foil of the layer beneath the voltage tap:

Red circle: region enlarged on photo #48 (Green arrow) Red circle: detail clearly shows treeing traces at the These treeing traces are lighter than those at the upper edge of the upper foil. These are lighter than bottom edge of the bottom layer beneath the voltage tap. discharge traces on bottom edge of bottom foil.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 19/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 49: H3 bushing: detail of an intermediate layer Picture 50: H3 bushing: detail view of the bottom halfway between the voltage tap layer and the central edge of the lower foil of the intermediate layer conductor, bottom edge of the lower foil: Red circle: detail of the clear but slighter treeing Red circle: region enlarged on photo #50 (Green arrow) traces, where it is visible that the traces are more intense lighter treeing traces observed than traces observed on at the corners created by small folding of the aluminum the layer just beneath the voltage tap. foils (red arrows).

Picture 51: H3 bushing: detail of the innermost layer Picture 52: H3 bushing: detail view of the bottom st (1 layer over the central conductor), bottom edge of the edge of the lower foil of the innermost layer:

lower foil: Red circle: detail of the clear but slighter traces, where it Red circle: region enlarged on photo # 52 (Green is visible that the treeing traces are more intense at the arrow) with clearly visible treeing traces. corners created by small folding of the aluminum foils (red arrows).

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 20/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Upper edge bottom foil of the innermost layer: no traces even at the small Innermost corners of the foil folding. aluminum foil.

Picture 53: Bushing H3: detail view of the innermost aluminum foil (1st layer over the central conductor),.

No treeing traces are visible at the internal (upper edge) of the lower foil.

5. Most Probable Failure Path A drawing with the schematic sketch of the structure of the condenser core of the investigated bushing is shown on the picture indicated on the Attachment 1.

Condenser grading Condenser grading configuration on the Grounded layer configuration on the lower upper (air) side with the (oil) side, with the higher lower field stress; field stress; Central conductor, 100% rated potential.

No electrical Field stress on the inner foil edges Sketch 2. View of the longitudinal half section of the condenser core, showing the main elements and detail of the regions with capacitive grading.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 21/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer In the following items, the most probable failure path is explained:

5.1 The treeing on the lower edge of the layers on the bottom part (oil side of the bushing) of the condenser core is more intense than on the upper part (air side of the bushing).

Remark: The treeing activity within the insulation will not sustain initial partial discharges at a level sufficient to generate overall bushing failure.

First partial breakdown between neighboring layers Sketch 3. The highest electrical field stress at the edge of each layer is radially inward (e.g. in direction of the next inner layer) Therefore, the partial breakdown between two layers tends to grow inwards.

5.2 As the treeing continues to extend along the paper fibers, the insulation system is weakened resulting in a distorted electrical grading at the edge of the aluminum foils.

5.3 Sporadic system overvoltages imposed on the weakened insulation result on partial discharges (PDs) of substantial energy to create the first puncture between layers, establishing a carbonized (e.g. semi-conductive) path between layers.

5.4 Consequently at this point the PDs melt the aluminum foil underneath and begin to damage the paper layers underneath. As soon the overvoltage stops, the partial discharge also extinguishes.

5.5 When further overvoltages will occur, the gassing in the oil and byproducts from the paper degradation produces the weakening of the insulation of the remaining paper layers underneath.

5.6 When the remaining paper layers cannot withstand the electrical field stress to the next aluminum layer, a further puncture will occur, enlarging the semi-conductive path in direction of the central conductor.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 22/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer 5.7 Consequently, each following normal overvoltage will cause the repetition of the phenomenon between the second and third layer, then between the third and forth layer and so layer-to-layer breakdown continues inwards.

Note: The stress between layers increases in the same proportion when the carbonized path progresses and successive layers are short circuited.

5.8 After a certain number of layers are short circuited by the mentioned carbonized path, PDs initiated by an overvoltage will no longer extinguish. This is because the voltage stress between layers is raised to the point where normal operating voltage maintains the PD activity.

These layers are short-circuited by the partial discharges Electrical Field Stress at the remaining layers increase proportionally Sketch 4. Once established, the partial discharges do not extinguish and continuously grow inwards.

5.9 Now, having the PD activity no more extinguished, the progression of the phenomenon of short circuiting further layers goes faster and faster, also bringing the ground potential closer to the 100% potential of the central conductor.

5.10 The progression of the partial discharge activity continues inwards and stops when the inner edge of the aluminum layers is touched. At this point a critical condition is reached at the outer (bottom) edge of the foil at the lower part of the bushing, where the field stress gets so high that a pre-breakdown in the oil is generated.

5.11 This pre-breakdown activity rapidly escalates to a discharge toward the central conductor, which is at the 100% potential.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 23/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer A full flashover is initialized at the outer (lower) side of the foil This complete portion assumes the ground potential Partial discharges reaching the inner edge of the aluminum foil Sketch 5. When the partial discharges reach the inner edge of one foil, there is no further radial breakdown between layers which can be established. But the electrical field stress at the lower edge on the outer side of this foil is now extremely high, initializing a full flashover to the central conductor.

5.12 Finally, the discharge expands until it reaches the grounded flange. This establishes a high energy flashover between the central conductor and the bushing flange. The pathway travels axially through the 19th layer, rupturing the external paper layers and causing the explosion of the oil side of the bushing. This final high energy discharge results in external electrical failure.

The flashover also propagates in direction of the bushing flange The full flashover completely destroys this portion of the bushing High energy flashover between ground and 100% potential Central conductor Bottom plate Sketch 6. The flashover reaches the central conductor and establishes the high energy discharge between 100%

potential and ground. An explosive thermal oil expansion occurs, making the lower part (oil side) of the bushing to rupture.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 24/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer

6. Observations During the tear down of the failed bushing of the middle phase of the Unit #22 transformer, treeing traces were detected on the upper edges of the foils above the flange region of the condenser core. Only the innermost layers of the lower part (oil side) could be inspected, as from the 19th layer outwards the condenser core was mostly destroyed by the high energy flashover.

The second bushing which was inspected, belonging to the C phase showed the same type of treeing traces at the upper part (air side) of the bushing. In addition, the lower portion of the condenser core showed the same treeing marks. It was noted that these were clearly more intense than those within the upper portion of C phase.

This is explainable as, by construction, the electrical field stress at the lower part of the condenser core (oil side of the bushing) is significantly higher than the field stress at the upper part of the condenser core (air side of the bushing).

In contrast, at the edge of the inner side of the foils (refer to Sketch 2) no treeing marks were detected at all. This is consistent with the fact that there is no significant electrical stress occurring at the internal edges of the foils.

These observations suggest that the formation of the treeing traces is related to the presence of an electric field.

The proposed path for the failure as indicated in section 5 is consistent with the findings at the failed bushing. That is, the presented failure path matches with the findings observed in the field (refer to Technical Report ST 19/01dd. January 17, 2011) as well as those verified during the bushing tear-down, as reported herewith.

These facts suggest that most probably some abnormal condition related to the insulating system of the condenser core, involving the oil as well as the paper layers was a contributing factor to the bushing failure.

The investigation about the causes of the mentioned abnormality in the bushing insulating system is still ongoing and will be reported separately. This may give some insight about the ultimate root cause of this phenomenon.

As the root cause analysis is only at an early stage, it is not yet known what factor(s) have created the abnormality in the bushing that led to its electrical failure. Complete investigation may require specialized research such as additional (non-standardized) oil testing, search for contaminants in other bushings removed from service, etc.

Since this is first and only failure reported for this type of TRENCH bushings, it is not yet clear what tasks will be required to fully explain failure cause.

Overall failure investigation will take several months and will certainly require more data from in-service bushings than what is available from the spare bushing installed in the MT 32 as well as those bushings installed on bus MT 22.

ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 25/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer

7. Various Failure Hypotheses Several possible causes of failure have been considered during this investigation. This section describes the various possibilities (and any resolution that has occurred as of the issuance date of this report - 11March 2011.)

A) External system event As a result of a ruptured MPT 21 transformer tank, there was an oil fire and damage to the overhead buswork. An external system event was considered as a possible failure cause. This was due to arcing along broken buswork, reports of possible flashes in the adjacent switchyard and evidence of a post insulator flashover next to the failed transformer phase B.

As a result of this investigation, the flashover along the porcelain of the insulating post of the phase B 345 kV bus appears to be only a consequence of the fire ball which involved the post. In addition, the possibility was considered that bushing explosion could be initialized solely due to a transmission overvoltage event (i.e. external to the transformer.)

Unfortunately, transient records of system events prior to and during the transformers failure are incomplete and a definitive conclusion could not be reached (for example, it was not possible to consider lightning activity and possible transient overvoltages which occurred some days or weeks prior to the transformer failure.) However, the presence of insulation treeing within the MPT 21 bushings probably excludes the possibility of this initial hypothesis.

B) Transformer design and manufacturing The possibility of a design or manufacturing defect was also considered as a possible failure scenario. This hypothesis was discussed extensively in the initial failure report #ST_19Jan2011 and excluded therein. Briefly summarized, this hypothesis was disproved by DGA data and during inspection of the failed transformers core and coils. The two factors were:

1) IPEC monitoring data clearly indicated that active part of the transformer (Core & Coils, together with its insulating system) was completely healthy until 2 1/2 hours before flashover at the H2 bushing. This statement is based on DGA results of the on-line gas monitoring device installed on the tank, which periodically analyzed MPT21 transformer oil (every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />).

2) Visual inspection revealed a lack of Core & Coil damage. All physical displacement and fire damage of leads, bushing supports and other ancillary parts within the tank was attributed to the oil surge during tank rupture and consequent fire damage. The physical evidence indicates that transformer #21 itself was not the initiating cause of failure.

C) Abnormality in insulation within bushings condenser core Since the treeing traces were not present at the time of winding or processing of the bushings active part, it is reasonable to believe that such traces developed during the number of years that the bushing was in service.

Preliminary laboratory analysis of the paper samples indicates the presence of copper in such traces and did not find indication of charring or partial discharge activity in the area. The copper most likely comes from the centre conductor as there are no other sources of this material inside the bushing.

Considering the above findings, the hypothesis is presented that a reaction may have occurred inside the bushing. Because root cause analysis of the bushing is only at an early stage, it is not yet possible to identify various mechanisms which might have contributed to the insulation abnormality. Overall failure investigation may take several months, and is dependent on access to ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

PHOTOGRAPHICAL REPORT ST 02/11 Inspection of TRENCH Bushings - Jan 18/2011 Page 26/26 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer the spare bushing installed on unit MT 32 as well as those bushings installed on unit MT 22.

Complete understanding of the failure mechanism will certainly require more data from in-service bushings, in addition to that which is available from IPEC units.

D) Bushing Insulation Treeing, followed by PD enhancement from system OV This hypothesis is being presented based upon observations obtained during the bushing teardown described in report sections above.

All three MPT 21 bushings were taken apart and inspected and all showed the same type of treeing on the edge of foils at the upper part (air side) and lower part (oil side) of the bushings. In areas of higher electrical stress, the treeing was clearly more intense. This suggests that the formation of the traces is related to the presence of an electric field.

It is important to note here that this hypothesis requires interaction between a pre-existing insulation abnormality and a normal, arrester-protected system overvoltage transient. The scenario is based upon the fact that treeing traces observed during bushing teardown do not appear to show signs of partial discharge activity. If such a situation is generally true throughout affected bushings, this would mean that initial treeing activity cannot support partial discharge at operating voltage. Therefore, insulation breakdown would also require an initiating overvoltage event.

Therefore, in this hypothesis repeated cases of normal system overvoltage are required to initiate partial discharge at the observed insulation abnormalities.

Root cause analysis of the bushing insulations abnormality is only at an early stage, and will be reported upon in subsequent report(s). It is not yet known what factor(s) have created the abnormality in the bushing that led to its electrical failure. Since this is first and only failure reported for this type of TRENCH bushings, it is not yet clear what tasks will be required to fully explain failure cause.

8. Monitoring and Replacement Recommendations For monitoring and replacement recommendations please see the attached statement from TRENCH.

9. Attachment List Attachment 1: Schematic structure of the investigated Condenser Bushings ENTERGY-TRENCH Bushing Inspection - Photo Report_ST02 11_FINAL.doc Issued by: SIEMENS / TRENCH Date: March 11, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 1/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer

1. Equipment Data Ratings: Three Phase Generator Step Up Transformer Power Rating: 372/449,6/562 (629) MVA Cooling: ONAN/ONAF/ODAF Frequency: 60 Hz HV: 345 +2x2,5% -2x2,5% kV (DETC) - YN Rated Voltages:

LV: 20,3 kV - D Customer: ENTERGY ENTERGY NUCLEAR NORTHEAST - INDIAN POINT ENERGY NY/USA Serial Number #4.019.269 (Unit #21)

2. Scope This report contains the major aspects of the inspections, investigations and tests performed after the event on November 07, 2010, when the H2 bushing (phase B) installed on the unit #21 exploded, rupturing the weld between cover and tank, making vaporized oil get spilled out as a fire ball.

3. History Two units were manufactured in 2005; final electrical tests were performed on January 2006.

Replacing old units from other manufacturer, these first two units were installed and commissioned at site in 2006:

Unit #21: Serial Number 4.019.269; Unit #22: Serial Number 4.019.272; An additional unit was manufactured in 2009 as a spare (Serial Number 8.324.845), final acceptance tests of this unit performed in May 2009.

The dimensions, arrangement of the cooling system were designed to match within the existing space and be suitable to be connected to the existing LV bus duct.

Two units operate in parallel solidly connected both on the HV and LV side. On the LV side via bus duct which is connected to the single power generator; on the HV side by the common 345 kV bus protected by a single surge arrester per phase, from which point on a regular transmission line transports the energy to the neighbored Substation of CONED, crossing the street.

On November, 7th 2010 at 6:39 pm the unit #21 failed due to an internal flashover at the oil side of the H2 bushing.

This caused an explosion which ruptured the weld between the cover and the transformer tank in front of the H2 bushing. The oil was expelled like a fireball which touched the radiator bank, the firewall, as well as the HV surge arrestor and post insulator of the central phase (B phase).

The event triggered the intervention of the fire brigade, which successfully extinguished the fire in few minutes. During this operation a second explosion occurred, minutes after the first, when the transformer was completely off circuit (disconnected by the 345 kV circuit breaker and disconnect switches and the generator shut down at the LV side). This second explosion was interpreted as FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 2/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer an ignition of the oil mist formed inside the tank, triggered by the remaining heat of the former explosion.

The oil was completely spilled out of the tank due to the rupture of the valves of the cooling system caused by the mechanical impact of the explosion.

The sister unit #22 was not touched by this event, as it is separated from the damaged unit by a firewall.

4. Analysis of the Sequence of Events The Picture 1 was taken on November 08, 2010, one day after the event and shows the main components of interest for the analysis of the event occurred with Unit #21.

345 kV Surge 345 kV Line Arresters Cables 345 kV Bus 345 kV Post insulators Unit #21 Unit #22 Firewall Broken 345 kV Bus tube connector Picture 1: General view of the transformer yard showing the main involved components.

The analysis of the sequence of events (see Attachment 1) showed that the circuit breaker on the 345 kV opened very quickly after ~3 cycles, triggered by the Buchholz relay trip of Unit #21.

Both units #21 & #22 are solidly connected at the LV side to the main generator of nuclear power plant. According to information of ENTERGY, the excitation of the generator was cut down immediately upon receiving the trip signal from Unit #21.

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 3/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Considering that the excitation of the main generator takes approximately one second to be reduced to less than 20% of the rated level, during this period of time the HV terminals of both units remained with high potential. This is valid even for the unit #21, as its windings were not damaged by the event as confirmed later.

Thus, the voltage on terminal H2 sustained the arc on the phase B bushing of unit #21, which vaporized the surrounding oil and expelled it like a fire ball through the ruptured weld of the tank cover.

The fire involved the radiator bank, the post insulator of the phase B installed on a beam over the radiator battery, also hitting the firewall on the top on which the 345 kV surge arresters are installed.

Flashover marks were identified on the post insulator of phase B. Whether this flashover occurred some time before the event and triggered the failure of the H2 bushing of Unit #21 or this flashover was a result of the ionized air of the fireball could not be clarified until now. Eventually the dissection of the failed bushing may bring additional evidences about this question.

It has to be considered that the Units #21 & #22 are equipped with an on-line monitoring device (TRUE-GAS) which performs an on-line oil analysis for dissolved gases (DGA) every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This on-line gas monitor showed perfectly stable values until ~2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> before the event.

(see Attachment 2).

The records of the on-line monitoring device verify that no internal event inside the transformer was detectable until close to the failure occurrence.

On the other hand, it has to be considered that the bushing oil is completely separated from the transformer oil. The oil space inside the bushing is a sealed container, where oil volume expansion due to heat is absorbed by a gas space situated in the bushing head. Thus, the on-line gas monitor of the transformer oil cannot detect any gas evolution inside the bushing oil. This means, any pre-damage ongoing in the insulating system of the bushing cannot be detected through the monitoring of the transformer oil.

5. Inspection of the damaged Unit #21 5.1 Inspection on the External Parts The flashover at the oil side of the H2 bushing caused an explosive pressure wave inside the tank which ruptured the weld between cover and tank in front of the middle phase (Picture 2 & 8).

Other consequential damages (caused by the tank wall at the HV side bowing out) were found at several points of the tank reinforcements (Picture 5 & 6).

The shock wave throughout the tank ruptured also the bottom main valves of the cooling system.

This caused complete drainage of the oil, which continued to spill out until reaching the level of these valves (Picture 3 & 4).

Also the porcelain of the neutral bushing installed at the tank wall was broken by the shock wave (Picture 7).

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 4/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 2: Damaged tank of the Unit #21 after the occurrence:

Red arrow: Ruptured tank & cover weld caused by the shock wave produced by the flashover on the oil side of H2 bushing.

Picture 3: Red arrow: ruptured cooling system 12 valve Picture 4: Red arrow: ruptured cooling system 12 valve FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 5/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 5: Red arrow: mechanical stress marks on the Picture 6: Red arrow: mechanical stress marks on the corner of the tank frame; bottom end of the vertical tank reinforcements; Picture 7: Arrow: Neutral bushing (H0) broken porcelain; Picture 8: Detail of the ruptured tank & cover weld; Picture 10: Red arrows: 345 kV bus disrupted due to Picture 9: Radiators and fans were involved by the fire; the connector broke apart by the mechanical impact; Blue arrow: H2 bushing (Phase B);

Brown arrow: Insulating post for the 345 kV bus; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 6/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 11: Picture 12: Red arrow: Broken connector of 345 kV bus; Red arrows: Showing the parts of the connector which Blue arrows: Damaged porcelain of the insulating post for was broken due to the mechanical impact of the shock the 345 kV bus; wave caused by the flashover on the H2 bushing; Orange circle: Space between the radiator banks in front of the phase B bushing, allowing the propagation of the Blue arrow: Insulating post for the 345 kV bus; expelled fire ball until the surge arrester installed on the top of the fire wall (Green arrow)

Picture 13: Red arrows: The grounding lead insulation Picture 14: Red arrows: The plastic covering of the was melted by the fire, rather than by a short circuit grounding leads melted away but the copper isnt current to ground: the plastic covering of the grounding discolored,. Therefore no heavy fault current to ground strips is melted only at a single side; circulated during the event through these components.

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 7/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 15: Red arrow: Damaged top connector of the Picture 16: Red arrows: Crack on the flange of the H3 H2 Bushing (Phase B) Bushing (Phase C) caused by the shock wave.

5.2 Internal Inspection: HV Bushings and DETC The internal inspection was performed by the Siemens Field Engineer after the atmosphere inside the transformer was thoroughly flushed with dry air. The transformer was released with healthy conditions of Oxygen content and adequate levels of other gases by a gas monitor.

It was confirmed that a flashover occurred inside the H2 bushing. This destroyed completely the bushings oil side portion (i.e.between the tank cover and the internal lead connection). Several flashover marks were found at its bottom plate made of copper and also on the nearby grounded parts of the phase B (turret and upper core frame) (see Pictures 17 & 18).

The shielding electrode which was installed on the lower end of the bushing was forced downwards by the heavy pressure surge created inside the oil. This was due to the explosive expansion of the gases caused by the flashover inside the bushing and due to the oil being expelled through the tank rupture in vicinity of the H2 bushing (see Picture 17 & 18).

This shielding electrode is installed at the lower end of the bushing to provide electrical shielding to the bottom plate and also to the flexible connection leads bolted to the bottom plate. A specific report was issued on this matter of the shield displacement (see Attachment 3 - Technical Report ST15/10).

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 8/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 17: Red arrow: Bottom plate of the H2 Bushing; Picture 18: Red arrows: Flashover marks on the Blue arrow: remaining insulation its condenser core; grounded parts around H2 bushing (on frame and turret);

Green arrow: Shielding electrode forced downwards; Blue arrows: Arcing marks on the bushing bottom plate; It was observed that also the bushings of the outer phases were heavily damaged. This physical damage appears to be due to ignition of oil, and the electrical discharges occurred after failure of the phase B bushing:

- The Phase C bushing had its lower insulating shell made of epoxy resin broken; several discharge marks were also visible on the bottom plate and surrounding grounded parts;

- The Phase A bushing had its epoxy shell heavily burned by the flashover at phase B; several foot points of discharges were also visible on the bottom plate.

It has to be pointed out that those flashover foot points (arcing marks) on the phases A and C were caused at the instant when the explosion on phase B bushing occurred. This created a shock wave followed by ionized gases. When this gas bubble hit the outer phases, further electrical flashovers occurred.

As the windings of the Unit #21 were intact even after the H2 bushing failed, the HV bushings of all three phases still presented a high voltage potential. This is because the main generator had its excitation shut down, but the magnetic circuit maintained its output voltage for a period of approximately one second (~60 cycles).

Thus, the sustained potential on all three HV bushings was sufficient to create the subsequent flashover events on all three phases.

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 9/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 19: H3 (Phase C) H3 Bushing: Picture 20: Red arrows: Flashover marks on the Red arrows: Flashover marks on grounded parts; grounded parts of the H3 bushing; Blue arrow: Condenser core without its epoxy shell; Blue arrows: insulating layers of the condenser body; Green arrow: Shielding electrode dropped downwards; Green arrows: Supporting spacers for the bushing CTs.

Picture 21: H1 (Phase A) H1 Bushing: Picture 22: H1 (Phase A) H1 Bushing:

Red arrow: Flashover marks on grounded parts (turret); Red arrows: Flashover marks on the grounded parts of Blue circle: Epoxy shell at the oil side heavily burned; the H1 bushing turret; Green arrow: Shielding electrode still in place; Blue arrow: Inner part of the phase A turret; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 10/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 23: DETC on HV winding: Picture 24: DETC on HV winding:

Red arrow: HV neutral point outlead connection without Green circles: Both contact groups of the DETC didnt any damage, flashover or burning marks; show any damage or displacement; Blue arrow: Slider of the DETC didnt show any damage; Blue arrow: Slider of the DETC didnt show any Green circle: The contact group of the DETC didnt show damage; any damage or displacement; Red arrows: HV tap outleads for the DETC; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 11/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer 5.3 Internal Inspection: HV Windings During the internal inspection only the upper part of the HV winding was accessible.

Even so, it could be verified that the HV windings of all three phases did not show any damage as a result of the bushing failure. This included absence of any flashover mark or any distortion caused by heavy short circuit currents.

This situation confirms adequacy of the transformers design, according to the calculation of the short circuit currents. These circulating currents passed through the several parts of the involved circuit during the heavy flashover event on the phase B and also some consequential flashover occurrences at the phases A and C.

The short circuit calculation (see Attachment 4) performed by the ENTERGY specialist showed, as expected, that the main short circuit contribution during the first ~4 cycles of the event came from the 345 kV network (~20kA). This flow was from the network through the damaged bushing to ground. In contrast, the contribution from the main generator flowing through the windings of both transformers (as they are solidly paralleled on the LV side) was only 10% of this value (~2 kA). It was restricted by the sub-transient impedance of the main generator, in series with the impedance of the transformers.

After the 345kV circuit breaker cleared the 345 kV network from the power plant, the high potential at the HV bushings of all three phases was sustained only by the remaining magnetization of the main generator, as already mentioned in the foregoing item.

This situation caused several flashover events between the bushing bottom plate and the grounded parts, as the upper part of the tank was filled with ionized gas generated by the flashover, as explained under item 5.2.

These secondary flashover events extinguished only when the voltage supplied by the generator dropped to less than 20% of its rated value, which most probably occurred approximately one second (~60 cycles) from the main event on the H2 bushing.

The pictures on the following page show the parts of the windings which could be accessed.

FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 12/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Picture 25: Top of the HV winding: Picture 26: Top of the HV winding:

Red arrow: Debris of burned paper coming from the Green circles: ; No bending of the HV winding bushing flashover; conductors was detected, demonstrating that no Blue arrow: Pressboard spacers on the top of the HV remarkable short circuit forces occurred during the winding; flashover event; Green circle: Showing carbonized debris resulting from Blue arrow: Pressboard spacers on the top of the HV the flashover; no bending of the HV conductors was winding; detected, demonstrating that no remarkable short circuit Red arrow: HV winding outlead on the uppermost disk forces occurred during the flashover event; connecting to the neutral point (H0 Terminal);

Further pictures of the surroundings of the windings:

Picture 27: Top of the HV winding Phase B: Picture 28: External part of the HV winding:

Red arrow: Shielding electrode of the H2 bushing as well Green circle: Pressboard cylinder involving the HV as some paper debris of burned paper coming from the winding; no damage was observed; bushing flashover; Blue arrows: Outleads from each half (upper and lower Blue arrows: Winding pressing elements showing no part) of the HV winding; displacement or misalignment; Red arrow: HV winding central outlead connecting to the Green circle: Pressboard spacers right in place on the top HV phase terminal; of the HV winding, no displacement or misalignment was detected; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 13/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer 5.4 Further Inspections: HV Bushings, 345 kV Bus, Insulator Post of 345 kV Bus After the dismantling from the damaged Unit #21, the HV bushings were inspected; the relevant pictures oft this inspection are included in the Attachment 5.

Also the insulator post which supports the 345 kV bus of phase B was inspected. This is because clear flashover marks were detected both on the porcelain body as well as on the fixing elements of the top and of the bottom of the insulator. For this inspection the relevant pictures are included in the mentioned Attachment 6.

The connector which joins both sections of the 345 kV bus of phase B was broken by the mechanical impact of the shock wave caused by the flashover at the H2 bushing. This separated the bus connector of phase B.

The inspection of the broken connector clearly shows that the H2 bushing explosion caused mechanical shock which ruptured the connector. Even after the bushing explosion there was a significant voltage potential present causing several flashover events between the pieces of the connector as they separated.

All relevant pictures of this inspection are included in the mentioned Attachment 6.

6. Preliminary Observations as of 19Jan 2011 The first output of the investigation and analysis of the evidences related to the failure event. This clearly indicated that the active part of the transformer (Core & Coils, together with its insulating system) was completely healthy until 2 1/2 hours before the flashover at the H2 bushing. This statement is based on the DGA results of the on-line gas monitoring device installed on the tank analyzing periodically (every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) the transformer oil. In addition, the lack of Core & Coil damage indicates that transformer #21 itself was not the initiating cause.

At the time of this inspection of the destroyed transformer, it was not clear whether the explosion of the H2 bushing was caused by an external event or due to deterioration of the bushings insulation.

Subsequent teardown and inspection of the failed bushing showed failure cause to be related to a deterioration of the insulation system of the bushings condenser core.

Further information regarding physical inspection and teardown of bushings from failed transformer unit #21 was obtained after generation of this report. This detail is contained in the report entitled TRENCH Bushing Inspection_Photo Report #ST 2 11.

The flashover along the porcelain of the insulating post of the phase B 345 kV bus appears to be only a consequence of the fire ball which involved the post.

7. Attachment List Attachment 1: Sequence of Events Recorder Report dd. Nov. 08, 2010; Attachment 2: DGA records of the TRUE GAS on line monitoring device; Attachment 3: Technical Report - HV Bushing Shielding Electrode; Attachment 4: Fault Current Calculation; Attachment 5: Photographical Report - HV Bushings; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 19/10 General aspects after Event on November 07, 2010 Page 14/14 ENTERGY -Indian Point - 629 MVA - 3 GSU Transformer Attachment 6: Photographical Report - 345 kV Bus; FINAL_ENTERGY-IndianPont_ST 19 10 (2).doc Issued by: Miethke - E T TR - Technical. Support Date: January 19, 2011

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 1/6 HV Bushing Shielding Electrodes

1. Equipment Data Ratings: Three Phase Generator Set up Transformer Power Rating: 372/449,6/562 (629) MVA Cooling: ONAN/ONAF/ODAF Frequency: 60 Hz HV: 345 +2x2,5% -2x2,5% kV (DETC) - YN Rated Voltages:

LV: 20,3 kV - D Customer: ENTERGY ENTERGY NUCLEAR NORTHEAST - INDIAN POINT ENERGY USA Serial Number #4019269

2. Function of the HV Bushing Shielding Electrodes The shielding electrodes installed around the bottom end of the HV bushing has the function to prevent the connection between the HV outlead and the HV bushing bottom plate be exposed to a high electrical field stress.

Considering that the maximum current of the transformer is around 1100A, the connection of the HV outlead to the bushing bottom plate is done via four flexible copper straps. Thus, this bottom plate as well as the flexible strap and the correspondent bolts have sharp edges, which shall not be exposed to a high electrical field stress.

3. HV Electrode Assembly details The shielding electrode is attached with four bolts to the end plate of the HV solid copper tube. The flexible copper straps which made the connection to the HV bushing bottom plate are brazed to this conductor end flange.

The other ends of the flexible straps are brazed to solid copper terminals, which is then bolted in the bushing bottom plate.

The copper connectors of the flexible straps are the only bolted contact between HV bushings and HV winding outleads.

Bushing bottom Connectors bolted plate to the bottom plate Flexible copper HV outlead end straps attaching plate HV shielding electrode HV electrode supporting plate Picture 01 - ProE View Shielding Electrode ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 2/6 HV Bushing Shielding Electrodes The HV winding outleads are made of copper tubes with a thick paper insulation supported in many points, as it is visible in the Pictures 02 and 03. The supported HV winding outleads alone provide a self-supporting structure to the HV shielding electrodes HV shielding electrodes HV winding outleads Picture 02 - General View - Core and Coils Picture 03 - General ProE View of the active part Additionally, the shielding electrode assembly is supported externally by a structure of WEIDMAMANN Transformer Pressboard, manufactured of pure compressed long fiber cellulose.

ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 3/6 HV Bushing Shielding Electrodes This structure is composed by a split ring around the electrode and two supporting arms, which provide the required clearance between the electrode (100% potential) and the grounded parts of the frame.

Each arm is bolted (using two bolts) to a steel plate welded to the upper frame.

See Picture 04 below.

Pressboard ring HV shielding preventing damage to electrodes the shielding electrode.

Flexible copper straps with connecting HV electrode split terminal. insulating ring HV winding outlead (copper insulated tube)

HV electrode supporting arms Picture 04 - Shielding Electrode All this structure is designed to withstand to the maximum forces caused by an external short circuit.

The insulation on the upper part of the electrode is also protected by a solid pressboard ring, which prevents the bottom plate of the bushing to damage the electrode insulation when lowering the bushing into the transformer.

ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 4/6 HV Bushing Shielding Electrodes

4. Assembly details Installing the HV bushing into the turrets, it must be observed that the bottom plate cannot damage either the CT insulation or the insulation of the shielding electrode.

Approximately 10 inches before the flange makes contact with the turret, the internal connection of the flexible copper strap to the bottom plate shall be done.

This step is uppermost important to be enacted for the two outside phase bushings, which are installed at an angle to the vertical.

When lowering the bushings into the final position, is shall be observed that the flexible strap fits completely into the shielding electrode and that the bottom plate of the bushing reaches its specified penetration into the shielding electrode.

5. Critical Analysis of the possible Failure Mode of the Shielding Electrode The two independent supporting systems of the shielding electrode prevent the electrode dropping down, making impossible the bushing bottom plate getting uncovered.

Even in a very unlikely event of a shielding electrode getting loose, this condition would cause some partial discharges be onset at the bushing bottom plate.

The generation of fault gases caused by the partial discharges would be promptly detected by the on-line gas monitoring device. (THRU-GAS)

The traces of this device showed a perfectly stable condition very close to the event (about 2:30 hours before the flashover event). Also the off-line DGA results taken two month before (September 01, 2010) the event showed stable results, without any concern about fault gases.

Thus the transformer itself was in a good shape until the occurrence of the internal flashover event.

6. Analysis of the internal Flashover Event The flashover inside the bushing punctured its condenser body and hit the grounded metallic flange extension (see Picture 05).

This flashover caused an explosive rupture of the insulation shell installed on the bottom part of the bushing. Consequentially, the very steep pressure wave generated by the explosion displaced the shielding electrode downward, breaking the supporting pressboard arms (see Picture 06).

ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 5/6 HV Bushing Shielding Electrodes Picture 05 - Detail view of failed bushing H2:

Red Line: indicates the arcing trace puncturing the condenser body and hitting the grounded flange extension.

Picture 06 - View of Phase 2 after the flashover event, showing the Shielding Electrode and the supporting pressboard arms damaged by the explosion.

The ionized medium around the bottom part of the bushing caused many secondary discharges between the bushing bottom plate and the grounded parts (see Picture 07)., as the voltage at the HV terminals was sustained for several cycles by the generator even after 345kV circuit breakers cleared the transformer from the transmission line.

ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

TECHNICAL REPORT ST 15/10 ENTERGY Indian Point - 372/449,6/562(629) MVA - 3 GSU Page 6/6 HV Bushing Shielding Electrodes Picture 07 - Detail view of failed bushing H2:

Red Arrows: indicates the arcing marks on the bottom plate.

7. Conclusion The DGA results show that there was no disturbance at the internal part of the transformer previous to the flashover event.

It is concluded that the HV shielding electrodes of all three phases were sound until the occurrence of the internal flashover event.

It can be noted that the bushings and shielding electrodes installed on unit MT 22 are of duplicate design to that described above for MT 21. Also, on-line gas monitoring of MT 22 shows similar stable behavior as the DGA monitoring of MT 21. (See section 5 above for discussion of the significance of stable DGA observations with respect to proper orientation of shielding electrode.)

It is reasonable to conclude that shielding electrodes and bushing bottom plates were in correct position in both MT 21 and MT 22, prior to the internal flashover within MT 21.

Therefore, Siemens has made the recommendation that the benefits of oil draining and internal inspection of MT 22 were minimal, and did not justify the possible negative impact such draining would create (that is, a lengthened outage duration.)

____________________________ ___________________________

Bernd Rudolf Wilhelm Miethke Tamyres Luiz Machado TECHNICAL SUPPORT TECHNOLOGY DIRECTOR ATTACHMENT 3_ HV Electrode Report_ST15 10.doc Issued by: Adriano / Miethke Date: Nov 19, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 1/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer

1. Scope This Photographical Report contains the relevant pictures obtained during the external inspection of the HV Bushings manufactured by TRENCH / Canada, which were directly involved with the event occurred on November 7th 2010 with the Step up transformer 629 MVA installed on the ENTERGY Nuclear Plant at Indian Point -NY/USA.

Remark: the pictures of the inspection of the Insulating Post supporting the 345 kV buses which interconnects the HV terminal of both Units #21 & #22 as well as the pictures taken from the connector which joins the two sections of the 345 kV buses and which broke making the two section fell apart during the flashover event are contained in the Attachment 6.

2. Pictures of the HV Bushing Inspection Type of the HV bushings: 1175 - F020-23-AG3-02-AEP, LI Level: 1175 kV, manufactured in 2005; The Serial Numbers of the HV Bushings which were installed on the Unit #21 are:

05F908001assembledinH1

05F908004assembledinH2

05F908003assembledinH3

After the bushings were disassembled from the damaged transformer, they could be inspected in respect of the external damages occurred due the flashover at the bushing installed in phase B.

Picture 1: Nameplate of one of the bushings installed in the sister Unit #22:

Red circle: Year of manufacturing: 2005.

ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 2/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Phase A Phase C Phase B Picture 2: General view of the bushings after disassembled from the Transformer Unit #21 2.1 Pictures of the H2 Bushing (Phase B)

The bushing installed on H2 (Phase B) experienced an internal flashover, which made the epoxy shell being ruptured, causing a explosive shock wave inside the oil, which ruptured the weld between cover and tank wall. The tank wall itself bowed outwards.

As the flashover was sustained for approximately one second (~60 cycles) by the remaining magnetic field of the main generator, the oil was expelled as a dust from the tank an immediately caught fire, involving the radiator banks, the insulating post sustaining the 345 kV bus phase B connected to the H2 bushing.

Picture 3: General view of the bushing H2:

Red circle: Area with the puncture to inner layers; Orange arrows: Discharge trace on the remaining layers; Blue circle: Flashover foot points on the bottom plate; ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 3/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Inside the tank, the ionized atmosphere of the burning oil mist made several flashovers to be produced between the bottom plate of the bushing and the surrounding grounded parts.

Picture 4: General view of the bushing H2:

Red circle: Area with the puncture to inner layers; Orange arrow: Remaining layers of the condenser body; Blue circle: Flashover foot points on the bottom plate; Picture 5: Detail view of failed bushing H2:

Red Line: indicates the arcing trace puncturing the condenser body and hitting the grounded flange extension.

ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 4/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 6: Further view of the bushing H2:

Red circle: Area of the layers destroyed by the flashover; Orange arrows: Further flashover foot points on the bushing flange extension; Blue arrow: Remaining layers of the condenser body; Picture 7: View of the H2 bushing head:

Red circle: The bushing head was distached from the porcelain as the lower epoxy shell was destroyed by the internal flashover; Orange arrows: Porcelain sheds; Blue arrow: Bushing head; ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 5/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer 2.2 Pictures of the H3 Bushing (Phase C)

The bushing H3 (installed on Phase C) had its lower epoxy shell mechanically destroyed by the shock wave caused by the explosion of the bushing H2.

Picture 8: View of the H3 bushing:

Red circle: Condenser body partially damaged, without the epoxy shell destroyed by the flashover on the H2 bushing; Blue circle: Flashover foot points between bottom plate and surrounding grounded parts; Green arrow: Part of the bushing flange that was broken by the mechanical impact of the pressure surge inside the tank; Picture 9: View of the H3 bushing bottom plate:

Red circle: Foot points caused by several flashover strikes occurred after the H2 event; Blue arrows: Flexible connection leads cut away during the dismantling of the bushing; Green arrow: Oil circulation hole on the central conductor; ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 6/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 10: View of the H3 flange extension region:

Red circle: Foot points on the grounded flange extension caused by flashover events occurred on the condenser body ;

Blue arrow: Discharge traces on the condenser body; 2.3 Pictures of the H1 Bushing (Phase A)

The H1 bushing had its epoxy shell heavily burned, but the shell maintained the bushing filled with oil, whereas the other two bushings lost all oil due to the destruction of the epoxy shell on the oil side.

Picture 11: View of the H1 bushing oil side area:

Red circle: Foot points on the bushing bottom plate caused by flashover events to surrounding grounded parts after the H2 bushing explosion; Blue circle: Heavy burning marks on the external surface of the epoxy shell; ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 5 HV Bushings Inspection (ST 19/10)

Page 7/7 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 12: Detail view of the H1 bushing bottom plate:

Red circle: Foot points on the bottom plate caused by several flashover events occurred after the explosion of the H2 bushing; Blue arrow: Heavily burned surface of the epoxy shell at the oil side.

3. Further Investigation The bushings are packed in appropriate crates and stored at the external areas of the Indian Point site, ready to be dispatched for the final investigation by dissection of their condenser core.

These dissections bring some evidences that may clarify the questions about the origin of the explosion of the H2 bushing and thus give the necessary evidences for the root cause analysis.

Once the local and date for the investigation are defined, the bushings will be dispatched in sequence.

ATTACHMENT 5_PhotoReport_HV Bushings.doc Issued by: Miethke - E T TR - Technical. Support Date: December 22, 2010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 1/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer

1. Scope This Photographical Report contains the relevant pictures obtained during the inspection of the 345 kV buses and the post insulator which sustains these buses of the phase B, which were directly involved with the event occurred on November 7th 2010 with the Generator Step Up (GSU)

Transformer 629 MVA 345 kV installed on the ENTERGY Nuclear Plant at Indian Point -NY / USA.

2. Inspection of the 345 kV Bus Connector The connector of phase B which joints the two sections of the 345 kV bus on the right side of the surge arrester broke as a consequence of the mechanical shock caused by the flashover and explosion of the H2 bushing installed at Unit #21.

Consequently, the section connected to the H2 bushing fell apart as shown in Picture1 below and the insulator post was broken at its base, as shown in the pictures of the following item.

345 kV Surge Arresters 345 kV Bus 345 kV Line Cables 345 kV Post insulators Unit #22 Unit #21 Broken 345 kV Bus tube connector Picture 1: General view of the transformer yard showing the main involved components.

ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 2/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer 345 kV Bus tube connector to the bushing terminal of phases A and B Broken 345 kV bus tube connector (Transformer side)

Picture 2: General view of the 345 kV buses after dismantling; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 3/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 3: Detail view of the broken connector of phase B, (Surge arrester side);

Blue circle: Fractured surface with melting points caused by arcing; Red arrows: Flashover marks; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 4/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 4: Detail view of other half of the broken connector of phase B (Transformer side);

Blue circle: Fractured surface with melting points caused by arcing; Red arrows: Melted aluminum deposited on the connector surface, which fell down when the flashover occurred on the braking connector; Picture 5: Detail view of one half of the broken connector of phase B (Surge arrester side);

Blue circle: Fractured surface with melting points caused by arcing; Red arrows: Melted aluminum caused by the flashover occurred between the parts of the braking connector; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 5/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 6: Detail view of one half of the broken connector of phase B (Transformer side);

Blue circle: Tube end with melting & arcing marks; Red arrows: Fractured surface of the connector; Picture 7: Detail view of bus tube of phase B (Transformer side);

Remark: the blackened surface of the tube was caused by the fireball which involved this part of the 345 kV bus after the explosion of the H2 bushing; Red arrows: Melted aluminum deposited on the upper surface of the tube coming from the arcing occurred between the connector parts which broke in consequence of the mechanical shock wave; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 6/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer

3. Investigation of the Phase B 345 kV Post Insulator Picture 8: General view of the Post Insulators:

Red arrow: Phase B insulator, blackened by the dust of the fireball caused by the bushing explosion and which involved the components of phase B; Blue arrow: Phase C insulator, with a clean porcelain surface.

Picture 9: Detail view of the fixing base of the Post Insulator phase B:

Red arrow: Foot points of the flashover which occurred on the post Insulator, before the occurrence of rain; Blue circle: Flashover marks on the fixing base of the Insulator; Brown arrows: Fracture surface of the broken porcelain.

ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 7/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 10: Further detail view of the fixing base of the Post Insulator phase B,:

Red arrows: Foot points of the flashover which occurred on the post Insulator, before they were wetted by rain; Brown arrows: Fracture surface of the broken porcelain.

Picture 11: Detail view of the fixing base of the Post Insulator phase B:

Red arrows: Rusty foot points of the flashover which occurred on the post Insulator, after the occurrence of rain; Brown arrows: Fracture surface of the broken porcelain.

ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 8/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 12: Detail view of the fixing base of the Post Insulator phase B:

Blue circle: Rusty foot points of the flashover which occurred on the post Insulator, after the occurrence of rain; Picture 13: Detail view of the top of the Post Insulator phase B:

Red arrows: Rusty foot point of the top armature after the occurrence of rain; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 9/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Blue circle: Flashover traces on the porcelain surface of the uppermost shed.

Picture 14: Detail view of the intermediate sections of the Post Insulator phase B:

Blue circle: Flashover traces on the upper metallic piece installed between porcelain sections; Picture 15: Detail view of the intermediate sections of the Post Insulator phase B:

Blue circle: Flashover traces on the bottom metallic piece installed between porcelain sections; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

PHOTOGRAPHICAL REPORT Attachment 6 (ST 19/10) 345 kV Bus Inspection Page 10/10 ENTERGY - Indian Point - 629 MVA - 3 GSU Transformer Picture 16: Bottom piece of the Post Insulator phase B:

Blue circle: Flashover traces on the porcelain sheds; Picture 17: Detail view of the bottom piece of the Post Insulator phase B:

Blue circle: Flashover traces on the porcelain sheds; ATTACHMENT 6_PhotoReport_345 kV Bus.docx Issued by: E T TR - Miethke Date: December 22, 201010

Attachment VI Why Staircase Analysis Why did 21MT Fail?

B-Phase HV Bushing Fault Why?

B-Phase HV Bushing Insulation Why?

Vendor Design /

Manufacturing Deficiency RC1

Attachment VII Problem Statement (object/deviation format): 21 Main Transformer Failed POSSIBLE CAUSE (Technically explains IS (Facts Only) IS NOT (Facts Only) DISTINCTION (Facts Only) CHANGE (Facts Only) EXPLAINS ONLY IF (Assumptions) DOES NOT EXPLAIN (Conflicting facts) deviation)

Failure was catastrophic, there was no evidence A 21 Main Transformer 22 Main Transformer A 21 Main Transformer NKC - transformers are sister units of degradation in prior tests B Multiple arc strikes on B phase bushing B #1 "B" Phase bushing failed internally #1 What What conductor. Main Arc Strikes on A or C B Phase initiated event C C B' Phase failure as evident by protective relays.

Overall Unit Differential Phase 'B' (87/GTB) and D A' or 'C' Phases D B' Phase NKC Main Transformer Differential Phases 'B' and 'C' (87/T21B and 87/T21C)

No Evidence of arcing found in routine oil

1. 2 Failure of crib supports for corona shield Evidence of arcing found in prior oil samples #2 samples E E B' Phase failure as evident by location of tank Tank rupture at any other location on the rupture. Tank ruptured at top center below the B' Phase below location of HV Bushing NKC transformer.

location of the 'B' phase high voltage bushing F F Where Where G G There was past evidence thermography hot No thermography hot spots or corona inspection

1. 3 Failure of bushing connectors #3 spots issues.

H H This alarm has been coming in following Occurred within a minute of receiving a increases in Lagging MVARs, this time the alarm I 11/7/10 at 18:38 Automatic Reactor Trip Prior to 11/7/10 (recent history) I Generator High RF Alarm occurred without a corresponding change in MVARs

1. 4 Loss of bushing oil Loss of oil level in bushing #4 When When NKC - monthly transformer oil sample results J Replaced in 2006- early in life cycle Not at initial, middle or end of life. J Early in life cycle have been trending steady, no sudden changes in gassing rate.

K K Catastrophic failure of B phase bushing resulting L Non-Catastrophic Failure L Catastrophic failure NKC in tank rupture and neutral bushing failure Two explosions occurred. One was upon the NKC - CCR verified Breakers 7 and 9 and #5 #5 Unit trip and the second was ~ 10 minutes later. A second explosion occurred after the Unit had disconnect F7-9 were Open at the time of the M One or multiple explosions. M Other than sound no other observations were been tripped for ~10 minutes event. The Generator Field shorting breaker was made of the second explosion. verified Closed on 11/9/10.

Upon initial explosion oil was observed to be Upon initial explosion the tank was observed to N coming out of transformer and flaring up. Upon Sustained Fire N NKC be ruptured and there was fire full actuation of deluge the fire went out.

1. 6 #6 Extent Extent Primary and Backup Pilot Wire Relays for 87L1/345 and 87L2/345, these relays are O Generator Differential (87G or 87G2) O NKC Feeder W95 Tripped (87L1/345 and 87L2/345) outside of the transformer zone of protection B Phase bushing no condenser paper or resing P C phase and A phase P insulation Q Q #7 #7 R R

Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 1 of 8 TABLE 1 - SAFETY CULTURE COMPARISON SAFETY CULTURE CR-IP2-2010-06801 - Unit 2 tripped due to a DESCRIPTION COMPONENT fault in 21 Main Transformer

1. Decision-Making Licensee decisions demonstrate that nuclear safety is an overriding priority: Considered, but not applicable to issue.

2. Resources The licensee ensures that personnel, equipment, procedures, and other Considered, but not applicable to issue.

resources are available and adequate to assure nuclear safety.

3. Work Control The licensee plans and coordinates work activities, consistent with nuclear Considered, but not applicable to issue.

safety:

4. Work Practices Personnel work practices support human performance. Considered, but not applicable to issue.

5. Corrective Action The licensee ensures that issues potentially impacting nuclear safety are Considered, but not applicable to issue.

Program promptly identified, fully evaluated, and that actions are taken to address safety issues in a timely manner, commensurate with their significance.

6. Operating The licensee uses operating experience (OE) information, including vendor Considered, but not applicable to issue.

experience recommendations and internally generated lessons learned, to support plant safety.

7. Self- and The licensee conducts self- and independent assessments of their activities and Considered, but not applicable to issue.

Independent practices, as appropriate, to assess performance and identify areas for Assessments improvement.

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Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 2 of 8 SAFETY CULTURE CR-IP2-2010-06801 - Unit 2 tripped due to a DESCRIPTION COMPONENT fault in 21 Main Transformer

8. Environment For An environment exists in which employees feel free to raise concerns both to Considered, but not applicable to issue.

Raising Concerns their management and/or the NRC without fear of retaliation and employees are encouraged to raise such concerns.

9. Preventing, A policy for prohibiting harassment and retaliation for raising nuclear safety Considered, but not applicable to issue.

Detecting, and concerns exists and is consistently enforced.

Mitigating Perceptions of Retaliation

10. Accountability Management defines the line of authority and responsibility for nuclear safety. Considered, but not applicable to issue.

11. Continuous The licensee ensures that a learning environment exists. Considered, but not applicable to issue.

learning environment

12. Organizational Management uses a systematic process for planning, coordinating, and Considered, but not applicable to issue.

change evaluating the safety impacts of decisions related to major changes in management organizational structures and functions, leadership, policies, programs, procedures, and resources. Management effectively communicates such changes to affected personnel.

13. Safety policies Safety policies and related training establish and reinforce that nuclear safety is Considered, but not applicable to issue.

an overriding priority in that:

Notes 1 RC1: The most probable root cause deals with a vendor design/manufacturing deficiency associated with transformer bushings. There were no safety culture issues identified for this root cause.

2 There were no significant contributing causes identified for this event.

3 4

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Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 3 of 8 TABLE 2 - DETAILED SAFETY CULTURE COMPONENT REVIEW CR-IP2-2010-06801 - Unit 2 tripped due to a fault in Description 21 Main Transformer

1. Decision-Making Licensee decisions demonstrate that nuclear safety is an overriding priority. Specifically (as applicable):

DM H.1(a) The licensee makes safety-significant or risk-significant decisions using a systematic Considered, but not applicable to issue.

process, especially when faced with uncertain or unexpected plant conditions, to ensure safety is maintained. This includes formally defining the authority and roles for decisions affecting nuclear safety, communicating these roles to applicable personnel, and implementing these roles and authorities as designed and obtaining interdisciplinary input and reviews on safety-significant or risk-significant decisions.

DM H.1(b) The licensee uses conservative assumptions in decision making and adopts a Considered, but not applicable to issue.

requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disapprove the action.

The licensee conducts effectiveness reviews of safety-significant decisions to verify the validity of the underlying assumptions, identify possible unintended consequences, and determine how to improve future decisions.

DM H.1(c) The licensee communicates decisions and the basis for decisions to personnel who Considered, but not applicable to issue.

have a need to know the information in order to perform work safely, in a timely manner.

2. Resources The licensee ensures that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety.

Specifically, those necessary for:

RES H.2(a) Maintaining long term plant safety by maintenance of design margins, minimization of Considered, but not applicable to issue.

long-standing equipment issues, minimizing preventative maintenance deferrals, and ensuring maintenance and engineering backlogs which are low enough to support safety.

RES H.2(b) Training of personnel and sufficient qualified personnel to maintain work hours within Considered, but not applicable to issue.

working hours guidelines.

RES H.2(c) Complete, accurate and up-to-date design documentation, procedures, and work Considered, but not applicable to issue.

packages, and correct labeling of components.

RES H.2(d) Adequate and available facilities and equipment, including physical improvements, Considered, but not applicable to issue.

simulator fidelity and emergency facilities and equipment.

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Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 4 of 8 CR-IP2-2010-06801 - Unit 2 tripped due to a fault in Description 21 Main Transformer

3. Work Control The licensee plans and coordinates work activities, consistent with nuclear safety. Specifically (as applicable):

WC H.3(a) The licensee appropriately plans work activities by incorporating

• risk insights;

• job Considered, but not applicable to issue.

site conditions, including environmental conditions which may impact human performance; plant structures, systems, and components; human-system interface; or radiological safety; and

• the need for planned contingencies, compensatory actions, and abort criteria.

WC H.3(b) The licensee appropriately coordinates work activities by incorporating actions to Considered, but not applicable to issue.

address: l

• the impact of changes to the work scope or activity on the plant and human performance.

• the impact of the work on different job activities, and the need for work groups to maintain interfaces with offsite organizations, and communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance.

• The need to keep personnel apprised of work status, the operational impact of work activities, and plant conditions that may affect work activities.

• The licensee plans work activities to support long-term equipment reliability by limiting temporary modifications, operator work-arounds, safety systems unavailability, and reliance on manual actions.

Maintenance scheduling is more preventive than reactive.

4. Work Practices Personnel work practices support human performance. Specifically (as applicable):

WP H.4(a) The licensee communicates human error prevention techniques, such as holding pre- Considered, but not applicable to issue.

job briefings, self and peer checking, and proper documentation of activities. These techniques are used commensurate with the risk of the assigned task, such that work activities are performed safely. Personnel are fit for duty. In addition, personnel do not proceed in the face of uncertainty or unexpected circumstances.

WP H.4(b) The licensee defines and effectively communicates expectations regarding procedural Considered, but not applicable to issue.

compliance and personnel follow procedures WP H.4(c) The licensee ensures supervisory and management oversight of work activities, Considered, but not applicable to issue.

including contractors, such that nuclear safety is supported.

5. Corrective Action Program The licensee ensures that issues potentially impacting nuclear safety are promptly identified, fully evaluated, and that actions are taken to address safety issues in a timely manner, commensurate with their significance. Specifically (as applicable):

CAP P.1(a) The licensee implements a corrective action program with a low threshold for Considered, but not applicable to issue.

identifying issues. The licensee identifies such issues completely, accurately, and in a timely manner commensurate with their safety significance.

EN-LI-118 Rev 13

Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 5 of 8 CR-IP2-2010-06801 - Unit 2 tripped due to a fault in Description 21 Main Transformer CAP P.1(b) The licensee periodically trends and assesses information from the CAP and other Considered, but not applicable to issue.

assessments in the aggregate to identify programmatic and common cause problems.

The licensee communicates the results of the trending to applicable personnel.

CAP P.1(c) The licensee thoroughly evaluates problems such that the resolutions address causes Considered, but not applicable to issue.

and extent of conditions, as necessary. This includes properly classifying, prioritizing, and evaluating for operability and reportability conditions adverse to quality. This also includes, for significant problems, conducting effectiveness reviews of corrective actions to ensure that the problems are resolved.

CAP P.1(d) The licensee takes appropriate corrective actions to address safety issues and Considered, but not applicable to issue.

adverse trends in a timely manner, commensurate with their safety significance and complexity.

CAP P.1(e) If an alternative process (i.e., a process for raising concerns that is an alternate to the Considered, but not applicable to issue.

licensees corrective action program or line management) for raising safety concerns exists, then it results in appropriate and timely resolutions of identified problems.

6. Operating Experience The licensee uses operating experience (OE) information, including vendor recommendations and internally generated lessons learned, to support plant safety. Specifically (as applicable):

OE P.2(a) The licensee systematically collects, evaluates, and communicates to affected internal Considered, but not applicable to issue.

stakeholders in a timely manner relevant internal and external OE.

OE P.2(b) The licensee implements and institutionalizes OE through changes to station Considered, but not applicable to issue.

processes, procedures, equipment, and training programs.

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7. Self- and Independent The licensee conducts self- and independent assessments of their activities and practices, as appropriate, to assess performance and identify Assessments areas for improvement. Specifically (as applicable):

SA P.3(a) The licensee conducts self-assessments at an appropriate frequency; such Considered, but not applicable to issue.

assessments are of sufficient depth, are comprehensive, are appropriately objective, and are self-critical. The licensee periodically assesses the effectiveness of oversight groups and programs such as CAP, and policies.

SA P.3(b) The licensee tracks and trends safety indicators which provide an accurate Considered, but not applicable to issue.

representation of performance.

SA P.3(c) The licensee coordinates and communicates results from assessments to affected Considered, but not applicable to issue.

personnel, and takes corrective actions to address issues commensurate with their significance.

8. Environment For Raising An environment exists in which employees feel free to raise concerns both to their management and/or the NRC without fear of retaliation and Concerns employees are encouraged to raise such concerns. Specifically ( as applicable):

ERC S.1(a) Behaviors and interactions encourage free flow of information related to raising Considered, but not applicable to issue.

nuclear safety issues, differing professional opinions, and identifying issues in the CAP and through self assessments. Such behaviors include supervisors responding to employee safety concerns in an open, honest, and non-defensive manner and providing complete, accurate, and forthright information to oversight, audit, and regulatory organizations. Past behaviors, actions, or interactions that may reasonably discourage the raising of such issues are actively mitigated. As a result, personnel freely and openly communicate in a clear manner conditions or behaviors, such as fitness for duty issues that may impact safety and personnel raise nuclear safety issues without fear of retaliation.

ERC S.1(b) If alternative processes (i.e., a process for raising concerns or resolving differing Considered, but not applicable to issue.

professional opinions that are alternates to the licensees corrective action program or line management) for raising safety concerns or resolving differing professional opinions exists, then they are communicated, accessible, have an option to raise issues in confidence, and are independent, in the sense that the program does not report to line management (i.e., those who would in the normal course of activities be responsible for addressing the issue raised).

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Root Cause Analysis for CR-IP2-2010-06801 Attachment VIII ATTACHMENT 9.6 SAFETY CULTURE EVALUATION Sheet 7 of 8 CR-IP2-2010-06801 - Unit 2 tripped due to a fault in 21 Main Description Transformer

9. Preventing, Detecting, and A policy for prohibiting harassment and retaliation for raising nuclear safety concerns exists and is consistently enforced in that:

Mitigating Perceptions of Retaliation PDR S.2(a) All personnel are effectively trained that harassment and retaliation for raising safety Considered, but not applicable to issue.

concerns is a violation of law and policy and will not be tolerated PDR S.2(b) Claims of discrimination are investigated consistent with the content of the regulations Considered, but not applicable to issue.

regarding employee protection and any necessary corrective actions are taken in a timely manner, including actions to mitigate any potential chilling effect on others due to the personnel action under investigation.

PDR S.2(c) The potential chilling effects of disciplinary actions and other potentially adverse Considered, but not applicable to issue.

personnel actions (e.g., reductions, outsourcing, and reorganizations) are considered and compensatory actions are taken when appropriate.

10. Accountability Management defines the line of authority and responsibility for nuclear safety. Specifically (as applicable):

ACC A.1(a) (a) Accountability is maintained for important safety decisions in that the system of Considered, but not applicable to issue.

rewards and sanctions is aligned with nuclear safety policies and reinforces behaviors and outcomes which reflect safety as an overriding priority.

ACC A.1(b) (b) Management reinforces safety standards and displays behaviors that reflect safety Considered, but not applicable to issue.

as an overriding priority.

ACC A.1(c) (c) The workforce demonstrates a proper safety focus and reinforces safety principles Considered, but not applicable to issue.

among their peers.

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11. Continuous learning The licensee ensures that a learning environment exists. Specifically (as applicable):

environment CLE C.2(a) (a) The licensee provides adequate training and knowledge transfer to all personnel Considered, but not applicable to issue.

on site to ensure technical competency.

CLE C.2(b) (b) Personnel continuously strive to improve their knowledge, skills, and safety Considered, but not applicable to issue.

performance through activities such as benchmarking, being receptive to feedback, and setting performance goals. The licensee effectively communicates information learned from internal and external sources about industry and plant issues.

OCM 12. Organizational Management uses a systematic process for planning, coordinating, and Considered, but not applicable to issue.

change evaluating the safety impacts of decisions related to major changes in management organizational structures and functions, leadership, policies, programs, procedures, and resources. Management effectively communicates such changes to affected personnel.

13. Safety policies Safety policies and related training establish and reinforce that nuclear safety is an overriding priority in that:

SP SP.4(a) (a) These policies require and reinforce that individuals have the right and Considered, but not applicable to issue.

responsibility to raise nuclear safety issues through available means, including avenues outside their organizational chain of command and to external agencies, and obtain feedback on the resolution of such issues.

SP SP.4(b) (b) Personnel are effectively trained on these policies. Considered, but not applicable to issue.

SP SP.4(c) (c) Organizational decisions and actions at all levels of the organization are consistent Considered, but not applicable to issue.

with the policies. Production, cost and schedule goals are developed, communicated, and implemented in a manner that reinforces the importance of nuclear safety.

SP SP.4(d) (d) Senior managers and corporate personnel periodically communicate and reinforce Considered, but not applicable to issue.

nuclear safety such that personnel understand that safety is of the highest priority.

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Attachment IX

Attachment X Equipment Failure Evaluation CONDITION REPORT: IP2-2010-06801 EQUIPMENT AFFECTED:

EQUIPMENT (COMPONENT) ID: 21MTRFR PROCESS SYSTEM CODE: 345K UNIT 1 2 3 C EDB PMO CODE: 3 TAG NAME 21 MAIN TRANSFORMER TAG SUFFIX NAME HCHM/NS COMPONENT CODE TRANSF

1. Verification Of The Correctness Of Criticality Classification: YES NO

a. Is the Component Classification correct per EN-DC-153, Attachment 9.3, Section 1?

b. Is the Component Duty Cycle correct per EN-DC-153, Attachment 9.3, Section 2?

c. Is the Component Service Condition correct per EN-DC-153, Attachment 9.3, Section 3?

2. Adequacy Of System and Component Monitoring: YES NO N/A

a. For condition monitoring performed under the System Monitoring Plan per EN-DC-159 or the Component Monitoring Plan per EN-DC-325, are the appropriate parameters being monitored at the optimum frequency to detect the degradation mechanisms/influences that resulted in this component failure?

As documented in the RCA, the mechanism that caused the failure (electrical treeing) is not detectable through condition monitoring. The electrical treeing was only evident upon bushing teardown.

b. If not performed, should it be?

c. If performed, is the monitoring and threshold for action adequate?

d. If performed, is there improvement needed in collecting or trending the data?

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Attachment X

3. Adequacy Of PM Program: YES NO N/A

a. Does a PM task exist?

b. Are the PM tasks adequate to defend against the degradation mechanisms/influences that resulted in this component functional failure?

As documented in the RCA, the mechanism that caused the failure (electrical treeing) is not detectable through preventive maintenance. The electrical treeing was only evident upon bushing teardown.

c. Is the PM task content adequate? Is the content consistent with the current PM Template?

d. Is PM frequency adequate? Is the frequency consistent with the current PM Template?

e. Is the current PM Template adequate? Is the content consistent with the current EPRI PM Template and/or industry guidance?

f. If a PM Change or PM Deferral was previously performed, was it a causal factor in this component failure?

g. Was applicable PM feedback adequately implemented?

4. Adequacy Of Predictive Maintenance: YES NO N/A

a. Is the Predictive Maintenance (PdM) tasks performed per the EN-DC-310 Predictive Maintenance Equipment List (PMEL) adequate to detect the degradation mechanisms/influences that resulted in this component functional failure?

As documented in the RCA, the mechanism that caused the failure (electrical treeing) is not detectable through predictive maintenance. The electrical treeing was only evident upon bushing teardown.

b. If not performed, should predictive maintenance tasks be initiated?

c. If performed, is the monitoring and threshold for action adequate?

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Attachment X

5. Adequacy Of Work Practices: YES NO N/A

a. Was the Work Order instruction scope, content and detail adequate?

b. Were the maintenance practices appropriate and acceptable?

c. Was the Post Maintenance Test (PMT) adequate? Was it performed?

6. Adequacy Of Design And Operation: YES NO N/A

a. Is the design of this component appropriate for the application?

As documented in the RCA, the root cause for this event is a Vendor Design/Manufacturing Deficiency.

b. Are the operating procedures and practices appropriate?

c. Was the component operated within design?

d. If a Design Change was performed:

x Was the Design Change adequate? Is the component appropriate for its configuration/application?

x Was Design Change implementation adequate?

7. Adequacy Of Parts: YES NO N/A

a. Were parts availability and quality adequate?

b. Was Receipt, Inspection, and Storage adequate (ex.

Environment, Shelf Life, Control of Scavenged Parts, Storage PM)?

c. Were there Vendor quality or workmanship issues (manufacturing defects)?

While it is possible that there was an initial defect in the bushing that started the insulation breakdown, the presence of the electrical treeing is what lead to the rapid and complete breakdown of the insulation system.

d. Was Procurement adequate (ex. Specification, Equivalence)?

3 of 4 Equipment Failure Evaluation EN-LI-119-01, Rev. 0

Attachment X

8. Adequacy Of Long Range Plan: YES NO N/A

a. If the failure is attributed to an aging / obsolescence concern, is the EN-MS-S-013-Multi Long Range Plan or Life Cycle Management Plan adequate?

b. Are Site Integrated Planning Database (SIPD) related items adequate?

c. Are they appropriately prioritized, scheduled, and funded?

d. If the SIPD item was deferred, was the deferral a causal factor in this component failure?

Coding:

INPO PO&C Code(s): None INPO Failure Mode(s): FM38 - Short Circuit AP-913 Cause Code(s): 601 - Vendor Quality or Workmanship Issues (Manufacturing Defect)

Comments:

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