ML20202J121

Submits Summary of 990128 Meeting with Listed Attendees at Region II Ofc for Presentation of Recent Plant Performance. Presentation Handout Encl

ML20202J121
Person / Time
Site:	Sequoyah
Issue date:	02/02/1999
From:	Fredrickson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	Scalice J TENNESSEE VALLEY AUTHORITY
References
NUDOCS 9902090042
Download: ML20202J121 (47)

Text

.

i February 2,1999 Tennessee Valley Authority ATTN: ' Mr. J. A. Scalice Chief Nuclear Officer and Executive Vice President 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT:

MEETING

SUMMARY

- SEQUOYAH NUCLEAR STATION (SNS) j

Dear Mr. Scalice:

This refers to the open management meeting that was conducted at your request at the Region ll Office on January 28,1999, for presentation of recent plant performance. A list of attendees and a copy of your presentation handout are enclosed.

It is our opinion that this meeting was beneficial in that it provided the NRC staff with a good overview of your perceived strengths, as well as existing challenges and plans for improvement.

In accordance with Section 2.790(a) of the NRC's " Rules of Practice," Part 2. Title 10, Code of Federal Regulations, a copy of this letter and its enclosures will be placed in the NRC Public j

Document Room.

Should you have any questions concerning this meeting, please contact us.

Sincerely, (Original signed by Paul E. Fredrickson)

Paul E. Fredrickson, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos. 50-327,50-328

. License Nos. DPR-77, DPR-79

Enclosures:

'1.

List of Attendees I

2.

- Licensee Presentation Handout

(

cc w/encls: See page 2

^

9902090042 990202 PDR ADOCK 05000327 P

PDR h Y.5

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TVA 2

cc w/encis:

Senior Vice President

. Nuclear Operations

- Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Jack A. Bailey, Vice President Engineering and Technical Services Tennessee Valley Authority 6A Lookout Place 1101 Ma.rket Street Chattanooga, TN 37402-2801 Masoud Bajestani Site Vice President Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy-Daisy, TN 37379 General Counsel Tennessee Valley Authority

. ET 10H -

- 400 West Su Timit Hill Drive Knoxville,TN 37902 Raul R. Baron, Genera; Manager Nuclear Assurance Tennessee Valley Authority SM Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 l

Mark J. Burzynski, Manager i

Nuclear Licensing Tennessee Valley Authority.

j

. 4X Blue Ridge 1101 Market Street Chattanooga,TN 37402-2801 Pedro Salas, Manager

' Licensing and Industry Affairs 1

' Sequoyah Nuclear Plant i

Tennessee Valley Authority P. O. Box 2000 R

Soddy-Daisy, TN 37379 ~

..cc w/encls continued: See page 3 L

. ~. - -, _ - _. -

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TVA-

-3 i

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1' cc w/encis: Continued l

[

D.' L. Koehl, Plant Manager

. Sequoyah Nuclear Plant -

)

l

' Tennessee Valley Authority '

J P. O.' Box 2000 Soddy Daisy, TN 37379 l

~

' Michael H.' Mobley, Director Division of Radiological Health

..TN Dept. of Environment and Conservation 3rd Floor, LNC Annex

.401 Church Street -

Nashville, TN 37243-1532 County Executive Hamilton County Courthouse l

Chattanooga, TN 37402-2801 Distribution w/encish L. R. P!isco, Rll R. W. Heman, NRR l;

. C. O. Thomas, NRR

- W. C. Bearden, Ril C. F. Smith, Ril D. W. Jones, Ril D. H. Thompson, Ril J

L. S. Mellen, Ril l.

PUBLIC.

1 NRC Resident inspector, Operations

- U. S. Nuclear Regulatory Commission

'1260 Nuclear Plant Road -

' Spring City, TN 373811 j

NRC Resident inspector-

-Sequoyah Nuclear Pla_nt U. S. Nuclear Regulatory Commission 2600.lgou Ferry Road Soddy-Daisy, TN.37379 l:

v.. m FWI:WP SIGNATURE, g' NAISE PTaylor alt DATE --

2/ / /se 2/ 199 2/ /se 2/ /se 2/ /so

. 2/ /se 2/ /se COPY?

YES No YES NO

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f-f LIST OF ATTENDEES 1

Nama Title NRC Staff r

L.Reyes Regional Administrator, Region II (Rll)

L. Plisco.

Director, Division of Reactor Projects (DRP), Ril C. Casto Deputy Director, DRP, Rll V. McCree Deputy Director, Division of Reactor Safety (DRS), Ril H. Christensen Branch Chief, Operator Licensing and Human Performance, DRS, R!l j

G. Belisle Branch Chief, Maintenance Branch, DRS, Rll R. Bernhard.

Senior Reactor Analyst, DRS, Ril P. Fredrickson Branch Chief, Branch 6, DRP, Rll M. Shannon Senior Resident inspector, Sequoyah Nuclear Plant, DRP, RIl TVA Staff J. Scalice Chief Nuclear Officer and Executive Vice President, Tennessee Valley Authority M. Bajestani Site Vice President, Sequoyah D.Koehl Plant Manager C. Burton Assistant Plant Manager

. J. Herron Engineering and Support Services Manager H. Butterworth Operations Manager E. Freeman Maintenance and Modification Manager M. Lorek Acting Engineering and Materials Manager i

J. Beasley Site Quality Manager P. Trudel Acting Site Licensing Manager T. Marshall Unit Supervisor

- M. Munroe Emergency Preparedness Manager R. King Operator Training l

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Plant Performance D. L. Koehl I

Vital Inverter M. J. Lorek t

Sudden Pressure Relay M. J. Lorek I

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t Self-Assessment / Corrective Action Effectiveness C.' L. Burton

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Department Performance r

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H. H. Butterworth Maintenance E. E. Freeman Engineering M. J. Lorek Plant Refueling Outages J. T. Herron Unit 1 Cycle 9 Results 1

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Introduction Site Performance

- Plant Performance

- Unit Trips

- Self-Assessments Department Performance Indicators l

Outage Update

- U1 C9 Results

- U2 C9 Preoutage Activities 2

Bajestani i

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Plant Performance Unit 1 Daily Rx Power level Averages 100 W=' [

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Autornatic SCRAM on 5/19/98 due to loss of power to 1-1 Vital AC Inverter (entered Mode 3).

2.

Automatic SCRAM on 11/9/98 at 11:39 am due to loss of power to 1-IV Vital Inverter (entered Mode 3).

3.

Power reduction on 11/20/98 at 16:16 pm to allow tightening of Iligh Point Isolation Valve for Loop 1 RCS Flow Channels.

Net Capacity Factor (maximum dependable capacity) 120,

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Automatic SCRAM on 8/27/98 at 13:57 am due to failure of Sudden Pressure Relay located on the "B" Phase main Transformer.

2.

Automatic SCRAM on 10/15/98 at 05.01 am due to a Generator lockout caused by a failure of a Sudden Pressure Relay on the "B' Phase Main Transformer. Off-line 18 hrs 59 min. on 10/15 and 6 hrs 39 min on the 10/16 ( total of 25 hrs 38 min.).

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Plant Performance INPO Performance Index 100.0

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-u--Unit 2 Industry Median 40.0 Q1 O2 Q3 Q4 Q1 O2 Q3 04 Q1 O2 Q3 Q4 Q1 O2 Q3 Q4 95 96 97 98 Calendar Year Unit 1 Unit 2 Actual Actual Performance Indicator Value Weight

% Max Index Value Weight

% Max Index Unit Capability Factor (1) 87.23 16 94.5 %

15.11 93.99 16 100%

16 Unplanned Capability Loss Factor (1) 1.20 12 92 %

11.04 1.45 12 90 %

10.84 Unplanned Automatic Scrams (1) 0.90 8

100 %

8.00 0.8369 8

100 %

8 High Pressum Safety injection System (1) 0.00 10 100 %

10.00 0.0052 10 100%

10 Auxiliary feedwata System (1) 0.01 10 100 %

10.00 0.0057 10 100%

10 Emergency AC Power (1) 0.01 10 94 %

9.38 0.0125 10 94 %

9.375 Themial Per1ormance (2) 99.80 6

90 %

5.40 99.8127 6

91 %

5.438 Fuel Reliability (3) 0.00 8

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8.00 0.0001 8

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8 Chemistry Indcator (2) 1.03 7

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7.00 1.0269 7

100%

7 Collectim Radation ExposumfUnit (1) 243.01 8

52 %

4.19 87.705 8

100 %

8 Industrial Safety Accident Rate (site)(2) 0.00 5

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5.00 0

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5 INPO Performance Index - December 1998 93.1 97.7 (htemally Calculated)

(1) Based on 24 Month Awrage (2) Based on 12 Month Amrage (3) Based on 3 Month Amrage 5

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Plant Performance INPO Performance Indicator Benchmark INPO Index 3rd Quarter 1998 Data k

100 GOOD Top Quartile Entry 92.6 90 IndustryMedian 89.1 80 70 60 50 40 30 20 10 6

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l Unit Capability Factor Unplanned Capability Loss Factor 2 Year Average 2 Year Average 3rd Quarter CY 1998 Data 3rd Quarter CY 1998 Data i

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Three Challenges as a Result of Vital Inverter Problems

- May 19,1998, Loss ofI-IInverter Caused by Breaker Arcing

- Noveraar 9,1998, Inverter I-IV Bridge Circuit Failure

- November 25,1998, Inverter I-IV Oscillator Board Failure l

Major Actions Taken, To be Taken

- Failed components replaced

- Working with vendor on circuit board quality

+

- Modification to replace with inverters that contain static switch

- Unit 2 inverter will be retained as a spare

- Technical specifications will be modified as necessary to accommodate new design i

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Sudden Pressure Relay Unit Trips as a Result of Sudden Pressure Relay Failure

- Two Unit Trips - Similar Causes August 1998 trip caused by vibration induced frettine October 1998 trip caused by vibration induced faticue

- Industry Operating Experience SQN event information provided to industry Other plants addressing similar problem due to SQN identification; North Anna found 2 relays ready to fail during recent refueling outage inspection - condition was a result of transformer vibration

- Major Actions Taken, To be Taken Disablement ofinstalled relays on main bank, USST, and CSST

. Modification to change logic to 2 out-of 2 Isolate relays from transformer to eliminate vibration source 12 Lorek

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Self-Assessment /

Corrective Action Effectiveness Self-Assessment Effectiveness

- Formal site process with management oversight

. Selected assessments presented to Management Review Committee t

Targets for outside involvement / benchmarking

. - Good selfidentification of problem amas and areas for improvement In FY 98,78 Assessments identified 144 PERs and 255 Areas For Improvement

- Line organizations own program implementation Assessment areas identified Assessment schedules developed and monitored Periodic review (2 yrs) of major station programs

- Effectiveness Assessments critiqued by Self-Assessment Steering Committee The program requires an periodic assessment of the Self-Assessment Program INPO September 1998 Evaluation - program strength i

"Self-evaluations have contributed to steady progress and improvement in equipment performance, plant materiel condition, and human error reduction."

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Self-Assessment /

Corrective Action Effectiveness Corrective Action Program Effectiveness

- PerformanceIndicators i

. Line identification of problems at 88%, with a goal of 90%

. 93% of corrective actions are completed on time (quarterly average)

. Human performance errors have been reduced by 48% (6-month trend)

- LineInvolvement

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. Root cause analysis l

. Corrective action plan development Self-assessment

- Overall Effectiveness i

Problems continue to be identified and closed in a timely manner l

Recurrence control over human-and process-related problems has been good Corrective action effectiveness continues to be a focus area for the site l

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- Key performance indicators increased from 18 to 21 l

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- " Raised the Bar" on several previous indicators

- Integrated into annual performance evaluations I

i OPERATIONS DECEMBER 1998 PERFORMANCE i

INDICATORS

SUMMARY

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- Procedures

. Eliminated requests greater than 6 months old Set new goals of keeping avarage age less than 1 month old

. Plan in place to meet goal by July 99

. More responsive to procedure changes on-shift

- Labeling

. Eliminated requests greater than 6 months old

. Set new goal of keeping average les than 1 month old

. Plan in place to meet goal by September 99 17 Buttenvorth

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Operations Human Performance Trends

- Plant Status Control

. Number of errors remains low Internally identified Initiating periodic checks ofinfrequently operated systems Status Control Errors s -

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- Emphasis on 360-degree coaching and feedback to reinforce good performance and identify and correct performance weaknesses 20

.Butterworth

Maintenance and Modifications 1

Performance Indicators Evaluate 5 Key Areas:

(Quality, Material Condition, Efficiency, Initiatives, and Budget) l 1

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i Corrective action timeliness Self-assessment item tracking t

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- Material Condition

. Non-outage Corrective Maintenance (CM) backlog of 62 i

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= Overall non-outage work order backlog is at 1834

. Control Room WRs at 3 Non-outage leaks are at 20 (Steam, Water, or Oil) l Non-outage catch containment leaks is zero

- Efficiency l

Schedule performance 95%

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23 Freeman l

Maintenance and Modifications Thermo-lag Program-

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- Self-Assessment Process Evaluation

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. Benchmark the process

. Determine effectiveness in improving performance

. Strengths for identification ofissues and establishing and communicating the department expectations

. Improvement areas for additional detail and self-critical approach to daily observations and business, and for effective recurrence control of some issues 25 Freeman

Maintenance and Modifications Self-Assessments (Continued)

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- FCR backlog elimination complete !

'" M O S",^!?,".' O (PUMP & VALVE TESTING 106 FCRs completed in T.

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. FAILURE MAINTENANCE GENERIC SNUDPER3 TRENDING '

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- Thermal Performance INPO September 1998 Evaluation - Program Strength Thermal performance indicator of greater than 99.5% over last 10 months

. System engineer team effort Detailed daily reviews by team:

System parameter trends Operator logs Chemistry changes Turnover notes from previous shifts

+

Reviews and discussions result in timely identification of problems Thermal Performance Indicator (TPI) not

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- Non-Intrusive Check Valve Testing

= 64 valves tested during Unit 1 Cycle 9 refueling outage

. Testing results supported deletion of 7 ASME Section XI and 14 SOER 86-03 disassembly and inspection (D&I) activities 6 deleted D&Is involved valves on high radiation / contamination systems

-. Approximately 1000 Maintenance man-hours and 3100 MREM dose saved

. 5 valves needed D&I activities

- System Engineering Performance Monitoring and Trending

. INPO September 1998 Evaluation - Program Strength Examples of problems identified before they adversely affected station operation Rod control cabinet fuse high resistance RCP motor cooler boron accumulation RCP seal performance Lower compartment cooler boron accumulation Main generator hydrogen cooler performance 29 Lorek

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see Engineering Y2K Project

- Each item cla.ssified as Mission Critical, Important to Operation, or Desirable Detailed assessment of each item to determine testing requirements

- Y2K sensitive mission critical items include validation testing by TVA and/or vendor

- Mission critical and important to operation non-compliant items will be fixed or have a contingency plan in place by July 1999

- Contingency plan contained in a site procedure that follows guidance of NEI/NUSMG 98-07

- Mission critical and important to operation items not verified compliant by July 1999 will be included in the contingency plan Y2K Program Status 900 -

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mes mas Engineering Self-Assessments

- Ice condenser self-assessment was detailed and included large volume of industry operating experience

. Strengths identified

. Controlled group of 72 baskets weighed each outage since Cycle 7

. Maintenance practices for removal ofintermediate deck door structural steel Weighing ofice baskets Thermal drilling

. Areas for improvement identified Minor FSAR and design criteria discrepancies Cumulative assessment of non-retrievable debris 1

Ice basket damage and maximum ice weight Documentation of maintenance activities and procedural improvements 31 Lorek

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sus as Engineering Self-Assessments (Continued)

- Two breaker program self-assessments, focused on program content and implementation

. Strengths identified Aggressive rebuild program Good training program and facility Timing tests performed Good participation in industry working groups Good program documentation Low threshold in problem identification i

Very thorough root cause on DS 532 breakers

. Areas for improvement identified Not tracking maintenance by breaker serial number Procedural weaknesses Over due preventive maintenance (PM) on some breakers and missing packages on others

. Incorrect functional failure calls for Maintenance Rule l

Incorrect testing technique on the Direct Trip Actuator l

High contact resistance on 6.9kV breakers Repeat problems with vendor workmanship 32 Lorek

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Engineering Initiatives

- Engineering Work Management System Uses Primavera which is compatible with rest of site Allows Design and System Engineering to man-load O&M schedules Helps prioritize incoming work and identifying work that needs to be moved Improves resource allocation efficiency

- Ice Condenser Ice condenser mini group Mini group executive steering committee Technical specifications improvements Ice condenser 3-dimensional containment analysis model upgrade Maintenance and servicing improvements

- Breaker Program Establishing rebuild schedules and improving tracking for breakers important to operation Provide additional training for other breaker types Evaluate several vendor and industry items for inclusion into the maintenance procedures Enhance non-safety PMs with lessons learned on safety-related breakers Add post-rebuild receipt inspections for other breaker types Ensure proler use of shelflife limitations Review maintenance procedures with vendors to identify needed improvements 33 Lorek

t t=

aw Outage L1C9 Results Goals Met

~

Safe and reliable Unit 2 operation No lost-time accidents

< Less than 212 REM exposure and no high rad violations

< Clear outage control room deficiencies (28 total) i

/ Total completion of baseline outage scope

- Reliability Improved

/ Containment spray heat exchanger replacement

/ 480-V and 6.9-kV breakers refurbishment (26) 480V, (14) 6.9kV

/ Rebuild primary and BOP pumps / motors (12 total)

/ MDAFW pump 1 A-A replacement

- Man-machine interface f

/ New main feed pump recirculation valves / controllers l

/ Install redundant channel Mansell RCS level monitoring

/ Replace angle valves on upper pressurizer taps and correct sense line slope en not cal and cold cal pressurizer level transmitters

- Equipment performance

/ Install a new electrical containment penetration

/ Temporary leak repairs (27)

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Unit 2 Cycle 9 Refueling Outage I

U2C9 Goals

- Safe and reliable Unit 1 operation

- No events

- Strong Unit 2 performance after startup

- No more than 1 recordable injury

- No lost-time accidents

- Less than 165 REM exposure and no high rad violations

- Clear outage TACFs (6 total) l

- Clear temporary leak repairs (12 total)

- Clear outage control room deficiencies (18 total)

- Total completion of baseline outage scope i

- Outage completed within schedule and budget i

f i

35 i

Herron i

m

t Unit 2 Cycle 9 Refueling Outage Material ConditionImprovements I

- Reliability i

= 480-V and 6.9-kV breakers refurbishment (26) 480V, (10) 6.9kV

= Rebuild primary and BOP pumps / motors (9 total) i a

MDAFW pump 2B-B replacement a

High pressure turbine rotor replacement

=

RCP motor and seal replacement (1 motor,1 seal packages) a L

Steam generator work

=

i 100% full-length inspection using a bobbin coil probe 100% hot leg top of tubesheet using a rotating pancake coil l

100% row I and 2 U-bend examinations using a magnetic biased plus-point probe t

I l

36 i

Herron l

Unit 2 Cycle 9 Refueling Outage Material Condition Improvements

- Man-machine interface Install fuel transfer cable drive system

=

Modify reactor buildingjib crane to improve equipment handling

=

Clear main control room deficiencies (18) a Replace angle valves on upper pressurizer taps and correct sense line

=

slope on hot cal and cold cal pressurizer level transmitters Install temporary lower containment cooling connection

=

- Equipment performance Temporary leak repairs (12)

=

Flow-accelerated corrosion inspection / repairs (160 inspections and

=

replacing approximately 530 feet of small bore piping)

Ice condenser subfloor dewatering

=

= Condenser sparger relocation Turbine impulse pressure switches a

37 Herron a

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Outage U2C9 Preparations i

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• Improved reliability 1

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i Keys to Sustain Good Performance l

- Critical Self-Assessments

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t 42 Bajestani i

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