ML20135C003

Partially Deleted Rev 5 to OP-III-1.3.1, Turbine Generator Operation

ML20135C003
Person / Time
Site:	Salem
Issue date:	05/14/1991
From:	Public Service Enterprise Group
To:
Shared Package
ML20135B759	List: ML20135B755 ML20135C003 ML20135C045
References
FOIA-96-351 NUDOCS 9703030302
Download: ML20135C003 (11)

Text

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l 8ALEN UNIT _2_. / OPERATIONS PROCEDURE NUMBER OP-III-1.3.1 _ - REY. 5 TURRINE GENERATOR OPERATION

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SPONSOR ORGANIIATION: N/A .

USE CATEGORT: II REVISION

SUMMARY

1.- This is a Full Revision. Revision Bars have not been utilized due l to the extent of the changes made. l Incorporates the following: 1 LR A & B, ACN P-1, P-2, P-3, P-4, P-5, P-6, P-7, P-8, P-9, P-10,-

P-11, P-12, P-13 & P-14.

OTSC P-1, P-2, P-3, P-5 & P-6). P-4 could not be located.

2.- Changed precaution 3.8 to include additional appendices.

3.- Added Salem - Deans Line Outage Curves & Tables.

4.- Added Hope Creek - Keeney Line Outage Curves & Tables.

5.- Changed Appendix 2:

a) Includes the additional appendices.

b) Deleted the code for numbering the operating curves.

c) Added guidance on when the Cross Trip should be armed.

6.- Added step 5.1.6f to have the turbine test switches closed.

7.- Changed Load Dispatcher to Systems Operator.

S.- Added Step 5.5.3b, Adds direction, if the wrong 500 KV line had been selected prior to selecting the Unit to be tripped. Also adds Step 5.5.2 to verify that the Lock-out relays are reset.

9.- Added procedure Section 5.6, Dis-arming the Trip a Unit Scheme.

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IMPLEMENTATION REQUIRENENT8 NONE REQUIRED 1

APPROVED: h M

[ operations Manags?'- Salem Date Page _1_ of _1_

9703030302 970226 PDR FOIA O'NEILL96-351 PDR

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OPERATING PROCEDURE '

III-1.3.1 TURBINE-GENERATOR OPERATION 1.0 PURPOSE -

1 1.1 This procedure.provides the instructions necessary to .

perform the following:

l 1.1.2 Applying Generator Excitation 4

O N 1.1.4 Loading the Generator in Turbine Manual 1.1.5 Arming and Dis-Arming the Trip a Unit Scheme 2.0 INITIAL CONDITIONS 2.1 The Turbine-Generator is on the Turning Gear with the following systems in earvice IAW their individual operating instructions.

2.1.1 Main Lube Oil, OP III-3.3.1, " Main Turbine Lubricating Oil System-Normal Operation". ]

l 2.1.2 Main Steam, OP III-2.3.1, " Main, Reheat, Turbine j Bypass Steam Warmup". l 2.1.3 Turbine Gland Seal, OP III-4.3.1, " Turbine Gland Sealing System-Normal Operation".

2.1.4 Turbine Auxiliary Cooling, OP III-6.3.1, l

" Turbine Auxiliary Cooling System-Normal Operation".

s 2.1.5 Circulating Water, OP III-7.3.1, " Circulating Water System-Normal Operation".

2.1.6 Condenser Air Removal, OP III-8.3.1, " Condenser Air Removal System-Normal Operation".

2.1.7 Turbine E/H Control, OP III-1.3.6, "E/H System Normal Operation".

2.1.8 Service Water, OP V-1.3.1, " Service Water-Normal Operation".

2.1.9 Generator Seal Oil, OP IV-2.3.1, " Generator Seal Oil System-Normal Operation".

2.1.10 Stator Cooling, OP IV-2.3.3, " Stator Cooling System-Normal Operation". .

Salem Unit 2 1 Rev. 5

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'III-1.3.1 l 2.2 The Generator is filled with hydrogen of greater than 95% purity IAW OP IV-2.3.2, Generator Gas System - i Normal Operation. l 2.3 The following lamps are illuminated on the Turbine E/H _

Control Panel:

2.3.1 UNIT TRIP 3 2.3.2 TURB MANUAL i

! 2.3.3 IMP OUT 2.3.4 CLOSED lights for all Stop, Governor, Reheat and Intercept valves.

2.4 All Turbine drain control switches on the Turbine Drain l Status Panel are in the Auto position.

l 2.5 The.500 KV switchyard has been aligned IAW-the Systems s Operator's instructions in preparati.on for synchronization.

2.6 The Exciter Field Breaker is Open, Voltage Regulator is l OFF, Manual and Automatic Voltage Adjuster is set to '

zero percent.

2.7 The Bus Duct Cooling Fans are inservice IAW .

OP-III-1.3.9, Bus Cooling Systems.

i 2.8 Turbine Supervisory Instrumentation is in service as indicated by the following on Panel 982:

2.8.1 Voltage indicating lights on power supplies '

are lit. i 2.8.2 OK Status lights on individual monitors are  !

lit. i 2.8.3 All alarms are reset. ]

3.0 PRECAUTIONS l 3.1 The turbine may not be operated above 30% load with a Reheat Stop or Intercept closed except for short periods when the valves are tested for valve stem i freedom.

. 3.2 Reheat Steam temperature should not exceed 400'F when turbine load is less than 10%.

3.3 Instantaneous change of Reheat system temperature should be less than 100*F. The normal rate of reheat temperature-change should not be exceed 250*F per hour.

l l 3.4 Do not operate the turbine with a temperature difference between exhaust hoods of greater than 50*F.

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'ro Salem Unit 2 2 Rev. 5 L

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3.5 Do.not operate the turbine with one condenser out of l service for an extended period of time. If one l r Circulating Water Pump cannot be returned to service, Turbine Load must be reduced accordingly. If vibration L increases rapidly, the turbine should be tripped. - ;

3.6 ' Turbine drains should be open during any operation at -

less than 20% load. j l 3.7 care must be taken to avoid overheating the exhaust end l

of the turbine. Overheating may occur as a result of low exhaust vacuum (high backpressure). If low pressure exhaust temperature above 160*F occurs, ensure that the exhaust hood sprays are on. An alarm is provided at 175'F. Trip the turbine, if exhaust hood temperature reaches 250*F.

3.8 The generator should be operated IAW the curves-in Appendix 3A, 3B or 3C for operation with and without the automatic voltage regulator.

3.9 With one section of a hydrogen cooler out of service, do not exceed the following:

3.9.1 80% of rated load (24,017 amps on any phase). -

(If the Unit is following a voltage schedule of 95% to 99%, a voltage change will be required).

3.9.2 Maximum Cold Gas temperature - 118'F.

3.10 Stator Cooling Heat Exchanger. outlet temperature should not exceed 113*F.

3.11 Seal Oil Cooler outlet temperature should be maintained ,

between 80*F and 120*F. l 3.12 Hydrogen Cooler outlet temperature should not exceed  !

114*F.

3.13~Normally operate with both Stator Water Coolers in service. If one or both is out of service, load must i be reduced as follows:

- 3.13.1 One Cooler out of service, 80% RTP'(24,017 Stator Amps).

3.13.2 Two Coolers out of service, 20% RTP (7,055 Stator Amps).

3.14 Do not hold speed in a resonant speed range for an extended period. If a hold is necessary, reduce speed I

below the resonant range before holding. The LP l turbine blades resonant speed ranges to be avoided are 580-630; 710-750; 870-960; 1070-1140; 1260-1330 and 1400-1620. Generator critical speed is 802 RPM. -

Rev. 5 j Salem Unit 2 3 i

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l j III-1.3.1 i 3.15 The turbine must be on the turning gear whenever Gland

Sealing Steam is applied.

t 3.16. Prior to latching the turbine, the generator' gas

? pressure should be reduced to 60 PSIG and maintained at -

! or below 60 PSIG for at least one -(1) hour after the '

! turbine has been loaded. -

l 3.17 With no M:in Bus Duct Cooling fans operating, the Main Generator Isolated Phase Bus should be limited to

! 16,000 amps or 105'C Bus Conductor temperature.

' 3.18 At turbine loads greater than 30% of rated capacity, the maximum permissible back pressure is 5.5 inches of Hg.

3.19 At turbine loads less than.30% of rated capacity, the r maximum permissible back pressure is 3.5 inches I of Hg.

I 3.20 The Trip-A-Unit SEL SW (43) and Trip-A-Unit LINE SELECT SW (43-1) cross trips are to be C/T for

! SHIFT, SUPER-ADMIN in the OFF position IAW Step 5.6.  !

l l 3.20.1 The cross trips will not be enabled without -

the permission of the Operations Manager and i the System Systems operator IAW step 5.5.

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! 3.21 Perform the following if a Generator bearing i (bearings 9 and 10) vibration increases to the levels listed below:

l a) 5 6 mils - Acceptable I b) > 6 mils and 5 8 mils - Continue operation - Notify

System Engineering.

c) > 8 mils and 5 10 mils - Commence controlled l Shutdown - Notify System Engineering.

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l d) > 10 mils'and 5 12 mils - Commence immediate Shutdown, Trip Generator within 15 minutes of exceeding 10 mils - Notify System Engineering.

e) > 12 mils - Immediately Trip the Generator.

l 3.22 Maintain turbine bearing metal temperature less than 210*F. If temperature exceeds 210*F, reduce load to less than 75% and notify System Engineering.

1 If temperature exceeds 225'F, TRIP the turbine.

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i, Salem Unit 2 4 Rev. 5

t III-1.3.1 3.23 Perform the folloNing if any Main Turbine Stop/ Governor.

valve fails closed during power operation:

- 3.23.1 If Reactor Power is >85% , reduce load to 85%

at 10%/ min. If valve cannot be reopened in the -

following 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> reduce load to 30% at 104/ min.

If valve is not reopened in the following -

3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> remove the turbine from service.

3.23.2 If Reactor Power is <85%, reduce load to 30% at 10%/ min. If valve is not reopened in the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> remove the turbine from service.

4.O ATTACHMENTS LIST 4.1 Tables 4.1.1 Table 1 - Turbine Vibration, Metal and Bearing Temperature Computer Address Codes 4.1.2 Table 2 - Turbine and Generator Expansion Limits 4.2 Appendices .

4.2.1 Appendix 1 - Turbine Loading Charts 4.2.2 Appendix 2 - Generator Operating Guide Generator Operating Curves 4.2.3 Appendix 3A - Normal Operation (All Transmission Lines in service).

4.2.4 . Appendix 3B - Hope Creek - Keeney Outage 4.2.5 Appendix 3C - Salem - Deans Outage

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5 Rev. 5 Salem Unit 2 i

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III-1.3.1

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• 5.0 PROCEDURE 4 5.1 TURBINE STARTUP 5.1.1 INITIATE Turbine Trend (Test 24), or ENTER ,

4 computer points listed on Table 1 on the Trend Typewriter. MONITOR the listed .

! instrumentation on Table 1 and the limits on

Table 2, from the time the unit is rolled off of the turning gear until synchronization.

5.1.2 Check all Turbine Drain Valves are open and that i the OPEN pushbutton is illuminated.

} S.1.3 SELECT OPER AUTO mode of operation of the E/H l Control Panel. The OPER AUTO pushbutton will be

, illuminate, the TURBINE MANUAL mode selector and Manual control station lamps will go off.

5 1.4 DEPRESS the VALVE POSITION LIMIT lower button until the VALVE POSITION LIMIT indicator

! registers 0% valve limit position.

{- 5.1.5 START the Standby E/H Pump.

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! a. START the High Pressure Seal Oil Backup Pump.

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< 5.1.6 After making the 1-9 and 9-10 500 KV Breakers j . ready, RESET the following multi-trips (follow 4

sequence) in elev. 100' Relay Room:

a. Panel 2R2 - Generator Differential, Loss of  ;

Field, Negative Phase Sequence, Excitation l l

Field Forcing HEA.

b. Panel 2R6 - Generator Overload, Out of Step, Loss of Field HEA.

c. Panel 2R1 - No. 2 Generator Main i

Transformer Cooling HEA.

j d. Panel 2R16 - Turbine Trip Rog. HEA.

1 . e. Panel 2R23 - Turbine Trip Backup HEA.  ;

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Salem Unit 2 6 Rev. 5 ,

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Test Switches listed in step f may have been tagged open if  :

the generator vertical drop had been disconnected during unit shutdown.

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j ~1) Regular test (knife) switches located at 2R16 behind ~l the Turbine Trip regular (Coil #1) Multi-trip. ,!

2) Backup test (knife) switches located at 2R23 behind

the Turbine Trip backup (Coil #2) Multi-trip.

! f. CLOSE the following Turbine regular and backup multi-trip test (knife) switches:

j 1.- Trips 30X (9-10) BKR Trip Coil #1.

f 2.- Trips 32X (1-9) BKR Trip Coil #1'.

3.- Trips 30X (9-10) BKR Trip Coil #2.

i h 4.- Trips 32X (1-9) BKR Trip' Coil #2.

i 5.1.7 HOLD OVER Trip / Reset lever until hydraulic oil pressure is greater than 90 PSIG, then DEPRESS l the LATCH button. This pushbutton must be held . l

' for approximately two seconds. . When the Auto l Stop and Vacuum Trips are latched, the LATCH j . lamp will stay on and the UNIT Trip Monitor lamp

. will go off, the REFERENCE-and SETTER displays l will be energized with the number 0000 displayed and the. SPEED CONTROL lamp will be illuminated.

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! 5.1.8 VERIFY Turbine Intercept, Reheat and Stop Valves l 3

OPEN and Governor Valves CLOSED on the E/H l

Control Panel and that STOP VALVES CLOSED and j LOW OIL PRESSURE lamps extinguished on Reactor j

Protection Status Panel (2RP4). i I

! a. If Turbine speed exceeds 200.PRM, WRITE a i work request to Maintenance to have the 3

governor valves inspected during the next i

Refueling outage.

5.1.9 TRIP the Turbine at the Front Standard by l

operating the TRIP / RESET lever. VERIFY all Turbine Intercept, Reheat and Stop Valves closed 4

freely.

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5.1.10 REPEAT steps 5.1.3 and 5.1.4, 5.1.6 a through e i anid 5.1.7 and. rta

urn to step 5.1.11. '

5.1.11 VERIFY Turbine Intercept and Reheat Stop Valvas

• OPEN and Governor Valves CLOSED on the EH  !

Control, Panel.

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Salem Unit 2 7 Rev. 5 l

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III-1.3.1 5.1.12 VERIFY STOP VALVES OPEN and LOW OIL PRESSURE lamps extinguished on Reactor Protection Status

, Panel (2RP4).

Y 5.1.13 INSERT key in the OPC (OVERSPEED PROTECTION _

CONTROLLER) key switch. g

a. TURN the key to the TEST position and OBSERVE that the Interceptor Valves close 9 rapidly.

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b. RETURN the switch to normal IN SERVICE i position. ,

5 I c. VERIFY that the Interceptor valves reopen. j l 5.1.14 STOP one of the E/H Pumps and Place in AUTO.

5.1.15 INCREASE the Main Turbine Lube Oil temperature controller setpoint to 110*F, so that the cooler outlet temperature is approximately 100*F by the time the Turbine reaches synchronous speed.

5.1.16 DEPRESS the VALVE POSITION LIMIT raise button until the VALVE POSITION LIMIT indicator registers 25%' valve. limit position. The Governor Valves should stay closed.

NOTE Ensure all Turbine Stop Valves are Open before setting terminal speed of 520 RPM in the setter display unit.

5.1.17 DEPRESS the REFERENCE raise button to set a terminal speed of 520 RPM (300 RPM if performing a balance shot on the turbine) in i

l the setter display unit.

5.1.18 SET the ACCELERATION RATE at 80 RPM. HOLD lamp will be illuminated.

NOTE Personnel should keep clear of the Turning Gear operating l lever, which is moved to the disengaged position by air i

. pressure. If the Turning Gear did not disengage automatically, it must be done manually.

l 5.1.19 DEPRESS the GO pushbutton. The REFERENCE display will increase at the predetermined rate.

After several seconds, the rotor speed will l

l increase and the Turning Gear will automatically l disengage. When the REFERENCE display has j

reached the desired value, the GO lamp will go  ;

off and the rotor speed will be approximately l equal to the displayed terminal speed. (The ,

i small difference between the terminal and rotor speed is a function of regulation).

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8 Rev. 5 Salem Unit 2 l J

ADMINISTRATIVE CONTROLS  :

'6. 8 PROCEDURES AND PROGRAMS j 4

6.8.1 Written procedures shall be established, implemented and maintained .t covering the activities referenced below:

a. The. applicable procedures recommended in Appendix "A" of Regulatory l Guide 1.33, Revision 2, February 1978. i

b. Refueling operations.  !

c. Surveillance and test activities of safety related equipment. I J

d. Security Plan implementation.

e. Emergency Plan implementation.

f. Fire Protection Program implementation.

g. PROCESS CONTROL PROGRAM implementation.

h. OFFSITE DOSE CALCULATION l%NUAL implementation.

1. 0;ality Assurance Procjram for effluent and environmental nonitoring.

6.8.2 Each procedure and administrative policy of 6.8.1 above, and' changes thereto, shall be reviewed and approved in accordance with Specification 6.5.1.6 or 6.5.3, as appropriate, prior to implementation and reviewed periodically as set forth in administrative procedurac.

6.8.3 On-the-spot changes to procedures of 6.8.1 above may be made provided:

a. The intent of the original procedure is not altered.

b. The change is approved by two members of the plant management staff, l at least one of whom holds a Senior Reactor Operator's License on the l unit affected.  !

,c. The change is documented and receives the same level of review and .

approvat as the original procedure under Specification 6.5.3.2a within 14 days of implementation.

1 6-13 Amendment No. 62 SALEM - UNIT 1

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- 1 APPENDlX A I I i TYPICAL PROCEDURES FOR PRESSURIZED WATER REACTORS AND BOILING WATER REACTORS i

- i The following are typical safety related activities  !

I that should be covered by written procedures. This

b. Control Red Drive System (including part- . .

' length rods)

' appendix is not intended as an inclusive listing of all  !

c. Shutdown Cooling System i needed procedures since many other activities carried

d. Emergency Core Cooling System ,

i out during the operation phase of nuclear power e. Component Cooling Water Sptem i plants should be covered by procedures not included f. Containment in this list.

(1) Meintaining Containment Integrity

1. Administrative Procedures (l PecW ConWnment Sysums

! a. Security and Visitor Control ' ^'

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, and Responsibilities for Safe Opera. (c) le Containment with Controlled

c. Equipment Control (e.g., locking and tagging)

d. Procedure Adherence and Temporary Change I""] Ice Coh'm

! Method (3) Containment Ventilation System

e. Procedure Review and Approval (4) Containment Cooling System

f. Schedule for Surveillance Tests and Calibration '

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g. Shift and Relief Turnover g AtmosP ere h Clearn:p Systems

' h. Log Entries Record Retention, and Review h. Fuel Storage Pool Purification and Cooling Sys-Procedures "'"

l. i. Access to Containment ' M'I" I'" 8 I 5*

j. Bypass of Safety Functions and Jumper Control J.' Pressurizer Pressure and Spray Control Systems

k. Maintenance of Minimum Shift Complement k. Feedwater System (feedwater pumps to steam i

< and Call.In of Personnel 8'""*I

1. Plant Fire Protection Program i tAuxiliary Feedwater System

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m. Communication System Procedures m{  ; atu Syjum ,

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2. General Plant Operating Procedures ing Letdown; Purification System)

a. Cold Shutdown to Hot Standby o. Auxiliary or Reactor Building Heating and Ventilation

b. Hot Standby to Minimum Load (nuclear start-up) p. Control Room Heating and Ventilation

q. Radweste Building Hearing and Ventilation

c. Recovery from Reactor Trip r. Instrument Air System

d. tion at Hot Stand

s. Electrical System (1) Offsite (access circuits)

. Changing Load and Load Follow (if applicable) (2) Onsite

3. Power Operation and Process Monitoring

h. Power Operation with less than Full Reactor (a) Emergency Power Sources (e.g., diesel generator, batteries)

Coolant Flow (b) A.C. System

i. Plant Shuidown to Hot Standby (c) D.C. System

j. Hot Standby to Cold Shutdown

k. Preparation for Refueling and Refueling t. Nuclear Instrument System Equipment Operation l 1. Refueling and Core Alterations (1) Source Range (2) latermediate Range

3. Procedures foe Startup, Operation, and Shutdown (3) Powse Range '

i o of Safety Related PWR Systems (4) lacere System l Instructions for energizing, filling, venting, drain- u. Reactor Control and Protection System  !

ing, startup, shutdown, and changing modes of oper-

v. Hydrogen Recombiner ation should be prepared, as appropriate, for the fol-lowing systems:

4. Procedure for Startup, Operation, and Shutdown

s. Reactor Coolant System l l, of Safety Related BWR Systems

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i Public Sennce Electnc and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 .

' Salem Generating Station -

October 09, 1990 U. S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555

Dear Sir:

SALEM GENERATING STATION  ;

LICENSE NO. DPR-70 DOCKET NO. 50-272 UNIT NO. 1 LICENSEE EVENT REPORT 90-030-00  ;

j This Licensee Event Report is being submitted pursuant to the

requirements of the Code of Federal Regulations 10CFR 50.73 (a) (2) (iv) . This report is required within thirty (30) days' of discovery.

4 Sincerely yours, i

S. LaBruna General Manager -

Salen Operations 4

4 MJP:pc Distribution The Energy People n.rm oeu r ri c ; 0 g ; e i i o g fg.

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] ves tre enrecreo steerssosom om res ] no l l l aseva*cr <u . . .a. _ . . - a ne on 9/10/90 at 1201 hours0.0139 days <br />0.334 hours <br />0.00199 weeks <br />4.569805e-4 months <br /> a reactor trip on No. 13 Steau Generator (S/G)

Low-Low Level occurred. Prior to the event, the pipe between the No.

11TD900 valve and the main steam line sheared providing a steam flow path to atmosphere. To reduce the steam flow, the No. 11MS29 valve (MS Governor Valve) was closed. At 80% power, tne 14MS29 valve is closed

(" partial are control scheme"). Both the Nos. Il&l4MS29 valves direct steam to the upper half of the Turbine. Therefore, with both valves closed, a significant dp across the HP Turbine developed. Contributing to this dp was opening the llTD4 valve which resulted in bleeding steam away from the upper half of the HP Turbine. The Turbine shaft deflected creating an elliptical oscillation resulting in destruction of the Aux. speed sensor which generated an overspeed signal causing closure of the MS29 valves. Closure of the MS29 valves led to the trip on No. 13 S/G Low-Low Level. The root cause of this event is attributed to personnel error. Ops. Dep't. management did not layout an approved plan of action in addressing the pipe break associat'ed with the 11TD900 valve. Contributing factors were procedural inadequacy and inadequate training. This event has been reviewed by senior management. Those individuals involved in this event have been held accountable.

Proceduras have been revised to clearly identify the concerns with Turbine Valve Testing below 85% power. Operations Directive procedure OD-15 wilI be revised. An Operations Department " troubleshooting" '

procedure will be prepared. Damaged equipment was replaced. This event will be reviewed by the Nuclear Training Center for incorporation of lessons learned.

se u_ne

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e ' LICENSEE EVENT REPORT (LER) TEXT CONTINUATION -

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Sclem Generating Station DOCKET NUMBER LER NUMBER PAGE

, Unit ; 5000272 90-030-00 2 of 7

!' Pr_av_ T AND SYSTEN IDENTIFICATMN_; ,

Westinghouse - Pressurized Water Reacter ,

i I Energy Industry Identification System (EIIS) coder are identified in the text as (xxl i IDENTIFICATION OF OCCURRENCE:

Reactor Trip from 79% power on 13 Steam Generator Low-Low Level due i

to personnel error s

l Event Date: 9/10/90 J'

l Report Date: 10/09/90 l This report was initiated by Incident Report No.90-671.

, CONDITIONS PRIOR TO OCCURRENCE:

1 Node 1 Reactor Power 79% - Unit Load 900 NWe 1

i DESCRIPTION OF OCCURRENCE:

a f On September 10, 1990 at 1201 hours0.0139 days <br />0.334 hours <br />0.00199 weeks <br />4.569805e-4 months <br />, during no~rmal power operation, a reactor trip on No. 13 Steam Generator (S/G) Low-Low Level occurred.

l Prior to the event, the 1/2" Main Steam System ISBl pressure indication line sheared upstream of the No. 11TD900 valve (Turbine

. Drain Instrument Isolation Valve). This provided a steam flow path j to atmosphere. The 1/2" line is located on the No. 11 Steam Inlet j 4 Drain Line (1.5") between the 11M829 valve (No. 11 Main Steakline j Governor Valve) and the High Pressure (BP) Turbine. In an attempt to .

reduce the steam flow, to assess repair requirements without removing l

! the Unit from service, the No. 11MS29 valve was closed. Operations Procedure III-1.3.3, " Turbine Valve Tests" was used.

i A " partial are control scheme" is used in providing steam to the HP ,

Turbine. In this scheme, the No. 14M829 governor valve will remain

{ i t

i closed until approximately 80% power is achieved. At 80% power, the

! valve is designed to begin opening to allow a power increase to i 1004. When the No. 11N829 valve was closed, the No. 14M829 valve began to open; however, since both the No. 11 and No. 14M829 valves direct steam to flow nozzles on the upper half of'the EP Turbine, an j unusual steam flow condition occurred. Also, Nos. 12M829 and 13M829 l

l valves were opening more (to compensate for the closure of the 11MS29 valve). This condition resulted in a significant differential j pressure (dp) across the upper and lower halves of the HP Turbine.

Contributing to this dp was opening the 11TD4 valve (Air Operated Steam Inlet Drain Line Valve). It was opened as an attempt to reduce I

j steam flow away from the 1/2" line break; however, it resulted in -

bleeding steam away from the upper half of the EP Turbine.

Nith the above conditions, the HP Turbine shaft deflected in the f

- LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Solen Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1 5000272 90-030-00 3 of 7 l

i DESCRIPTION OF OCCURRENCE: (cont'd) i direction of the No. 11MS29 valve inlet nozzle. This deflection

' created a wave like action, traveling outward to the ends of the HP l Turbine shsft. This wave was amplified towards the end of the shaft, i

due to shaft diameter reduction past the main bearing, resulting in

i. an elliptical oscillation.

i Located at the and of the shaft are three (3) speed sensors (Main,

}' Auxiliary, and Spare) which are mounted on the Oil Pump approximately 40 mils off the shaft. The shaft elliptical oscillation resulted in i damage to the Auxiliary speed sensor and the Main sensor. The Spare sensor remained undamaged. The damage to the Auxiliary speed sensor generated a 103% overspeed signal through the Electro-Hydraulic Control (ERC) electronics. The speed sensors work by producing A l

i pulses which are induced by the passing of the shaft gear teeth.

j single spike, exceeding the 103% overspeed protection control (OPC) setpoint (1854 rpm) occurred. The OPC signal then latched in for 5

{

seconds (by design) causing closure initiation (i.e., puffing) of all l

four (4) MS29 valves.

i

Control Room alarms received (in addition to the reactor trip alarms) included "EH Speed / Load Ch Failure"~end "EE Prot Sys Trbl". Also, a speed monitor channel failure light was observed illuminated, indicating a difference of at least 55 rps between the Main and

Auxiliary speed sensors.

L l The closure of the MS29 valves resulted in a steam flow / feed flow

! mismatch which causes the BF19 valves (Feedwater control Valves) to I begin closing. The combination of the " shrink" phenomenon (caused by I the closure of the MS29 valves) coupled with the reduction in feedwater flow lead to the reactor trip on No. 13 S/G Low-Low Level.

i Following the reactor trip, a main steamline isolation (JEl was l

manually initiated (from Train B) to maintain Reactor Coolant System (RCS) l AB I T. , . (as per the Emergency Operating Procedure).

Subsequently, the Unit was stabilized in Mode 3 (Hot Standby).

! The Muclear Regulatory Commission (NRC) was notified of the automatic j actuation of the Reactor Protection System and the initiation of Main l

Steamline Isolation (an Engineered Safety Feature) in accordance with i

the Code of Federal Regulations 10CFR 50.72(B) (2) (ii) on September

! 10, 1990 at 1233 hours0.0143 days <br />0.343 hours <br />0.00204 weeks <br />4.691565e-4 months <br />.

i APPARENT CAUSE OF OCCURRENCE:

j The root cause of this event is attributed to personnel error.

{

Operations Department management did not layout an approved plan of

action in addressing the pipe break associated with the 11TD900 j valve. ' Additionally, Operations Department management did not fully l utilize available resources (e.g., System Engineering) in making the j decision to proceed with Operations Procedure III-1.3.3, even though the reactor power level (79%) did not meet the procedural I _ . . -

LICENSEE EVENT REPORT (LER) TEXT CONTINUATION

! Solem Generating Station DOCKET NUMBER LER NUMBER PAGE l Unit 1 5000272 90-030-00 4 of 7 l

l APPARENT CAUSE OF OCCURRENCE: (cont'd) -

j requirements for initial conditions (i.e., 85 to 90% power). -

contributing factors to the cause of this event was procedural j inadequacy and inadequate training.

l l

Operations Procedure III-1.3.3 was found to be inadequate. The j procedure Precautions section implied that the reason for requiring j the plant to be between 85% and 90% power (Initial Conditions section), to perform the procedure, relates to unnecessary load

reduction. Therefore, Operations management and shift supervision j determined that it was acceptable to close the 11MS29 valve (per the i procedure), in attempting to limit steam flow through the pipe break l

above the 11TD900 valve, even though the Unit was operating at 79%

power. Engineering input was not fully utilized in making the decision to close the 11MS29 valve, using procedure III-1.3.3, or to open the 11TD4 valve.

l A significant contributing factor to this event was Operator training i inadequacy. Licensed Operator training includes training operators on j Turbine operation. This training includes a discussion of the partial arc control scheme. . Procedure III-1.3.3 is reviewed during this training. However, the reasons for the power restriction for use of l the procedure is not addressed. It was found that the Westinghouse l

Turbine technical manual in the Nuclear Training Center library was i not the latest revision (the 1981 version of the manual was found in i the library). This earlier revision does not contain information l relewant to load restriction. The latest revisica contains a brief j statement that identifies that Turbine valve testing below 854 power j should not be conducted due to a potential for Turbine damage.  ;

! A factor which contributed to the inappropriate management decision to l l proceed with the use of Operations Procedure III-1.3.3 was lack of l clear guidance as to the application of Operations Directive procedure  !

OD-15, "Use of Operations Department Procedures". This procedure '

defines under what circumstances a procedure deviation from initial '

conditions can be applied. The guidance provided is not specific  :

thereby allowing significant latitude in interpretation.

m %YSIS'OF OCCURRENCE: 4 The Low-Low S/G Level reactor trip prevents operation with the steam i generator water level below the minimum volume required for adequate heat removal. The trip is actuated on two_out of three low-low level signals in any S/G. The setpoint ensures adequate S/G inventory, at the time of a reactor trip, to allow for possible starting delays of the Auxiliary Feedwater Pumps (BAl; thus preventing S/G dryout and Reactor Coolant System (ABI thermal and hydraulic transients associated with a loss of the heat sink.

The OPC is designed to protect the EP Turbine from overspeed operation during conditions when the plant is not synchronized to the grid. The OPC in part of the EEC System (TGl. When an overspeed condition is sensed, the auxiliary governor emergency trip solenoids are designed

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! . . i d

. LICENSEE EVENT REPORT (LER) TEXT CONTINUATION

! Sclem Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1 5000272 90-030-00 5 of 7 J

ANALYSIS OF OCCUReEMCE: (cont'd)

! to release the operating fluid from the control emergency trip i header. This will result in the closure of the control valves and

[ the intercept valves for ten (10) seconds and five (5) seconds, i respectively. The OPC also functions to electronically provide a close bias signal to decrease the turbine governor demand to zero volts. This closes all four (4) MS29 valves through their hydraulic control valve stopping steam flow in approximately 10 to 15 seconds, i

! Investigation found that the OPC auxiliary governor emergency trip solenoid valves would not function (i.e., close the turbine governor j and intercept valves). However, the OPC did function by initiating a j signal to decrease governor demand to zero volts thereby causing closure of the NS29 valves. The solenoid valves were original i

j equipment.

The RPS functioned as designed and the heat sink was maintained i during this event. Therefore, this event involved no undue risk to

( the health or safety of the public. Bowever, due to the actuation of the RPS, this event is reportable in accordance with Code of Federal Regulations 10CFR 50.73(a)(2)(iv).

{

The plant cooldown was greater than anticipated for a reactor trip i from 79% power; however, it did not exceed the allowable Technical Specification limit. T. , , had decreased to approximately 532' F l

when main steamline isolation was initiated. Emergency Operating l Procedure EOP-TRIP-2 requires main steamline isolation if T.v. has ,

4 not trended back to 547' F approximately 10 to 15 minutes after a l Unit trip.

t l During the plant cooldown, pressurizer level decreased to 144 and Pressurizer pressure to 1975 psig. Prior to the trip, Pressurizer

]

3 level was 43% and Pressurizer pressure 2240 psig. The cooldown was

! compensated for by the manual initiation of Main Steamline Is.olation

! (per the Emergency Operating Procedure). l

} The excessive cooldown has been attributed to operation of all three i

! (3) Auxiliary Feedwater (AFW) Pumps (2 motor driven and 1 steam driven). The motor driven and turbine driven AFW Pumps started as designed; i.e., loss of main feedwater, and all four Steam Generators had reached the low-low level setpoint. With all three (3) AFW Pumps operating, approximately twice the design basis AFW flowrate to the Steam Generators is realized (8.855 lb./hr instead of 4.4E5 lb /hr). The Turbine Driven Pump is designed to supply 100%

flowrate and the Motor Driven Pumps are designed to provide 50%

flowrate each.

)

CORRECTIVE ACTION:

This event has been reviewed by senior management. Those individuals involved in this event have been held accountable as applicable.

Procedure III-1.3.3 and other applicable procedures have been revised

LICENSEE EVENT REPORT (LER) TEXT CONTINUATION j l ,

Solen Generating Station DOCKET NUMBER LER NUMBER PAGE l 4

Unit 1 5000272 90-030-00 6 of 7 l CORRECTIVE ACTION: (cont'd)_ _

l to clearly identify the concerns with Turbine Valve Testing below 85% .

j power.

t Operations Directive procedure OD-15 will be revised to clearly l

identify under what conditions the Nuclear Shift Supervisor can

~

authorize deviation from a procedures Initiating Conditions.

I

{ An Operations Department procedure.will be prepared which will define j what actions shift personnel are required to take for abnormal plant conditions that require " troubleshooting" not addressed by existing i procedures.

! The main, auxiliary, and spare speed sensors were replaced.

L The 11TD900 valve sheared piping was replaced. Preliminary analysis of the pipe has indicated that the pipe sheared due to vibration i induced metal fatigue. This laboracory analysis is continuing. Upon j completion of the analysis, the root cause of the pipe shear will be

determined and appropriate corrective actions will be implemented. -

l An Engineering review of the required AFN System capacity was

! previously initiated due to similar cooldown rates experienced following reactor trips (reference Unit 2 LER 311/90-029-00). This review is continuing.

This event will be reviewed by the Nuclear Training Center. Lessons l

i learned will be incorporated into applicable training programs.

Investigation as to why the OPC solenoid valves did not function revealed that they were mechanically binding. Subsequently, the OPC l solenoid valves and the emergency trip solenoid valve were replaced.

The new valves were tested satisfactorily prior to the Unit i synchronization on September 14, 1990. This testing included ~

functional testing during the Unit restart.

2 l

A preventive maintenance program for the OPC solenoid valves and the i emergency trip solenoid valve, which includes inspection and cleaning, j has been established.

i a

The Salem Unit 2 OPC solenoid valves and the emergency trip solenoid j

valve have been scheduled for replacement during the next outage of sufficient duration.

! The Nuclear Training Center will audit the vendor technical manuals in j the Nuclear Training Center Library to ensure that the latest revision is present. Additionally, a review of the program for ensuring that the latest revision of applicable technical manuals are obtained and 4

i i controlled by'the Nuclear Training Center Library will be conducted.

Changes to the progran~will be made as applicable.

f i

On September 13, 1990 at 0546 hours0.00632 days <br />0.152 hours <br />9.027778e-4 weeks <br />2.07753e-4 months <br />, the Unit entered Node 1 operation. During startup, Turbine instrumentation was closely monitored. This instrumentation includes monitoring for

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~

l. -

1 LICENSEE EVENT REPORT (LER) TEET CONTINUATION Snica Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1 5000272 90-030-00 7 of 7 CORKECTIVE ACTION: (cont'd)

eccentricity, bearing vibration, bearing metal temperature, return l lube oil temperature, and main oil pump discharge pressure. The l observed indications were compared with prior data. No abnormal indications were observed. Synchronization of the turbine-generator occurred on September 14, 1990 at 0519 hours0.00601 days <br />0.144 hours <br />8.581349e-4 weeks <br />1.974795e-4 months <br />.

General Manager -

Sales Operations MJP:pc SORC Mtg.90-139

. .