ML20090B546

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Rev 3 to Procedure 1-OP-2.2, Unit Power Operation Mode 1 to Mode 2
ML20090B546
Person / Time
Site: Ginna Constellation icon.png
Issue date: 10/20/1987
From:
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
Shared Package
ML20090B375 List:
References
FOIA-91-106 1-OP-2.2, NUDOCS 9203030459
Download: ML20090B546 (30)
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Text

_

k RIQUEST7tFCHANGE~ PROCEDURE ADM-5 5~

~~

~

NORTH ANNA POWER STATION.

VIRGINIA POWER Page 1 of 1 01-09-87

../ERVISOR RESPONSIBLE FOR FOLLOWING PROCEDURE:

1 O ABNORMAL O CURVE BOOK,

  • O OPERATING Q WELDING O ADMINISTRATIVE O EMERGENCY Q PERIODIC TEST O

O ANNUNCIATOR O IN-SERVICE INSPECTION O REALT11 FEYSICS O

O CALIBRATION O MAINTENANCE O SPECIAL' TEST

.O O CHEMISTRY O NON-DESTRUCTIVE TEST O START-UP TEST O

PROCEDURE NO:

2 UNIT NO:

/

3 REVISION DATE:

f,, f 7, 7 t.

9,y.g I1TLE:

U A, I r fo gg*2 O pgT2A-p W m or;F I IT) M*0C M 5

CHANGES REQUESTED:

(GIVE STEP NUMBER. EEACT SUGGESTED WORDING. AND LIST REFERENCES, STAPLE A

COPY OF PROCEDURE WITH SUGGESTED CHANGES MARKED TO THIS FORM.)

AoO SrFP 43 J'

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  • iv no n es, s m n in nw co n. ) Y t et7 tat:e nom i~A t Yv t 5 t r% 7v m,-

n~tG pay ss w ysorist is t er s'cty%rs.%

REFERENCES:

e hir< -

J ~/ - SG 9 REASON FOR CHANGES:

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CH.

REQUESTED BY

8 DATE:

9 f,,

f 9, p 7 ACTION TAKEN:

10 DOES THIS CHANGE THE OPERATING METHODS AS DESCRIBED IN THE UFSARv' Q YES NO DOES THIS CHANGE INVOLVE A CHANGE TO THE TECH. SPECS /

O YES NO

')0ES THIS CHANGE INVOLVE A POSSIBLE UNREVIEVED SAFETY QUESTION /

O YES NO IF ALL "NO",

NO " SAFETY ANALYSIS" IS REQUIRED.

IF ANY "TES" A " SAFETY ANALYSIS" I REQUIRED.

(10CFR50.59) APPROVED COPY TO BE PROVIDED TO LICENSING COORD. FOR INCLUSION IN ANNUAL REP ECOMMENDED ACTION:

11 pAPPROVED O DISAPPROVED DOES THIS PROCEDURE CREATE A QA DOCUMENT /

YESg NO-O BY:

(COGNI VISOR) 12 DATE:

13 jo /9-87 REVIEWED BY QUALITY ASSURANCE:

CHANGES MADE:

YESO NO 9' 14 BY:

1$ DATE 16 REVIEWED Y STATION NUCLEAR SAFETY AND OPERATING COMMITIEE:

^ *'h 17 APPROVED D DISAPPROVED O APPROVED AS MODIFIED BY COMMITTEE 1

CIIAIRMAN SIGNATU OA'E:

19 18 T

p7 NEU PROCEDURE REVISION DATE:

/

20 ACTION COMPLETED BY:

h 21 DATE:

I' 22 WILL I AM91 --106 PDR

1-0P-2.2 E

_____ _ Page J..o f_.10 09-04-86 YkRGINIA POWUt NORTH ANNA POWER STATION UNIT NO. 1 UNIT POWER OPDtATION MODE 1 TO N0EE 2 A

REFERENCES:

1.

North Anna Unit 1 Technical Specifications 2.

Westinghouse Operating Procedures 3.

Westinghouse Precautions, Limitations and Setpoints 4.

5.

UFSAR REV. No.:

15 PAGE:

ENTIRE DATE:

09-04-86 APPROVAL:

l REC 0!9 FEND APPROVAL:

A APPROVED BY:

b CHAIRMAN STATION NUCLEAR SAFETY AND OPERATING COMMITTEE SAF:-- Y h A..

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DATE:

^9-04-86 1

1-OP-2.2 Page.l.o L 10-.

._. _ _~...._..___,.

09-04-86 u. -

. = -. -== = = -.

.__.2.

IIRGINIA PohER NORTI N ATION WIT N0.1 3,.

WIT POWER OPDtATION HDDE l TO NODE 2 1.0 Purpose 1.1 This controlling procedure provides instructions for unit power operation from existing power level (Mode 1) to 5 5%' power (Mode 2).

-4 2.0 Initial Conditions 2.1 The unit is in Mode 1 'with Reactor Power > 5%.

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1-0P-2.2 Page 3 of 10 3.0 Precautions and Limitations 3.1 Entry into an OPERATIONAL HODE or other specified applicability condition shall not be made unless the conditions of the limit-

~

ing conditions for operation, as set forth in Technical Specif-ications, are met without reliance on provisions contained in 4

the ACTION STATEMENTS. Unless otherwise excepted, this provi-sion shall not prevent passage through 0PERATIONAL HODES as required to comply with ACTION STATEMENTS.

3.2 T.S. 3.2.1 - The indicated Axial Flux Difference shall be maintained within a i 5% target band (flux difference units) about the Target Flux Difference (for operation above 90% Rated Thermal Power).

NOTE:

The flux must be within the target band within 15 -

minutes or the power must be reduced to below 90%.

3.3 The indicated Axial Flux Difference shall not be outside the 1 5% target band for more than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> penalty deviation cumula-tive du' ring the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, for operation between 50% -

90% Rated Thermal Power.

NOTE:

One minute penalty deviation for each one minute of POWER OPERATION outside of the target band at THERMAL POWER levels equal to or above 50% of RATED THERMAL POWER, and NOTE:

One-half minute penalty deviation for each one minute or POWER OPERATION outside of the target band at THERMAL POWER levels between 15% and 50% of RATED THERMAL Poh1R.

3.4 T.S. 3.2.4 - The QUADRANT POWER TILT RATIO shall not exceed 1.02 (for operation above 50% Rated Thermal Power).

l M 3.5 E S.R. Inst. is inoperable due to the inoperability of 2 or more P.R. Detectors, contact the Inst. Dept. to manually bias, jumper OR reinstate inoperable P.R.

Detectors as required.

1-OP-3.3 Page 4 of 10

.._..- ~ 09 04086 3.0 Precautions and Limitations (cont.)

^ '.~~~ ~ ~

t 3.6 Condenser Vacuum should be maintained as low as possible, ideally below 3.5" Hg', when the Unit is' operating at low loads.

m.

3.7 To prevent potential Turbine damage, the kinit should not be

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operated at lov loads for extended periods without the.MSRs in service.

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1-0P-2.2 Paso 5 of 10

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09;04-36

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m Initials 4.0 Procedure This procedure may be used to decrease power level from any power 3

i level 5100% power to any power level 15% power ~ as dictated by plant w wk a,,

conditions. Mark all other steps MA, sign, date 'and route procedure notingreasonsonthecoversheet.'Alkstapeb.idM%OYiTW&

24inthetwees' starting the w.c power decrease and terminating the decrease must be signed off or a procedure deviation completed.

4.1 Initial Conditions are noted and satisfied.

kwe Wen r.s,e a r ~ J.

4.2 Precautions and Limitations are n td.

NOTE:

Auto rod control may be utilized from 15% to 90% provided that insertion limits are satisfied. Auto rod control may be utilized from 90% to 100% power provided "D" p g k ig aregteg g 2g5,stgs,g g,y 4 u,3 m g,

't. 3 dokg k J et m ov e rrn ener.

4./4 homace-It. it fond r@u,%ction utilizing main turbine " Reference 4

u un Control" V and GO pushbuttons, OR " Turbine Manual" V as ap-plicable.

NOTE:

An Isotopic Analysis for Iodine, including I-131, I-133 and I-135 shall be performed between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a thermal power change exceeding 15 percent of the RATED THERMAL POWER within a one hour period.

6 4./

Borate, as per 1-OP-8.3, as necessary to maintain control rods in the normal operating range.

T.S.3.1.3.6 The control banks shall be limited in physical insertion as shown in T.S. Figures 3.1-1 and 3.1-2.

4. h Verify that the Mixed Bed Demineralizer is in service as per 1-OP-8.2 AND increase letdown rate to at.ximum, _Q required.

4./ 7 As necessary, commence removing the high pressure drain AND low pressure drain systems from service as per 1-0P-34.0.

.-,-.---m---

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1-OP-2.2 PaI3 6 cf 10 g;y Initials 4.0 procedure (cont.)

3 4./

At approximately 70% Reactor Power transfer the Auxiliary-3 Steam supply from 2nd point extraction to main steam (Unit 1 or 2) OR_ U-2 2nd point extration g' to the Auxiliary Boilers

... ; q' t 3

u as per 1-OP-35.1.

NOTE:

An Isotopic Analysis for Iodine, including I-131, I-133 and I-135 chall be performed between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a thermal pcwer change exceeding 15 percent of the RATED THERMAL POWER with a one hour period.

4./

At approximately 55% Reactor Power verify that sufficient feedwater recire. valves (FCV-FW-150A, B 3 C) are open AND place their respective control switches to the "Open" position.

NOTE:

An Isotopic Analysis for Iodine, including I-131, k-133 and I-135 shall be performed between 2 and 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s:

following a thermal power change exceeding 15 percent of the RATED THERMAL POWER within a one hour period.

NOTE:

Pump operations are defined and limited by load shed system as per 1-OP-26.7.

to 4./

At approximately 50% reactor power, one main feed pump may be

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secured,IFdesired,asgr1-0Pgl.l.

g/, c orric/% M rs cct*************

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  • CAUTION:

Condenser vacuum should be maintained as low as s

possible, ideally below 3.5" Hg, when the Unit is o c * * * * * * * * * * * * * * *perating at low loads.

o ***************************

CAUTION:

To prevent potential turbine Damage, the Unit should not be operated at low loads for extended periods a

without the MSRs in ser @ a.

  • c******************************************

or

^ ;) 4.)4 At 35% power, connence removal of the Reheat Steam System by:

If (NA this step (4.p) Il the Unit is not going to be removed from service.)

1-OP-2.2 hee 44f-10--

09-04-86 7, = = =.:=.==: =_ = = -._ =_.....,====.

Initials 4.0

,cocedure (cont.)

et d

4.J.1 At the. reheater control panel, Decrease valve positioner at' sere Depress RESET buttoa 3 verify closed:

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, 1,.

FCV-MS-1044 FCV-MS-1043 FCV-MS-104C FCV-MS-104D

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]' 73 4.)d.2 Commence aligning the HSRa in preparation for start-up as per 1-OP-28.3.

4.g At 30% Reactor Power verify illumination of PR < 30% PWR P-8 PERN (Permissive Panel point D-4).

NOTE -

An Isotopic Analysis for Iodine, including I-131, I-133 and I-135 shall be performed between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a thermal power change exceeding 15 percent of the RATED THERMAL POWER within a one hour period.

4.}( At-20% Main Turbine Power:

t) -

4.p.1 Verify O_R open ALL turbine drain valves:

R MOV-SD-100A MOV-SD-1005 NOV-SD-100C

^

HOV-SD-100D MOV-SD-101 HOV-SD-102A HOV-SD-102B HOV-SD-102C HOV-SD-102D NOTE:

Pump operations are defined AND limited by load shed system as per 1-OP-26.7.

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09-04-86 Initials 4.0 Procedure (cont.)

4.

.2 Remove one feedwater pump from service as per 1-0P-31.1, g

g not done earlier.

4.%

At soproximately 15% Main Turbina Power:

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4.f.1 Verify illumination of IP-12 " IMP PRESS < 15% AUTO ROD BLE".

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4.}#.2 Verify no control rod motion in process, THEN transfer rod control to MANUAL.

4.)8.3. Verify that the steam dump control setpoint is at 1005 psig (pot setting of 71.78%), THEN transfer to " Steam 4

Press" control.

.4.)f.4 Transfer the Main Turbine load control to IMP OUT.-

NOTE:

Closely monitor steam generator levels during this operation.

on 4./ Verify OR transfer Feedwater control to the Bypass FCV's:

45 4.f.1 Verify the following in AUTO OR under operator control in MANUAL:

i FCV-1479 FCV-1489 FCV-1499 e5~

4.K. 2 Place the following in MANUAL AND close:

FCV-1478 FCV-1488 FCV-1498 l

  1. 6 l

4.)$ IF required, transfer auxiliary steam from Unit 1 to Unit 2 main steam OR_ the auxiliary boilers as per 1-OP-35.1.

1-OP-2.2 Rtse.9-ef-10 ~

09-04-86

,--..-...--.-=.~.r.

Initials 4.0 Procedure (cont.)

4.

At 10% Reactor Power:

4.

.1 -Verify illumfantion of IP-D3 "AT POWER TRIPS BLOCKED <

10% P-7 PIRM".

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@ NOTT:

E the following permiss_ive is E lost, note. hat S.R. Inst. will NOT re-instate AND that I.ow Power Ri Flux Trip Protection will 50fTe available. Refer to Precaution and Limitations 3.5.

M 4.)4.2 Verify loss of IP-El "PR > 10% P-10 PERM BLE NIS LP TRIPS".

15 II 4 3/ g not previously performed (Step 4.)d) coemence removal of the Reheater Steam System by:

4.

.1 At the reheater control panel, Decrease valve positioner to zero Depress RESET button AND verify closed:

FCV-MS-104A FCV-MS-104B FCV-!S-104C FCV-MS-104D

  1. 1 4./.2 Align the moisture separator reheaters in preparation of start-up as per 1-0P-28.3.

4.}d Reduce the Main Generator load to approximately 50 MWe THEN:

4.

.1 Remove the Main Generator from service as per 1-OP-15.2.

11 4.)4.2 Verify proper response of the steam dump system.

4.

Initiate 1-0P-26.7 to verify OR, establish required load shedding scheme while continuing with this procedure.

2I 4.J8 Reduce Reactor Power to E 2%, by manual Control Rod insertion.

2 '2-4.K Note proper response of Steam Dump System.

-_- -..- =_-.-. - -. -

i 1-OP-2.2 Page 10 of 10 -- -

4 09-04-86 Initials 4.0 Procedure (cont.)

tl 4.g Stabilize Steam Generator levels at desired level (s).

~ SY 4.y Remove the Main Turbine from service, as, per 1-OP-15.1.

25 4.

Select, to record on MR-45, the high reading P,owerg Inte.r-

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.p;7 mediate Range Channels.

4.

Proceed to 1-0P-2.1 OR 1-OP-3.1 as required.

Completed By:

Date:

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PRIMARY-70-SECONDARY LEAK RATE SURVEILLANCE (PT-46.2)

Check leak rate ---- every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> o

Check trends ---- every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> o

Check alarm setpoints ---- every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> /

o J

4 a

PRIMARY-TO-SECONDARY LEAK RATE SURVETITANCE ITEMS o

N-16 Monitor - every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> o

Condenser Air Ejector R;diation Monitor - every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> S/G Blowdown Radiation Monitors - every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> o

Condenser Air Ejector Grab Samples - every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> o

S/G Blowdown isotopic samples (CAP-4.0) - every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> o

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N-16 MONITOR o

One monitor placed on Main Steam Manifold On1y monitors high energy gammas (4.5 - 7 HeV) o o

N-16 has the following characteristics:

16 (n, p) reaction in core (.05 barns 10 HeV) 1.

0 2.

7.10 second half life 3.

6.1 HeV and 7.1 MeV gammas Automatically subtracts background (0.21 eps) o o

Conversion factor based on calculations 1.

99 gpd/ cps at 30%

2.

53 gpd/ cps at 50%

3.

33 gpd/ cps at 100%

. =.*

' CONDENSER AIR EJECTOR RADIATION MONITOR Radiation monf. tor resp >nds to RCS gas activity that leaks through the S/C's o

and out the condenser air ejector.

Correlation between gross count rate and RCS gas activity based on North o

Anna leak rate data (1983 -1987).

o Correlation is the same for Un4* I and Unit 2.

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S/C BLOWDOWN ISOTOPIC SAMPLES (CAP-4.0)

Mass balance on RCS and S/G isotopics o

1.

I-131 2.

Na-24 3.

Short-lived Iodines a.

I-132 b.

1-133 c.

1-134 d.

I-135 o

Highest value of 1, 2, or 3 above is used.

o CAP-4.0 is currently considered to be the " Keystone" to the leak rate surveillance.

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CONDENSFR AIR FJECT0lt CRAB SAMPLES Mass balance performed on RCS gas activity and air ejector gas activity, o

o No decay is assumed.

o Mass balance leak rate is performed on:

1.

Xe-135 2.

Fr-87 3.

Ar-41 1

3

1 e

RADIATION AIARM RESPONSES o

1-AR-10 (D- ) "High" Radiation Alarta annunciator response procedure refers to Standing Order # 155 -(if applicable).

o

.1-AR-10 (D-4) "High-High" Radiation Alarm annunciator response procedure refers to Standing Order # 155 (if applicable),

o 1-AP-5.1, " Unit 1 Radiation Monitoring System," procedure refers the Operator to immediately notify the STA to evaluate the leak rate trend, and to refer to Standing Order # 155 if the S/G Blowdown monitors, or the Air Ejector Monitor, or the N-16 monitor alarms.

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0917-16-b/

internal Correspondence MARTIN fJARIETTA ENERGY SYSTEMS,INC.

September 17, 1987 R. W. McClung, 45005, MS-151 Travel to North Anna Nuclear Power Plant, September 10, 1987 At the request of the NRC, I returned to the North Anna Nuclear' Power Pl ant in Fredericksburg, Vi rginia.

On September 11, I

met with Emmett Hurphy of the NRC, Ron Ingram of Westinghouse, and Gene Smith and Jim Ogren of the North Anna plant.

The trip was made as part of our technical support work under FIN A-9478 " Selected Operating Reactors Issues," Project 3 "On-Call Assistance."

The purpose nf this trip was to review the-status of the eddy-cur rent inspection to oata prior to the restart of the unit.

The ruptured tube, R9C51, was pulled and examined by metallography.

The cause of failure was determined to be f atigue.

The rupture pattern of this tube matched the pattern produced by a tube that was failed in a laboratory f atigue test.

The inspection t.nd data analysis with the 8 x 1 probe was completed on September 10, an.1 the analysis team took a day off before starting work on unit 2.

A sample of each type of indication was reviewed:

DI(distorted indication at support plate, bobbin coil only), TI (distorted indication at top of tubesheet, bobbin coil only), and PI (possible indication, 8 x 1 probe, anywhere in generator).

The calls and their disposition in each case seemed correct to me.

A review of tube R10C51 was also made.

This tube was adjacent to the ruptured tube and it was postulated that it might have been damaged by the ruptured tube flopping against it.

A possible defect that appeared to-be about 20% on the bobbin probe showed no indications on the rotating pancake probe.

No defects or pattern of defects were found that would indicate that there was any mechanism other than f atigue involved in the rupture.

Although no defect can be detected in advance, it may be possible to detect a region of cold work in the tube that would give advance warning. The electrical and magnetic properties of metals will change with cold work, and eddy -

currents have been used to measure this for some metals.

A fatigue experiment should be conducted using very accurate equipment to determine the amount of ch ar.,e in the electrical and magnetic properties of Inconel 600 with cold work.

Then, if these properties change enough.

sufficiently in advance of a rupture, an eddy-current test can be designed to detect f atigue in the tubes.

This experiment represents an extended-effort and could not be done before the restart, s

N.s

R. W. McClung Page 2 Septenber 17, 1987 To prevent this type of failure in the future, the flow rate in this region of the generator will be reduced.1d the outer unstabilized tubes will be plugged.

The stabilizing bars were found to extend further into the center of the bundle than previously thought. The failed tube was one of the last unstabilized tubes, as determined by an eddy-current location of the stabilizing bars.

The eddy-current location of the stabilizing bars with the bobbin probe was a lucky accident rather than by design.

The tests are utually designed to ignore things outside the tubing, but in most cases a signal from the 3/8-in.2 Inconel bar shows up in the scan.

The bar was not present in some of the scans on the outside of the bundle, although it nust have been present.

The unstabilized tubes toward the outside of the bundle will be preventively plugged, it is likely that some of the tubes to be plugged are actually stabilized but the bar is not being detected.

A large rotating pancake probe should detect these bars with no trouble.

Tne suggestions for detecting the cold work and antivibration bars were passed on to the utility.

They may use removable plugs to plug the outer unstabilized tubes and inspect with the large rotating pancake probe at the next outage.

O V.r0ertU C. V. Dodd, 45005, MS-151 (4-4839)

CV0:jlb cc:

H. F. Conrad J. H. Deva n J. B. Henderson, NRC A. P. Malinauskas E. Murphy, NRC /

J. G. Pruett G. M. Sl aughter i

C. V. Dodd/ File i

'C' S/G DATA

SUMMARY

,g AS OF 7/24/87 The IS sample selected for the 'C' S/G inspection is based on the following:

Satisfy IS T.S. sample plan Sample shall include:

1) all previously identified degraded tubes (degraded defined as any. callable indication) 2)

tubes identified by 3x3 grid for rows 10-46 and a 3x4 grid for rows 2-9 (tube will be excluded if previously plugged) 3)

the 8 tubes surrounding the failed tube

'To date the standard bobbin coil inspection has been performed from the hot leg on a total of 366 tubes (Westinghouse analysis is complete on all 366) out of a total of 374.

Tubes in rows 10-46 were inspected from tubesheet to tubesheet.

R>ws 2-9 were inspected to the 7th support plate on the cold leg side.

Of the 366 tubes analyzed there have been five distorted indictations (DI's) identified and one clear indication.

The following summarizes these indications and provides a review of the spring refueling outage data for these tubes.

Row Column Spring Data July Data Explanation 16 10 Not identified DI DI is located at the 6th support plate on the hot leg.

Indication was missed in spring inspection.

Signal appears the same now as in spring.

9 32 Not tested DI DI indication just above the 7th support plate on the cold leg. This area was not inspected during the spring outage.

31 49 Not identified 78%

Indication is located approx.

1/2 in. above the tubesheet.

Indication was missed in j-spring outage.

O' 19 19 No flaw apparent DI DI. located just above the 6th support plate on the cold I

leg.

Signal appears to have l

changed.

34 49 No flaw apparent DI DI located just above the 1st support plate on the hot leg.

Signal appears to have j

j changed.

25 58 No flaw apparent DI DI located just below the 2nd support plate on the hot leg.

Signal appears to have changed.

I b

o In addition to the standard bobbin coil inspection, an 8x1 inspection has begun on 'C' S/G on the hot leg side to just past the 7th support plate.

The initial 8xl inspection plan consisted of 150 tubes in the columns around celumn 51.

Of the; tubes inspected (107), 19 have been analyzed by Westinghouse.

The, results of these analysis show two possible indications.

These indications have not been verified. tith RPC. Neither of these tubes were inspected beyond the hot leg tubesheet region during the spring refueling outage.

The indications are sumarized below:

Row Column Indication Location 46 49 3rd and 4th support plate hot leg 46 50 1st support plate hot leg i

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= - - -. -

PAge~1 07/24/87 INSPECTION AND REPAIR HISTORY

  • Unit Start-up in 1978
  • 1979 Refueling Outage 1

Tubes Inspected Leakage Tubes Plugged S/G A - 440 None S/G A - 94 S/G B - 133 None S/G B - 94 S/G C - 480 2 leaks in S/G C S/G C - 96 Comments: Resin intrusion during cycle. Row 1's preventively plugged. 2 other tubes plugged due to denting. Denting first observed, Boric acid treatment initiated. Leakage rate barely detectable.

  • 1980 Refueling Outage Tubes Inspected Leakage Tubes Plugged S/G A - 485 None None S/G B - 476 None None S/G C - 478 None None Coeunents : None
  • 1982 Refueling Outage Tubes Inspected Leakage Tubes Plugged S/G A - 107 None None S/G B - 1165 None None S/G C '- 243 None None Comments: Partial tube end repair due to split pin damage in S/G's A and C.

Page 2 07/24/87

  • 1904 Forced Outage Tubes Inspected Leakage Tubes Plugged 4

S/G B - 579 3 leaks in S/G B S/G B 7 S/G C - 552 2 leaks in S/G C S/G C - 5 Comments: No progression in tube denting observed. Row 1 leaking explosive plugs repaired.

Partial tube end repair performed.

Distorted indications at support plates first ns,ticed. Leakage rate 396 GFD.

  • 1984 Refueling Outage Tubes Inspected Leakage Tubes Pluggd S/G A - 100% available None S/G A - 20 S/G B - 100% available None S/G B - 1 S/G C 100% available None S/G C - 5 Profilometry in all 3 5/G's.

Comments: Partial tube end repair performed. Attempted tube removal in A S/G.

Distorted indications observed.

Foreign object located and removed in S/G C.

2 tubes plugged preventively.

Leakage rates 2.3 GFD in

~ A, and 10. 8 GPD in C.

  • 1985 Outage Tubes Inspected-Leakage Tubes Plugged S/G A - 830 3 leaking tubes S/G A - 13 l

Comments: Distorted indications observed. Leakage rate 213 GFD.

l

'e Page 3.

07/24/87

  • 1985 Refueling Outage Tubes Inspected Leakage Tubes Plugged S/G A - 100% available None r

S/,G,A - 9 S/G B - 100% 'availab1'e 2 leaks in B S/G B - 17 S/G C - 100% available 4 leaks in C S/G C - 47 Comments: No tubes removed with 4 support plate intersections from C S/G.

30 tubes from the three steam generators were plugged due to

" strong" distorted indications.

Sample specialized NDE applied in S/G C.

Leakars rate 90 GPD.

  • 0ther Events During 1986 thru March 1987

-Extensive examination of tubing and materials with EPRI and Westinghouse.

-Preparation and submission of WCAP to NRC.

-Requested and held meeting with NRC staff in March,1987.

-Developed eddy current rule base for April 1987 Refueling.

. ?,

  • 1987 Refueling Outage Tubes Inspected

_ Leakage Tubes Plugged 4

S/G A - 100% available.

-None S/G A - 83 S/G B.'-" 100% available -

2 tubes in B-S/G B - 62 S/G C - 100% available 4 tubes in C S/G C - 118 Comments: Extensive additional NDE performed included:

-Profilometry of more than.100 tubes in each S/G.

r

-8 X 1 probing of nearly -100% of available tubes.

e

-Rotating pancake probing of all-identified tubesheet. indications and

- a sample of support plate intersections.

-AVB indications ' first noted,

. less than 40% and no tubes plugged.primarily in B S/G. All-indications Tube and ' repair completed.

U-bend stress relief performed on all l

svailable Row 2 tubes 'in all 3.- steam generators.

relief demonstration performed in S/G B.

Support plate stress containing. 2 tubasheet Two tubes removed from S/G A Leakage rate:

indications and one support plate intersection.

l' 11.5 GPD in B and 14.6 GPD in C.

m

~)

Page 4 07/24/87 NORTH ANNA UNIT 1 TUBE PLUGGING

SUMMARY

s'-

W AL OUTAGE DATE STEAM GENERATOR TUBES A

B C

SEPTEMBER '79 94 94 96 284 JANUARY '84 0

4 5

9 MAY '84 10 1

5 16 AUGUST '85 13 0

0 13 NOVEMBER '85 9

17 47 73 APRIL '87 83 62 118 263 TOTAL.

209 178 271 658 (6.2%)(5.3%) (8.0%)

(6.5%)

l.

4..

m

September 22.198P TypeilLeter Steam Generator Tube Rupture Event Westinghouse Preliminary Assessment Summary of Nor1h Anna Experlence On ' July 15, 1987, a steam generator tube rupture event occurred at North Anna Unit 1 shority after reaching 10h power. For several days prior to the event, air ejector radiation rnonitor readings we enatic. Howeser, grab samples were taken prior to the tube rupture for environrnental release calcul Subsequent ar.alysis of this data indicated that increasing primary to secondary leakage occurred 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> perbd. which was beiow normat technical specification limits, prior to the tube rupture eve ruptured tut >$ was beated in Row 9 Colurm 51 in steam generator *C*.

The leakage location was found to be at the top tube support plate on the cold leg sde of the tube. The opening was circumferentialin orientation and exterded 360* around the tube. A preliminary assessment indicafee that this event do not represent an unreviewed safety issue.

Failure Mechanlem Explanation ihe cause cf the tube rupture has been determined to be high cycle fatigue. The source of the loads belic ved to te a combination of a mean stress levelin the tube ard a supertmposed attomating s mean stress is produced by denting of the tube at the top tube support plaie and the attemating stress due to out of-plane defle:: tion of the tube above the top tube support caused by flow induced vibra Derring also sVta the maximJm tube bending stress to the vicinity of the top tube support plate loads are st.ffblent to pmduce fatigue and are consistent with a bwer bound fatigu's curve for the materialin an AVT water chemistry envirorrnent. The magnitude of the alte' mating titress la cons! st fluidolastk tt.be vibration macranism.

The most signficant contributcr to the occurrence of excessive vibration is t% reduction in dam tube to-t be support pla'e irterface cauced by the denting. The abserne of antivlbration bar (AVB) support neceasary for requis,lte vibration to occur, together wl:h the reduction in damping. The presenc The ort;inal deskan configuratbn required AVBs to be loserted to R some AVbs in the North Anna Untt 1 steam generators penetrate to Row 8, exceeding the mlnlmum AVB insertion depth requiremert. No AVB support was present for the Row 9 Column 51 tube that ru Also contributirg to the level of vt> ration, and thus loading, is the bcal flow fieid sasociated with th loading cond!tions and fatigue properties.geonetry of thi steam generttor. The ruptured tub The prerequisite cond!! ions derived from the evaluations were concluded to be:

EMig:afLEecubimda Prereutee Conmem l

Mean Stress

. Denting l

A!1emating Stress

. Tube Vibration

  • Denting at top TSP
  • High Local FluH Forces
  • Absence of AVB support Mate tal Fatigue Properties

. AVT Environmert

. Lower range of properties Steam Generator Evaluation Criteria A general criteria for operating steam generators has been developed based on the North Anna experience. Arry steam generators which have flow conditions and tube suppor conditions which are less conservative trun the mocification criteria estab!!shed for Row 8 through 12 a.t North Anna Unit 1 should be cva!uated.

i 1

b

Septembst 22,1587 Type Il Letter 6

v The followiry condtions make up this criteria:

The steam Conerator shoald be evaluated if the fo!!owing cond!tions (1) & (2) are met (1) De1 ting must be present at the top tube support plate,

.. and...

(2) the bundte Ibw parameters must be higher than 90% of those at North Ar.na prbr to modfication This second condition is satisfied if elther (a) the bund 4 flow is higher than 90% of North Arr.a.

...o r...

(b) the fluidelastic vbration stabillry ratio is higher than 90% of Nodh Anna.

This criteria la preliminary and believed to be conservative. It is important to note that the North Anna un!!s have the highest bundle flow parameters of the 51 Series steam generators. If a steam generator were fourd to exceed this criteria, it may still be less severely loaded than the North Anna units prior to modfication; yet, further detalled evaluations would be necessary to determine the potential for a similar tube rupture event.

Recommendations Based on the records aval!able to Westitchouse it appears that your plant falls bebw the criteria either because (1) denting is ret believed to be present at the top tube suppen plate in any of your steth generators or (2) the bundle Ibw parameters in your steam generators are kss than 90% of the North Anna steam generator values prbr to the recent field rnodffication.

Confirm That There im No Denting at the Top Tube 860 port Pfale As a precaution, it is recommended that the eddy current inspectan records for each steam generator be reviewed to confirm that to tube denting is present at the top tube e@ ort plate. Denting la believed to be necessary to produce a relatkely high mean stress which reduces the Nbe fatiguo endurance limit, to shift the maximum tube berxlity stress to the vicinity of the top tube support p%1e and for targe amplitude tube vbration to occur.

A;tions Recommended for Other Plante Other plants, with steam gerwrators which exceed the criteria, have been notified to evaluaa their plant recoros describing the condnien of all tubes in Row 8 through 12 in all steam generators. Co!! action of the fotbwing data has been recommerded:

(1)

Ident!fication of all tutes with any denting at the top 'ube support pitte (alther hot or coldles);

(2) Quantification of the AVB insertion depths for each column (from eddy current data);

(3)

Notatbn of any tube weat at any AVB of tap tube support plate intersection, if the results of this data colfsetion confirm that the above crtteria are exceeded, then it le also beirs recommended that the plant systems anc practices for determining primary to secondary leak rates be cvaluated. Such systems and practices should be capab!e of producing accurate leak rate data that wcid detect and clatalfy a tube rupture event like the one that occurred at North Anna.

A Technical Meeting is Planned The Westinghouse Projects Office will be communicating w!!h you to keep you informed about any further developments relating to your steam generators. A customer meeting to d!scuss the technica! details re!ated to this issue is scheduled for October 16,1987 in Pittsburgh. At that ilme a deta!!ad presentation will be given describiry both the North Anna situation and the potential actions to address and to resolve th's ISsu('.

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