ML20133P303

Draft Steam Generator Tube Rupture Incident Rept

ML20133P303
Person / Time
Site:	Fort Calhoun
Issue date:	06/30/1984
From:	OMAHA PUBLIC POWER DISTRICT
To:
Shared Package
ML20133P091	List: ML20133P090 ML20133P303
References
TAC-55237, NUDOCS 8508140254
Download: ML20133P303 (49)

Text

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0MAHA PUBLIC POWER DISTRICT FORT CALHOUN Steam Generator Tube Rupture Incident Report d

DRAFT

-- June 1984 8508140254 840618 PDR ADOCK 05000285 O PDR

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TABLE OF 'CONTEiiTS DRAFT

2.0 DESCRIPTION

OF EVENT ,,

2.1 Summa ry 2.2 Operator Procedures and Actions 2.3 Sequence of Events 2.4 Time Sequence-Steam Generator Level and Pressure 3.0 STEAM GENERATOR INSPECTION HISTORY

SUMMARY

3.1 Inspection Summary Prior to 1984 3.2 1984 Inspection Summary 3.3 Cycle 8 Leak Detection Program 4.0 VISUAL INSPECTION AND LABORATORY AtlALYSIS 4.1 Steam Generator B - Tube L29R84 Section 4.2 Steam Generator B - Tube L29R86 Section 5.0 OPERATION RELATED ACTIVITIES 5.1 Leakage Detection Improvements 5.2 Sampling Frequency Improvements 5.3 Procedure Reviews 5.4 Licensed Operator Refresher Training 6.0 CORRECTIVE ACTION TO REDUCE THE PROBABILITY OF THE '

FAILURE MECHANISM 7.0 TUBE PLUGGING TO ELIMINATE SUSPECTED DEFECTS 8.0 10 CFR 50.59 EVALUATION 8.1 Purpose 8.2 Method 8.3 10 CFR 50.59 - Unreviewed Safety Question Evaluation 8.4 Conclusions DRAFT

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i LIST OF' TABLES ;g l

l 1 Table 1: Sequence of Events

, Table 2: 1984 Eddy Current Testing Summary and

Results - Steam Generators A & B ,,

i Table 3: Summary of ECT Indications Table 4: Profilometry Data Table 5: Summary of Plugged Tubes i Table 6: Elemental Analysis of Tube. L29R84 1

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DRAFT 2 i

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LIST OF FlGURES Figure 1: Time Sequence Relating to Steam Generator Level and Pressure Figure 2: Dimensional fleasurement of Tube L29R84 Figure 3: Sectioning Diagram of Tube L29R84 Figure 4: Dimensional Measurements of Tube L29R86 Figure 5: Disposition of Pieces fran Tube L29R86 l DRAFT 3 I

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1.0 INTRODUCTION

At 4:50 p.m. on May 16, 1984, the Fort Calhoun Station experienced a tube failure in the "B" steam generator. At the time of tube failure, the plant was perfoming a Reactor Coolant System Leak Test as part of the normal startup procedure. The tube failure incident included a primary system depressurization with no release of radioactivity into the environment.

OPPD has performed extensive evaluations of the tube failure event.

The evaluations were presented to the NRC staff on May 29, 1984, and documented by letters dated 5/31/84 (LIC-84-159, W. C. Jones to J.

Miller and LIC-84-160, W. C. Jones to J. Collins). In addition, num-erous telephone calls have been held between District personnel and NRC personnel . The above submittals addressed the following items: sel-ective plant parameters and plant status immediately prior to, during, and following the incident; steam generator inspections performed and results obtained; visual inspections and laboratory metallurgical anal-ysis of the failed tube; operation related activities including plant procedures and chemistry analysis; conclusions reached and the Dis-trict's plans to return to power operation.

On June 5,1984, the District received a letter signed by Mr. John ,

Collins, Region IV Administrator, directing the District to perform and

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complete actions in addition to those stated in the District's May 31, 1984, letter. The letter dated June 5, 1984, also stated that NRC approval was required before the Station was taken out of refueling shutdown condition (Mode 5).

The purpose of this report is to summarize the District's activities to date, relating to the steam generator "B" tube failure incident. This report includes an update of the May 31, 1984, submittal referenced above and actions taken in response to the June 5, 1984, communication from the NRC-I&E Region IV Administrator. ,

This report is comprised of seven major sections. The first, Section 2, is a description of the event. Section 3 describes the steam gener-

' ator inspections performed and the results obtained. Section 4 des-cribes metallurgical examination performed and the re3ults obtained.

Section 5 describes operations related activities. Section 6 describes the District's corrective action to reduce the probability of the fail-ure mechanism. Section 7 describes the District's tube plugging to eliminate suspected defects. The final major section is comprised of the District's 10 CFR 50.59 evaluation.

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20 DESCRIPTION OF EVENT il 2.1 Summary At 4:50 p.m. on May 16, 1984, the Fort Calhoun Station experienced a tube failure in Steam Generator "B". During a routine plant startup from a refueling outage, the reactor coolant system (RCS) was being pressurized for a leak test. At approximately 1,800 psia, RCS leakage approached 110 gpm with indication of a tube rupture in RC-2B ("B" steam generator). A depressurization and cooldown of the RCS was initiated. RC-2 B was isolated. NOTIFICATION OF AN UNUSUAL EVENT was declared.

The unusual ever', was tenninated when the RCS was placed in cold shutdown. No release of radioactivity to the environment occurred .

2.2 Operator Procedures and Actions Various emergency procedures were used by plant personnel during the incident. Plant personnel performed actions dictated by procedures and safely placed the plant in a refueling shutdown condition (Mode 5). Operators' response and the written proce-dures used for mitigation of the incident were not only adequate, but performed as described and dictated by preplanned procedures for this type of incident.

2.3 Sequence of Events Table 1 contains a sequence of events for the steam generator tube rupture incident 2.4 Time Sequence - Steam Generator Pressure and Level Figure 1 contains a time sequence relating to steam generator level and pressure.

1. 9 9

5 DRAFT

Table 1

l Initial Conditions Plant was being taken from Mode 4 to P. ode 3 RCS boron approximately 2100 ppm Tc = 398* F Pressurizer level = 70%

rressurizer pressure = 880 psia Steam generator RC-28 level = 72%, pressure approximately 200 psig Pressurizer fill in progress for RCS leak test; one charging pump in operation taking suction of f of SIRWT RC pumps RC-3A, RC-3B and RC-3C in operation Letdown on minimum Both MSIV's, HCV-1041A and HCV-1042A, open Steam generator blowdown secured Feeding both steam generators with P4-6 aux. feed pump; FW bypass valves HCV-1105 and HCV-1106 in AUTO Atmospheric steam dump valve, HCV-1041, open slightly The following is the sequence of events for the steam generator tube rupture (SGTR) of May 16, 1984.

Time Event 1618 Operator noted that pressurizer level was no longer increasing with single charging pump in operation; pressurizer pressure decreasing slowly; started other two charging pumps.

1636 Pressurizer pressure and level slowly increasing; however...

charging flow rate only approximately 50 gpm versus expected flow rate of 120 gpm (probably due to inadequate NPSH with existing SIRWT level and three charging pumps); operator switched charging to VCT, flow rate increased to 120 gpm.

1639 PPLS reset at 1700 psia (automatic).

1641 Pressurizer solid; pressurizer pressure = 1800 psia and slowly increasing 6

DRAFT

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DRAFT Time Event  ;>

• 1642 Operator isolated letdown.

Operator noted level increasing above setpoint in RC-28, thought to be leakage through HCV-1106, operator closed block valve HCV-1385.

1645 VCT level approaching 0% despite blended makeup in progress; operator secured two charging pumps; pressurizer pressure = 1850 psia.

1646 PPLS blocked at 1700 psia (operator action).

1648 Pressurizer pressure dropping. rapidly.

• 1650 Operator noted continuing increase in RC-2B level; auxiliary FW pump FW-6 secured.

1654 Pressurizer pressure = 560 psia; RCS solid; operator opened letdown valve to draw pressurizer bubble.

1658 MSIV fron RC-2B, HCV-1042A, closed by operator.

1659 Cooldown of RCS initiated using steam generator RC-2A and atmospheric dump valve HCV-1040.

1700 Reactor coolant pump RC-3C secured.

1701 Reactor coolant pump RC-3B secured.

1711 ftotification of unusual event declared.

1717 flRC notified via red phone.

1718 RC-2B level of f-scale high; secondary pressure approximately 200 psig.

1720 Steam generator blowdown sample lined up to rad'i'oactive waste system; blowdown monitor pegged high.

1730 Cooldown and depressurization of pressurize:- initiated using auxiliary spray.

1830 Pressurizer pressure = 220 psia; Tc = 330 F; pressurizer level =

70%.

1841 VCT backfilled with fl2-2005 Shutdown cooling initiated.

I DRAFT 7 l

1

a Time Event  !,

(May17,1984) 0005 Tenninated unusual event at 210 F.

• 0730 Steam generator RC-2B solid.

• Time approximate based on interviews with operators; precise data unavail-M[

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Fioure 1: Time Seouence "elatinq to Steam Generator e

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DRAFT 3.0 STEAM GENERATOR INSPECTION hlSTORY

SUMMARY

g 3.1 Inspection Summary Prior to 1984 The Fort Calhoun StatNn utilizes two Combustion Engineering vertical U-tube steam generators, each of which contains 5,005 Inconel 600 tubes. The tubes are 0.75 inches outside diameter with 0.048 inch minimu9 wall thickness.

The Fort Calhoun Station has essentially always operated with a carefully maintained AVT secondary chemistry program. The peri-odic inspections utilizing visual and state of the art eddy cur-rent testing' techniques of the steam generators have shown them to be in good condition. The District has endeavored to address operational problems in a timely manner. The results of all of the eddy current examinations of the steam generator tubes have shown the generators to be in Technical Specificcuon Category C-1.

A pre-operational ECT baseline inspection of 200 tubes per steam generator was performed in July 1973. Some mechanical imperfec-tions were noted in the "A" generator.

225 tubes in each steam generator were ECT inspected at the first refueling outage in February 1975. No evidence of degradation or magnetite denting was noted at that time. The same was true of the inspection of 408 tubes in the "B" steam generator in Novem-ber 1976.

An ECT inspection of the "A" steam generator in November 1977 was performed in order to assess the imperfection indications which had been discovered in 1973 and 1975. This inspection was limit-ed to 165 tubes and was not intended to meet the requirements of Regulatory Guide 1.83. There was no evidence of deterioration or denting of the type related to magnetite growth at the drilled hole support plates.

500 tubes in the "A" steam generator were inspected in October 1978, using single frequency ECT. Some dent-like indications were observed, but evaluation showed no change with regard to the 1977 indications. One tube showed 38% degradation and two tubes showed less than 20% degradation. Although none of these tubes exceeded the plugging criteria, they were plugged as a precau-tionary measure. During the 1984 inspection, it was discovered that two tubes had actually been plugged and one end each of two adjacent tubes. The open end of these two tubes have been plug ged. The first indications which were reported to the-District as magnetite denting resulted fran the inspection of 328 tubes in the "B" generator in October of 1981. This was the first inspection which utilized multi-frequency FCT techniques.

All previouis exams had been done with single-frequency ECT. One tube was reported as having 38% degradation. This tube was not plugged, and it was reinspected in 1982. Evaluation of the indi-cation at that time showed a dent, but no defect, at the point in 4 question.

DRAFT

, b h,M In December 1982, 308 tubes in the "A" generator and 302 tubes in the "B" generator were examined using multi frequency ECT. This inspection showed the presence of moderate dent-like indications in both generators. One tube in steam generator "A" showed 20%

degradation, and two tubes in steam generator "B" indicated less than 20% degradation.

3.2 1984 Inspection Summary 3.2.1 Planned Outage Inspection ,,

Plans for the March 1984 inspection involved a nominal 1,000 tubes in each steam generator, primarily for assess-ment of the extent and growth of denting in the No. 8 par-tial drilled hole support plates as the primary input to a decision to perfonn the rim cut modification. The actual number of tubes which were examined full length during this inspection were 1,454 in steam generator "A" and 1,034 in steam generator "B". Additional part length examinations were conducted to measure sludge height, and some tubes restricted the passage of an ECT probe and are not included in these totals. The inspection showed fur-ther dent-like indications, primarily at the No. 8 par-tial drilled hole support plate and in the batwing areas.

Based on evaluation of this data..the District decided to perfonn the rim cut modification on the No. 8 partial drilled hole support plate. At the time of this inspec-tion, the evaluation of the data showed no degradation indications in the "A" steam generator and one previously detected indication in the "B" steam generator. Four tubes in steam generator "A" and five tubes in steam gen-erator "B" were plugged due to restriction to passage of a 0.540 inch ECT probe, which is consistent with Combus-tion Engineering's plugging recommendations for restrict-ed tubes. ,

Following the perfonnance of the rim cut modification, 120 peripheral tubes in steam generator "A" and 111 peri-pheral tubes in steam generator "B" were retested to de-termine if there had been any damage resulting from the perfonnance of the rim cut. One tube in steam generator "A" was verified to have been damaged and was subsequent-ly plugged. In addition to the peripheral inspections, 68 tubes in steam generator " A" and 69 tubes in steam gen-erator "B", in the area of the No. 6 partial suppor't' plate / egg crate interface were examined to determine if any additional tubes were restricted in these areas. No additional restricted tubes were found. 118 tubes.in steam generator "B" were examined in the steam-blanketed tight radius U-bend areas for the presence of indications such as have been found at other operating plants; no such indications were found. Also, approximately 50 tubes were examined with a profilometry probe in steam generator " A" in an ef fort to characterize the dent-like indications and the restriction at the No. 6 support ele-vation. This inspection was limited to vertical tube g

sections due to the type of probe that was used.

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a 'i 2 In addition to the eddy current examinations which are conducted from the' primary sides of the steam generators, detailed secondary inspections are conducted at each re-fueling outage. These inspections involve a detailed l crawl-through of the secondary sides of the steam gener-ators to ascertain that all components are properly se-cured and in good condition, sludge and scaling sampling and analysis, inspection of steam generator internals from the handholes, and photographic documentation. The secondary inspections which have , peen conducted have shown the Fort Calhoun steam generators to be in good I condition and without excessive amounts of deposits.

3.2.2 Post Tube Failure Inspections The failed tube, L29R84, was eddy current tested in De-cember of 1982. There were no defect or dent indications present in the tube at that time. The data tape from that inspection has been rereviewed subsequent to the failure, and certified analysts have again stated that there is no evidence of defect or dent indications in the tube at that time. This tube was included in the March 1984 inspection program. Reevaluation of the data tape from that March 1984 inspection shows a 99% through-wall defect at the location of the failure. This indication was missed on initial analysis of the data from the March 1984 inspection due to human error. Subsequent to identi-fication of the leaking tube, the location of the failure was confirmed by eddy current testing. There are no de-fects in other portions of the failed tube.

Following discovery of the leaking tube, the District em-barked on a test program which ultimately involved multi-frequency eddy current testing of all accessible tubes in both steam generators. There were 29 tubes in Steam Gen-erator "A" and 12 tubes in Steam Gen'erator "B" which could not be inspected using the Zetec SM-4 polar posi-tioner. The frequencies used for this inspection were as follows:

400 KHz differential 200 KHz differential 300 KHz absolute 100 KHz absolute ..

The 400 and 200 KHz signals were mixed to suppress the effects of the vertical support straps, and the 300 and 100 KHz signals were mixed to suppress the effects of the support plates and egg crates.

In addition, those tubes from the March,1984, program which were not retested otherwise with bobbin coil or pancake array probe ECT were retested using a 100 KHz absolute test for enhanced defect sensitivity. The original program used 800 KHz instead of 100 KHz in order to mix out ID tube noise and allow better determination of denting in the No. 8 partial support plates.

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+w b ,hwNa k [3 In addition to the failed tube, B-L29R84, the following tubes showed degradation or defect indications at the hot leg vertical support. The degree of degradation is also indicated.

A-L85R80 <20%

A-L85R82 28%

A-L94 R75 <20%

A-L101R80 <20% ..

B-L85R86 42%

B-L102 R77 22%

~~B-L104R75 26%

The following tubes from the above group which showed indications at the hot' leg vertical support were in-spected in December,1982, with results as noted:

A-L101R80 - NDD at hot leg vertical support, no known dent B-L102R77 - Dent at hot leg vertical support, NDD

" B-L104R75 - NDD at hot leg vertical support, no known dent From all of the ECT work which was performed, only four tubes showed a defect (> 40%) indication, two in each steam generator. Tube A-L37R18 showed possible evidence of wastage in an area several inches above the tube sheet, with 27% and 53% indications in the wastage area.

This tube has not been inspected previously. Because of concerns about the presence of these indications, the District has elected to cut and remove a tube section which contains the indications for future metallurgical analysis. There is no evidence to suggest that this problem is related to the failure of tube B-L29R84 which occurred at the top of the tube bundle. Tube A-L64R85 has a 44% indication just below the #7 hot leg support.

This tube was intended to be plugged in 1978, but only ,

the hot leg end was plugged. Reinspection showed pro- l gression of the indication. Tube B-L85R86 has a 42%

indication at the hot leg vertical support strap. Tube B-L29R82 is the failed tube. ,.

A summary of all degradations or defect indications fran the 1984 inspection programs is presented below: Further details are given in Tables 3 and 4. Pe rmeabi li ty. va ria-tions are also included.

Steam Generator "A" l

< 20% 7 20 - 40% 8

> 40% 2 PV 6 13 N

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Steam Generator "B"

< 20% 18 M[N'he/) *N 20 - 40% 5

> 4 0% 2 PV 16 Specialized eddy current testing using 1 x 8 and/or 4 x 4 pancake array probes was perfonned on 300 tubes on Steam Generator "B". The only tube in this program which showed an indication in the vertical support areas was tube L85R86, which has been discussed previously.

Profilometry, us.ing a 1x8 superflex profilametry probe, was performed and eval.uated on 206 tubes in Steam Gener-a to r "B" . 147 of these tubes are in the outer areas of the tube bundle and pass through all three vertical sup-port straps. The test results for these 147 tubes were compared to the results of a bobbin coil exam performed on the same tubes. Of the dents detected, the largest were at the vertical support strap on the hot leg side of the generator. 74 of the 147 tubes had dent indications at this location. In comparing the two test methods, it was noted that the bobbin coil was only able to detect 59.5% of the dents at this vertical support strap. The overall results for all three vertical support straps showed that the bobbin coil detected 41.5% of the dents detected by profilometry. The bobbin coil also showed smaller dent indications than those that were observed with profilometry. This was not unexpected, however, due to the differences in the two test methods.

Profilometry was conducted on 59 tubes in inner areas of the tube bundle. These tubes have only a single, center, vertical support strap. 21 of these 59 tubes had dent in-dications at the vertical strap. These dent indications were of significantly lower magnitude than that were

, noted in tubes which pass through the three vertical sup-po rt straps. Denting was noted with iricreasing frequency as the row number increased. From Row 49 outward, nearly all tubes had a dent indication in the vertical support strap.

> Further information regarding the bobbin coil ECT and profilometry testing is presented in Tables 2, 3 and 4.

A summary of the tubes which have been plugged since ,

initial operation is presented in Table 5. l In order to be assured that the probability of detecting degradation or defects is as high as possible, within the

< limits of eddy current testing, all data taken since the I

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tube failure has been analyzed and independently re-viewed. The data from the March 1984 inspection was re-analyzed and independently reviewed.

3.3 Cycle 8 Leak Detection Program In February 1984, approximately three weeks prior to a scheduled refueling shutdown, a very small primary-to-secondary leak was discovered in the "B" steam generator. Ti}is leak was confinned two weeks prior to this scheduled shutdown. Based on camparison of primary and secondary coolant activities, the leakage rate was detennined to be approximately 0.2 gallons per day. The esti-mated leak area to give this leak rate at nonnal operating temper-atures and differential pressures is 2 x 10-7 square inches. In a concerted effort to locate the leaking tube, the District con-ducted two helium mass spectroscopy tests, one each before and after sludge lancing of the "B" steam generator during the 1984 refueling outage. These tests were unable to isolate the leaking tube. The District also conducted a hydrostatic test with a dye indicator as a further effort to locate the leaking tube. This test was also unsuccessful in locating the leaking tube. The failure was detected by adding water in known quantities to the steam generator and inspecting the primary channel heads for evi-dence of leakage at hold points in the procedure. The tube fail-ure is located between the scallop bars in the vertical batwing support on the hot leg side of the generator, in the second peri-pheral row from the outside.

The District believes that it is highly likely that the tube which was leaking just prior to the refueling outage is the one which has now failed. This cannot be detennined for certain, how-ever, until additional chemical and radiochemical analyses can be conducted following the return of the unit to power operations.

Since the failed portion of the tube was reasonably accessible, the District decided to renove the failed section of tube for metallurgical analysis. The failed section was excised with a TIG torch after removing an equivalent portion of an adjacent tube for access. A brief onsite visual examinat. ion of the failed tube section was conducted, and the tube was packaged and shipped to Combustion Engineering's laboratory for analysis. The results of this analysis is documented in Section 4.0 of this report.

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DRAFT TABLE 2 li 1984 Eddy Current Testing Summary and Results Steam Generators A and B Steam Generator A:

Number of tubes - 5,005 ..

Number plugged prior to initial startup - 24 (to hold orifice plate) .,

Number plugged between initial startup and 1984 refueling outage

- 2 on both ends, 2 on one end each Number of tubes inspected using bobbin coil multi-frequency ECT in 1984 - 4,950 (includes 2 plugged on one end)

Number inaccessible - 29 Results 1

Number of t'abes with < 20% indications - 7 Number of degraded tubes - 8 Number of defective tubes - 2 1

Number of defective tubes plugged - 2 Number of other tubes plugged - 11 1 due to rim cut damage ,

4 due to, restriction 4 due to indications in hot leg vertical

~~

support 1 due to indication approaching plugging limit 1 electively plugged HL end of partially -

plugged tube Number of tubes profiled - 150 Results - analysis in progess

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TABLE 2 (Continued)

} .f il Steam Generator B:

Number of tubes - 5,005 Number plugged prior to initial startup - 24 (to hold orifice plate)

Number plugged between initial startup and'1984 refueling outage

-0 Number of tubes inspected using bobbin coil multi-frequency ECT in 1984 - 4,969 Number inaccessible - 12 Results Number of tubes with < 20% indications - 18 Number of degraded tubes - 5 Number of defective tubes - 2 Number of defective tubes plugged - 2 Number of other tubes plugged - 10 5 due to restriction 1 cut for access to failed tube 1 electively plugged due to proximity to failed tube 1 mis-plugged during process of plugged failed tube 2 due to indications in hot lig vertical support Number of tubes tested with 1x8 and/or 4x4 pancake array probes -

300 Results - only tube L85R86 showed an indication in a vertical support area Number of tubes profiled and analyzed - 206 Results - Denting /ovalization present in vertical supports, predominantly on_ the hot leg side Number of additional tubes profiled - 70 Results - analysis in progress n n =-* 17 DeRAN

Table 3

. , di II Summary of 1984 ECT Indications Steam Generator A Imperfection Indications Depth Location Tube L60R55 < 20% 2.2" above HL tube sheet L70R43 < 20% . 3.5" above HL tube sheet L70R43 < 20% 4.0" above HL tube sheet L76R51 < 20% 2.5" above HL tube sheet L85R80 < 20% Hot leg vertical support L94R75 < 20% Hot leg vertical support L101R80 < 20% Hot leg vertical support Degradation Indications Tube Depth Location L32R43 28% 15" above #3 support L45R34 26% 9.1" above HL tube sheet L58R87 27% 1.0" above #8 HL support L64R27 23% 25" above #4 CL tube sheet L72R23 39% 10" above CL tube sheet

/

L85R22 22% 4" above HL tube sheet L85R42 23% 4" above HL tube sheet L85R82 28% Hot leg vertical support Defect Indication Tube Depth Location L37 R18 27% & 53% 4" wastage area beginning 3" above CL tube-sheet, 2 defects within that area L64R85 44% Just below #7 HL support Permeability Variations - Six Reported 18 DRAFT

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. Imperfection Indications

"#* '* # ' 6 Tube Depth Location L32R25 < 20% 4.3" above HL tube sheet L39R30 < 20%. 5.3" above HL tube sheet L52R39 < 20% 6.6" above HL tube shedt L54R49 < 20% 4" above HL tube sheet L57 R64 < 20% #3 CL tube support L63R38 < 20% 6.5" above HL tube sheet L65R36 < 20% 5.0" above HL tube sheet I L65R40 < 20% 3.0" above HL tube sheet L66R41 < 20% 6.2" above HL tube sheet L66R51 < 20% 3.5" above HL tube sheet L67R40 < 20% 7.2" above HL tube sheet L67R50 < 20% 4.0" above HL tube sheet I L65R52 < 20% 5.2" above HL tube sheet i L69R40 < 20% 4.0" above HL tube sheet L71R48 < 20% 4.0" above HL tube sheet L74R47 < 20% 2.5" above HL tube sheet L83R40 < 20% 3.5" above HL tube sheet L89R52 < 20% 4.5" above #3 HL support Degradation Indications i

Tube Depth Location i L36R29 25% 3.0" above HL tube sheet -

L43R38 20% 5.0" above HL tube sheet i

L62R57 31% 12.8" above #1 CL support I L102R77 22% Hot leg vertical support '-

1 L104R75 26% Hot leg vertical support Defect Indications Tube Depth Location i

L29 R34 100% Hot leg vertical support L85R86 42% Hot leg vertical support l

Permeability Variations - Sixteen Reported 19 mw

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Table 4 - Profilometry Data g.

f1J, $q[$ mr-e U df' d Steam Generator B The profilometry data reduction for the horizontal tube runs was done i

manually to read the maximum radius change at a given vertical support strap.

The numbers recorded were in tenns of signal amplitude (strip chart divisions), and, although the correlation is not strictly linear, signal amplitude to dent size in mils is roughly 1.1. The following table presents the data in terms of relative dent size at each vertical support location.

Tubes with Three Vertical Supports (147 tubes profiled) location Approximate Size of Dents (Number of Dents) (Number of Dents)

Hot Leg 0-10 mils 10-20 mils 20 mils-Sat (74) (21) (8) (45)

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Center (47) (39) ~(4) (4)

Cold Leg (24) (17) (5) (2)

Tubes with Center Support Only (59 tubes profiled)

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Approximate Size of Dents Number of Dents (Humber of Dents) 21 0-10 mils 10-20 mils 20 mils-Sat (18) (3) (0) 1 20 u k:

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g%!9 d Table 5 - Summary of Plugged Tubes ^"

Steam Generator "A" Tubes plugged to hold orifice plate (pre-operation) - 24 Tubes plugged - 1978 Refueling Outage

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L79R98 L80R97 L64R85 - Hot leg side only l L63R84 - Cold leg side only Tubes plugged - April,1984 L16R67 - Rim cut damage .

L72R83 - Restriction at #6 tube support L72485 - Restriction at #6 tube support L75R92 - Restriction at #6 tube support L86R81 - Restriction at #6 tube support Tubes plugged - June,1984 L37R18 - Wastage and defect indications L63R84 - Plugged hot leg to eliminate concern about partially plugged tube L64R85 - Defect indication - plugged cold leg L72R23 - Indication approaching plugging limit l

L85R80 - Indication at hot leg vertical support 1 L85R82 - Indication at hot leg vertical support L94R75 - Indication at hot leg vertical support j

L101R80 - Indication at hot leg vertical support I Steam Generator "B" Tubes plugged to hold orifice plate (pre-operation) - 24 No operational plugging prior to 1984 Refueling Outage

Tubes plugged - April ,1984 L51R78 L53R98 All of these tubes were plugged due to L55R94 restriction at the #6 tube support L65R100 L83R82 Tubes plugged - June,1984

' L29R82 - Electively plugged due to proximity to failed tube L29R84 - Failed tube L29R86 - Removed for access to failed tube L30R83 - Misplugged d

L85R86 - Defect indication at hot leg vertical support L102R77 - Indication at hot leg vertical support L104R75 - Indication at hot leg vertical support 21 ?Y e.3 "J5b'  %!.P,5*'t

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4.0 VISUAL INSPECTION AND LABORATORY ANALYSIS g, 4.1 Steam Generator B - Tube L29R84 Section The following describes the results of the destructive examina-tion of a section of tube L29R84 from the Fort Calhoun "B" steam,

generator and the probable failure mechanism of this tube.

4.1.1 Receipt Inspection ..

Upon receipt at the CE lab, the two tube specimens labeled 23B and 23C were visually inspected. Two cracks were' observed on piece 238. The first was a large, axial (1-1/4") " fishmouth" type crack, while the second was a series of small (approximately 1/4") length fissures which made an acute angle (45 ) relative to the axis of the tube. One end from each tube section was removed to allow the eddy current probes to pass. Tube section 23B was the length of steam generator tube L29R84 from in-board of the first vertical tube support to outboard of-the hot leg batwing tube support. The tube section labeled 23C was the length of the same tube from inboard 1

1 of the first vertical tube support to outboard of the middle vertical tube support.

A. Eddy Current Testing The Combustion Engineering (CE) field / laboratory Miz 12 eddy current test equipment was calibrated using an inline calibration standard with mix fre-quencies of 400 and 100 kHz. A bobbin probe was used for the laboratory inspection of the tube sections.

A 1007. throughwall signal was 5dentified at the location of the " fishmouth" failure on tube specimen 238. One end of the defect signal was not clearly resolved due to probe interference at the torch cut end of the tube section;

}

' Approximately 1/4 of an inch fran the hot leg end of the first defect, a second 0.D. initiated defect signal was observed which corresponded to the.,

l second crack. A kink in the tube distorted the signals fraa the small defect, rendering depth estimates impossible.

) Significant dent signals were noted at the general location of the defects in 238. These signals could not be quantifled due to bending of the tube during removal from the steam generator. Several small dings were seen along the remaining portion i of the tube section. These were not observed l

within the steam generator and, consequently, were probably caused during tube removal from the steam ge ne ra to r. .

22 ,

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LLf No defect signals were observed in the tube section labeled 23C.

These results are comparable to the reanalysis of the June 1984 in-service steam generator ECT inspec-tion data, wherein two defect signals approximately 1/4" apart were identified. The first was approxi-mately 100%, while the second was estimated at 50%

throughwall. ..

B. Visual Inspection - Macro photography, Video Taping

-The first step of visual inspection consisted of documenting the as-received condition by video-graphy. Subsequently, photomacrographs were taken to document the appearance of the tube section, including defect areas and areas of deposits. In particular, photographs were taken to illustrate the lower and upper scallop bar deposits, the overall appearance of the defects, the area between the two defects, closeups of each defect, and final-ly the appearance of the fracture surface. The

~ large crack was located at the 6 o' clock position in the steam generator, as confirmed by the rela-tive position of the scallop bar contact areas.

C. Dimensional Measurements Figure 2 illustrates the dimensional measurements around the defect region. These measurements were taken before descaling and, as such, include the thickness of residual deposits. The measurement data indicate that the tube was ovalized. The major axis (6-12 o' clock) was elongated by 0.046-0.122 inch, while the minor axis (3-9 o' clock) was compressed by 0.045-0.070 inch diametrically.

4.1.2 Sectioning ,,

Cutting of the tube sections labeled 238 and 23C is shown in Figure 2, along with relative lengths and disposition of each piece.

A. Dual Etch Microstructures Two samples for dual etch microstructure evaluation were obtained: one for piece 23B and one for piece 23C. The 2% Nital etch revealed the grain boundar-ies, while the orthophosphoric acid.was used to ,

determine presence and location of carbides. The results identified that the material had a typical mill annealed Alloy 600 microstructure. l DRAF7

B. Modified Huey [i One piece from each of 23B and 23C was cut and i tested using the modified Huey procedure.

Specifically, the test pieces were exposed to boiling 25% nitric acid for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. After the exposure, the pieces were scrubbed and reweighed.

The weight losses of 0.1% for each specimen indi-cated that the tube material, was in the mill annealed condition. Mill annealed material typ-ically exhibit weight losses of 0.5% or less, while sensitized material exhibit weight losses in excess of 5.0%.

C. Bulk Chemical Analysis of Tubing Confirmation of the tubing as being Alloy 600 was being pursued through analysis of the base metal composition. One piece from each specimen, 23B and 23C, were chemically descaled using a nitric-hydro-fluoric acid solution. After all activity was re-moved from the tubing, the pieces were submitted 1 -

for chemical analysis. Results of the bulk chemi-cal analysis of tube L29R84 are shown in Table 6 below, and compared with the SB-163 specified

values. No discrepancies in the chemical compo-sition of tube L29R84 were indicated.

J a

Table 6 ELEMENTAL ANALYSIS of Tube L29R84 Ni Cr Fe Mn Cu Si C S Co 72.0 14.00- 6.00- 1.0 0.5 0.5 0.15 0.015 -

SB-163 (min) 17.00 10.00 (max) (max) (max) (max) (max) 76.08 14.50 8.10 0.248 0.325 0.190 0.025 0.001 0.035 23B 76.04 14.44 8.26 0.245 0.324 0.195 0.024 0.001 0.035 23C

0. pH Measurements Measurements of the pH of the residual deposits on i the steam generator tubing were attenpted with drops of deionized water and litmus paper. The .

litmus paper was capable of detecting pH's in the range of 9-12, with dif ferent colors at each .5 pH unit. The paper registered no reading (below 9) when wetted by deionized water.

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Some of the deposits were removed from the tube sur-face and crushed to form a slurry. When the pH of the slurry was checked, no change in color of the litmus paper was registered. This suggests the pH was below 9.0.

Finally, drops of water were placed at several loca-tions along section 238. In general, the pH paper did not register any color change at these loca-tions. However, one spot along section 238 did have a color change, suggesting a pH of 10.0.

4.1.3 Visual and SEM Inspection Results A. Major Crack - Transverse Mount One end of the " fishmouth" failure surface was mounted and polished using conventional metallo-graphic techniques. It was subsequently etched using 2% Nital and later glyceregia. The metallo-graphic examination revealed the presence of in-tergranular stress corrosion cracking (IGSCC).

- There was no evidence of the presence of a network of intergranular attack between the fissures.

B. Fracture Surface One face of the fracture surface was removed from the tube surface and chemically cleaned using a two step APAC descaling procedure. The descaled speci-men was then evaluated by scanning electron micro-scopy (SEM) to determine the relative amounts of IGSCC and ductile failure on the fracture surface.

Approximately 95% of the wall thickness exhibited a distinct intergranular appearance. Only a small amount of ductile tearing, approximately 5% of the wall thickness, was evident at the I.D. surface.

The " fishmouth" fracture was most7robably formed fran a series of essentially throughwall axially oriented intergranular penetrations, followed by ductile tearing of the material between the pene-trations and the remaining tube wall thickness.

There was no evidence of tube wall thinning as a result of corrosion or plastic deformation.

C. Minor Crack The piece from the smaller of the two cracks was cut, mounted, and polished " dry" to prevent the elution of contaminate species during specimen preparation. The intergranular nature of the cracks was apparent in the as-polished cross sec-tion. The bakelite mounting material penetrated several of the fissures, although the crack tips were free of bakelite.

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~ % d,A"h SEM energy dispersive spectrometry failed to reveal the presence of chemical deposits, even in the re-gions of the crack tips, which are known to be cap-able of the production of IGSCC in Alloy 600. Con-centration of species identified (i.e., potassium, sodium, sulfur) were at or near background levels.

The small quantity of silicon detected is attribut-ed to handling and mounting contamination. One 4

small particle rich in coppey was observed. No conclusions could be drawn rdgarding possible aggressive species that could promote intergranular stress corrosion cracking.

D. X-Ray Analysis: Dry Polished Specimen A transverse metallurgical mount was made through the smaller cracks of L29R84, piece 238. The mount was prepared without the application of water dur-ing the grinding / polishing process. Af ter carbon coating, the IGSCC in this specimen was examined with a scanning electron microscopic, supplemented with energy dispensive spectrometry for qualitative chemical analysis. Analyses of several areas around the crack tip region were completed. In general, only Ni, Cr, and Fe, typical of Alloy 600, were found. However, at one location weak indica-

' tions of potassium and sulfur were present. X-ray dot mapping showed no indications of concentrations

]

of these elements. In another area there were weak j

indications of calcium, chloride, copper, magne-j sium, and aluminum along with silica. At no loca-tions were there significant concentrations of chemical species that could have contributed to the fa ilure.

1 E. Scale Analysis Scrapings of the deposits from tube L29R84 were removed from the scallop bar region from the free length of tubing. Only light deposits were present within the scallop bar region, adjacent to the large " fishmouth" fracture. Ion chromatography detected 1793 ppm SO4 and 833 ppm NO3 , although the error was i 507. due to the sample size. Atomic absorption techniques did not detect metal cations such as potassium, sodium, calcium, or magnesium.

The threshold detection level was 1050 ppm because of the limited sample size.

4.1.4 Causative Mechanism 3 Laboratory analysis has identified OD initiated ICSCC as the cause of the steam generator tube failure at Fort Calhoun. The elements required for IGSCC include (a) a susceptible material condition, (b) a significant tensile stress, and (c) an agressive environment. All elements must be present for IGSCC to occur, l u.e q ,

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TM ; ;m adh#)W d Stress corrosion cracking (SCC) of Alloy 600 will occur under the appropriate condition in all metallurgical conditions, including the " mill annealed" condition.

Material used in the steam generator tubes at Fort i

Calhoun is typical of high temperature mill annealed Alloy 600. This material is resistant to IGSCC in some but not all enviroments.

Normal operating stresses in straf.ght lengths of steam generator tubes are relatively low. Additional stresses may be imposed through support-tube interactions. At Fort Calhoun, there was evidence that the failed tube was constrained by the vertical support member to the extent that defomation of the tube occurred, probably the result of corrosion product build-up between the tube and vertical support. Defomation of this type will provide i

additional stress at the point where failure occurred.

Three different environments are capable of producing IGSCC in Alloy 600. These environments are (a) caustic (caustic stress corrosion cracking), (b) relatively pure water (Coriou stress corrosion cracking), and (c) sulfur containing environments. Of these environments, it has been determined that a caustic environment was the most likely cause of the observed failure.

A caustic environment may have occurred in steam blanket-ed areas at Fort Calhoun as a result of periodic low l

4 level condenser in-leakage. When concentrated, the cool-ing water (Missouri River) tends to become alkaline, i thereby producing a caustic condition. Deposits in the steam blanketed area, which may have contained alkaline 4 species such as Na, K, etc., may have redissolved during

the plant shutdown prior to the failure. This could i explain the absence of these elements in the small cracks adjacent to the failure. Although some defomation of the tube occurred during service, the total deformation was relatively small (less than one percent). Caustic SCC has been produced in the laboratory **in Alloy 600 at strain levels as low as 0.5% (elastic plus plastic).

' Also, caustic SCC has occurred in relatively short times at temperatures of 600*F or less, which approximates the tube wall temperature at Fort Calhoun. These obser.va-tions, coupled with the fact that the failures occurred in a steam blanketed area where caustic species could concentrate, leads to the conclusion that the failure was probably the result of caustic stress corrosion cracking.

l It has been detemined that pure water stress corrosion a

l cracking (Coriou cracking) is rignificantly less likely a mechanism for the tube failure. Coriou cracking has been identified as the failure mechanism in numerous steam generator tube failures in both domestic and foreign PWRs. No chemical contaminate (s) have been associated i

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.5 %'[h 2,y with this type of SCC. Field and laboratory failures 4 attributed to this particular mechanism generally occur in either highly deformed tubes (strains greater than i 14%) or in tubes with distinct mechanical and/or micro-structured characteristics (high strength and intragran-ular carbides). Most, although not all, of the Coriou type failures have been I.D. initiated.

Although the failed tube at Fort Calhoun was deformed, the total strain was relatively low (probably less than one percent). Furthermore, the tubing used at Fort Cal-houn was relatively low strength and the microstructure was relatively resistant to Coriou cracking, i.e., inter-granular carbides with few intragranular carbides. Sim-i ilar tubing has been severely deformed as a result of support plate and/or 'eggcrate denting in other CE supplied steam generators. Non-destructive and post-ser-vice destructive examinations of removed tubes confinned the absence of Coriou type cracking in these steam gener-a to rs . Furthermore, Coriou cracking is strongly tempera-ture dependent and thus tends to occur when temperature

. is the highest; i.e., on the tube 1.D.. The Fort Calhoun failure was 0.0. initiated.

f IGSCC induced by a sulfur containing compound is the

. least likely of the three postulated failure mechanisms.

There was no apparent source of S bearing compounds at Fort Calhoun, other than the condenser cooling water.

Furthennore, the condenser cooling water becomes alkaline when concentrated, not acidic. The various forms of S induced corrosion (IGSCC, wastage, intergranular attack, pitting) all occur at acidic values of pH. In addition,

! analysis of the intergranular cracks in the failed tube J did not produce evidence of the presence of S, although some S compounds (ex. NiS) that fann in high temperature aqueous environments are insoluble.

4.1.5 Laboratory Analysis Conclusions ,,

A. The failure was 0.0. initiated intergranular stress corrosion cracking (IGSCC). There was no evidence of general intergranular attack.

B. The material Alloy 600, is in the mili anneal'ed condition, based on microstructural examination and modi fied Huey testing.

C. The tube was significantly ovalized. The tube diameter increased approximately 46 to 122 mils in the plane of the " fishmouth" fracture. At 90' rotation, the tube diameter was reduced by approxi-mately 45 to 70 mils. There was no change in the nominal wall thickness.

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D. Chemical species which could have caused The ~ "

observed intergranular stress corrosion cracking were not identified during this examination.

E. The most probable causes of the intergranular stress corrosion cracking are ranked in the l

1 following order of relative probability:

1. Concentration of caustic species, possibly as a result of condenser tooling water i n-l eakage .

l

-2. "Coriou" cracking in the secondary side AVT envi ronment.

1 Sulfur-induced corrosion.

3.

I Concentration of caustic species is the most likely causative agent.

4.2 Steam Generator 8 - Tube L29R86 Section The following describes the actions undertaken to perfonn a destructive examination of tube L29R86. A section of this tube was removed for access to the failed tube, L29R84.

4.2.1 Receipt Inspections

! Two additional tube sections labeled 13A and 13C fron i

tube L29R86 were visually inspected af ter receipt in l

Windsor. A kink and other marks associated with the tube removal were present on the tube sections. Deposits were l more abundant.and homogeneous on these sections, compared i

to L29R84. There was no evidence of significant corrosion attack to either tube section.

A. Eddy Current Testing Two small defect signals were dete.cted on section

' 13A during the receipt inspection. However, tube deformations from the removal operations created interferences which made it impossible to accurately assess the nature of these two defects.

The best interpretation of the data was that there

! were one or more kinks (creases) in the tube section as a result of deformation during the removal operation. (This was subsequently ..

confirmed during the destructive examination).

This laboratory ECT data used MIZ-12 equipment which had been calibrated with an on-line standard.

The mix frequencies were 400 and 100 KHz. A bobbin probe was used.

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^= E B. Visual Inspection I s.

After eddy current testing was completed, the as-received condition of sections 13A and 13C was documented by video tape and macrophotography. The location of one scallop bar in section 13A was indicated by the presence of " rust" colored l

deposits. The location of the second scallop bar l was not discernible. The crease in the tube, which occurred during the removal from the steam

(

4 generator, also helped establish the orientation of

the tube section within the steam generator.

C. Dimensional Measurements l

' Figure 4 illustrates the dimensional measurements l taken for tube sections 13A and 13C from L29R86.

These measurements were taken before descaling, and as such include the thickness of the residual i

deposits. The measurements suggested only slight ovalization of this tube. At the end of one scallop bar, the tube was indented .023 inches in the 3:00-9:00 position. In contrast, the removal

' of the tube caused a crease which reduced the 6:00-12:00 diametrical measurement by 0.033 inches and increased the 3:00-9:00 measurement by 0.009 inches, s

4.2.2 Sectioning 4

Figure 5 illustrates the sectioning of tube section 13A to provide samples for subsequent examinations. These samples were renoved for dual etch microstructure i

characterization, modified Huey testing, and surface examination. Prior to the sectioning, samples of the deposits were collected for chemical analysis. The locations of scrapings for chemical analysis are also illustrated in Figure 5.

Section 13C was not sectioned for any further destructive examination since laboratory eddy current testing did not indicate any flaws, and visual examination of the surface likewise did not identify any areas for further ,

j investigation. Only scrapings of the deposits for chemical analysis were made.

! A. Dual Etch Microstructure l One specimen of L29R86 was selected for a dual etch microstructural evaluation. The 2% Nital etch re-vealed grain boundaries, while the orthophosphoric acid etch detennined the presence and location of i

carbides. The grain size for this particular tube l'

was noted to be significantly finer than observed

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%)(.3u :,w;my on L29R84. Extensive carbides were noted, partic-ularly along the grain boundaries. This microstruc-ture may have resulted fran slow cooling during the fabrication process.

B. Modified Huey Testing A single specimen from tube L29R86, piece 13A, was ,

tested using a modified Huey procedure to assess '

the degree of sensitization. In this test, the weight loss of a specimen is detennined after 48

. hours exposure to 25% boiling nitric acid. Mill 1 annealed material typically exhibits weight losses of 0.5% or less, while sensitized materials exhibit weight losses in excess of 5.0%. When the L29R86 specimen was tested, a weight loss of approximately 2.1% was recorded. In comparison, L29R84 had a weight loss of 0.1%. Although the weight loss was higher than for typical mill annealed tubing used in CE steam generators, it was not as great as expected for fully sensitized tubing. As indicated

- above, slow cooling during fabrication may have resulted in minor sensitiza_ tion of the tube.

C. Visual Examination One section from tube specimen 13A was chemically descaled using APAC, a standard two step descaling solution. The piece chosen was from the middle of one scallop bar to just past the kink in the tube, as shown in Figure 5. The purpose was to establish whether defects other than the kink / crease existed, and if so to correlate them to the previously observed eddy current indications. Once descaled, the specimen was examined at 5-40X under a microscope. Whereas only one crease was visible on the exterior surface of the tube, two creases were observed on the inside diameter. ...The shallower of the two creases corresponded to the location of the scallop bar. The distance between the two creases j also matched the distance between the two eddy current signals. No other externally or internally visible defects were identified. "

i 4.2.3 Additional Work in Progress All easily renovable deposits on tube specimen L29R86

, were collected and labeled for analysis. Of particular interest were the scrapings at the location of the scal-lop bar for piece 13A. Analysis by several techniques were attenpted. These include X-ray fluorescence, atomic absorption, and emission spectrophotometry. X-ray fluor-escence was attenpted to identify the presence of various species, including the alkaline metals. The presence of 33 DRf

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calcium, potassium and sulfur was suggested, in addition ,

to firm indications of Fe, Cu and Ni, although the mini-

! mum detectable concentrations were unknown.

Numerous difficulties were encountered in trying to l

dissolve the deposit scrapings for tube L29R86. This is ,

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a necessary step prior to either wet chemical analysis or atomic absorption procedures. Thus far, the scrapings have not been dissolved in aqua rggia, agua regia with '

l-1 hydrogen peroxide, EDTA, or EDTA with hydrazine.

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Emission spectrophotometry appears to of fer the most 1

promising method for analysis of the deposit scrapings. ,

l Presently, standards have been prepared, and data collection is in progress.

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' ' 1 5.0 OPERATION RELATED ACTIVITIES g In the event that any future steam generator tube leaks are experi-enced, several measures have been taken to provide additional assurance that leaks are detected early, that procedures are adequate and that 11-censed operations personnel are thoroughly trained in implementing these procedures. These measures are described in the following para-graphs.

5.1 Leakage Detection Improvements An investigation of Fort Calhoun laboratory capabilities for de-tennining primary-to-secondary leakage rates was conducted using station experience from several weeks of operation with a leak prior to the end of the last cycle (Cycle 8). Fort Calhoun Sta-tion gamma isotopic equipment is supplied by Canberra Industries and consists of Series 80 and Series 90 multi-channel analyzers connected to a DEC PDP/11/34 computer with Ge(Li) detectors.

Typical 2000 second count times of 4 liter Marinelli beakers are used to obtain sensitivities and Lower Limits of Detectability necessary to support detection of low level leakage. All labor-atory personnel have been properly trained in the use of the equipment and data evaluation and have gained considerable exper-ience through daily demonstration of those skills.

It was detennined using routine laboratory capabilities, typical reactor coolant boron and radionuclide concentrations and typical steam generator blowdown rates that the smallest leak detectable using boron in hot shutdown _is 0.03__gpm_and using Cs-137 in hot shutdown after refueling is 0.002 com. The leak prior to shut-down was detected at the _0.001_ gpm rate. It was also determined that time to achieve a 90%_ equilibrium with typical blowdown is 1720 minutes and time to 10% equilibrium is Eminutes. The sens-itivity of analysis in the presence of typical operating short-lived fission products is such that a leak rate one to two orders of magnitude lower is possible.

5.2 Sampling Frequency Improvements ,,

In order to assure early detection of leakage at low leakage rates, Fort Calhoun Station analytical frequency for gamma iso-topic analysis of steam generator blowdown will be increased from weekly to daily. Boron analysis of blowdown will also be per-fonned on a once per shift basis beginning in Mode 4 and contin-uing until 10 days after reaching Mode 1. New procedure CMP-4.68, " Steam Generator Primary-to-Secondary Leak Rate Detennin-ation," will be perfonned whenever activity or boron is detected.

Steam generator blowdown monitors RM-054A and B wilI continue to be used to identify all but the smallest leaks during the inter-vals between sampling periods.

Special Order No. 35 entitled, " Allowable Primary-to-Secondary Reactor Coolant System Leak Rate" has been issued to establish an interim primary-to-secondary leakage limit through the steam generator tubes of 0.3 gpm total for both steam generators.

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+- %y , p @ m il 5.3 Procedure Reviews (,

In the District's letters of May 31, 1984, to the NRC, commi t-

ments were made to review the tube rupture emergency procedures j to reconfinn adequacy, to provide refresher training on these

emergency procedures prior to returning the plant to power oper-2 ation, and to establish an interim primary-to-secondary leakage

! limit through the steam generator tubes of 0.3 gpm total for both j steam generators. .

i The District was requested by the NRC to review the tube rupture emergency procedures using as guidance NUREG 0909, "NRC Report on the January 25, 1982 Steam Generator Tube Rupture at RE Ginna Nuclear Power Plant," Sections 9.0 and 10.0 and NUREG 0916, i " Safety Evaluation Report related to the restart of RC Ginna Nuclear Power Plant," Sections 1.4.1,1.4.2, 4.1, 4.2, 4.3 and j 7.4.

4 i The review team consisted of the following personnel. Reactor i Engineer (SRO), two licensed operators (ISRO,1R0) and a training i coordinator (SRO). The completed procedure has been reviewed by the Plant Review Committee.

l The following procedures have been reviewed using the above j listed NUREG sections:

) 1. EP-30, " Steam Generator Tube Rupture (PPLS Unblocked);"

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2. EP-30A, " Steam Generator Tube Rupture (PPLS Blocked);"

3. 01-RC-11 "RCS Natural Circulation Cooldown;"

4. OP-6, " Hot Standby to Cold Shutdown;" and

! 5. EP-35, " Reset of Engineered Safeguards." '

The existing procedures were found to adequately describe the

)j appropriate operator action to be taken in the case of a steam l

generator tube rupture or leak. Emergency Proc'edures EP-30 and EP-30A have been revised to clarify and to improve the fonnat of the procedure.

! 5.4 Licensed Operator Refresher Training .

i All licensed operating personnel will be given refresher training

] on these emergency procedures (EP-30 and EP-30A) prior to return-j- ing the plant to power operation. In the case of absence of any j licensed operator due to ilIness or vacation, he wili be trained prior to standing shift while the plant is at power operation.

As part of the regular training sequence, the Ginna tube rupture is currently being reviewed and discussed in detail. The Fort Calhoun steam generator tube failure event will also be reviewed.

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- . DRAFT 6.0 CORRECTIVE ACTION TO REDUCE THE PROBABILITY OF Tg FAILURE MECHANISM The intergranular stress corrosion cracking (IGSCC) initiated on the outer diameter which lead to the tube failure was initiated by the simultaneous presence of three conditions:

l A. A susceptible material condition I

l B. A significant tensile stress .

C. An aggressive environment (Refer to Section 4".1.4 for more infonnation on IGSCC and the causative mechanism).

To reduce the likelihood of the simultaneous presence of these condi-tions, immediate corrective actions are being or have been taken to appropriately institute operational programs and techniques as briefly described below:

A. Material Condition It may be po~ssible to reduce the susceptibility of Alloy 600 through changes in the operating environment. The District will review available infonnation to determine if changes in the physical operation of the station can provide an environment which is more resistant to IGSCC. This study will be completed in 6 months.

B. Tensile Stress Development of procedures to arrest the dent growth rate is in progress. Results from industry experience with baron and hydrazine pacification treatments are being reviewed with other utilities and vendors of the Fort Calhoun turbine generator and NSSS. A chemistry program to arrest denting will be initiated upon completion of this review if it is determined that such a program will not produce undesirable secondary effects, e.g.,

increasing the likelihood of initittion of a tuibine missile due to bucket or wheel failures.

C. Chemical Environment Several actions have been taken to control and monitor the chemical environment of the steam generator tubes:

1. Condenser Integrity Program The chief source of impurities to the secondary system has l been periodic low level condenser in-leakage. More restric-tive administrative limits with the purpose of eliminating in-leakage during power operation are being adopted. In addition, programs involving surveillance of condenser tube degradation and failure mechanisms are being initiated. In conjunction with this assessment, the District will remove 40 DRAST

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several previously failed and plugged tubes fron the conden-ser to determine the mechanisms leading to condenser tube failures for stainless steel tubing passing Missouri River water. ECT of condenser tubes is being considered to supplement the District's surveillance of condenser tube )

mechanical errosion of the inner diameter. ID wear has been monitored since 1974 and found to be nearly zero.

I A survey of utility practices in condenser integrity is underway to assist the District in adopting practices to eliminate condenser in-leakage as a result of tube failure.

2. Chemistry Improvement Program Fort Calhoun Station specifications for secondary system water quality have been reviewed and compared with those of Combustion Engineering. Specifications will be lowered for those parameters observed to be nonnally lower than the ex-isting specifications. In many cases they will become equivalent to the CE specifications. For other parameters, the District has no measured chemical history (sulphates for example). In such cases, analytical data will be col-lected and specifications established reflecting the best water quality achievable with existing plant equipment.

Additional analytical equipment of state-of-the-art sens-itivity is being purchased to assure identification of trace contaminants. A program of corrective actions for varying levels of out-of-specification conditions is being established. District resources are being devoted to limit and correct mechanical malfunctions that could increase levels of secondary system contaminants. An aggressive program for system leak detection is being expanded. The District is expediting previously approved on-line monitor-ing instrument purchases for measurement of selected chem-ical parameters indicative of system leakage and is evalu-ating purchase of additional instrumentation.

3. Temperature Soaks During Heatups ,,

Although the exact chemical causative agent or agents remain unknown, the District is reviewing operational procedures which will hold the steam generator temperatures at a plateau for a period of time to maximize secondarry side chemical impurity soluability for blowdown removal and result in a reduction in impurity concentrations in crevices. This program will be in place for the coming I

plant heatup and assessed for its effectiveness prio^r to making it a standard practice during all heatups.

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Db$ *lQ. ?W i 7.0 1UBE PLUGGING TO ELIMINATE SUSPECTED DEFECTS In order to prevent reoccurrence of a steam generator tube rupture, all tubes showing an ECT indication in the hot leg vertical support region, which could be characteristic of OD intergranular cracking have been plugged,_irreaardless_ of the size of the indication. This is a total of seven tubes whose b'obbin coil indications ranged from less than 20%

to 42%. All of these indications were detected during ECT inspections using a frequency of 100 KHz mixed with other fr,equencies. Essentially all tubes in both steam generators have been tested using this L frequency mix.

This precludes failure during operation of all tubes with detectable indications and may be presumed to be in a comparable category to the failed tube B-L29R84.

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8.0 10 CFR 50.59 SAFETY EVALUATION ;g 8.1 Purpose The purpose of this evaluation is to demonstrate that an unrc-viewed safety question does not exist with respect to the oper-ation of Fort Calhoun Station following the steam generator tube rupture event and the subsequent inspections and analysis of the Fort Calhoun steam generators. -

8.2 Method The method used to detennine that an unreviewed safety question does not exist is to examine the three questions contained in 10 CFR 50.59 and to make a negative declaration with respect to each question.

8.3 10 CFR 50.59 - Unreviewed Safety Question Evaluation 8.3.1 Will the probability of occurrences or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report be increased?

A. Events Considered This question relates to accidents or malfunctions of equipment important to safety evaluated in the safety analysis report. This safety evaluation will concentrate on accidents since the steam gen-erator tube rupture event and subsequent inspec-tions do not relate to any equipment important to safety and, therefore, no occurrences or conse-quences of malfunctions of equipment important to safety would result from this event and inspec-tions.

The accidents from the Safety Analysis Report which must be considered in this evaluat' ion are the steam generator tube rupture and the main steam line break which could lead to a release of radioactiv-ity through the steam generators.

B. Steam Line Break The probability of a main steam line break accident would not be affected by the integrity of the steam generator tubes; however, the consequences of a steam line break accident could be affected by the amount of primary-to-secondary leakage. Since the primary-to-secondary leakage limit has been adminis-tratively lowered on an interim basis to 0.3 gpm, the consequences of a steam line break are decreased relative to the steam line break radio-logical consequences analyzed in the Safety Anal-ysis Report.

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,s .-w, g!k..j'l C. Consequences of Steam Generator Tube Rupture 7

The consequences of the steam generator tube rup-ture event will not be increased for the following reasons: The activity in primary and secondary systems assumed in the analysis of the steam gener-ator tube rupture will be unchanged during future operation. The equipment available to deal with the steam generator tube rupt,ure event is unchanged from that considered in the Safety Analysis Report.

The operator action assumed in the Safety Analysis Report is unchanged and operator action in the fu-ture should be improved due to the review and improvements made in the District's Emergency Oper-ating procedures and operator training. There fare ,

it is concluded that the future operation of Fort Calhoun Station will not change the consequences of the steam generator rupture as discussed in the Safety Analysis Report.

D. Probability of Steam Generator Tube Rupture

- The probability of a future steam generator tube rupture occurring at Fort Calhoun Station is re-lated to the cause of the defective tube, current condition of the steam generators, actions which can be taken to reduce the probability of tube degradation, actions which can be taken to detect the precursor of a steam generator tube rupture and actions which can be taken to correct problems asso-

' ciated with the precursor of a steam generator tube ru pture.

The cause of the tube rupture at Fort Calhoun Sta-tion on May 16, 1984, has been ' identified as inter-granular stres s corrosion cracking (IGSCC). The most probable environment which produced this IGSCC is a caustic environment. There is evidence that the failed tube was constrained by the vertical sup-port member to the extent that defomation of the tube occurred, probably the result of corrosion product build-up between the tube and vertical sup-port. Deformation of this type would have provided additional stress at the point where failure "

occurred. The metalographic exams revealed that there had been no general chemical attack such as intergranular attack on the steam generator.. tubes which could lead to overali degradation of the steam generators. Section 4.0 details the metalo-graphic examinations which were perfomed on both the failed and unfailed tubes.

Eddy current testing has been performed on 100% of the accessible tubes in both steam generators. The inspection showed there were only 0.13% degraded tubes and only 0.04% of the tubes contained a de-44

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fect. 0.42% of the tubes showed some fonn of imper-fection. The profilometry testing revealed signifi-cant denting of exterior tubes in the vertical sup-port straps. This denting could provide additional stress on tubes similar to that seen in the rup-tured tube.

The eddy current examination revealed additional de-fective tubes which are summarized in Table 3 of this report.

The cause of the defect in the vertical support

' strap is postulated to be the IGSCC based on the defect's location and type of eddy current indica-tion. The cause of the IGSCC has been previously discussed. The cause of the defect near the tube sheet is postulated to be sludge pile pitting simi-lar to that which has been seen in other CE steam generato rs. This conclusion is based on the fact that defects and degradation seen near the tube sheet of other CE steam generators has been attrib-uted to sludge pile pitting. The cause of the sludge pile pitting is thought to be a galvanic cell type of corrosion in which the free copper in the sludge pile plays a role. To further evaluate the cause of the defect near the tube sheet, the District has removed a section of a tube containing these defects from the steam generator and examina-tien of this section is currently underway.

l' The District has plugged all tubes which exhibit an imperfection greater than or equal to 40% of the nominal tube wall thickness. The degraded tube which exhibited a 39% imperfection was also plugged. The District has chosen to conservatively plug any tubes which exhibit an imperfection, irres-pective of depth, within the hot leg vertical support strap structure. The District is utilizing a mechanical plug which can be removed from the tube. In the future, the District may analyze those tubes with imperfections less than the

.l plugging limit of 40% of the nominal wall thickness utilizing the criteria given in Regulatory Gu,fde 1.121 and detennine that all or a portion of the plugged tubes are acceptable for operation. At that time, the plugs may be removed from the acceptable tubes.

- Table 5 in Section 3 of this report contains the tubes plugged in the Fort Calhoun Station Steam Generators . These plugged tubes are widely dis-persed throughout the steam generators and will not adversely ef fect the thennal hydraulic and mechani-we 45 e

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• a cal perfomance of the steam generators. The assumption of the number of tubes plugged in both steam generators used in the Safety Analysis also remains valid.

Based on the extensive examinations and limited plugging of selected steam generator tubes, there is an extremely low probability of steam generator leakage and an even lower probability of a steam generator tube rupture upon startup of Fort Calhoun Station.

The District will conduct the standard reactor cool-

' ant system integrity testing in accordance with Technical Specification 3.4 prior to returning the unit to hot shutdown. This testing will confirm the integrity of the steam generators.

The District will take actions which will reduce the probahility of future intergranular stress corrosion cracking. A soak of the steam generators i

at an intemediate temperature will be perfomed during the upcoming heatup to remove the maximum

~ amount of chemical species which may be involved in the intergranular stress corrosion cracking of the tubes from the steam generators. The temperature is chosen such that the maximum solubility of these species is obtained.

The District will take the necessary action to as-sure that concentrations of chemical species identi-fled as environmentally causative agents in IGSCC will be maintained within the limits recommended by the steam generator manufacturer consistent with the current design capabilities of the Station.

This includes a program to improve condenser per-fomance to reduce raw water inleakage to a minimum level. In addition, the District is studying a boric acid neutralization of the denting process in

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the Fort Calhoun steam generators". This neutrali-zation will be initiated once it is detemined that the addition of boric acid to the steam will not significantly degrade the turbine rotor and will not increase the probability of the turbine rotor failure.

The District has taken and wili take several cor-rective actions which should reduce sludge pile pit-ting if it is occurring in the Fort Calhoun steam generators. During the 1984 refueling outage, the District hydrolanced the sludge pile regions of both steam generators to remove the sludge pile material . The temperature soak of the steam gen-erators during heatup will also help remove active chemical species from the sludge pile region.

Finally, the District intends to remove the primary source of copper from the feedwater train.

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. . . o The District has implemented programs which will increase the ability to detect a primary-to-second-ary side leak, which is a potential precursor of a steam generator tube rupture. In our letter of % y 31, 1984, the District committed to revising the operating manual to reflect an interim primary-to-econdary leakage of 0.3 gpm total for both steam generators, as opposed to the existing Technical Specification limit of 1.0 gpm. If the 0.3 gpm leakage limit is exceeded, the action required by Technical Specification 2.1.4 Paragraph 3 wilI be followed. Section 5.0 of this report details the 1 ~ District's secondary side chemistry program that will be undertaken upon startup. The program increases the frequency of testing for primary to secondary leakage and discusses the sensitivity of this program. This program can detect a leak of 0.002 gpm.

The District has undertaken a massive campaign to insure that there is no increase in the probability of a steam generator tube rupture at Fort Calhoun Station. The District has detennined that the steam generators can be returned to service with an extremely low probability of a tube rupture during nonnal or transient conditions. The District has committed to taking actions to reduce any identi-fied chemical and mechanical degradation of the steam generator tubes. The District will be able

, to detect a very small primary-to-secondary side leak and will take the appropriate action if such a leak occurs. Therefore, it is concluded that the i

probability of a steam generator tube rupture occur-ring is not increased. .

8.3.2 Will the possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report be created?

To answer this question, the District has surveyed the accidents currently analyzed in the Safety Analysis Report and multiple event scenarios which have been used for the generation of Emergency Operating Procedures and in probabilistic safety analyses. The two events of a different type than any evaluated previously in the Safety Analysis Report with the highest possibility of occurrence are a multiple steam generator tube rupture event, either rupturing more than one tube in a single l steam generator, or rupturing tubes in both steam gener-ators, and a steam line break with a concurrent steam generator tube rupture. The possibility of either of these events occurring upon startup is extremely low because the integrity of essentially all tubes is ensured due to the extensive eddy current testing and limited tube plugging.

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. .,1 DRAfi' During the next operating cycle, the probability of these events is extremely low because the cause of the steam generator tube rupture, intergranular stress corrosion cracking, is not indicative of an overall chemical or mechanical weakening of the steam generator tubes. The District is committed to taking corrective actions to reduce the chemical and mechanical causative agents of intergranular stress corrosion cracking and sludge pile pi tting . In addition, the Distric,t has undertaken a program which will identify the potential precursor of these events and will take action prior to significant tube degradation.

The District concludes that the actions which have been taken to reduce the probability of intergranular stress corrosion cracking and ' sludge pile pitting and to detect a degraded tube, will prevent the possibility for an acci-dent or malfunction of a different type than any evalu-ated previously in the Safety Analysis Report.

8.3.4 Will the margin of safety as defined in the basis of any Technical Specification be reduced?

The applicable Technical Specifications are Technical Speci fication 2.1.4, primary-to-secondary leakage , Tech-nical Specification 2.9, radioactive material release, Technical Specification 2.20, steam generator coolant radioactivity, and Technical Specification 3.3, steam generator tube inservice inspection program.

The margin to safety in Technical Specification 2.1.4 will be increased because of an interim limit on primary to secondary side leakage of 0.3 gpm. The margin of safety in Technical Specification 2.9,is unchanged be-cause none 'of the radiological release limits are changed. The margin of safety of Technical Specification 2.20 is unchanged because the radiological limits on the steam generator coolant radioactivity is unchanged. The margin of safety of Technical Specification 3.3 is in-creased because the District has undertaken an inspection of 100% of all accessible tubes in both steam generators at the Fort Calhoun Station.

The District concludes that the margin of safety asde-fined in the basis for any Technical Specification wilI not be reduced and in two instances will be increased.

8.4 Conclusions The District concludes that the actions described in the previous paragraphs will assure that there is not an unreviewed safety question associated with the restart of Fort Calhoun Station and its subsequent operation.

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