ML16342D201

Tube

De radation

~

The predominant

tubing degradation

modes in Unit

1 have.

to date.

been primary water stress

corrosion cracking (at dented

and

non-dented

tube support plate intersections'elow

the explosive

expansion transition region,

and in the low radius

bends of Rows

1 and

2

U-tubes).

wear at anti-vibration bars.

cold-leg thinning,

and outside

diameter

stress

corrosion cracking at nondented

tube support plate

intersections

(Section 2.5. 1).

~

The predominant

tubing degradation

modes in Unit 2 have.

to date.

been primary water stress

corrosion cracking (at dented tube

support plate intersections'elow

the explosive expansion transition

region,

and in the low radius

bends of Rows

1 and

2 U-tubes), cold-leg

thinning,

and outside diameter stress

corrosion cracking at nondented

tube support plate intersections

(Section 2.5.2).

~

The incidence of Unit

1 primary water stress

corrosion cracking was

significantly lower, to date,

in Steam Generators

1-3 and 1-4 than in

Steam Generators l-l and 1-2 (Section 2.5.3).

Maintenance

~

The foreign material exclusion program requirements

and practices for

the steam generator

secondary

side were appropriate

and have

been

generally well implemented

(Section 3. 1).

0

-3-

~

Visual inspections of the steam generator

secondary

side were first

performed during Refueling Outage

1R6 in April 1994.

Earlier

implementation of an internal inspection

program could have provided

a

more timely identification and evaluation of J-tube.

barrel riser.

and

nozzle plug erosion/corrosion

phenomena

(Section

3. 1).

~

Licensee nondestructive

examination

personnel

were knowledgeable of

examination techniques

and showed

good adherence

to procedural

requirements

(Section 7.5).

~

Inclusion of operational

experience

in ultrasonic inservice inspection

efforts was considered

commendable

(Section 7.5.3).

En ineerin

The licensee

was viewed to have

been proactive with respect to eddy

current examination

scope.

adoption of new eddy current examination

technology,

and incorporation of industry experience

(Section 4. 1).

The eddy current examination

program requirements

were found to be

generally consistent with the recommendations

contained in Electric

Power Research

Institute

EPRI NP-6201.

Revision 3.

An exception noted

was the absence

of quantitative criteria for handling noisy data.

An

inspection

followup item was identified pertaining to review of the

conformance of the eddy current examination

procedures

to Appendix

H of

Electric Power Research

Institute

EPRI NP-6201,

Revision 3

(Section 4.2.1).

Eddy current examination

program strengths

noted were:

(1) use of only

analysts

who had been certified as qualified data analysts

in accordance

with the requirements

of EPRI NP-6201,

Appendix G: (2) screening for

loose parts in Rows

1 and

2 and the outer two rows of the tube bundle

periphery;

and,

(3) use of two separate

companies

to perform independent

primary and secondary

analysis

(Section 4.2. 1).

An inspection followup item was identified pertaining to review of a

analyses

of conformance of cold-leg thinning indications to

Regulatory Guide 1. 121 (Section 4.3).

The failure of licensee

personnel

for 10 years to identify a procedural

error pertaining to ultrasonic Level I examiner training requi rements

was considered

an indicator of inadequate

attention to detail

when

revising and using procedures

(Section 7.3).

Plant

Su

ort

The licensee

has developed

a good secondary

water chemistry program and

has

been responsive to industry secondary

water chemistry initiatives

(Section 6.1).

0

~

The chemistry history reflected significant improvements

in secondary

water chemistry performance in the past

5 years,

with the reductions

achieved since

1993 in feedwater iron concentrations

viewed as notable.

The current feedwater iron concentrations

were.

however.

considered to

be still of a magnitude that warranted continued

management

attention

(Section 6.2).

~

The review of overall secondary

side chemistry history was adversely

impacted

by the inability to assess

effectiveness

of chemistry controls

in the first 5 years of plant operation

(Section 6.2).

~

On-line instrument

upgrades

have provided improved sensitivity and

accuracy for monitored parameters

in the steam generator

blowdown,

feedwater.

and condensate

systems

(Section 6.4).

~

The use of a Level III eddy current examiner

from another utility as

a

team member in quality assurance

survei llances of eddy current

examination activities

was considered

commendable.

and

an excellent

practice to follow when performing audits or survei llances of specialist

activities (Section 4.2.3).

Safet

Assessment/

ualit

Verification

~

The historical

eddy current examination

program scope

and ongoing steam

generator

degradation

management

actions were considered

indicators of

both management

awareness

of and support for steam generator

tube

integrity initiatives.

The steam generator

strategic

plan was noted.

howevers

to have not been revised since its issue in 1993 'espite

awareness

that the current

document

does not consider all active

degradation

mechanisms

in its projections

(Sections

4. 1 and 5).

~

The inservice inspection supervisor actively assured

quality of

nondestructive

examinations

and was performing effective oversight of

nondestructive

examination

personnel

(Section 7.6).

Summar

of Ins ection Findin s:

~

Inspection Followup Item 275/9510-01;

323/9510-01

was opened

(Section 4.2.1).

~

Inspection

Followup Item 275/9510-02:

323/9510-02

was opened

(Section 4.3).

~

Open Item 323/9307-08

was closed

(Section 8. 1).

~

Violation 275/9425-01;

323/9425-01

was closed

(Section 8.2).

Attachment:

~

Attachment

- Persons

Contacted

and Exit Meeting

-5-

DETAILS

1

STEAM GENERATOR TUBE INTEGRITY REVIEW (73755,

79501,

79502)

The objectives of this part of the inspection were:

(a) to ascertain

the

history and material condition of the Units

1 and

2 steam generator tubing:

and (b) to assess

the effectiveness

of licensee

programs

in detection

and

analysis of degraded

tubing, repair of defects,

and correction of conditions

contributing to tube degradation.

The inspection

scope

and findings are

documented

in Sections

2 through

6 below.

The results of a previously

conducted

inspection of the effectiveness

of licensee

programs

and training in

regard to detection of and response

to steam generator

primary-to-secondary

tube leakage

were documented

in NRC Inspection Report 50-275/95-04:

50-323/95-04.

2

STEAM GENERATOR MATERIALS AND TUBE DEGRADATION HISTORY

2. 1

Descri tion

Diablo Canyon

Power Plant.

Units

1 and 2, are Westinghouse-designed

pressurized

water reactors.

with an approved

megawatt electric output of 1137

for Unit

1 and

1164 for Unit 2.

The respective

commercial operation dates

were

May 7.

1985, for Unit

1 and March 13,

1986, for Unit Z.

The Diablo

Canyon

Power Plant unit design utilizes four Westinghouse

Model

51 vertical

recirculating

This model of steam generator

contains

3.388

Inconel

600

(ASME Material Specification

SB-163) U-tubes, with a nominal

diameter

and wall thickness.

respectively,

of 0.875 inches

and 0.050 inches.

After insertion of the ends of the U-tubes in drilled holes in an 21.5-inch

thick steam generator

tube sheet forging. the tubes

were initially expanded

against the tube sheet

hole surfaces

by mechanical

rolling for a distance of 2

inches to 4 inches

from the primary side surface of the tube sheets

followed

by welding of the tube ends to compatible composition weld cladding

on the

primary side surface of the tube sheet.

Explosive expansion of the unexpanded

portion of the tubes in the tube sheet

was subsequently

performed onsite at

the Diablo Canyon

Power Plant to eliminate the remaining crevice between the

tube

and the tube sheet hole surface.

Secondary

side tube bundle support structures

consist of seven 3/4-inch

thickness

carbon steel

horizontal tube support plates

and two sets of Inconel

600 anti-vibration bars in the upper tube bundle.

The tube support plates

utilize

a drilled round hole configuration, with a nominal

gap of 0.008 inches

between the outside surface of the tubes

and the surface of the holes.

The

selection of carbon steel for the tube support plates,

in conjunction with a

drilled hole configuration, create

a susceptibility to tube denting due to the

pressure

that can be imposed

on the tubes

as

a result of magnetite growth on

the surface of the holes

and entrainment of corrosion oroducts.

The inspectors

also ascertained

that

16 U-tubes in Unit

1 Steam Generator

1-1

contain 30-inch long "implants."

These

implants were installed onsite by

during Unit

1 construction for the purpose of gaining service

experience with potential alternate

tubing materials.

The

16 U-tubes were cut at approximately

8 inches

above the top of the secondary

face of the tube sheet

on the hot-leg side of the steam generator.

and the

resulting approximately 30-inch long segments of original tubing material

removed from the steam generator.

The removed tube segments

were replaced

by

segments

of alternate tubing materials,

with a welded Inconel

606 sleeve

used

to attach the "implant" to the U-tube.

Four implants were manufactured

from

each of the following candidate tubing materials:

stress

relieved Inconel

600. shot peened

Inconel

600,

Incoloy 800,

and Inconel

690.

2.2

Hot-Le

Tem erature

Licensee

personnel

informed the inspectors that

a primary side inlet hot-leg

temperature (i.e., T-Hot) of 603'F has

been

used at Diablo Canyon.

Units

1

and 2. during commercial operation.

The inspectors

ascertained

from review of

the licensee

"Diablo Canyon

Power Plant Strategic Plan." dated February

13

'993.

that

a recommendation

was

made to evaluate the possible

implementation

of a 4'F reduction in T-Hot to 599'F during the respective sixth refueling

outage for Units

1 and

2 (i.e.

~

1R6 and 2R6).

This recommendation

was noted

by the inspectors

to be consistent with actions

taken by other individual

licensees

to reduce hot-leg temperature

as

an approach to limit initiation and

propagation of stress

corrosion cracking.

The inspectors

questioned

licensee

personnel

regarding the status of the T-Hot reduction

recommendation.

and were

informed that T-Hot reduction

was still an open issue.

but was currently not

a

high priority item.

2.3

T~ti

3 2

The inspectors

requested

to see the procurement

requirements

for the Diablo

Canyon

Power Plant,

Units

1 and 2, steam generator tubing that had been

imposed

on its tubing vendor(s).

In response

to the

licensee's

request,

furni shed:

(a) Westinghouse

Tampa Division

Material Specification

2656A95.

"Material-Nickel-Chromium-Iron Tubing,"

Revision 2,

and (b) Westinghouse

Specialty Metals Division Process

Specification

1001-01-B,

"Westro 600T," issued

Oecember

10,

1971.

Both of

these

documents

were marked

as containing proprietary information.

Licensee

personnel

informed the inspectors that tube manufacture

was performed for six

of the Units

1 and

(i.e., Unit 1,

1-1

and 1-2: Unit 2.

2-1, 2-2, 2-3;

and 2-4) by Westinghouse

Specialty Metals Division, with materials production

and initial mechanical

working performed

by Huntington Alloy Products.

Licensee

personnel

stated

that materials production

and complete manufacture of the tubing for the two

remaining steam generators

(i.e.

~ Unit 1.

1-3 and 1-4) were

erformed by Huntington Alloy Products.

Two documents

were obtained

by the

icensee

from Huntington Alloy Products,

which were applicable to the

manufacture of the tubing that was utilized in Steam Generators

1-3 and 1-4.

These

documents

were. respectively,

Procedures

QCP 51. "Quality Control

-7-

Procedure for Bright Annealing of Inconel

600T Steam Generator Tubing,"

Revision 0.

and

QCP 53,

"Tube Bending Procedure,"

Revision 0.

The inspectors

noted from review of Materials Specification

2656A95,

Revision 2. that the specification

invoked

ASHE Materials Specification

SB-163

and was consistent with ASME Sections II and III requirements

with respect to

the furnishing of the material in the annealed

condition and performance of

hydrostatic testing, ultrasonic examination,

and eddy current examination.

The inspectors

noted that the material specification did not identify the

annealing

temperature

to be used for the

ASME SB-163

( Inconel

600) tubes.

The

inspectors

ascertained

from review of Process

Specification

1001-01-B that

this document did define the minimum annealing

temperatures

to be used during

tube manufacture.

Details of specification requirements

for annealing

have

not been included in the inspection report.

as

a result of the inspectors

being informed by Westinghouse

personnel

that this information was considered

proprietary.

The inspectors

selected

three

steam generators (i.e..

1-2.

1-4.

and 2-2) for review of samples of steam generator

tubing certified

material test report data.

The inspectors

noted during review of the sample

data that the reported

chemical

composition

and mechanical

properties

conformed to the requi rements of ASME Haterial Specification

SB-163 and

Materials Specification

2656A95. Revision 2.

The ranges of

0.2 percent yield strength

values for the Steam Generators

1-2. 1-4,

and 2-2

tubing certified material test reports were ascertained

to be, respectively,

35,000-76,000 '5.000-69.000.

and 46,000-70,000.

The respective

ranges of

ultimate tensile strength

values for Steam Generators

1-2,

1-4.

and 2-2 were

91,000-115.000.

89.000-114,000,

and 94.000-111.000.

The inspectors

considered

the ranges of yield strength properties

in the tubing for the two selected

Unit

to be of a magnitude which covered properties that

were typical for both low-temperature

and high-temperature

mill annealed

conditions.

The inspectors

accordingly concluded that these relatively wide

ranges of yield strength properties

were at least partially attributable to

variations in tube annealing

temperatures

and/or times that occurred during

tube manufacture.

The yield strength

values

observed

in Steam Generator

2-2

tubing data were noted

by the inspectors

to have

a reduced

range

compared to

the Unit

1 tubing material.

The inspectors

concluded that tighter annealing

process

controls

appeared

to have been

used during manufacture of the Unit 2

steam generator tubing.

The inspectors additionally calculated the mean value and standard deviation

for carbon content,

0.2 percent yield strength,

and ultimate tensile strength

for the individual samples of certified material test reports.

The results

obtained

from these calculations

are listed below in Table 1.

The inspectors

noted from these results that the mean 0.2 percent yield strength

and ultimate

tensile strength

values

were lower for the Steam Generator

1-4 tubing than the

comparable properties

calculated

for the tubing in both Steam Generators

1-2

and 2-2.

The inspectors

concluded that it was probable that tube temperatures

and/or annealing

times were typically higher during final annealing of the

1-4 tubing, than those present

during the final annealing of

'0

-8-

the Steam Generators

1-2 and 2-2 tubing.

The lower standard deviation value

for the 0.2 percent yield strength properties

in the Steam Generator

2-2

tubing was considered

by the inspectors

to be further confirmation of the

observation

made

above regarding the use of tighter annealing

process

controls

during manufacture of the Unit 2 steam generator tubing.

Table

1

STEAM GENERATOR (SG)

TUBING CARBON COMPOSITION AND MECHANICAL PROPERTY

DATA

Parameter

SG 1-2

Unit

1

SG 1-4

Unit 2

SG 2-2

Mean

o"'ean

0.2

X Yield

Stren th (KSI)

Ultimate Tensile

Strenath

(KSI)

'arbon

50.0

8.6

47.0

7.0

55.9

4.2

103.0

4.0

97.6

5.1

105.3

3.4

0.033

0.009

0.031

0.009

0.035

0.010

(1)

- Standard deviation.

2.4

Tube-to-Tube

Sheet

Ex ansion

As noted in Section

Z. 1 above,

mechanical rolling was utilized during original

fabrication of the Units

1 and

to partially expand tubes

against

tube sheet

hole surfaces (i.e., the first 2-4 inches of tube starting

at the primary surface of the tube sheet).

The resulting tube-to-tube

sheet

crevices

were subsequently

eliminated prior to unit startup

by explosive

expansion

by Westinghouse of the tubes against the tube hole surfaces.

The

explosive expansion

process

used

was given the name

"WEXTEX" by Westinghouse,

and subsequent

references

in the inspection report to tube expansion

and the

tube expansion transition region utilize this name.

Reviews were not

performed by the inspectors

during the inspection of the technical

and quality

requirements

that were applicable to onsite

WEXTEX explosion expansion

activities.

2.5

Tube

De radation Histor

2.5.1

Unit

1

Prior to operational

service.

the Unit 1 steam generators

contained

one

plugged tube (i .e.,

1-2).

Table 2 below provides the tube

plugging history for the four Unit

as

a function of

0

'0

-9-

effective full-power years of operation at the time of repair.

Table 3

details the number of tubes

removed

from service in terms of applicable

degradation

mechanism.

Eddy current examinations

during Refueling Outage

1R1 identified the presence

of tube denting in the Unit 1 steam generators

at tube support plate

intersections.

The denting was believed to have occurred

as

a result of

condenser

in-leakage during the first cycle of operation,

which created

corrosion conditions favorable for magnetite

growth at tube support plate hole

surfaces.

In response to the observed denting'odifications

were made to the

condenser after the first operating cycle and boric acid additions to the

feedwater were commenced after Refueling Outage

1R2.

The licensee

continued

to monitor tube denting in subsequent

refueling outage examinations,

with no

new dents or growth of existing dents

found since Refueling Outage

1R2.

A

summary of dented

tubes with bobbin coi l signals

over 5 volts is listed below

in Table 4.

Table

2

UNIT 1

STEAN GENERATOR (SG)

TUBE REPAIR HISTORY

Time of

Repair

(Outage)

Preservice

1R1 (1986)

1R2 (1988)

1R3 (1989)

EFPYs"'.00

1.25

2.28

3.45

SG 1-1

SG 1-2

SG 1-3

Tubes

Plugged

Tubes

Plugg'ed

Plugged

1

0

5

3(4>

3

SG 1-4

Tubes

Plugged

1R4 (1991)

4.49

0

1

1R5 (1992)

5.87

6

15

1R6 (1994)

7.15

21

36

4

1R7 (1995)

8.47

28

70

3

16

Total

Re airs

60

126

15

27

R Re airs (I"', T"')

1.77.

1.77

3.69, 3.72

0.44,

0.44

0.80.

0.80

(1) - Effective full-power years of operation;

(2) - Inservice:

(3) - Total:

(4) - Net plugged total (i.e.. four tubes

plugged

and one tube unplugged).

-10-

During Refueling Outage

1R2.

one low radius

Row 2 U-tube was plugged

as

a

result of the motorized rotating pancake coil identification of axial primary

water stress

corrosion cracking.

To reduce the susceptibility to stress

corrosion cracking.

the licensee

performed

a thermal stress relief of the bend

regions in all of the

Rows

1 and

2 U-tubes.

This subject is further discussed

in Section 2.6 below.

Despite performance of the thermal stress relief,

an additional four low

radius

Rows

1 and

2 U-tubes requi red plugging during Refueling Outage

1R3.

as

a result of the identification by eddy current examination of the presence

of

primary water stress

corrosion cracking in the bend regions.

In response

to

Bulletin 88-02,

"Rapidly Propagating

Fatigue

Cracks in Steam Generator

Tubes."

dated February 5,

1988 'he licensee

concluded that five tubes

were

susceptible

to the type of fai lure described

in the bulletin and preventively

plugged the five tubes.

Two tubes

were also plugged

due to anti-vibration bar

wear.

and one tube was plugged

due to a restriction that prevented

passage

of

an eddy current probe.

On May 15.

1989 'he

NRC issued Bulletin 89-01,

"Failure of rlestinghouse

Tube Mechanical

Plugs." in response

to

a plug fai lure at North Anna-1.

The bulletin identified several

steam

generator

tube plug material

heats

which were potentially susceptible

to

stress

corrosion failure.

In Refueling Outage

1R2.

Tube

R2C88 (i .e..

Row 2.

Column 88) in Steam Generator

1-2 was plugged after eddy current examinations

revealed indications that was characterized

as primary water stress

corrosion

cracking in the U-bend region of the tube.

The plugs in this tube were

installed prior to the date of issue of Bulletin 89-01

and were fabricated

from one of the heats (i.e.,

Heat 4523) which was identified in the bulletin

as being susceptible

to failure.

The licensee

removed the plugs during

Refueling Outage

1R3 and reexamined

the tube U-bend region.

The tube

examination data did not reveal

the existence of any degradation

and.

as

a

results

the tube was returned to service.

During Refueling Outage

1R4,

one tube was plugged

as

a result of the

identification of anti-vibration bar wear.

Eddy current examinations

in Refueling Outage

1RS identified that

17 low

radius

Rows

1 and

2 U-tubes required plugging because of primary water stress

corrosion cracking in the bend regions.

This number was considered

by the

inspectors to be

a significant increase

in this type of degradation.

Twelve

tubes experiencing

anti -vibration bar wear were also plugged in this outage.

A total of 68 tubes

were plugged during Refueling Outage

1R6.

The majority of

the corrosion-related

degradation that was found was located in Steam

Generators

1-1 and 1-2.

Further information on this subject is contained in

Section 2.5.3 below.

Active corrosive degradation

mechanisms

identified were

primary water stress

corrosion cracking'utside

diameter stress

corrosion

cracking.

and cold-leg thinning.

Four tubes were plugged

due to outside

diameter stress

corrosion cracking at non-dented

tube support plate

intersections.

which was the first identification in Unit

1 of secondary

side

stress

corrosion cracking.

In this outage

an increase

also occurred in the

number of tubes identified as requiring plugging because of detected

primary

0

-11-

water stress

corrosion cracking (i.e.,

39 tubes

versus

17 tubes in Refueling

Outage

1R5).

The tube locations affected

by primary water stress

corrosion

cracking were:

low-radius

Rows

1 and

2 U-bends.

4 tubes:

below the bottom of

the

WEXTEX transition region.

6 tubes:

dented

tube support plates.

23 tubes;

and

~ nondented

tube support plates'

tubes.

Five tubes were plugged

because

of the detection of crack-like indications in the tubes at nondented

tube

support plate locations for which cause could not be determined.

Cold-leg

thinning was first identified in Steam Generator

1-2 during Refueling

Outage

1R3

however, indications did not exceed the 40-percent

throughwall

limit until Refueling Outage

1R6 when ten tubes

were required to be removed

from service.

The licensee identified in the Refueling Outage

1R6 report that

the growth rate of these indications

was nominally 17-percent

throughwall per

cycle.

Based

on

a review of the eddy current data for cold-leg thinning

indications

recorded

in previous outages

~ the inspectors

noted that there

was

considerable

scatter in the growth rate data, with several

indications having

exhibited apparent

growth rates in excess

of 40-percent

throughwall per cycle.

Table 3

UNIT

1

INSERVICE PLUGGING HISTORY BY DEGRADATION MECHANISH

Tube Degradation

Hechanism

H.C. Fati ue"'nit

2 Refueling Outage

(2R)

1R1

1R2

1R3

1R4

1R5

1R6

1R7

T" '

0

5

0

5

AVB Wearr>>

0

2

1

12

8

12

35

ODSCC/non-dented

TSPs"'

0

4

9

13

ODSCC/TTS'"'

0

1

PWSCC/R18R2 U-bends"'

1

4

0

17

4

1

27

PWSCC/WEXTEX'

0

1

PWSCC/TS below BWT"'

0

6

4

10

PWSCC/Dented

TSPs"'

0

23

75

98

PWSCC/non-dented

TSPs'"

0

6

0

6

Unknown TSP flaws'"'

0

5

0

5

CL Thinnin /TSPs'"'

0

10

14

24

Restriction

0

1

0

1

0

2

Other

0

1

0

1

Tubes

Un lu

ed

0

1

0

1

Net Tubes

Plugged

0

1

11

1

29

68

117

227

-12-

(1)

- Preventively plugged in response

to Bulletin 88-02;

(2) - Anti-vibration

bar wear in the U-bend region;

(3)

- Outside diameter stress

corrosion

cracking at non-dented

tube support plates;

(4) - Outside diameter stress

corrosion cracking at the top of tube sheet;

(5) - Primary water stress

corrosion cracking in the

Row 1/Row 2 U-bends:

(6) - Primary water stress

corrosion cracking in the

WEXTEX expansion transition region:

(7) - Primary

water stress

corrosion cracking at the tube sheet

below the bottom of the

WEXTEX expansion transition:

(8) - Primary water stress

corrosion cracking at

dented tube support plates:

(9) - Primary water stress

corrosion cracking at

non-dented

tube support plates:

(10} - Crack-like flaws at non-dented

tube

support plates for which cause

was

unknown;

(11)

- Cold-leg side thinning at

tube support plates:

(12)

- Total.

Other reasons

for tube plugging during Refueling Outage

1R6 were:

restriction,

one tube: anti-vibration bar wear. eight tubes:

and pre-service

inside diameter crack.

one tube.

Table 4

UNIT 1

STEAN GENERATOR (SG}

DENT DISTRIBUTION (DENTS > 5 VOLTS)

TSP/HLS'"

1H

2H

SG 1-1

37

SG 1-2

132

90

SG 1-3

SG 1-4

Total

17.

386

540

5

69

201

3H

7

74

97

189

4H

1

106

5

123

235

5H

4

34

39

50

127

6H

2

7

22

277

308

7H

155

51

116

353

675

Total

211

494

215

1355

2275

(1)

- Tube support plate/Hot-leg side.

During Refueling Outage

1R7,

117 tubes

were plugged

because of detected

anti-vibration bar wear (12 tubes)

and corrosion-related

degradation

(105 tubes).

Of the

105 tubes that were plugged because of corrosion-related

degradation,

81 tubes were affected

by primary water stress

corrosion cracking

(i.e.,

bends in low radius U-tubes,

1 tube:

WEXTEX transition region.

1 tube;

below the bottom of the

WEXTEX transition region,

4 tubes;

and dented tube

support plate locations.

75 tubes).

The inspectors

considered

the increase

from 23 tubes during Refueling Outage

1R6 to 75 tubes in Refueling Outage

1R7

for primary water stress

corrosion cracking at dented tube support locations,

to be the most notable

change in detected

degradation.

A moderate

increase

was

-13-

also noted in required plugging for detected

outside diameter stress

corrosion

cracking, with nine tubes

found to be affected at non-dented

tube support

plate locations

and one tube at the top of the tube sheet.

Fourteen

tubes

were plugged

as

a result of identified cold-leg thinning at tube support

plates.

The licensee's

lead eddy current analyst

reexamined

the population of

cold-leg thinning indications in Steam Generator

1-2 during this refueling

outage.

and concluded that cold-leg thinning was

an active mechanism in the

as evidenced

by the growth of pre-existing degradation

and the

appearance

of new indications.

Other plants with Model

51 steam generators,

which have experienced

tube

denting (e.g..

Salem-l,

North Anna-1 and Sequoyah-1)

in the first one or two

cycles of operation,

have detected

outside diameter circumferential

stress

corrosion cracking

and axial primary water stress

corrosion cracking at dent

locations.

A total of 98 tubes

have

been plugged in the Diablo Canyon

Power

Plant Unit

through seven cycles of operation

as

a result of

the identification of axial primary water stress

corrosion cracking at dent

locations.

The

NRC consultant

reviewed the eddy current data

from tubes that

had

been plugged during Refueling Outage

1R6 because of primary water stress

corrosion cracking that had been detected

at dented

and non-dented

tube

support plate intersections.

Although the

NRC consultant

could not

definitively conclude that dents were present

in all cases'here

were

some

indications that the non-dented

intersections

did, in fact. contain

a small

dent.

Additional discussion of steam generator

tube denting is contained in

Section 2.5.3 below.

2.5.2

Unit 2 History

Prior to operational

service.

the Unit 2 steam generators

contained

no plugged

tubes.

Table

5 below provides the tube plugging history for the four Unit 2

steam generators

as

a function of effective full-power years of operation at

the time of repai r.

Table

6 details the number of tubes

removed

from service

in terms of applicable degradation

mechanism.

During Refueling Outage

2R1.

two tubes required plugging as

a result of damage

that occur red during removal of a tube lane blocking device.

Thermal stress

relief was also performed of the low radius

bends in the

Rows

1 and

2 U-tubes

during this refueling outage.

in order to reduce the susceptibility to primary

water stress

corrosion cracking.

Despite performance of the thermal stress relief, six tubes

from Rows

1 and

2

required plugging during Refueling Outage

2R2,

as

a result of the

identification of primary water stress

corrosion cracking.

Prior to Refueling

Outage

2R2

~ the

NRC issued Bulletin 88-02.

The licensee initially identified

a total of 24 tubes that were considered

susceptible to the high cycle fatigue

mechanism described

in the bulletin

and preventively plugged these

tubes

during the outage.

A subsequent

analysis

completed

(WCAP-12064) 'of the potential for high cycle fatigue damage to the

preventively plugged tubes

revealed that only 5 of the 24 tubes were

susceptible to fatigue damage.

The Office of Nuclear Reactor Regulation

-14-

reviewed the licensee's

response to Bulletin 88-02 and verified the

conclusions of the analysis

ir) the safety evaluation,

"Closeout of NRC Bulletin 88-02 for Diablo Canyon

Power Plant. Units

1 and 2."

dated

May 25,

1990.

Consequently,

the licensee

removed the plugs during

Refueling Outage

2R3 from the

19 tubes that had been

shown to be not

susceptible to fatigue damage,

and returned the tubes to service.

The eddy current examinations

in Refueling Outages

2R3 and

2R4 did not

identify any tubes with pluggable indications.

However.

Tube R42/C55 in Steam

Generator

2-1 was preventively plugged during Refueling Outage

2R4 because of

a restriction in the U-bend.

In Refueling Outage

1R5. the plugs were removed

from this tube and it was reexamined.

Although the eddy current probes

initially experienced

some resistance

to passage

through this tube. the tube

was successfully

inspected.

No degradation

was detected.

and the tube was

returned to service.

A reddish-brown

substance

was visible on the probe after

passage

through the tube,

which led the licensee to conclude that the tube had

been obstructed

by

a ferritic object that had corroded

away during the

previous operating cycle.

Table

5

UNIT 2 STEAM GENERATOR (SG)

TUBE REPAIR HISTORY

Time of

Repair

(Outage)

Preservice

2R1 (1987)

2R2 (1988)

2R3 (1990)

2R4 (1991)

2R5 (1993)

EFPYs"'.00

1.02

2.05

3.16

4.43

5.75

Tubes

Plugged

Tubes

Plugged

Tubes

Plugged

3

25

0

19(2)

0

30

SG 2-1

SG 2-2

SG 2-3

SG 2-4

Tubes

Plugged

9(3)

2R6 (1994)

7.09

10

12

Total

Re airs

C Re airs (Inservice)

21

0.62

43

1.27

31

0.91

19

0.56

(1)

- Effective full-power years of operation;

(2) - Tubes

unplugged during

refueling outage;

(3)

- Net plugged total (i.e., ten tubes

plugged

and one

tube unplugged).

0

-15-

Sixty-two tubes

were plugged during Refueling Outage

2R5

~ with all the tubes

with one exception

plugged because of the detection of corrosion-related

degradation.

The exception pertained to anti -vibration bar wear.

Fifty-one

tubes out of the 62 total were removed

from service

because of the detection

of primary water stress

corrosion cracking indications.

Primary water stress

corrosion cracking was identified in low radius

U-bends

(10 tubes),

the

WEXTEX

expansion-transition

region

(1 tube), in the tubesheet

below the bottom of the

WEXTEX transition

(24 tubes),

and at dented tube support plate intersections

(16 tubes).

A single circumferential indication was identified by motorized

rotating pancake coil examination of the Unit 2 steam generator

tubes in the

area of the

WEXTEX expansion transition region in Steam Generator

2-2.

Four

tubes experienced

outside diameter stress

corrosion cracking at the tube

support plates,

while another tube was plugged for outside diameter stress

corrosion cracking located at the top-of-tubesheet

elevation.

Table

6

UNIT 2

INSERVICE PLUGGING HISTORY BY DEGRADATION MECHANISM

Tube Degradation

Mechanism

H.C. Fati

ue"'VB

Wear<>>

Unit 2 Refueling Outage

(2R)

2R1

2R2

ZR3

2R4

2R5

2R6

Total

0

5

0

5

0

1

3

ODSCC/non-dented

TSPs"'

0

4

8

12

ODSCC/TTS"'

0

1

0

1

PWSCC/R18R2 U-bends"'

6

0

10

2

18

PWSCC/WEXTEX'

0

1

2

PWSCC/TS below BWT"'

0

24

11

35

PWSCC/Dented

TSPs"'

0

16

3

19

CL Thinnin /TSPs'"'

0

5

10

15

Mechanical

Dama

e

2

0

2

Other'"'

20

0

1

0

21

Tubes

Un lugged

Net Tubes

Plugged

0

19

0

1

0

20

2

31

-19

1

61

38

114

(1) - Preventively plugged in response

to Bulletin 88-02:

(2)

- Anti-vibration

bar wear in the U-bend region:

(3) - Outside diameter stress

corrosion

cracking at non-dented

tube support plates:

(4)

- Outside diameter stress

corrosion cracking at the top of tube sheet:

(5) - Primary water stress,

r

-16-

corrosion cracking in the

Row 1/Row 2 U-bends;

(6) - Primary water stress

corrosion cracking in the

WEXTEX expansion transition region;

(7)

- Primary

water stress

corrosion cracking at the tube sheet

below the bottom of the

WEXTEX expansion transition;

(8)

- Primary water stress

corrosion cracking at

dented tube support plates;

(9)

- Crack-like flaws at non-dented

tube support

plates for which cause

was

unknown;

(10)

- Cold-leg side thinning at tube

support plates:

(11)

- Of 20 tubes

plugged in 1R2,

19 tubes were preventively

plugged

due to initial high cycle fatigue concerns

and

1 tube was plugged

because of a restriction.

In Refueling Outage

2R4,

one tube was plugged

because of a restriction.

A total of 21 indications were identified as cold-leg thinning during

Refueling Outage

2R5.

However. only five tubes

required plugging due to

depths in excess of the 40 percent throughwall repair limit.

Cold-leg

thinning is not

a major source of degradation within the industry,

and limited

information is presently

known regarding this phenomenon.

Indications

from

this form of degradation

are volumetric in nature

and

may result from a

combination of corrosion

and mechanical (i.e.. tube motion) mechanisms.

Thirty-eight tubes

were pluggea during Refueling Outage

2R6.

The eddy current

inspections

identified similar degradation

mechanisms

as observed

in the

however.

the overall

number of pluggable tubes

decreased

from the previous inspection.

The decrease

primarily stemmed

from a decline

in the number of tubes identified with axial primary water stress

corrosion

cracking.

The respective

plugging numbers

and degradation

locations in

Refueling Outage

2R6 for axial primary water stress

corrosion cracking were

3 tubes at dented

tube support plate intersections.

11 tubes

below the bottom

of the

WEXTEX transition region in the tubesheet.

1 tube in the

WEXTEX

transition region,

and 2 Rows

1 and

2 tubes in the low radius

bend region.

The corresponding

plugging numbers at these locations in Refueling Outage

2R5

were, respectively.

16.

24'.

and

10 tubes.

The number of pluggable tubes

affected

by outside diameter

stress

corrosion cracking increased slightly to

eight (up from four).

Although the licensee

had previously concluded in the

steam generator strategic

plan (see Section 5.0) that outside diameter

stress

corrosion cracking would be the dominant degradation

mechanism in the future,

a significant increase

in pluggable tubes

due to outside diameter stress

corrosion cracking indications

was not apparent

as of Refueling Outage

2R6.

Cold-leg thinning continued to be an active degradation

mechanism in the cycle

of operation prior to Refueling Outage

2R6.

Ten tubes with cold-leg thi nning

depths in excess of 40-percent

throughwall were plugged

as

a result of the

Refueling Outage

2R6 eddy current examinations.

Because of the continued

activity of this degradation

phenomenon,

the licensee

considers it a "special

concern"

as stated in "2R6 Steam Generator

Outage Activities Report," dated

June 3,

1995.

The inspectors

reviewed the Refueling Outage

2R6 outage report

and verified that the licensee

had monitored

and recorded the growth rates of

previously identified cold-leg thinning indications.

0

-17-

A reduced

number of dents occurred in Unit 2 steam generator

tubes atter

the

initial cycles of operation

compared to Unit 1.

The initiation of these

dents

is

a result of the

same

mechanisms

described for Unit 1.

A summary of the

number of dented

tubes is given in Table 7.

Table

7

UNIT 2 STEAM GENERATOR (SG)

DENT DISTRIBUTION (DENTS > 5 YOLTS)

TSP/HLS'"

SG 2-1

SG 2-2

SG 2-3

SG 2-4

Total

1H

0

426

0

426

2H

3H

0

1

13

2

3

9

46

60

4H

1

ill

4

7

123

5H

2

0

2

4

oH

0

Total

551

16

60

634

1

- Tube support plate/Hot-leg side.

2.5.3

Comparison of the Degradation in the Unit

1 and

2 Steam Generators

The licensee

furnished to the inspectors

a compilation of the number of tubes

plugged in the Units

1 and

for each applicable degradation

mechanism.

Summaries of the Units

1 and

2 information are provided,

respectively,

in Tables

8 and 9.

The inspectors

concluded

from review of this

information that there were

some current degradation

differences

between the

two units.

The inspectors additionally noted that tube plugging history. to

date.

suggests

that there

may be differences in susceptibility to primary

water stress

corrosion cracking between

1-3 and 1-4 and the

other six steam generators.

The inspectors

noted that tube wear at anti-vibration bars varied

significantly between units. with Unit

containing

a total

of 35 tubes

plugged for this degradation

mechanism

versus

a total of only

4 tubes in Unit 2 steam generators.

The inspectors

also compared the overall

number of tubes

plugged by unit for primary water stress

corrosion cracking

and noted that the incidence in Unit

1 was approximately twice that of Unit 2

(i.e..

141 tubes

versus

74 tubes).

Unit 1 had,

however.

accrued

8.47

effective full-power years of operation

as of Refueling Outage

1R7 versus

7.09

effective full-power years of operation in Unit 2 at Refueling Outage

2R6.

In

that

81 tubes

were plugged during'Refueling Outage

1R? because

of identified

-18-

rimary water stress

corrosion cracking,

the current overall difference

etween units for this degradation

mechanism

was considered

by the inspectors

to be primarily related to the difference in time of commercial

service.

The inspectors

noted from review of individual Unit

1 steam generator

plugging

history that the incidence of primary water stress

corrosion cracking was

significantly lower in Steam Generators

1-3 and 1-4 than in Steam

Generators l-l and 1-2.

The respective

numbers of tubes that have been

plugged through Refueling Outage

1R7 because

of identified primary water

stress

corrosion cracking were two in Steam Generator

1-3 (i.e.,

low radius

Rows

1 and

Z U-bends)

and nine in Steam Generator

1-4 (i.e.. dented tube

support plate intersections).

The comparable

tube totals for primary water

stress

corrosion cracking in Steam Generators

1-1 and 1-2 were, respectively,

35 and 95.

Steam Generators l-l and 1-2 exhibited

a greater

incidence of

primary water stress

corrosion cracking in both the low radius

bends of the

Rows

1 and

2 U-tubes (i.e..

9 tubes

and

15 tubes.

respectively.

plugged)

and

at dented tube support plate locations (i.e..

17 tubes

and

72 tubes.

respectively.

plugged).

Of particular significance to the inspectors

was the

plugging data for primary water stress

corrosion cracking at dented tube

support plate intersections.

As noted in Table 4 in Section 2.5. 1 above.

the

distribution of dents

~ 5 Volts in the Unit

was

as of

Refueling Outage

1R7:

1-1

~ 211:

1-Z. 494:

1-3.

215:

and Steam Generator

1-4.

1355.

The respective

numbers of tubes

plugged for identified primary water stress

corrosion

cracking at dented tube support plate intersections

were,

as of Refueling

Outage

1R7:

1-1

~

17;

1-2.

72:

Steam

Generator

1-3, 0:

and Steam Generator

1-4, 9.

The inspectors

considered that

the latter two plugging numbers

indicated

a significantly greater resistance

to initiation of primary water stress

corrosion cracking in Steam

Generators

1-3 and 1-4 tubing than demonstrated

by Steam Generators

1-1 and

1-2 tubing.

This view was based,

in part.

on the relative sizes of the dent

populations.

with the respective

percentages

of dented

tubes containing

primary water stress

corrosion cracking found to be 8.06 in Steam

Generator

1-1,

14.57 in Steam Generator

1-2

~

0 in Steam Generator

1-3,

and

0.66 in Steam Generator

1-4.

Other locations in Steam Generators

1-1 and 1-2 where primary water stress

corrosion cracking

has

been identified were:

below the bottom of the

WEXTEX

expansion transition region (i.e.,

seven

tubes

and three tubes,

respectively.

plugged): the

WEXTEX expansion transition region (i.e.,

one tube in Steam

Generator

1-1 only plugged):

and at non-dented

tube support plate

intersections

(i .e.,

one tube

and five tubes,

respectively,

plugged).

Table

7 lists the number of tubes that have been identified to contain hot-leg

side dents

~ 5 Volts in the Unit 2 steam generators

as of Refueling

Outage

2R6.

With the exception of Steam Generator

2-2, which contained

551

dents,

the incidence of denting

was significantly lower than was found in the

Unit

1 steam generators.

Although cracking at dented tube support plate

intersections

is not necessarily

a function of dent voltage,

the limited

number of dents

a 5 Volts in Steam Generators

2-1. 2-3.

and 2-4 (i.e.,

-19-

respectively,

7,

16,

and 60) suggest

that the long-term incidence of primary

water stress

corrosion cracking at dented tube support plate intersections

should

be limited in these three Unit 2 steam generators.

Table 8

UNIT 1

STEAM GENERATOR (SG)

TUBE DEGRADATION BY MECHANISM

Tube Degradation

Mechanism

Mi h

C cle Fati

ue'VB

Wear'

0

1

0

4

7

9

15

35

Total

1-1

1-2

1-3

1-4

ODSCC/non-dented

6

1

0

13

ODSCC/TTS'

0

PWSCC/R18R2

U-Bends'

15

2

0

PWSCC/WEXTEX'

0

PWSCC/TS Below BWT'

3

0

PWSCC/Dented TSPs'7

72

0

9

PWSCC/Non-'dented

5

0

Unknown TSP flaws"

3

2

0

C.L. Thinnin /TSPs"

7

13

1

3

26

10

98

24

Other"

Total Plugged

60

125

0

2

1

0

15

27

227

(1)

- Preventively plugged in response

to Bulletin 88-02:

(2)

- Anti-vibration

bar wear in the U-bend region;

(3) - Outside diameter stress

corrosion

cracking at non-dented

tube support plates;

(4) - Outside diameter stress

corrosion cracking at the top of tube sheet:

(5) - Primary water stress

corrosion cracking in the

Row 1/Row 2 U-bends;

(6)

- Primary water stress

corrosion cracking in the

WEXTEX expansion transition region;

(7)

- Primary

water stress

corrosion cracking at the tube sheet

below the bottom of the

WEXTEX expansion transition:

(8) - Primary water stress

corrosion cracking at

dented tube support plates;

(9)

- Primary water stress

corrosion cracking at

non-dented

tube support plates:

(10)

- Crack-like flaws at non-dented

tube

support plates for which cause

was unknown; (ll) - Cold-leg side thinning at

tube support plates:

(12)

- Two tubes

were plugged in Steam Generator

1-2 due

to probe restrictions

and one tube in Steam Generator

1-3 due to a freespan

indication that was pre-service

related.

0

-20-

As noted in Table

1 in Section 2.3 above,

the mean 0.2 percent yield strength

and ultimate tensile strength

values for a sample of Steam Generator

1-4

tubing were found to be lower than the corresponding

values determined

from

samples of Steam Generators

1-2 and 2-2 tubing.

The inspectors

concluded that

it was probable that higher tube annealing

temperatures

and/or longer

annealing

times were used by Huntington Alloy Products

during final annealing

of the Steam Generator

1-4 tubing than the values

used

Specialty Metals Division during final annealing of the Steam Generators

1-2

and 2-2 tubing.

Lower 0.2 percent yield strength properties

would be expected

to result in a lower susceptibility

to primary water stress

corrosion

cracking,

which would at least partially explain the lower incidence of this

type of degradation

in Steam Generators

1-3 and 1-4.

The relatively large

range of 0.2 percent yield strength

values

noted during review of the Steam

Generator

1-4 certified material test report data,

in conjunction with a

calculated

standard deviation of 7 KSI. suggested.

however.

to the inspectors

that other factors

had to be contributing to the apparent difference in

degradation susceptibility.

Table 9

UNIT 2

STEAM GENERATOR (SG)

TUBE DEGRADATION BY MECHANISM

Tube Degradation

Mechanism

Hi h

C cle Fati ue'G

2-1

0

5

0

5

Total

2-2

2-3

2-4

AVB Wear'

0

3

1

4

ODSCC/non-dented

4

5

2

12

ODSCC/TTS'

1

0

1

PWSCC/R18R2

U-Bends'

5

18

PWSCC/WEXTEX

0

1

0

1

2

PWSCC/TS Below BWT'l

5

9

10

35

PWSCC/Dented

19

0

19

PWSCC/Non-dented

0

Unknown TSP flaws"

0

C.L. Thinnin /TSPs"

5

8

2

0

15

Other"

Total Plugged

21

43

31

19

114

1

0

2

0

3

(1)

- Preventively plugged in response

to Bulletin 88-02;

(2) - Anti-vibration

bar wear in the U-bend region:

(3)

- Outside diameter stress

corrosion

0

-21-

cracking at non-dented

tube support plates:

(4)

- Outside diameter stress

corrosion cracking at the top of tube sheet:

(5)

- Primary water stress

corrosion cracking in the

Row 1/Row 2 U-bends;

(6)

- Primary water stress

corrosion cracking in the

WEXTEX expansion transition region:

(7)

- Primary

water stress

corrosion cracking in the tube sheet

below the bottom of the

WEXTEX expansion transition:

(8) - Primary water stress

corrosion cracking at

dented tube support plates;

(9)

- Primary water stress

corrosion cracking at

non-dented

tube support plates:

(10)

- Crack-like flaws at non-dented

tube

support plates for which cause

was unknown.;

(11)

- Cold-leg side thinning at

tube support plates;

(12)

- Two tubes

plugged in Steam Generator

2-1 and one

plug in Steam Generator

2-3 due to probe restriction in U-bend.

2.6

Licensee Actions Taken to Increase

Tubin

Stress

Corrosion Crackin

Resistance

The inspectors

were informed by licensee

personnel

that onsite shot peening

was performed

on the inside diameter of all Units

1 and

2 steam generator

tubes in the area of the tube sheet

through the tube expansion transition

region.

Hoth hot-leg

and cold-leg sides of the U-tube bundle were peened.

with the purpose

being to increase

resistance

to initiation of primary water

stress

corrosion cracking by inducing surface

compressive

stresses

(i.e..

a

tensile stress

is required to be present for stress

corrosion cracks to

initiate).

The Units

1 and

2 shot peening activities were performed,

respectively,

during Refueling Outages

1R5 (1992)

and

2R5 (1993).

The

inspectors

considered that achieving

any beneficial effects

from shot peening

would be strongly dependent

upon whether primary water stress

corrosion cracks

had already

commenced to form during the five cycles of operation that

preceded

the shot peening.

The Unit 2 degradation

data presented

in Table

6

in Section 2.5.2

shows that primary water stress

corrosion cracks were

detected

below and in the

WEXTEX expansion transition region during Refueling

Outage

2R5. the outage in which the shot peening

was performed.

The

inspectors

therefore considered

the detection of further primary water stress

corrosion cracking at these

locations during Refueling Outage

2R6 not to be

surprising.

As shown in Table 3 in Section 2.5. 1, primary water stress

corrosion cracking was not detected

in and below the

WEXTEX transition region

in the Unit

as of Refueling Outage

1R5 when shot peening

was performed.

The subsequent

detection of primary water stress

corrosion

cracking at these locations during Refueling Outages

1R6 and

1R7 was viewed by

the inspectors

as probably indicative that cracks were present at the time of

shot peening

~ but were of sizes that were below the eddy current detection

limit.

foreign material exclusion

also performed onsite thermal stress relief of the low radius

Rows

1 and

2 U-bends in each Unit

1 and

2 steam generator

during,

respectively.

Refueling Outages

1RZ (1988)

and

2R1 (1986). in order to

increase

the resistance

of the bend regions to primary water stress

corrosion

cracking.

The Units

1 and

2 degradation

data contained,

respectively,

in

Tables

3 and

6 show.

however. that primary water stress

corrosion cracking has

0

-22-

continued to be detected

in low radius

U-bends despite

performance of the heat

treatment.

The inspectors

did not believe that sufficient information was

available to determine with any certainty the reason for the continuing

detection of this type of degradation'ut

considered

a possible explanation

was

a continuing slow growth of cracks that initiated prior to performance of

the heat treatment.

Reviews were not performed

by the inspectors of the procedural

requirements

and process

controls that were in effect for accomplishing the shot peening

and stress relief activities.

3

VISUAL EXAMINATION OF THE SECONDARY SIDE OF THE STEAN GENERATORS

3. 1

Review of Pro

ram

Re uirements

and Ins ection Data

The inspectors

reviewed Procedures

ISI VT-5. "Steam Generators

Secondary

Side

Internal Inspection." Revision I: and AD4. ID6. "Foreign Material

Exclusion

Program." Revision 2.

The inspectors

performed

a visual inspection of the

upper internals of Steam Generator

1-4. including the foreign material

exclusion barriers.

and interviewed personnel

during the closeout of Steam

Generator

1-2 for Refueling Outage

1R7.

The inspectors

noted that Procedure

ISI VT-5 was first utilized during

Refueling Outage

1R6 in April 1994.

Secondary

side inspections of steam

generators

had not been performed in either unit prior to that outage.

The

licensee's

current program appeared

to be responsive

in addressing

secondary

side degradation

issues.

Howevers earlier implementation of the program could

have provided for a more timely identification and evaluation of J-tube.

barrel riser.

and nozzle plug erosion/corrosion

phenomena.

An evaluation

by the inspectors of the licensee's

program and practices for the secondary

side of the steam generators

showed

that measures

taken to preclude foreign materials

from entering the feedwater

annulus during maintenance

and inspection were appropriate.

The inspectors

were informed that steel

wedges.

specially fitted for the annulus,

are used in

conjunction with wood planking and nylon reinforced drop cloth to provide the

foreign material exclusion barrier.

Inspectors

observed

the barrier in place

during an inspection of Steam Generator

1-4.

Based

upon discussions

with

licensee

personnel

and observation of the closeout of Steam Generator

1-2. the

inspectors

noted that material accountability

was reestablished

prior to

removal of the foreign material exclusion barrier.

Subsequent

to the removal

of the drop cloth,

a visual inspection of the planking and wedges

was

performed

and debris

removed.

Planking

and wedges

were then

removed

and final

closeout

completed.

Review by the inspectors of the results of visual inspections that were

performed of the secondary

surfaces of steam generator

tube sheets

during

refueling outages

revealed that minimal foreign objects

had been observed

0

-23-

during commercial operation.

To date,

no objects

have

been

observed of a size

and type that could impair tube integrity.

Overall. the inspectors

considered

that the data

was indicative of effective implementation of foreign material

exclusion program requirements

for steam generators.

4

REVIEW OF TUBE EXAMINATION HISTORY.

PROGRAM REQUIREHENTS,

AND DATA

4.1

Review of Tube Examination Histor

During Refueling Outage

1Rl in 1986,

the licensee

performed

a full-length

bobbin coil examination of a

16 percent

sample of active tubes in each

steam

generator.

This sample size exceeded

the Technical Specification

minimum

sample size requirement of 3 percent

when each individual

is examined.

Initial Unit 2 inservice examinations

during

Refueling Outage

2R1 utilized a sample size for full-length bobbin coil

examination which ranged

from 22 to 100 percent of active tubes in the steam

generators (i.e..

2-1

~

25 percent:

2-2

~

22

percent:

2-3.

100 percent:

and Steam Generator

2-4.

25 percent).

Full-length bobbin coil examinations

during Refueling Outages

1R2 through

1R4

utilized sample sizes in individual steam generators

which ranged

from 22 to

31 percent of active tubes.

Similar bobbin coil sample sizes

were utilized in

Unit 2 during Refueling Outages

2RZ through

2R4 (i .e..

20 to 25 percent of

active tubes).

In addition. the licensee initiated during Refueling Outages

1R2 and

2R2

a motorized rotating pancake coil examination of the low radius

bend region in all of the

Rows

1 and

2 U-tubes.

This type of examination

was

utilized to increase

the assurance

of detection of primary water stress

corrosion cracking.

The inspectors

noted that examinations of the low radius

bends in the

Rows

1 and

2 U-tubes

have also been performed during each

refueling outage

subsequent

to Refueling Outages

1R2 and

2R2.

During

Refueling Outages

1R4 and 2R4. the licensee

added to the examination

program

motorized rotating pancake coil examinations of a 20 percent

sample of WEXTEX

expansion transition regions

on the hot-leg side of each

steam generator.

The

motorized rotating pancake coil examinations of the

WEXTEX expansion

transition region were added to increase

assurance

of detection of

circumferential

stress

corrosion cracking.

During Refueling Outage

1R5. the sample size for full-length bobbin coil

examinations

ranged

from 28 to 45 percent of active tubes in individual Unit

1

During Refueling Outage

2RS. the bobbin coil sample size

was increased to 100 percent of the active tubes in each Unit 2 steam

generator.

Motorized rotating pancake

coi 1 examinations

during Refueling

Outages

1R5 and

2R5 of the hot-leg side

WEXTEX expansion transition regions

utilized. respectively.

sample sizes of 22 and 41 percent of active tubes.

Beginning in Refueling Outage

2R5. the licensee

fut ther augmented

the

examination

program to include motorized rotating pancake

coi 1 examinations of

dented tube support plate intersections

on the hot-leg side of the steam

generators.

The purpose of these

examinations

was to increase

assurance

that

any stress

corrosion cracking associated

with dents would be detected.

All

-24-

hot-leg side intersections

in Tube Support Plates

01 through 06, which

exhibited

a dent signal amplitude

> 5 volts during bobbin coil examination.

were examined

by motorized rotating pancake coil during Refueling Outage

2R5.

During Refueling Outages

1R6 and 2R6,

100 percent of the active tubes in each

were examined full length using

a bobbin coil.

The steam

generator

sample sizes

used for motorized rotating pancake

coi 1 examination of

the

WE)(TEX expansion transition region ranged

from 22 to 23 percent of active

tubes in the Unit

and from 22 to 46 percent of active tubes

in the Unit 2 steam generators.

The Refueling Outage

1R6 motorized rotating

pancake coi 1 sample sizes

used for examination of dented hot-leg side

intersections

ranged in the four steam generators

from 10 to 26 percent of the

intersections

in Tube Support Plates

01 through

07 with bobbin coi 1 dent

signal

amplitudes

~ 5 volts.

All steam generator hot-leg side intersections

in Tube Support Plates

01 through 07, which exhibited

a bobbin coi 1 dent

signal amplitude

~ 5 volts, were examined

by motorized rotating pancake coil

during Refueling Outage

2R6.

During the onsite inspection.

the inspectors

reviewed the examination

requirements

that had been developed for Refueling Outage

1R..

These

requirements

were documented

in a licensee

memorandum

dated October

16.

1995.

which was entitled.

"1R7

SG Tube Eddy Current Inspection Criteria."

Revision 2.

The inspectors

noted from the review that

a full-length bobbin

coil examination of 100 percent of the active tubes

was specified in each

steam generator.

A sample size of 28 percent

was selected

for Plus Point

motorized rotating pancake

coi l examinations

in each

steam generator of the

WEXTEX expansion transition region.

The inspectors

ascertained

that the

sampling requirements

for the

WEXTEX expansion transition region were

implemented in accordance

with Westinghouse

Owners

Group guidelines.

The

sample size selected

for Plus Point motorized rotating pancake

coi 1

examinations of dented hot-leg side intersections

was

100 percent of the

intersections

(with dent signal

amplitudes

~ 5 volts) in each

in Tube Support Plates

01,

02.

and 03.

The sampling criteria additionally

required sampling

be performed

above

Tube Support Plate 03. if necessary.

to

achieve

a sample of 20 percent of the hot-leg side dented intersections.

The

low radius

bends in all

Rows

1 and

2 U-tubes were specified to be examined

by

motorized rotating pancake coil and all anomalies

noted in the

WEXTEX

expansion transition region were required to be examined

by the Plus Point

motorized rotating pancake

coi l.

Overall. the inspectors

concluded that:

(1) the historical examination

program scope

was considered

an indicator of management

awareness

of and

support for steam generator

tube integrity initiatives;

and (2) the licensee

has

been proactive with respect to examination

scope,

adoption of new eddy

current examination technology,

and incorporation of industry experience.

0

-25-

4.2

Review of Examination

Pro

ram

Re ui rements

4.2. 1

Current

Program

and Process

The inspectors

and

NRC consultant

reviewed the eddy current examination

program requirements

for Refueling Outage

1R7 which were contained in:

(1) Document

DCPP-Guide-001.

"Data Analysis Guidelines." Revision 95. 1 dated

October

7,

1995;

(2) Procedure

AD5. ID4,

"Steam Generator

Tube Inspections,"

Revision 2; (3) Procedure

N-ET-4,

"Eddy Current Data Analysis of Diablo Canyon

Units

1 and

2 Steam Generator

Tubing," Revision

1; (4) Westinghouse

Document

DAT-GYD-005. "115/+Pt./80HF

RPC Probe Analysis Guidelines." Revision

0: and,

(5) Westinghouse

Nuclear Services

Division Procedure

HRS 2.4.2

PGE-35,

"Eddy Current Inspection of Inservice

Nonferromagnetic

Tubing

for Diablo Canyon Units 182." Revision 4.

The inspectors

also compared the

current program against the recommendations

contained in Electric Power

Research

Institute

EPRI NP-6Z01.

"PWR Steam Generator

Examination Guidelines."

Revision 3.

't was ascertained

during this review that the licensee

data analysis

guidelines

were generally consistent

with the recommendations

contained

in

Electric Power Research

Institute

EPRI NP-6Z01. Revision 3.

The data analysis

guidelines

were noted to contain legible Lissajous figures

and standard

drawings that were considered to provide appropriate

guidance to analysts.

The most significant omission in the licensee

data analysis guidelines

was the

absence of any quantitative guidance

regarding the Electric Power Research

Institute

EPRI NP-6201

recommendation

for establishment

of criteria for noisy

data.

The inspectors

also noted that. in addition to the licensee

data

analysis guidelines

(DCPP-Guide-001,

Revision 95. 1), Westinghouse

data

analysis guidelines

(DAT-GYD-005, Revision 0) were also in effect for analysis

of motorized rotating pancake

coi 1 data,

resulting in some overlap and

redundancy.

Eddy current examination

program strengths

noted during the

review included:

(1) use of only analysts

who had been certified as qualified

data analysts

in accordance

with the requirements

of EPRI NP-6201,

Appendix G;

(2) screening for loose parts in Rows

1 and

2 and the outer two rows of the

tube bundle periphery;

and (3) use of two separate

companies to perform

independent

primary and secondary

analysis.

Site-specific training and testing of primary and secondary

eddy current data

analysts

were performed by the licensee

Level III eddy current examiner.

Assessments

of the training and testing materials

were not performed during

the inspection.

The inspectors

and

NRC consultant

reviewed the process

and equipment that were

applicable to Refueling Outage

1R7 eddy current data acquisition

and analysis.

Data acquisition

and primary analysis

were performed

by Westinghouse,

with

secondary

analysis

performed

by Anatec International.

Both primary and

secondary

analysis

were performed remotely at the Westinghouse

Waltz Hill

facility in Pennsylvania.

using

a dedicated

telephone line for data

transmission.

Resolution analysis for differences in "calls" between primary

and secondary

analysts

was performed onsite

and Anatec

-26-

International

Level III analysts.

It was ascer tained that motorized rotating

pancake coil examinations of straight sections

in Refueling Outage

1R7

utilized

a three-coil

probe.

The three-coil

probe contained

a 0. 115-inch

diameter

pancake coil.

a Plus Point coil, and

a high frequency shielded

0.080-inch diameter

pancake coil.

The inspectors

considered that the probe

should enhance

detection capability compared with previous examinations'ue

to the increased

signal-to-noise ratio of the Plus Point coil and the ability

of the high frequency

pancake coil to detect shallow inside diameter cracking.

Bend regions were examined with a two-coi 1 probe containing

a 0. 115-inch

diameter

pancake coil and

a Plus Point coil.

The

NRC consultant

considered

that the scope of electric discharge

machined axial

and circumferential

inside

diameter

and outside diameter

notches

in the licensee

standards

for motorized

rotating pancake coil examinations

was excellent.

and would be very useful

for

probe setup

and defect sizing.

During the inspections

the

NRC consultant

ascertained

that Westinghouse

was

utilizing 100-foot extension

cable for the bobbin coil examinations.

This

cable length was permitted

by the applicable job data sheet.

Prior to the

start of motorized rotating pancake coil examinations.

personnel

were questioned

concerning

the extension

cable length that was planned to be

used for that series of examinations.

in that the applicable Aestinghouse

job

data sheets

for this examination

method specified that

a 50-foot extension

cable

be used.

The

NRC consultant

was initially informed that

a 100-foot

extension

cable would also be used for the motorized rotating pancake

coi 1

examinations.

because

of an

ALARA concern that had been expressed

by health

physics personnel.

The inspectors

requested

licensee

personnel

to review the

matter

and determine whether

a 50-foot extension cable could be used without

posing

an ALARA problem.

since the increased

extension

cable length could

result in some degradation of motorized rotating pancake

coi 1 data quality.

After review. licensee

personnel

determined that the motorized rotating

pancake coil examinations

could be appropriately

accomplished

using

a 50-foot

extension cable.

While this issue

does not raise regulatory concerns. it is

indicative of a lack of a thorough evaluation

and proactive

management

of

contractor activities.

The

NRC consultant

noted that the Westinghouse

Anser software permitted

analysts to view C-scan (or isometric) plots

as they were being rotated,

which

allowed the analysts

to get

a better

idea of the contours of the plots and

limited the ability of artifacts to "hide" defects.

The mix residual

in the

Anser software

was ascertained

by the

NRC consultant to be typically

0.43 volts, with the residual

appearing to increase with increase

in probe

speed.

The residual

masks small defect indications

and contributes additional

error in the measurement

of defect depth. with the error noted by the

NRC

consultant to be at

a maximum if the defect

was near the edge of a support.

The

NRC consultant

considered

the mix residual to be of a magnitude which

would make detection of outside diameter stress

corrosion cracking at tube

supports

more difficult for signals

less

than one volt.

During the onsite inspection.

the inspectors

noted that Westinghouse

Procedure

MRS 2.4.2

PGE-35.

Revision 4, did not require

use of low capacitance

0

-27-

probe extension cable for motorized rotating pancake coil examinations (i.e.,

Appendix

E of MRS 2.4.2 PGE-35,

Revision 4, specified

a capacitance

value of

26 pico farads/foot

+ 10 percent for the cable).

Additional review of eddy

current equipment criteria was performed subsequent

to the onsite inspection.

Included in the offsite review was the licensee

response

dated

June

29.

1995

'o

Generic Letter 95-03 'Circumferential

Cracking of Steam Generator

Tubes. "

The inspectors

noted that the licensee identified in its response that it will

use

augmented

inspection techniques

that are consistent with industry

recommendations

and that are qualified to Appendix

H of the Electric Power

Research

Institute Guidelines.

Appendix

H qualifications that had been

previously seen

by the inspectors uti lized low capacitance

extension cable.

Conformance of the Westinghouse

eddy current examination procedures

to the

qualification criteria contained in Appendix

H of Electric Power Research

Institute

EPRI NP-6201.

Revision 3.

was not specifically checked during the

onsite inspection.

An additional exit meeting

was held by telephone

on

January

17 '996. to inform the licensee that review of the conformance of the

eddy current examination

procedures

to Appendix

H of Electric Power Research

Institute

EPRI NP-6201.

Revision 3.

was considered

an inspection followup item

(275/9510-01:

323/9510-01).

4.2.2

Response

to Generic Communications

The inspectors

performed

a limited review of the licensee's

handling of NRC

generic communications pertaining to steam generator

tube degradation

problems.

The sample

used for this review consisted of Bulletin 89-01

'Failure

of Westinghouse

Tube Mechanical

Plugs."

and

Information Notices 90-49,

"Stress

Corrosion Cracking in

PWR Steam Generator

Tubes."

and 91-67.

"Problems With the Reliable Detection of Intergranular

Attack

( IGA) of Steam Generator Tubing."

The review indicated that the licensee

had appropriately

responded to

Bulletin 89-01, with removal of Westinghouse

Inconel

600 mechanical

plugs from

Unit

1 complete

and removal of the remaining

14 Unit 2 cold-leg side plugs

scheduled to be completed during Refueling Outage

2R7 in Spring 1996.

The

inspectors

noted that the licensee

immediately responded to Information Notice 90-49 by implementing (in the 1991

and subsequent

Units

1 and

2

refueling outages)

a motorized rotating pancake coil examination of the

expansion transition region of at least

20 percent of the tubes.

The

inspectors

considered

the licensee

actions to be appropriate

for optimizing

detection sensitivity for circumferential cracking.

No specific additional

actions

were taken

by the licensee in response to Information Notice 91-67.

The inspectors

considered

the licensee's

bases for this determination (i.e.,

(a) the historical

non-use of a voltage amplitude threshold for analysis of

bobbin coi 1 data,

and (b) the existing use of revised Electric Power Research

Institute guidelines for interpreting bobbin coil indications at tube support

plates attributed to outside diameter stress

corrosion cracking/intergranular

attack) to be reasonable.

0

-28-

4.2.3

Eddy Current

Program Oversight

The inspectors

observed that oversight of the eddy current examination

contractors

during Refueling Outage

IR7 was performed

by both steam generator

engineers

from the licensee's

secondary

engineering organization

and by

a

nondestructive

examination engineer

from the licensee's

Technical

and

Ecological Services organization in San

Ramon, California.

The latter

individual. who held certifications

as

a Level III eddy current examiner

and

Electric Power Research

Institute qualified data analyst,

was the author of

the licensee's

data analysis guidelines

and had administered

the site specific

training and testing of data analysts.

No documentation

was

seen during the

onsite inspection that would allow an assessment

of the scope of the oversight

activities by the licensee

personnel.

The inspectors

ascertained

that the quality assurance

organization

had

increased its oversight of steam generator activities during the sixth

refueling outage in both units.

A team surveillance

(SQA-94-0091)

was

performed of Unit 2 steam generator activities during Refueling Outage

2R6.

which included in its scope:

eddy current

and ultrasonic examinations.

chemistry controls.

the foreign material exclusion program.

computer programs.

and high impact team meetings.

A surveillance

(SQA-94-0020)

was also

ascertained

to have been performed

by the quality assurance

organization of

eddy current examination activities during Refueling Outage

1R6.

The

inspectors

reviewed the surveillance reports

and found them to be well written

and indicating thorough review in the eddy current examination

area.

The

inspectors

considered

the use of a Level III eddy current examiner

from

another utility as

a team member in both of these survei llances to be

commendable.

and an excellent practice to follow when performing audits

or

survei llances of specialist activities.

The inspectors

also reviewed the

planned

scope for an audit of steam generator activities that was to be

performed during Refueling Outage

1R7,

and attended

the audit entrance

meeting.

The inspectors

considered

the planned

scope,

which included audit of

eddy current examination activities at the Westinghouse

Waltz Hill facility,

to be comprehensive.

4.3

Review of Tube Examination

Data

The

NRC consultant

reviewed several full-length bobbin coil scans

and also

several three-coil

probe motorized rotating pancake coil examinations of

WEXTEX expansion transition regions.

The bobbin coil examination data quality

was considered

good, with the noise level (using the maximum vertical signal)

observed to be under

0. 17 volts for the sample of scans that was examined.

During review of the three-coil motorized rotating pancake coil examination

data'he

NRC consultant

noted that the high frequency coil appeared to give

additional information about indications, particularly in distinguishing

whether

an indication was located at the inside diameter or outside diameter

0

-29-

surface of the tube.

In addition, the high frequency coil was noted to allow

the analyst to more easily distinguish

between lift-offsignals

and shallow

inside diameter cracks.

Only one potential

inside diameter indication was

observed

by the

NRC consultant during the onsite inspection,

and it indicated

less than 10-percent

throughwall.

The

NRC consultant also reviewed during the inspection

a sample of data

from

Refueling Outage

1R6 pertaining to primary water stress

corrosion cracking

that was detected at dented

and nondented

tube support plate intersections.

The results of this review are documented

in Section 2.5. 1 above.

During the review of Unit

1 steam generator

degradation history, which is

discussed

in Section 2.5. 1 above,

the inspectors

noted high apparent

growth

rates

had occurred in some cold-leg thinning indications.

As part of this

review, the worst-case

data (i.e.

~ Tube

R34C18 in Steam Generator

1-2), which

exhibited

an apparent

change

from "no detectable

degradation"

at Tube Support

Plate

01 on the cold-leg side during Refueling Outage

1R6 to

a

68 percent

throughwall defect indication in Refueling Outage

1R7.

was reviewed

by the

NRC

consultant.

The

NRC consultant

noted

from review of the Refueling Outage

1R6

data that

a 1.5 volt signal

was generated

at this location. but with a phase

angle which indicated

a depth that was too shallow to be "called" by an

analyst.

The

NRC consultant

confirmed from the Refueling Outage

1R7 data that

the tube defect

now measured

at 68-percent

throughwall

and appeared

to be

located near the edge of the tube support plate.

The

NRC consultant

concluded

that the high apparent

growth was at least partially related to the masking

effect of the mix residual.

(Note:

Effects of mix residual

are discussed

in

Section 4.2. 1 above).

The inspectors

questioned

licensee

personnel

subsequent

to the onsite inspection

about plans to address

the apparent

rapid growth of

cold-leg thinning indications.

The inspectors

were informed that:

(1) preliminary analysis

(of the 68 percent throughwall

indication worst-case

indication in Steam Generator

1-2 Tube R34C18) indicated

that the structural

requirements

of Regulatory Guide

1. 121 were still

satisfied;

(2) the growth curve for cold-leg thinning indications

showed small

growth for larger existing indications,

making it questionable

whether

plugging less than 40-percent

throughwall indications offered any benefit;

and.

(3) Westinghouse

had been instructed to perform

a structural

analysis

and

growth study.

Licensee

personnel

were informed on January

17,

1996, that

review of the Westinghouse

preliminary analysis

and structural

analysis

and

growth study were considered

an inspection followup item (275/9510-02;

323/9510-02).

5

STEAN GENERATOR DEGRADATION HANAGEHENT

5. 1

Steam Generator Strate ic Plan

During the onsite inspection,

the inspectors

were provided with a document

entitled'Steam

Generator Strategic

Plan," dated

February

13,

1993.

This

document described

the licensee's

plans for the future in the area of steam

-30-

generator

tube degradation

management

at the Diablo Canyon

Power Plant.

The

document contained projections of the expected

number of defective tubes which

would require plugging by the end of the plant life, and described mitigative

efforts for containing future degradation

mechanisms.

Based

on the degradation

projections in the report, the licensee

concluded

that the life of the Diablo Canyon

Power Plant steam generators

would extend

to the end of the operating license if aggressive

mitigation efforts were

undertaken.

The noted mitigation efforts included:

reduction of corrosion

product transport,

prevention of caustic tube support plate crevice

conditions,

and reduction of oxidant concentrations

by hydrazine addition and

minimizing air in-leakage.

The primary degradation

mechanism

was projected to

be outside diameter stress

corrosion cracking at the tube support plate

intersections.

This projection was primarily based

on the current status of

the Diablo Canyon

Power Plant steam generator

tubes

and data provided from

other nuclear plants with Westinghouse

Model

51 steam generators.

The

licensee predicted

an end-of-life plugging total in the Diablo Canyon

Power

Plant steam generators

of less

than

17 percent of the total tubes.

Approximately 85 percent of this end-of-life plugging total

was predicted

would occur

as

a result of outside diameter stress

corrosion cracking at the

tube support plates.

Several

recommendations

were made for limiting the

extent of outside diameter stress

corrosion cracking in the future.

The

mitigation measures

listed in the report included:

enhancement

of the

condensate

polishers,

reduction of air in-leakage into the condensers.

continuing to follow the secondary

water chemistry guidelines

issued

by the

Electric Power Research

Institute and Westinghouse,

and investigation of a

potential

T-Hot reduction to 599'F.

The inspectors

noted that the steam generator strategic

plan considered

the

following degradation

mechanisms:

outside diameter stress

corrosion

cracking/intergranular

attack at the top of the tubesheet,

outside diameter

stress

corrosion cracking/intergranular

attack at the tube support plate,

primary water stress

corrosion cracking in the

WEXTEX expansion

region of the

tube sheet.

primary water stress

corrosion cracking in the tube U-bend

regions.

and anti-vibration bar wear.

The inspectors

reviewed

a summary of

pluggable indications in the previous Unit

1 and

2 outages

and concluded that

the dominant acti ve degradation mechanisms'o

date.

were primary water stress

corrosion cracking below the bottom of the

WEXTEX expansion transition region,

primary water stress

corrosion cracking at dented tube support plate

intersections,

and cold-leg thinning.

The absence of apparent

consideration

of these degradation

modes in the licensee's

original projections

was viewed

by the inspectors

as potentially affecting the overall conclusions of the

strategic plan.

During the review of steam generator

business

team activities, which is

discussed

in Section 5.2 below.

a meeting

summary dated July 8,

1994,

was

noted by the inspectors

which indicated that Westinghouse

had comoleted

a

review of the licensee's

steam generator strategic plan.

-31-

determined that the key conclusions of the plan were sound, with the exception

that primary water stress

corrosion cracking should

be considered

as

one of

the dominant future degradation

mechanisms

in the Diablo Canyon

Power Plant

The strategic plan recognized that,

although the degradation

projections

were

based

on data

from similar pressuri zed water reactors,

the final conclusions

regarding the end-of-life state of the Diablo Canyon

Power Plant steam

generators

primarily relied on best engineering

judgement.

The strategic

plan

also identified that degradation

rates

would be closely monitored to verify

that actual

rates

stayed at or below expected

levels,

and that the plan would

be updated annually to reflect the most recent industry steam generator

degradation

experience.

The inspectors

ascertained,

however, that the

strategic

plan had not been

updated since its original issue

on February

13,

1993.

Licensee

personnel

informed the inspectors that outage reports

were

being used to document the results of program actions that had been taken

on

strategic plan issues'ith

open issues

identified in steam generator

business

team minutes.

Licensee

personnel

additionally indicated that

a determination

was

made in 1994 to assign

a lower priority for updating the strategic plan.

due to the other vehicles

used to document results of program actions

and open

issues.

The inspectors

reviewed the steam generator

outage activities reports

that had been written for Refueling Outages

1R6 and

2R6 and found them to be

both comprehensive

and well written.

The reports

were noted to contain

detailed

information on degradation

mechanisms

and status,

but only partially

compared actual results with strategic plan projections.

The inspectors

concluded that the steam generator strategic

plan would.

without regular revision to maintain it as

a living document,

be of limited

value to management

in determination of needed

program actions for maintaining

the integrity of the Units

1 and

2 steam generators.

5.2

Business

Team

On September

14 and 15,

1993 'epresentatives

from the licensee

and

met to form a steam generator

business

team.

The team was formed

to:

provide

a forum for discussion of Units

1 and 2 steam generator

tube

inspection data.

emerging issues,

and industry events;

and to make

recommendations

regarding future steam generator

chemistry,

operations,

and

outage activities at the Diablo Canyon

Power Plant.

The steam generator

business

team formally convened for the first time in December

1993.

Subsequent

meetings

have occurred approximately every

6 months, with the most

recent meeting taking place June 8-9.

1995.

The inspectors

reviewed the meeting

summaries

from each of the steam generator

business

team meetings.

The meeting

summaries

indicated that much of the

discussions

regarding

tube degradation

and inspection

issues

focused

on recent Diablo Canyon

Power Plant steam generator

tube inspection

results

and findings at other U.S. pressurized

water reactors.

In addition,

the steam generator

business

team also discussed

potential mitigation efforts

in the meetings.'he

inspectors

concluded

from review of Procedure

TS1. ID3,

-32-

"Steam Generator

Aging Management

Program," Revision

1. the meeting

summaries,

and discussions

with licensee

personnel,

that the steam generator

business

team meetings

were

a key part of the licensee's

overall approach

toward

managing

tube degradation.

6

REVIEW OF SECONDARY WATER CHEMISTRY CONTROLS AND HISTORY

Many impurities that enter

the secondary

side of steam generators

can

contribute to corrosion of steam generator

tubes

and support plates.

While

the concentration of impurities needed to cause corrosion problems is normally

much higher than that present

in steam generator

bulk water. concentration of

impurities to aggressive

levels is possible in occluded

areas

where dryout

occurs.

Typical areas

where dryout and resulting concentration of impurities

can occur are tube sheet crevices,

tube support plate crevices.and

sludge

piles.

Impurities known to contribute to tube denting (i.e., squeezing of

tubes at tube support plates

and tube sheets

as

a result of the pressure of

corrosion products)

are chlorides. sulfates'nd

copper

and its oxides.

Pitting of steam generator

tubes

has

been attributed to the presence

of copper

and concentrated

chlorides.

Concentrated

sulfates

and sodium hydroxide are

believed to be major causes

of intergranular stress

corrosion cracking

and

intergranular attack in steam generator

tubes.

Iron oxide deposits

and sludge

promote local boiling and concentration of impurities.

leading to these

damage

mechanisms.

6. 1

Pro

ram Evolution

The inspectors

reviewed the licensee's

secondary

water chemistry control

program requirements

and initiatives.

It was ascertained

that the secondary

water controls utilized all volatile tr eatment with hydrazine.

Ammonia was

used for pH control

from initial commercial operation unti 1 replacement

by

ethanolamine

in August 1993 (Unit 1) and in March 1994 (Unit 2).

The

inspectors

compared

the Diablo Canyon

Power Plant historical secondary water

chemistry program requirements

against the criteria contained in the Electric

Power Research

Institute

"PWR Secondary

Water Chemistry Guidelines."

These

guidelines

were initially issued in October

1982 as

EPRI NP-2704-SR, with a

different document

number assigned

for each issued revision (i.e.. Revision

1

~

EPRI NP-5056-SR;

Revision 2.

EPRI NP-6239;

and the current Revision 3.

EPRI TR-102134).

To accomplish this task, the inspectors

compared selected

revisions of Operating Procedure

OP F-5: II, "Chemistry Control Limits and

Action Guideline for the Secondary Side." against the Electric Power Research

Institute document that was in effect at the time.

The Procedure

OP F-5: 11

revisions included in the review were:

(a) Revision

0

~ which was effective on

January

28.

1984, against

EPRI NP-2704-SR;

(b) Revision

1, which was effective

on April 13,

1987,

against

EPRI NP-5056-SR;

(c) Revision 4

~ which was

effective on March 30.

1989.

and Revision 5, which was effective on

January

10.

1990, against

EPRI NP-6239:

and (d) Revision ll, which was in

effect on September

8.

1995. against

EPRI TR-102134.

-33-

The inspectors

determined that.

in addition to the limits contained in the

Electric Power Research

Institute guidelines,

the licensee

secondary

side

chemistry program initially included monitoring and Action Level

1 limits for

sulfate. silica. iron.

and copper in the steam generator

blowdown samples.

Further review established

that,

as the Electric Power Research

Institute

secondary

water chemistry guidelines

and the licensee

secondary

side chemistry

program evolved,

the two were in full conformance

upon issue of Revision

5 of

Procedure

OP F-5: II in January

1990.

The inspectors

ascertained

that the licensee

had adopted

several Electric

Power Research

Institute

recommended initiatives in its secondary

chemistry

program.

These initiatives included:

implementation of boric acid addition

to the secondary

side in 1988 in response

to denting.

adoption of 100 ppb

minimum hydrazine levels in December

1992 'nitiation of molar ratio control

in August

1993 using

ammonium chloride injection.

and replacement of ammonia

by ethanolamine for pH control in August 1993 (Unit 1) and in March 1994

(Unit 2).

Overall the inspectors

considered

that the licensee

had developed

a good

secondary

water chemistry program

and had been

responsive

to industry

secondary

water chemistry initiatives.

6.2

Secondar

Side Chemistr

Histor

The inspectors

reviewed the history of the Diablo Canyon

Power Plant. Units

1

and 2, steam generators

with respect to significant chemistry events

and

compliance with the Electric Power Research

Institute secondary

water

chemistry guidelines.

Details on off-normal chemistry are discussed

below in

Section 6.5.

Prior to the onsite inspections

the inspectors

were informed

that retrieval of chemistry records for the first 5 years of commercial

operation would be extremely time consuming

and labor intensive.

due to the

records

management

system that was in effect at the time.

Other offsite

records that were germane to secondary

chemist y performance in this time

period had also not been retained after reorganization

and consolidation of

chemistry engineering discipline responsibilities

at site.

To avoid burdening

the licensee.

the inspectors

did not request that data

be assembled

for the

first 5 years of operation.

This action impacted both the completeness

and

effectiveness

of the review of secondary

side chemistry history, in that the

majority of secondary

side chemistry problems

occurred during the ear ly years

of plant operation,

As part of this review, the inspectors

requested

available historical

information from the licensee

for annual

average

blowdown chemistry values.

The information provided in response

by the licensee for Units

1 and

2 is

listed below in Tables

10 and

11.

0

-34-

Table

10

UNIT 1 AVERAGE STEAM GENERATOR

BLOWDOWN CHEMISTRY VALUES AT > 30K

POWER

Par ameter"'urrent

Limit

CGA

S/cm

< 0.8

Cl

~

b

< 20

SO.

b

< 20

Na.

b

< 20

Molar Ratio"'.1

- 0.7

Na'/Cl

0. 28

2.56

3.38

1.58

1.28

0 crating Cycle

5

6

0.24

0.28

1.14

1.12

1.69

1.53

0.84

0.51

1.10

0.73

0.39

1.14

0.55

0.25

0.35

(1)

-

CC (cation conductivity).

Cl

(chloride).

SO,

(sulfate).

Na

(sodium):

(2)

- Determined

from -;he ratio of molar concentration of sodium to molar

concentration of chloride.

Table

11

UNIT 2 AVERAGE STEAM GENERATOR

BLOWDOWN CHEMISTRV VALUES AT > 30K

POWER

Parameter'"

Current

Limit

0 eratin

C cle

4

5

6

CC. pS/cm

< 0.8

0.26

0.24

0.35

0.75

Cl

.

b

< 20

1.89

SO,

b

< 20

2.07

Na'.

b

< 20

2.58

Molar Ratio"'. 1

- 0.7

2.54

Na /Cl

1.28

1.04

1.23

1.73

1.17

1.38

0.53

0.44

1.29

0.71

0.31

0.37

1.65

1.03

0.50

0.34

(1)

-

CC (cation conductivity).

Cl

(chloride),

S04

(sulfate),

Na

(sodium);

(2)

- Determined

from the ratio of molar concentration of sodium to molar

concentration of chloride.

The data

from both Units

1 and

Z showed

an improving trend over the last

5 years with respect to control of secondary

water chemistry.

The molar ratio

data

suggested

that alkaline crevice conditions

had been present in earlier

years of power operation.

Reduced

average

molar ratio values

were observed

by

the inspectors to have occurred in Cycle 6 (i.e., the cycle in which molar

ratio control was

implemented using

ammonium chloride injection).

The

inspectors

noted.

however. that the reduction in molar ratio values

appeared

to be related

more to reduction in blowdown sodium concentrations

than from

increases

in chloride content created

by ammonium chloride injection.

The

concurrent reductions

in blowdown sulfate concentrations

during the last two

-35-

operating cycles suggested

to the inspectors

that the improvements in blowdown

chemistry were primarily related to improvements

in condensate

polisher

operational

practices.

The inspectors additionally requested

available trend information for

feedwater iron content

from the licensee.

in order to gain

some understanding

of the amount of corrosion product transport to the steam generators.

Trend

data

from 1989 to the present for both units was furnished in response

by

chemistry staff.

The trend data.

which consisted

simply of connected

data

points,

showed high iron contents

were historically present

in the feedwater

in both units.

Although the data

format and scatter

impacted interpretations

the inspectors

concluded that feedwater iron concentrations

in both units were

typically in the range of 10-20 ppb through approximately the end of 1992,

with Unit

1 iron values

appearing slightly higher than those in Unit 2.

The

data for this period showed

an essentially stable condition, with no

noticeable

upward or downward trend in iron concentration.

Reduction in

feedwater iron concentrations

were noted by the inspectors

to have occurred

following the replacement of ammonia

by ethanolamine

for pH control in August

1993 (Unit 1) and March 1994 (Unit 2).

Recent

feedwater

iron concentrations

were typically in the 5-6 ppb range for Unit

1 and 6-7 ppb for Unit 2.

The

inspectors

also noted.

however. that Unit 2 feedwater iron concentrations

had

declined

as

low as the 3-4 ppb range

by Summer

1994 and then proceeded

to

trend

up to the current 6-7 ppb range.

Licensee

personnel

informed the

inspectors

that this was due.

in part, to ethanolamine

breaking

down to

organic acids at

a. faster rate in Unit 2,

and which resulted in higher steam

cation conductivity values in Unit 2 for a given ethanolamine

concentration.

A current limit for steam cation conductivity of 0.3 ymho/cm requi red by the

turbine warranty resulted in Unit 2 having to operate with feedwater

ethanolamine

concentrations

of 1.7

ppm versus 2.1-2.2

ppm in Unit 1.

The inspectors

requested

historical information from the licensee

regarding

the weight of sludge

removed by sludge lancing from each

during refueling outages.

The data provided by the licensee for the Units

1

and

are listed below in Tables

12 and

13.

The data

indicated to the inspectors

that total Unit

1 steam generator

sludge

removal

quantities during refueling outages

have typically been higher than the

amounts

removed from the Unit 2 steam generators.

Although historical

feedwater iron contents

appeared

to the inspectors to have

been slightly

higher in Unit

1 than Unit 2, the differences did not appear

to the inspectors

to be of a magnitude that would account for the sludge variance.

Overa'Il, the

data did not indicate to the inspectors that any clear trend was occurring in

either unit in sludge

removal

amounts.

The inspectors

also reviewed the sludge

removal

data with respect to the

Units

1 and

2 implementation

dates for injection of ethanolamine.

This review

was performed to ascertain

whether the reduction in feedwater iron content.

that was noted to have occurred after beginning

use of ethanolamine

~ was

reflected in reduced

sludge quantities.

Ethanolamine

was introduced into

Unit

1 in August 1993. approximately

7 months before Refueling Outage

1R6.

The inspectors

noted from review of the data in Table

12 that 492 and

-36-

654 pounds of sludge,

respectively.

were removed during Refueling Outages

1R6

and

1R7.

The values for sludge

removal

from the previous five refueling

outages

ranged

from 376 to 850 pounds,

with the mean

removal quantity

calculated to be 729 pounds.

A test

was conducted during Refueling Outage

1R7

which involved use of dimethylamine during wet layup of the steam generators.

The purpose of the test

was to evaluate

whether the dimethylamine would help

dissolve or loosen iron deposits

on steam generator

tubes.

The inspectors

did

not have specific information on the results of the test.

and so could not

assess

whether the dimethylamine

use contributed to an increase

in sludge

removed during lancing operations

in Refueling Outage

1R7 compared with the

previous refueling outage.

The inspectors

concluded that review of sludge

removal

data

from additional Unit

1 refueling outages

would be required before

a determination

could be made of the effects of ethanolamine

use

on sludge

accumulation.

Ethanolamine

was not introduced into Unit 2 until March 1994.

approximately

6 months before the last refueling outage (i.e.. Refueling

Outage

2R6).

The time frame of this change

precluded current assessment

of

the effects of ethanolamine

use.

The inspectors

also reviewed the results of chemical

analyses

that were

performed

on sludge

samples

-.hat had been

removed

from the Units

1 and

2 steam

generators

during each refueling outage through

1R6 and

2R6.

The most

significant feature of the analyses

noted

was the progressive

decrease

in

sludge copper content in successive

refueling outages (i.e.

~ the percent

copper

(as oxide) by weight declined in Unit

1 sludge

from 18. 1 in Refueling

Outage

1Rl to 0.9 in Refueling Outage

1R6,

and in Unit 2 sludge from 21.8 in

Refueling Outage

2Rl to 0.57 in Refueling Outage

2R6.

Progressive

reductions

in zinc and nickel contents

were also noted in the sludge

from both units

during successive

refueling outages.

The high original copper contents

in the

sludge were ascertained

to be related to the original use of copper alloys for

the feedwater heater tubes.

These tubes

were replaced with Type 439 stainless

steel

during the first refueling outage in each unit.

The zinc and nickel

quantities

were also believed to have originated

from feedwater heater

tubes,

in that the original tubing used

was cupronickel

and brass,

a copper-zinc

alloy.

The inspectors

were informed that the only remaining copper

alloys

were in condenser

tube sheets

and condensate

coolers.

Table

12

WEIGHT (LBS)

OF SLUDGE REMOVED FROM UNIT 1

STEAM GENERATORS

(SGs)

1Rl

1R2

UNIT 1 REFUELING OUTAGE (1R)

1R3"

1R4

1R5"'R6

1R7

276

286

211

68

226

151

161

1-2

234

154

262

98

241

84'

260

1-3

166

163

169

106

220

100

90.5

1-4

149

247

143

104

124

157

142.5

Total

825

850

785

376

811

492

654

-37-

(1)

- Sludge values

include sludge

removed

by pressure

pulse cleaning;

(2)

- Sludge

removed

by the CECIL process

versus

conventional

sludge lancing.

Table

13

HEIGHT (LBS)

OF SLUDGE

REMOVED FROM UNIT 2 STEAM GENERATORS

(SGs)

Unit 2 Refueling Outage

(2R)

2-1

2Rl

117

2R2r>>

135

2R3

40

2R4

2R5'R6

97.5

142"'-2

2-3

2-4

144

95

182

59

85

83

39

41

127

39

69

121.5

122.5

105

78.5

85

Total

~67

52:

177

237

420

473

(1)

- Sludge values

include siuaae

.emoved

by pressure

pulse cleaning:

(2)

- Sludge values

include sludge

removed

by bundle flushing.

Overalls

the inspectors

considered

that the chemistry history indicated that

the licensee

has significantly improved secondary

chemistry performance

in the

past

5 years. with the reductions

achieved

since

1993 in feedwater iron

concentrations

viewed as notable.

The current feedwater iron concentrations

were.

however.

viewed to be still of a magnitude that warranted continued

management

attention.

6.3

Self Assessment

of Mater Chemistr

Pro

ram

The inspectors

performed

a limited review of the licensee audit and

surveillance

history pertaining to the primary and secondary

water chemistry

control programs.

In review of the audit and surveillance findings. the

inspectors

observed

no findings which would bring into question the quality of

the water chemistry programs.

6.4

Chemistr

Laborator

Instrumentation

The inspectors

toured the secondary

water chemistry laboratory

and reviewed

the in-line process capabilities with licensee staff.

The inspectors verified

from the review that the necessary

instrumentation

was installed in the

process

lines or available in the laboratory. for analysis of the diagnostic

and control parameters

specified in the secondary

water chemistry control

program.

The inspectors

ascertained

that analog in-line instruments

were

originally used to monitor the

pH

~ conductivity.

sodium.

and oxygen content of

feedwater.

Recent instrumentation

upgrades

included

a complete upgrade of the

in-line instruments

in 1988 and

a condensate

polisher computer upgrade in

1993.

The in-line instrument

upgrade

provided improved sensitivity and

0

-38-

accuracy for monitored parameters

in the steam generator

blowdown, feedwater,

and condensate

systems (i.e.,

sodium and chloride monitoring improved from + 3

ppb to + 0.5 ppb with sensitivity to 5 ppt).

In 1992.

an on-line ion

chromatography

system

was installed.

This upgrade

enabled chemistry personnel

to monitor contaminants

to the parts per trillion level in the steam generator

blowdown, feedwater,

and condensate

systems.

6.5

Off-Normal Secondar

Chemistr

Histor

The inspectors

requested

licensee

personnel

to provide available

information

regarding significant out-of-specification conditions which have occurred

during commercial service.

The criteria used

by the inspectors

to define

significant were values which exceeded

Action Levels

2 and

3 limits in the

Electric Power Research

Institute secondary

water chemistry guidelines.

The

number of hours exceeding Action Levels

Z and

3 in each cycle for Units

1 and

Z are listed in Tables

14 and

15 below.

The inspectors

noted during review of

the data discussed

in Section 6.2 that minor out-of-specification conditions

were promptly corrected.

This was further illustrated by the relatively few

hours in which conditions in excess

of Action Levels

2 and

3 existed.

From

a

review of supporting information provided by the licensee.

the inspectors

noted that each unit has encountered

sea water intrusions

caused

by condenser

tube leaks which resulted in the pass

through of sodium and chloride ions to

the steam generators.

In addition. Unit 2 experienced

a resin intrusion event

in July 1993 which resulted in an increase

in sulfate concentration

in the

Table

14

UNIT 1 STEAN GENERATOR OFF-NORMAL SECONDARY WATER CHEHISTRY HISTORY

Cycle

Hours Exceeding

Level

2

Hours Exceeding

Level

3

CC(l)

13

SO

- (2)

Cl. "'a'"'0

CC(1)

Na1)

cation conductivity; (2)

blowdown

sulfate:

(3)

blowdown chloride:

(4)

blowdown sodium.

-39-

Table

15

UNIT 2 STEAM GENERATOR OFF-NORMAL SECONDARY WATER CHEMISTRY HISTORY

Cycle

Hours Exceeding

Level

2

Hours Exceeding

Level

3

CC(1)

48

SO

- (2)

Cl

(3)

Na "'C(l)

12

Na'"'6

(1)

- Steam generator cation conductivity: (2)

blowdown

sulfate:

(3)

blowdown chloride:

(4)

blowdown sodium.

7

INSERVICE INSPECTION-OBSERVATION OF

WORK AND WORK ACTIVITIES (73753)

The objective of this inspection

was to determine whether the inservice

inspection examinations

were performed in accordance

with Technical

Specifications,

The American Society of Mechanical

Engineers

(ASME) Boiler and

Pressure

Vessel

Code.

requirements

imposed

by

NRC and industry initiatives.

and correspondence

between the Office of Nuclear Reactor Regulation

and the

licensee

concerning relief requests.

This part of the inspection

and the

followup activities documented

in Section

8 of this report were performed

by a

single inspector during October 16-20,

1995.

7. 1

Inservice

Ins ection Pro ram

The licensee's

inspection

program incorporated the requirements

of the

1977

Edition of the

ASME Code through

and including the

Summer

1978 Addenda. with

the exception that

Code Class

1 and

2 pipe weld requirements

were determined

by the 1974 Edition through

Summer

1975 Addenda of the

ASME Section

XI Code.

This was the third inspection period of the first 10-year inservice inspection

program interval.

7.2

Personnel

ualifications and Certifications

The inservice inspection examinations

observed

were performed

by

nondestructive

examination

personnel

who were employed

and certified by the

licensee.

The inspector

reviewed the qualification files of the seven

individuals who performed the examinations

observed

during this inspection.

-40-

The files contained

the appropriate

examinations

and certifications for the

observed

nondestructive

examination

methods.

The records

showed that the

personnel

had been certified in accordance

with American Society for

Nondestructive

Testing

Recommended

Practice

SNT-TC-IA. 1980 Edition.

7.3

Personnel

ualifications

and Certifications Procedure

Discre anc

The inspector

reviewed Procedure

2. 1, "Qualifications and Certifications of

Personnel'

" Revision 7.

This procedure established

the requirements

for

nondestructive

examination

personnel

training and qualification. Table l.

"Training and Experience

Hinimum Levels," in Procedure

2. 1 identified the

minimum training hours that were applicable for each type of examination

and

qualification level.

The inspector

reviewed Procedure

ISI C-855.

"Inspection of Nondestructive

Examinations Activities." Revision 6.

Procedure

ISI C-855 stated.

that.

"This

procedure

assures

the

NDE work done by examination contractors

wi 11

be

properly controlled and monitored for conformance to Code and approved

procedures

and specifications

as required

by the

PG&E Quality Assurance

Program."

This procedure

also contained

an inservice inspection/

nondestructive

examination standard

inspection checklist which identified the

minimum training hours for each examination

type and qualification level.

These

requirements

pertained to contractors

who were certified under programs

other than the licensee's certification program.

The inspector

compared the minimum training hours listed in Procedure

2. 1 and

Procedure

ISI C-855 and noted

a difference in the requirements

between the two

procedures

for ultrasonic Level I minimum training hours.

Procedure

2. 1 had

identified 40 formal training hours

and Procedure

ISI C-855 noted

20 required

training hours.

The inspector questioned

licensee

representatives

concerning

this difference in procedural

required training hours.

The licensee

representatives

stated that Procedure

ISI C-855 was in error.

Action

Request

A0383185 was initiated and Procedure

ISI C-855 was revised to reflect

the required

40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />.

The licensee

representatives

stated that

a

transposition error occurred

when Procedure

ISI C-855 was revised in July

1984.

The licensee

representatives

indicated that the only known uses of the

inadequate

procedure for ultrasonic examination

personnel

was during

ultrasonic examination of the reactor vessel

in the first and thi rd

examination periods.

The licensee

representatives

also indicated that the

vendors

who performed the reactor pressure

vessel

examinations

had their

programs

audited

and approved

by the quality assurance

organization.

and were

on the nuclear qualified suppliers list.

Subsequent

to the end of the onsite

inspection,

licensee

personnel

reviewed the certification records for the

personnel

who had performed the reactor pressure

vessel

ultrasonic

examinations'nd

determined that all personnel

met the requirements of

SNT-TC-1A.

The inspector concluded that the failure of licensee

personnel

to identify the

procedural

error for 10 years

was

an indicator of inadequate

attention to

detail

when revising and using procedures.

-41-

7.4

Inservice

Ins ection Procedures

Review

The inspector

reviewed the nondestructive

examination

procedures

used during

the performance of the observed

examinations.

The procedures

reviewed

included the following:

~

Procedure

N-MT-1. "Magnetic Particle Examination." Revision 6:

~

Procedure

N-PT-1, "Liquid Penetrant

Examination." Revision 5A:

~

Procedure

N-UT-l. "Ultrasonic Examination Procedure

For Pipe Welds."

Revision 8:

~

Procedure

N-UT-4. "Ultrasonic Examination of Pressure

Vessel

Welds Other

Than Reactor Vessels."

Revision

3A:

~

Procedure

N-UT-8. "Automated Ultrasonic Data Acquisition and Analysis

Procedure."

Revision 4:

~

Procedure

ISI VT 2-1.

"Visual Examination During Section

XI System

Pressure

Test." Revision 4: and.

Procedure

ISI VT 3/4-1.

"Visual Examination of Component

and Piping

Supports."

Revision 8.

Based

on the review. the inspector concluded that the procedures

were

consistent with the requirements

of ASME Code

and had been

approved

by the

appropriate

licensee

personnel.

7.5

Observation of Nondestructive

Examinations

The inspector

observed

the nondestructive

examination personnel

perform

nondestructive

examination activities in the field.

These

observed

examinations

were conducted

using the liquid penetrant.

ultrasonic

(both

manual

and automated),

magnetic particle,

and visual examination

methods

on

Class

1, 2,

and

3 piping and components.

The inspector

noted that prior to

the examinations,

the examiners

performed inspections to verify correct weld

identification, surface cleanliness,

surface temperature,

and industrial

safety

and radiological conditions.

7.5. 1

Magnetic Particle Examinations

The inspector

observed

the performance

by nondestructive

examination personnel

of magnetic particle examinations

on the following system piping and

components:

Code Class

Line/Weld No.

Description

2

K15-225-28V

Hanger

No.

1028.

Feedwater

Line Attachment

Welds

2

556/WICG-92-4A

1-4 Feedwater

Supply Line

0

-42-

The inspector noted that nondestructive

examination

personnel

used

an

AC yoke

and appropriately verified that it was capable of lifting a 10-pound weight

prior to the examinations.

The inspector verified that approved color

contrast magnetic particles

were used

and nondestructive

examination personnel

verified magnetic flux lines

and pipe temperature prior to examinations.

The

inspector also verified that the examination results

were appropriately

documented

and reviewed in accordance

with procedures.

No recordable

indications were noted during the examinations.

7.5.2

Dye Penetrant

Examinations

The inspector

observed

the performance

by nondestructive

examination personnel

of a liquid penetrant

examination

on the following system piping weld:

Code Class

Line/Weld No.

Description

2

508/58N-52A

Integral Attachment

Weld to

Residual

Meat Removal

Line

The inspector

noted that the nondestructive

examiner performed

a thorough

inspection for weld identification. surface preparation.

cleanliness.

and

temperature prior to start of liquid penetrant

examinations.

Subsequent

to

the surface

inspections

the examiner applied approved cleaner to assure

the

surface

area

was clean prior to application of the penetrant fluid.

The

inspector noted that appropriate

dwell times were allowed for the liquid

cleaners

liquid penetrant'nd

developer in accordance

with the procedure.

No recordable

indications were noted by the examiner.

7.5.3

Ultrasonic Examinations

(Manual

and Automated)

The inspector

observed

the performance

by nondestructive

examination personnel

of manual

and automated ultrasonic examinations

using both shear

and

longitudinal wave forms on the following system piping welds:

Code Class

Line/Weld No.

Description

I

WIB-374SE

Pressurizer

Spray Line to Inlet Nozzle

I

Girth I

Pressurizer

Bottom Head to Shell

2

WICG-92-4A

1-4 Feedwater

Supply Line

The inspector noted that nondestructive

examination personnel

performing the

observed

examinations

adhered to procedural

requirements.

The inspector

noted

that the examiners

were very knowledgeable of the examination techniques

and

procedural

requirements.

During the manual ultrasonic inspection of the pressurizer

spray line to

inlet nozzle welds, the examiner noted

and documented

observed

geometric

indications.

The inspector did not observe this examination.

Based

on

evaluations

performed

by nondestructive

examination personnel,

the geometric

indications were attributed to thermal sleeve

attachment

welds

and were not

0

-43-

recordable.

However,

licensee

representatives

were aware of a previous

operational

event at another facility in 1993 where subsequent

to

nondestructive

examinations

during heatup

a leak was identified in the

pressurizer's

safe-end

near where

a pressure-operated

relief valve header

connected to the pressurizer.

Based

on that operational

event

and concerns

for cracks in nozzles

having similar configurations,

licensee

representatives

performed further examinations of the pressurizer

spray line to inlet nozzle

welds.

Ultrasonic examination

was performed using the licensee's

automated

ultrasonic examination

and data acquisition system.

The inspector

was

informed that the area to be examined

was indicating approximately

800 milli rem on contact.

However, the inspector

observed

the nondestructive

examination

personnel

display good ALARA practices while performing this

examination.

Based

on review and evaluation of the examination data taken

during the subsequent

examinations

nondestructive

examination personnel

concluded that the geometric indications identified with both the manual

and

automated ultrasonic examinations

were thermal

sleeve attach welds.

The inspector considered that the licensee's

inclusion of operational

experience

for inservice inspection efforts was commendable.

7.5.4

Visual Examinations

The inspector

observed nondestructive

examination personnel

perform visual

examinations

on the following welds

and system piping:

Code Class

Line/Weld No.

Description

ISI Test

58

Containment

Spray Discharge

Functional

Pressure

Test Visual Examination

Hanger

14-47SL

Component Cooling Water Line Snubber

Replacement

Preservice

Visual Inspection

During the containment

spray discharge

functional pressure test.

the inspector

noted that the line was pressured

to approximately

250 psi

and the pressure

maintained for approximately

20 minutes.

which was in excess of the minimum

time requirements

specified in the procedure.

No system

leakage

was

identified.

During the preservice visual examination for the component

cooling water line snubber

replacement.

the examiner noted that Hanger

14-47

had been mislabeled

as "14-74."

The nondestructive

examiner appropriately

documented this observation

on the visual examination report.

No other

problems

were identified.

The inspector noted that nondestructive

examination

personnel

who performed the observed visual examinations

displayed

a

questioning attitude

and attention to detail.

7.6

Safet

Assessment/

ualit

Verification

During the observed

examinations,

the inspector

noted that on several

occasions

the licensee inservice inspection supervisor

was observing

and

monitoring nondestructive

examination personnel.

The inspector also noted

that the inservice inspection supervisor

was cognizant of ongoing activities

0

-44-

and status of scheduled

examinations.

Based

on these observations.

the

inspector concluded that the inservice inspection supervisor

was actively

assuring the quality of examinations

and was performing effective oversight.

8

FOLLOMUP

-

HAINTENANCE

(92902)

8. 1

Closed

0 en Item 323/9307-08:

Fuel Handlin

Area Exhaust

Carbon Filter

Bank Test Failure

8.1.1

Original Open Item

This open item involved

a subsequent

review of the licensee's

corrective

action associated

with test failure of the charcoal filters in the ventilation

system.

The charcoal filters were tested prior to fuel movement during

Refueling Outage

2R5.

The results of the analysis,

which were received after

refueling activities

had begun.

concluded that the efficiency of the charcoal

was slightly below the Technical Specification requirement.

8. 1.2

Licensee Action

As part of the licensee's

corrective action.

the charcoal filter bank was

replaced.

Unit

1 and Unit 2 Procedures

STP 0-41.

"Fuel Handling Building

Ventilation System

-

DOP and Halide Penetration

Tests."

were revised to

caution that results of the test should

be received prior to moving fuel so

that adequate

time for filter replacement

was available.

8. 1.3

Inspector Action During the Present

Inspection

During this inspection.

the inspector verified that the Unit

1 Procedure,

STP H-41. Revision

13,

and the Unit 2 Procedure,

STP M-41. Revision

1,

included consideration for the receipt of the charcoal filter test results

prior to moving fuel.

In addition, the inspector verified that the charcoal

filter test results

had been received

and evaluated prior to moving .fuel in

the current Refueling Outage

1R7.

8.1. 4

Conclusions

Based

on the inspector's

review. it was concluded that Unit 1 and Unit 2

Procedures

STP H-41 had been appropriately revised

and that the charcoal

filter test results

had been received

and evaluated prior to moving fuel in

the current Refueling Outage

1R7.

-45-

8. 2

Closed

Violation 275 323/9425-01:

Inade uate Measures

For Control lin

Reactor Coolin

S stem Water

Leaka

e durin

Hachinin

0 erations

and

Failure to Initiate an Action Re uest for a Previous Simi1ar Occurrence

8.2.1

Original Violation

This violation involved a failure to provide documented

instructions

appropriate to the circumstances

for the resistance

temperature

detector

modification on Unit 2 that resulted in reactor coolant system water spilling

out of the Loop

1 hot leg during machining operations.

In addition, this

violation involved the failure to initiate an action request

during the

previous Refueling Outage

1R6,

when

a reactor coolant system water spill

occurred during the Unit 1 resistance

temperature

detector modification

project.

8.2.2

Licensee Action

Licensee representative

concluded that

a more thorough prejob planning process

could have prevented

the spill of contaminated

water.

As part of the

licensee's

corrective action.

a thermowell drain adapter

and discharge line

were installed to control reactor coolant system water leakage for the

remaining modifications project activities.

A case

study of this event

was

prepared for review by plant personnel

to heighten

awareness

of the need for

proper work planning

and the need to initiate problem identification

documentation.

Administrative Procedure

AD7.NC2,

"Conduct of Work," was

issued to provide specific guidance to plan for handling unanticipated

amounts

of water when

a fluid system is breached.

8.2.3

Inspector Action During the Present

Inspection

During this inspection.

the inspector

reviewed Procedure

AD7.NC2 and verified

that the procedure

addressed

planning for handling

an unanticipated

amount of

water during

a fluid system breach.

The inspector questioned

licensee

representatives

concerning

any water spills that might have occurred

subsequent

to these

two events.

Licensee representatives

indicated that none

have occurred.

8.2.4

Conclusions

Based

on review of Procedure

AD7.NC2 and the case

study prepared for this

event,

and the fact that no subsequent

water spills from fluid system

boundaries

have occurred.

the inspector concluded that the licensee's

corrective actions

were adequate.

ATTACHMENT

PERSONS

CONTACTED AND EXIT MEETING

1

PERSONS

CONTACTED

l. 1

Licensee

Personnel

D. Adamson,

Nondestructive

Examination Supervisor,

Technical

and Ecological

Services

~J. Arhar,

Engineer,

Turbine Support

Systems

S. Cortese.

Chemistry Engineer,

Chemistry

and Environmental Organization

R. Exner, Supervisor,

Turbine Support

Systems

W. Fujimoto. Vice President

and Plant Manager

"J. Gardner,

Senior

Chemistry Engineer,

Chemistry and Environmental

Organization

¹D. Gonzalez,

Inservice Inspection Supervisor.

Nuclear Steam System Supplier

System Engineering Services

- C. Harbor,

NRC Interface.

Regulatory Services

~A. Hardy. Quality Assurance

Engineer.

Nuclear Quality Services

C. Hartz. Quality Assurance

Engineer.

Nuclear Quality Services

J. Hays. Director, Chemistry and Environmental Organization.

Operations

Services

D. Helete.

Engineer.

Turbine Support

Systems

J. Kang. Nondestructive

Examination Engineer.

Technical

and Ecological

Services

¹T. McKnight. Quality Assurance

Supervisor.

Nuclear Quality 'Services

¹P.

Nugent, Senior Engineer,

Regulatory Services

¹G. Toison, Audit Team Leader.

Nuclear Quality Services

T. Polidoroff, Senior Engineer,

Nuclear Technical

Services

D. Taggart

~ Director, Nuclear Safety Engineering,

Nuclear Quality Services

¹D. Vosburg. Director. Nuclear Steam

System Supplier System Engineering

Services

¹J.

Young. Director, Quality Assurance,

Nuclear Quality Services

1.2

Contractor

Personnel

J.

Semelsberger,

Site Outage

Manager,