UNITED STATES

NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

WASHINGTON, D.C. 20555

August 28, 2003

NRC INFORMATION NOTICE 2003-13: STEAM GENERATOR TUBE DEGRADATION AT

DIABLO CANYON

Addressees

All holders of operating licenses for pressurized-water reactors (PWRs), except those who have

permanently ceased operations and have certified that fuel has been permanently removed

from the reactor.

Purpose

The U.S. Nuclear Regulatory Commission is issuing this information notice to inform

addressees about findings from a recent steam generator tube inspection at the Diablo Canyon

Power Plant, Unit 2 (DCPP-2). The NRC anticipates that recipients will review the information

for applicability to their facilities and consider taking actions, as appropriate, to avoid similar

problems. However, no specific action or written response is required.

Description of Circumstances

DCPP-2 has four Westinghouse model 51 steam generators (SGs), with 7/8 inch outside

diameter (OD), mill-annealed Alloy 600 tubing and drilled hole carbon steel tube support plates. 

The model 51 steam generator has 45 rows of tubes, with row 1 having the smallest bend radii

in the U-bend area. 

During Operating Cycle 11, a small steam generator tube leak (less than or equal to

approximately 6.5 gallons per day) was present at DCPP-2. During the 2003 refueling outage,

Pacific Gas & Electric (PG&E), the licensee for DCPP-2, performed SG secondary side

pressure tests to locate the source of the SG leakage. Several potentially leaking SG tubes

were identified and subsequent eddy current testing identified two contributing degradation

modes: circumferential primary water stress corrosion cracking (PWSCC) in the U-bend region

and axial outside diameter stress corrosion cracking (ODSCC) at the tube-to-tube support plate

intersections.

Circumferential Indications

The licensee inspected the U-bend region of all of the active tubes in all four SGs with a

rotating eddy current probe after finding leaking circumferential flaws in the U-bend region of a

row 5 tube and identifying other circumferential indications in the U-bend region of other high

row (above row 3) tubes during the initial examinations. In all, 12 tubes in rows 3 through 10

were identified with circumferential indications in the U-bend region. The indications were

short, about 0.25 inch long. They were on the tube flank and originated from the inside of the

ML032410215
IN 2003-13

Page 2 of 4

tube. PG&E concluded that PWSCC was the most probable cause of cracking based on the

susceptibility of mill-annealed Alloy 600 tubing, the residual stresses from bending the tubes,

and the exposure of the tubes to primary coolant. It was not practical to remove one of these

flawed tubes for destructive analysis because of the tubes’ location in the SG. All tubes with

circumferential indications in the U-bend region were pressure-tested in situ and met the

structural integrity performance criteria. The estimated potential for accident induced leakage

from these tubes when combined with estimated potential for accident induced leakage from

other tubes in the SG did not exceed the accident leakage integrity performance criteria.

Axial ODSCC

All of the axial ODSCC indications identified in the potentially leaking tubes had been detected

during the previous SG tube inspection. The tubes were left in service in accordance with the

voltage-based alternate repair criteria (ARC) discussed in Generic Letter (GL) 95-05, “VoltageBased Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter

Stress Corrosion Cracking,” and the plant’s technical specifications. During subsequent bobbin

coil inspections of the SG tubes during the 2003 refueling outage, the licensee detected an

unexpected number of large bobbin voltage indications (i.e., greater than 3 volts), including one

indication which had a substantially larger voltage than any other indication. This indication

measured 21.5 volts. The licensee investigated the cause of the 21.5 volt indication and the

cause of the unexpected number of high voltage (>3 volts) indications.

The licensee found that the tube with the 21.5 volt indication had been previously identified with

a 2 volt indication during the 2001 refueling outage. The tube was left in service at that time

since the bobbin voltage (2 volts) met the plant’s technical specification repair criteria for

remaining in service. PG&E had also inspected the indication with a rotating eddy current

probe during the 2001 outage and the 2003 outage. During the root cause investigation in

2003, PG&E used the rotating probe eddy current data to estimate the length and depth of the

flaw for both outages. The licensee estimated that the flaw was nearly through wall at the time

of the 2001 refueling outage and that the flaw fully penetrated the tube wall during the ensuing

operating cycle. This through wall penetration occurred over a significant portion of the crack

length. Industry data shows that flaw voltage response increases sharply upon initial through

wall penetration and with subsequent lengthwise growth of the through wall component. Thus,

the licensee concluded that the large increase in voltage observed for this indication over the

operating cycle was the result of the crack penetrating entirely through wall over a significant

length rather than being the result of a significant increase in growth rate of the physical

dimensions of the flaw.

The licensee partly attributed the unexpected number of large voltage indications (other than

the 21.5 volt indication) to the voltage growth rate distribution used in earlier projections. These

earlier projections were based on the industry methodology outlined in the EPRI report “Steam

Generator Tubing Outside Diameter Stress Corrosion Cracking at Tube Support Plates

Database for Alternate Repair Limits.” The methodology described in the EPRI report

recognizes that voltage growth rates can be higher for indications with larger initial voltages. To

determine the growth rate distribution, the growth rate data is binned based on this initial

voltage. The industry methodology specifies that each bin (i.e., range of initial voltages) should

have a certain number of growth rate data points. To satisfy this minimum number-of-datapoints requirement, the licensee expanded the range of the highest growth rate bin to include
IN 2003-13

Page 3 of 4

the growth rates for indications with lower initial voltages. This reduced the probability that a 

large growth rate would be selected for indications in the upper voltage bin and resulted in

nonconservative projections of the bobbin voltage.

The licensee pulled two tubes with axial ODSCC indications for destructive examination: the

tube with the largest axial ODSCC flaw voltage and a tube with a large voltage axial ODSCC

flaw. The laboratory burst and leakage test results indicated that both tubes had adequate

integrity.

Discussion

DCPP-2 identified two steam generator tube issues during the 2003 refueling outage: 

circumferential indications in the U-bend region out to row 10, and large, increases in bobbin

voltage associated with axial ODSCC at the tube-to-tube support plate intersections.

Historically, industry practice has been to inspect the U-bend region of low row tubes for

indications of circumferential cracking and to expand the inspection to higher row tubes based

on the results. This practice was developed based on the understanding that the low row tubes

have higher residual stress levels in the U-bend region due to the tighter bend radii than the Ubend region of higher row tubes. The higher residual stress level makes the U-bend region of

low row tubes more susceptialble to cracking. Prior to the experience at Diable Canyon,

operating experience from steam generator inspections has validated this approach. The

experience from DCPP-2 suggests that the U-bend region of higher row tubes may have a

similar susceptibility to cracking in the U-bend region as the U-bend region of lower row tubes.

PG&E’s experience with axial ODSCC indications yields two insights. First, collection and

further evaluation of rotating probe inspection data from axial ODSCC indications may help

identify indications that could be prone to significant bobbin voltage growth. Second, when

developing voltage-dependent growth rates through the use of generic industry guidance or

other methodologies, it is important that the methodology result in conservative growth rates.

The previously described examples of SG tube degradation illustrates the need for maintaining

robust steam generator inspection programs. An effective program should sample for

degradation based on both operating experience and engineering assessments of potentially

susceptible locations and should be able to conservatively predict degradation growth.

Related Generic Communications

The following documents describe other recent reactor operating experience with steam

generator tubes:

IN 2003-05, “Failure to Detect Freespan Cracks in PWR Steam Generator Tubes,” dated

June 5, 2003

IN 2002-02 and IN 2002-02 supplement 1, “Recent Experience With Plugged Steam

Generator Tubes” dated January 8, 2002 and July, 17, 2002

IN 2002-21, “Axial Outside-Diameter Cracking Affecting Thermally Treated Alloy 600

Steam Generator Tubing” dated June 25, 2002
IN 2003-13

Page 4 of 4

IN 2001-16, “Recent Foreign and Domestic Experience with Degradation of Steam

Generator Tubes and Internals,” dated October 31, 2001

NRC Generic Letter 97-05, “Steam Generator Tube Inspection Techniques,” dated

December 17, 1997

Inspection Report 50-323/03-09, “Diablo Canyon Power Plant - NRC Special Team Inspection

Report” dated May 8, 2003 (Adams ML031290198)

This information notice does not require any specific action or written response. If you have

any questions about the information in this notice, please contact one of the technical contacts

listed below or the appropriate project manager in the NRC’s Office of Nuclear Reactor

Regulation (NRR).

/RA/

William D. Beckner, Branch Chief

Reactor Operations Branch

Division of Inspection Program Management

Office of Nuclear Reactor Regulation

Technical contacts: Martin Murphy, NRR Jerry Dozier, NRR

301-415-3138 301-415-1014

E-mail: mcm2@nrc.gov E-mail: jxd@nrc.gov

Attachment: List of Recently Issued NRC Information Notices