ML17310B388
| ML17310B388 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 06/22/1994 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML17310B387 | List: |
| References | |
| NUDOCS 9406280091 | |
| Download: ML17310B388 (12) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555 0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO THE OPERATION OF PALO VERDE NUCLEAR GENERATING STATION UNIT 2 FOLLOWING THE MID-CYCLE STEAM GENERATOR TUBE INSPECTION ARIZONA PUBLIC SERVICE COMPANY DOCKET NO. 50-529
1.0 BACKGROUND
AND INTRODUCTION Palo Verde Nuclear Generating Station (Palo Verde) Unit 2 has two Combustion Engineering (CE) System 80 steam generators.
The CE System 80 steam generators are recirculating U-tube steam generators which contain 11,012 high temperature mill-annealed Alloy 600 tubes with an outside diameter of 0.750 inch (19 mm) and a nominal tube wall thickness of 0.042 inch (1.07 mm).
In March 1993, a steam generator tube ruptured in Palo Verde Unit 2, Steam Generator No.
2 while the unit was at 98% power.
In response, the operators shut the reactor down (reactor trip) and entered the unit's emergency procedures to mitigate the event.
The tube ruptured about one week prior to a
scheduled refueling outage that would have ended a planned 15-month period of operation.
The rupture (about 2-inches long, axially oriented) occurred in a tube near the edge of the tube bundle, high in the tube in the free span between tube supports designated as "OBH" (the eighth tube support above the tube sheet on the hot leg side of the steam generator) and the "09H" support.
The licensee formed a special task force consisting of both licensee employees and outside industry experts to determine the root cause of the tube failure, to inspect the steam generator
- tubes, and to establish a basis for future operation.
Extensive eddy current inspections conducted during this outage (1993) identified an arc-shaped area of tubes in the upper elevation of the tube bundle with axial crack indications.
The licensee plugged a total of 74 tubes in SG 21, and 175 tubes in SG 22.
The licensee analyzed the inspection
- results, and proposed to operate Unit 2 for 6 months and then shut down to perform steam generator tube inspections.
The NRC staff reviewed the basis for the proposed operating period and issued a safety evaluation addressing plant startup and cycle length.
The staff concluded in the August 19, 1993, safety evaluation that operation of Palo Verde Unit 2 for the proposed operating interval of 6 months would not pose an undue risk to the public health and safety.
This conclusion was based on the numerous licensee actions to address the root cause of the Unit 2 SGTR event to minimize the potential for future SGTR events, actions taken to enhance primary-to-secondary leakage monitoring to provide early indication of tube degradation, improvements in emergency operating procedures for SGTR 9406280091 940622 PDR ADOCK 05000529 PDR
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- events, and the reduction in the variable overpower trip setpoint and limits on primary coolant activity to limit potential consequences should an SGTR occur.
- Further, the evaluation summarized that while uncertainty exists in estimating the structural integrity of the steam generator tubes toward the end of the proposed 6-month operating period, the risk evaluation confirmed that the potential risk to the public was small.
2.0 CYCLE 5 OPERATION Unit 2 operated for approximately 4q months (at approximately 85-percent power) prior to the licensee electing to shutdown the Unit for a mid-cycle steam generator inspection and chemical cleaning on January 8,
1994.
Since the licensee concluded that the secondary corrosion attack within the arc region of the Unit 2 SGs was caustic-induced intergranular stress corrosion cracking (IGSCC), mitigating actions were focused on secondary water chemistry control and the elimination of dryout conditions.
The licensee maintained feedwater hydrazine concentration at levels greater than 100 ppb to promote a
reduction in the electrochemical potential.
The molar ratio (sodium to chloride) was controlled at levels considerably lower than those maintained prior to the tube rupture event.
Secondary system pH was increased to approximately 9.8, and the average feedwater iron concentration was reduced to levels consistent with the latest EPRI water chemistry guidelines.
The licensee has also improved their resin intrusion control (suspected of contributing to previous Unit 2 tube degradation),
begun controlling chemistry by sampling from the steam generator downcomer (utilizing the increased concentration factor to reduce sampling error),
and scheduled Unit downpowers to optimize crevice contaminant removal.
Additionally, leakage monitoring enhancements (both procedural and equipment design) have been implemented.
An N-16 monitoring system has been installed in all units.
Steam generator blowdown monitors now monitor the downcomer flow, thereby providing a greater sensitivity to leakage.
The condenser vacuum exhaust monitor alarm setpoints were reduced to provide an earlier indication of leakage.
- Also, a formalized process (with escalating actions) has been in place for managing leakage.
For example, a formal evaluation for continued operation is conducted if a 10 gallon-per-day leak increases by 50-percent or a stable leakrate of 25 gpd is reached.
A plant shutdown is initiated at 50 gpd.
Prior to the mid-cycle outage
- shutdown, a small amount of tritium was detected in the SG (tritium is used to monitor for primary to secondary leakage).
During the outage a small leak was identified in a welded tube plug.
During a discussion with the licensee on April 22, 1994 (following a month of operation after startup from the outage),
the licensee indicated that tritium is currently below detection levels.
3.0 EDDY CURRENT TESTING INSPECTION During the inservice inspection of the steam generator tubing, the licensee identified and characterized various forms of steam generator tube degradation by eddy current testing.
The eddy current examination involved the use of two different types of eddy current test probes:
a bobbin coil probe and a
motorized rotating pancake coil (HRPC) probe.
The bobbin coil probe was used
to examine lOON of the bobbin arc area (approximately 4000 tubes) and a
"checkerboard" sample of approximately 400 tubes throughout the bundle, in both steam generators.
The HRPC probe, which provides better detection/
characterization capability, was used to examine approximately 1800 tubes in the HRPC arc (from the 08H to first vertical support),
and for a 20-percent sample of the hotleg tubesheet (approximately 2200 tubes).
The NRC staff reviewed the inspection scope prior to the outage and discussed the order of chemical cleaning and eddy current testing with the licensee.
The staff was concerned that the licensee adequately sample the steam generators following the scheduled chemical
- cleaning, in order to characterize whether a detectability shift had occurred (e.g.,
as evidenced by tube degradation readings being more prevalent post-chemical cleaning as a result of deposit material being removed from the tubes).
The licensee submitted an examination plan by letter dated January 27, 1994, that addressed the staff's concerns.
The plan included reexamining (post-chemical cleaning) tubes that had axial indications detected prior to the cleaning.
- Also, a reexamination of a number of tubes with pre-chemical cleaning deposits in the arc area were to be performed.
The licensee modified the original inspection scope several times during the outage.
These expansions were based on circumferential indications at the tubesheet, bobbin arc axial indications, and the effects of the chemical cleaning.
Due to the detection of four circumferential indications in the sludge pile area of SG 22, 100 percent of the hotleg tubesheet area was inspected.
Prior to chemical
- cleaning, several axial indications were detected in the bobbin arc area.
Accordingly, approximately 980 tubes in SG 21 and 1000 tubes in SG 22 were added to the inspection scope (so that all indications were bounded by a 5-tube buffer area).
The final area of expansion of the eddy current inspection scope was based on an evaluation of indications following chemical cleaning.
The results varied in each steam generator, as presented below.
SG 21 No evidence of detectabilit shift The eddy current inspection was interrupted for chemical cleaning of this steam generator.
Approximately 500 additional tubes were examined after chemical
- cleaning, and 11 tubes with axial indications were identified in this sample.
Eleven axial indications that had originally been detected before chemical cleaning were reexamined.
No significant change was identified.
Sixty-two tubes with deposits were reexamined.
No new axial indications were identified.
One hundred and eight additional tubes were inspected in a random pattern.
No evidence of change was identified.
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Axial indications found during this outage were compared with those found in the previous outage.
The distribution of axial indications on each side of SG 21 was reviewed and noted to be similar to the 1993 outage distribution.
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Twenty-two tubes had axial indications.
Thirty-eight tubes were plugged.
SG 22 Evidence of detectabilit shift
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Essentially all of the HRPC arc area eddy current inspection was completed before this steam generator was chemically cleaned.
Based on the initial post-cleaning inspections, the HRPC arc inspections were reperformed, identifying approximately 222 additional tubes with axial indications.
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Eighty-six axial indications (originally detected prior to chemical cleaning) were reexamined.
A significant change had occurred in a number of the indications, and approximately 32 additional indications were identified in those tubes.
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Sixty-two tubes with deposits were reexamined, and six of the tubes were identified as having axial indications.
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Additionally, several of the pre-chemical-cleaning axial indications appeared larger post-cleaning.
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Axial indications were not compared with the results of the last inspection because the entire arc area was reexamined.
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Three hundred and eight tubes had axial indications.
Three hundred and seventy-one tubes were plugged.
The vast majority of the axial indications referenced above were observed between the 08H support and the first vertical strap on the hot leg side.
The only axial indications found below the 07H support were three axial indications at 01H.
The staff concludes that the HRPC inspections performed within the arc region and the bobbin coil and random HRPC inspections outside the arc region provide reasonable assurance that the structurally significant cracks have been identified and subsequently repaired (i.e., plugged).
4.0 CURRENT OPERATING INTERVAL Prior to plant restart, at a meeting on Harch 15, 1994, the licensee provided their justification for a 6-month operating interval.
The proposed 6-month operating interval is based on consideration of the following input parameters:
the depth of cracks remaining in service at the time of plant restart (i.e., cracks which are below the detection threshold of eddy current
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testing),
crack growth rates, and the maximum crack size which will satisfy the limiting burst pressure criterion in Regulatory Guide
- 1. 121;
,The licensee stated that no indications identified during the mid-cycle outage would challenge RG 1. 121 limits.
Axial crack indications were, for the most part, too small to size with bobbin coil inspection.
Four axial defects in SG 22 were sized.
Two of these defects were less than or equal to.25 inch.
The other two defects (1.04 and 2.21 inches) were longer than the minimum length for which RG 1.121 calculations indicate that a through-wall defect could still maintain required structural safety margins.
However both of these defects maintained at least a 13-percent depth margin to the RG 1. 121 limit calculated by the licensee.
The licensee has stated that the bobbin depths readings are conservative, since pulled tube examinations from the previous refueling outage demonstrated that the bobbin coil consistently overcalled the average crack depth.
Regarding other-type indications, the largest wear defect had a depth of 52 percent (measured by bobbin coil), which the licensee states is well below the allowable for wear-type defects as calculated in their RG 1. 121 analysis.
Additionally, the longest of the circumferential indications was
.35 inches circumferential.
The licensee compared this result to the bounding Unit 1
calculation (where a 100-percent through-wall defect, 1.6 inches long, was calculated as maintaining structural margin) and stated that acceptable margin is maintained.
The licensee attempted to select the largest defects for in-situ testing (by developing a method for assessing the depth of the defect using the MRPC signal).
Nine tubes (two in SG 21, seven in SG 22) were successfully pressurized to 4260 psia, indicating that r equired safety margins against bursting were maintained.
Additionally, all nine tubes were subsequently reexamined by HRPC to verify that there was no change in the eddy current signals.
These tubes were subsequently plugged.
The licensee removed a portion of 21 tubes from the hotleg bend region (above the 09H tube support) of SG 22 in order to gain additional information pertaining to eddy current detectability issues.
Laboratory nondestructive and destructive analyses will be performed on the tube sections to support SG tube integrity analyses.
This information will be used by the licensee as it completes its statistical and deterministic analyses in support of better defining an appropriate cycle length.
In support of restart from the mid-cycle outage, the licensee completed a
preliminary analysis using the apparent crack growth rate observed over the last operating interval.
The licensee has stated that preliminary data indicates an operating interval of 10 months is justified.
However, the licensee conservatively requested a 6-month operating interval while the final analyses were completed.
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5.0 CONCLUSION
The staff approves the 6-month interval based on the inspection results as presented in the licensee's Harch 8,
- 1994, SG inspection report, the above evaluation, and the bounding evaluation performed by the staff in the safety evaluation dated August 19, 1993 (this evaluation, issued for the restart of Unit 2 after the SG tube rupture, documented the staff's concerns regarding the substantial uncertainties in SG tube crack initiation times and crack growth rates).
Principal contributors:
B. Holian K. Karwoski Date:
June 22, 1994
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