IR 05000285/1993022
| ML20058M093 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 11/30/1993 |
| From: | Howell A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20058M083 | List: |
| References | |
| 50-285-93-22, NUDOCS 9312200147 | |
| Download: ML20058M093 (26) | |
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- I APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report:
50-285/93-22
License: DPR-40
Licensee: Omaha Public Power District Fort Calhoun Station FC-2-4 Adm.
P.O. Box 399, Hwy. 75 - North of Fort Calhoun
Fort Calhoun, Nebraska Facility Name:
Fort Calhoun Station Inspection At:
Blair, Nebraska i
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Inspection Conducted: October 4-8, October 18-22, and November 1-5, 1993
~I Inspectors:
I. Barnes, Technical Assistant Division of Reactor Safety
V. Gaddy, Reactor Inspector
Maintenance Section
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Division of Reactor Safety L. Gilbert, Reactor Inspector Maintenance Section Division of Reactor Safety i
C. Johnson, Reactor Inspector Maintenance Section Division of Reactor Safety
Accompanying Personnel:
J. Pate, Consultant Oak Ridge ional Laboratory l
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8-h"91 Approved:
Arthur T/ Rowell, Deputy Director Date Division %f Reactor Safety
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Inspection Summary Areas Inspected:
Regional initiative, announced inspection to review the
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history and material condition of steam generator tubing and.to assess the i
effectiveness of licensee programs in detection and analysis of degraded
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tubing, repair of defects, and correction of conditions contributing to tube
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9312200147 931201 PDR ADDCK 05000285 G
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degradation. The inspection additionally included observation of inservice
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inspection work and work activities.
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Results1
Fort Calhoun Station has used a hot-leg temperature range of.575"F to
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596*F since commercial operation began in 1973, with the predominant hot l
leg temperature in the last 10 years being 593*F. The inspectors noted that this temperature was one of the lower values used by pressurized water reactors (Section 2.1).
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The percentage of tubes plugged in each steam generator after 13.57
effective full power years of operation was 1.1, with 0.6 percent being
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plugged as. a result of service degradation (Section 2.4).
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A tube rupture occurred in Steam Generator B at. the first hot leg
vertical support in May 1984, which was determined to have been caused
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by intergranular stress corrosion cracking (Section 2.4).
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No further evidence of intergranular stress corrosion cracking or l
progression of tube denting has been found since boric acid treatment of
the secondary side of the steam generators was initiated subsequent to
Refueling Outage 9 in 1985. Only one tube has been determined by eddy
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current examination to require plugging since the 1985' outage
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(Section 2.4).
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Visual inspection of SMam Generator A during Refueling Outage 13 (1992 i
appeared to have been well performed for the documented inspection i
scope, with the results indicating that the overall condition.of. the j
steam generator was good (Section 3.1).
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Current foreign material exclusion controls were considered
satisfactory. The effectiveness of the controls during performance of secondary side work activities in the steam generators during Refueling Outages 13 and 14 (1993) could not be assessed due to the non-retention of control logs (Section 3.2)..
Eddy current sample sizes consistent with current Electric Power
Research Institute (EPRI) recommendations have been examined by the-bobbin coil method since Refueling Outage 9 in.1985 (Section 4.1).
Motorized rotating pancake coil eddy current examinations were performed
in response to Information Notice 90-49 on a 20 percent sample of hot leg side tube expansion transition areas during Refueling Outages 13 and 14. No evidence of defects was noted during these examinations (Section 4.1).
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f The data interpretation guidelines were viewed as a strength.
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specific training and testing of analysts was implemented during
Refueling Outage 14 by the licensee's contractor (Section 4.2.1).
The absence of independent technical oversight by the licensee of the i
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eddy current examination program was considered a weakness (Section 4.2.3).
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Since commercial operation of Fort Calhoun Station, the secondary water
chemistry program requirements have been progressively upgraded to incorporate industry guidelines as they were made available. The
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current program requirements were comprehensive and reflected the most recent EPRI information (Section 5.1).
Review of analytical data indicated that impurity values were generally j
well within procedural limits. The review of'overall historical chemistry performance was impacted, however, by the-absence of any chemistry records prior to 1983 and by only limited trend information being available (Section 5.2).
Sludge removal quantity and copper / iron ratio trends indicated
progressive improvement in secondary water chemistry controls (Section 5.2).
Improvements have been made to the insarvice inspection program which
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have facilitated overall planning and control of examination activities
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(Section 6.1).
l Contractor non-destructive examination personnel were found to be
appropriately qualified and performing examinations in accordance_with
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procedural requirements (Sections 6.2, 6.3).
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The inservice inspection program was being effectively implemented, and
l management attention was evident (Section 6.3).
Replacement of internal parts for Valve HCV-443 was performed by a
l qualified craftsman. However, the relevant work instructions did not clearly identify all work to be performed. (Section 6.4).
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Summarv of Inspection Findinas:
No inspection findings were opened or closed.
- Attachments:
Attachment 1 - Persons Contacted and Exit Meeting
Attachment 2 - Documents Reviewed During. Inservice Inspection
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-4-DETAILS 1 STEAM GENERATOR TUBE INTEGRITY REVIEW (73755, 79501, 79502)
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The objectives of this inspection were:
(a) to ascertain the history and material condition of the unit steam generator tubing; and (b) to assess the
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effectiveness of licensee programs for detection and analysis of degraded tubing, repair of defects, and correction of conditions' contributing to tube degradation.
2 STEAM GENERATOR MATERIALS AND TUBE DEGRADATION HISTORY 2.1 Steam Generator Description
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Fort Calhoun Station (FCS) is a Combustion Engineering (CE)-designed 1500
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megawatt thermal pressurized water reactor, which commenced commercial
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operation in September 1973. The plant design was unique to FCS and utilized two vertical U-tube recirculating steam generators.
Both steam generators
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contained 5005 Inconel 600 (ASME Material Specification SB-163) U-tubes with a nominal diameter and wall thickness, respectively, of 0.75 inches and 0.048 inches. The steam generator U-tubes were supported by eight horizontal supports (at intervals of 3 feet or less along the tube length) and five strap i
supports (two batwings and three vertical _ supports) for the horizontal run of
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the tubing. The first six horizontal supports above the tube sheet-(i.e., the
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forging used to support the U-tubes) were full supports and utilized an eggerate type design. An unusual feature noted by.the inspectors with respect i
to the horizontal full supports, was that each eggerate type support actually
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contained two small drilled plate segments. The licensee did not have any
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information regarding the reasons for incorporating segments of drilled plate
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into the eggerate type supports. The seventh horizontal support was a partial
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l support and was a composite of both eggerate and drilled plate construction.
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The eighth huizontal support was also a partial support and consisted only of drilled plate. The materials used for fabrication of the steam generator vessels and internals (including supports) were, respectively, low alloy and
carbon steels.
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l The inspectors ascertained that a steam generator primary side inlet hot leg
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temperature of 593*F was currently being used in unit operation. Historical-
information provided by the licensee showed that the hot leg temperature value that had been used over the operational life of the plant varied from 575*F to 596*F.
Values of 575*F and-582 F were used in the. initial years of plant l
operation, with the predominant hot leg temperature in the last 10 years being
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j 593*F. The inspectors noted that, based on available Electric Power Research.
i Institute (EPRI) information, the FCS hot leg temperature was one of the lower
values used by pressurized water reactors. The inspectors also noted that reduction of hot leg temperature is being pursued by other individual licensees as an approach to limit initiation and propagation of stress corrosion cracking.
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-5-2.2 Tubino Material The inspectors reviewed the technical requirements for the FCS steam generator tubing material contained in CE Purchase Specification P4382(b), " Purchase Order for Nickel-Chromium-Iron Alloy Tubular Products," dated November 29, 1966, and CE Purchase Order 46-77000 dated December 20, 1966.
It was noted from the review that ASME Material Specification SB-163 and Code Case 1336 were invoked for the procurement.
The test requirements for the tubing included a hydrostatic test at 3150 psig, ultrasonic examination, and eddy current examination.
Prohibitions were imposed on the tubing manufacturer in regard to using sulfur-bearing compounds and low-melting point elements in the manufacturing process.
In reviewing the purchase order and purchase specification, the inspectors noted that neither document specified the annealing temperature to be used for the ASME SB-163 (Inconel 600) tubes. The certified material test
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reports (CMTRs) furnished by the tubing manufacturer also did not indicate the actual annealing temperature used. The inspectors noted, however, from review of the CMTR mechanical properties that the results generally indicated that a high annealing temperature had been used.
The reported 0.2 percent yield strength and tensile strength values ranged, respectively, from 36,000 psi to 50,000 psi and 90,000 psi to 101,000 psi. ASME Material Specification 58-163 specified a minimum 0.2 percent yield and tensile strengths of 35,000 psi and 80,000 psi for Inconel 600, respectively.
During the CMTR review, the inspectors noted a discrepancy with respect to the hydrostatic testing of one heat (50 pieces) of tubes. The CMTR identified that these tubes had been hydrostatically tested at 4030 psig for 10 minutes, although the procurement requirement was 3150 psig for 5 minutes. The inspectors questioned the licensee regarding this anomaly. The licensee determined from ABB Combustion Engineering (ABB-CE) that the documentation submittal was in error and that the heat of tubing in question had not been utilized in the FCS steam generators. Tne inspectors did not pursue the matter any further, in that use of a hydrostatic test pressure of 4030 psig did not appear to pose a technical concern.
2.3 Tube-to-Tube Sheet Exoansion The inspectors reviewed CE Procedures FAB-9287-1-0, " Expanding Steam Generator Tubes Into Tubesheets," dated April 23, 1969, and FAB-9287-ti-0, "One-Step Seal
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Rolling Procedure for Steam Generator Tubes in Tubesheets," also dated April 23, 1969. The inspectors ascertained from this review that the fabrication sequence consisted of initially performing the tube-to-tube sheet welds on the clad primary side of the tube sheet.
Verification of weld quality was accomplished by use of liquid penetrant examination. The tubes were then i
explosively expanded into the tube sheet over its full height by use of detonating cords. The inspectors noted that Procedure FAB 9287-1-0 did not include any requirements for inspection verification that the expansion process had been satisfactorily accomplished.
In response to a question from the NRC inspectors, the licensee ascertained from ABB-CE representatives that
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-6-Procedure FAB-9287-6-0 was used for rolling a 2-inch length at the ends of the U-tubes subsequent to explosive expansion.
2.4 Steam Generator Tube Deoradation History Prior to operational service, Steam Generators A and B contained, respectively, 24 and 25 plugged tubes.
Twenty-four of these tubes in each steam generator were plugged as part of a field modification to reduce primary i
flow in tubes in the steam blanket region. The modification consisted of the attachment on the hot leg side of the steam generators of a 0.75 inch Inconel
orifice plate. Table 1 provides the plugging history for the two steam generators as a function of effective full power years (EFPYs) at the time of repair.
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Table 1 Time of Repair Operational Steam Generator A Steam Generator B Refueling Time (EFPYs)
Outaan (RFO)
Tubes Plugged Tubes Plugged Preservice
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REO 4 (1978)
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REO 8 (1984)
6.78
12 REO 9 (1985)
7.91
17 RE0 14 (1993)
13.57
1 l] Total Repairs
55 Initial evidence of tube denting was identified by single frequency bobbin coil eddy current examination of Steam Generator A tubes during Refueling Outage (REO) 4 in 1978. Three tubes were plugged as a precautionary measure, although measured to have degradation less than the Technical Specification 40 percent through-wall plugging criteria (i.e., one tube 38 percent through wall, two tubes less than 20 percent through wall).
It was subsequently discovered in 1984 that the cold leg side of an adjacent tube to that containing the 38 percent through-wall indication had been plugged during RE0 4, rather than the cold leg side of the degraded tube. The open ends of these two tubes were plugged in 1984.
Bobbin coil examinations performed during RE0 6 (1981) and RE0 7 (1982) using multi-frequencies showed further evidence of dent-like indications in both steam generator l
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-7-l In February 1984, approximately 3 weeks prior to the scheduled start of RE0 8, l
a small primary to secondary leak (i.e., approximately 0.2 gallons per day)
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Helium mass spectroscopy tests were performed during RE0 8 and were unsuccessful in locating the leaking tube. A hydrostatic test using a dye indicator was also unsuccessful in detecting the source of the leak. Additional evidence of denting in both steam generators I
was identified by eddy current examinations during REO 8, with the indications
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being primarily located at the eighth partial drilled support plates and in the vertical support region.
Four tubes in Steam Generator A and five tubes in Steam Generator B were plugged during RE0 8, as a result of denting having progressed to a point of restricting passage of a 0.540-inch eddy current probe (i.e., a CE recommended plugging criteria).
Following evaluation of the j
eddy current data, a decision was made to perform a rim cut modification on the eighth partial drilled support plates. One additional tube required plugging in Steam Generator A because of damage that occurred during performance of this modification.
l During plant startup from RE0 8 in May 1984, a tube failure occurred at
approximately 1800 psia in Steam Generator B, with reactor coolant system leakage approaching 110 gallons per minute. The failure was subsequently established to have occurred in Tube L29R84 in the vicinity of the first vertical support on the hot leg side of the steam generator. Sections of the tube were removed for CE laboratory examination. Visual examination of the removed tube sections by CE personnel revealed the presence of a 1%-inch axial " fishmouth" through-wall crack, which was present at the 6 o' clock
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position on the tube and was located between the first vertical support (hot-leg)
scallop bars. Laboratory examination showed that the tube was significantly ovalized at the fracture location. The tube diameter increased approximately 46 to 122 mils in the plane of the fracture, and was reduced by i
45 to 70 mils at 90 degrees from the fracture.
Examination of the fracture surface showed that approximately 95 percent of the wall thickness exhibited a distinct intergranular appearance. About 5 percent of the wall thickness at the inner diameter surface exhibited evidence of ductile tearing.
Metallographic examination confirmed
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initiated intergranular stress corrosion cracking (IGSCC). The chemical species responsible for the observed IGSCC was not identified. Concentration of caustic species was, however, considered the most likely causative agent.
The ruptured tube was ascertained to have been examined by the bobbin coil method in both RE0 7 (1982) and RE0 8 (1984).
Reevaluation of the 1982 eddy current data again confirmed that there was no evidence of a defect or dent indication in the tube at that time. Reevaluation of the 1984 eddy current data showed, however, that a 99 percent through-wall defect was present at the failure location. This defect was missed during initial analysis of the data in March 1984 by the single analyst that was used in that time frame. All accessible tubes in both steam generators were examined by the multi-frequency bobbin coil method as a result of the failure.
A total of eight additional tubes were plugged in Steam Generator A following these examinations. This number included plugging the open ends of the two tubes from RE0 4, as
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Two of the other six tubes exhibited degradation in excess of the 40 percent plugging limit, with the defect indications being located several inches above the tube sheet (one on the hot leg side, one on the cold leg side).
The remaining four tubes, although exhibiting defect indications below the 40 percent plugging limit, were preventively plugged because of the defect location being the same as the failed tube (i.e., at the first vertical support on the hot leg side). Seven tubes were plugged in Steam Generator B following the additional examinations. This number included the failed tube, one removed to gain access to the failed tube, one electively plugged because of its proximity to the failed tube, and one misplugged tube.
The remaining three tubes all exhibited defect indications at the first vertical support on the hot leg side, one of which exceeded the 40 percent plugging limit.
In total, 23 new tubes were plugged during RE0 8 and the immediately following forced outage.
During RE0 9 in 1985, the eddy current examination sample included the profilometry baseline taken in 1984 and all tubes in the most severely dented area of the hot leg vertical support region. The results showed significant positive growth of denting. Two defect indications were also detected in Steam Generator B at the first hot leg vertical support, which suggested that IGSCC was continuing. A total of 33 tubes were plugged, with 15 tubes in each steam generator being plugged due to their restricting passage of a 0.540-inch
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eddy current probe.
Following REO 9, the licensee initiated boric acid treatment of the secondary side of the steam generators in an attempt to curtail further IGSCC and denting.
Eddy current examinations performed during RE0 10 (1987), RE0 11 (1988), and
RE0 12 (1990), showed no tubes affected by IGSCC and no significant dent growth. The samples examined in these outages included the profilometry sample previously examined in 1984 and 1985. No tubes were plugged during
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these outages.
In RE0 13 (1992), both the bobbin coil and the motorized rotating pancake coil (MRPC) eddy current examination methods were used. The MRPC tests were performed to detect if circumferential cracking was present at the hot leg t@e expansion transition regions. No circumferential indications were detected using the MRPC probe. Bobbin coil examinations continued to indicate that denting had been arrested.
In RE0 14 (1993), the bobbin coil and MRPC methods were again used to conduct the eddy current examinations. One 45 percent through-wall defect indication requiring plugging was detected in Steam Generator B in Tube L69R80. The
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defect indication was located near the seventh horizontal support on the hot leg side and axially extended about 2.5 inches. The defect could not be positively characterized from review of the eddy current data.
Increases were noted in RE014 (compared to RE013) of numbers of indications in the <20 percent and between 20 percent and 40 percent through-wall ranges (see Section 4.3 for additional information). Only the one tube in Steam Generator B was plugged during RE0 1,
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-9-To date, a total of 55 tubes in each steam generator have been plugged. This represents approximately 1.1 percent of the tubes plugged per generator, with
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0.6 percent of the tubes being plugged during operational-service.
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2.5 Conclusions The FCS plant utilized two vertical U-tube recirculating steam
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generators, each containing 5005 high-temperature mill annealed Inconel 600 tubes. The hot leg temperature used over the operational life of the plant varied from 575*F to 596*F, with the predominant hot leg temperature in the last 10 years being 593*F. The inspectors noted that this temperature was one of the lower values used by_ pressurized water reactors.
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The percentage of tubes plugged in each steam generator after 13.57
EFPYs of operation was 1.1, with 0.6 percent of the tubes being plugged
as a result of service degradation.
A tube rupture occurred in Steam Generator B in May 1984 at the first
hot leg vertical support, which was determined to have been caused by
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No further evidence of IGSCC or progression of tube denting has been i
found since boric acid treatment of the secondary side of the steam
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generators was initiated subsequent to RE0 9 (1985). Only one tube has
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been determined by eddy current examination to require plugging since the 1985 outage.
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3 VISUAL INSPECTION OF THE STEAM GENERATOR A SECONDARY SIDE INTERNALS l
3.1 Steam Generator A Secondary Internals Inspection The steam generator visual inspection data for REO 14 was still being compiled
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as of this inspection and was, thus, not available for review. _ Accordingly,.
the inspectors reviewed Maintenance Work Order (MWO) 918019, completed l
March 12, 1992, which implemented a visual inspection of the secondary side internals of Steam Generator A during RE013. The visual inspection was i
conducted by ABB-CE personnel in accordance with licensee
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Procedure SS-RI-M-0100, " Visual Inspection of Steam Generator Secondary Side,"
Revision 1.
In reviewing the inspection procedure, the inspectors noted_that tool accountability was required during inspection activities and that precautions were to be taken to prevent foreign materials from entering the i
steam generator. However, the procedure provided no specific direction for ensuring tool accountability or foreign material exclusion.
i The scope of the secondary inspection consisted of a visual examination of the j
area above and below the steam separator support deck, the feedring area, and
the tube sheet area as observed through the secondary handhole opening.
During the inspection, ABB-CE personnel noted minor deposits on the steam dryers. The deposits were observed primarily on the hot leg side of the steam
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-10-generator. There was also evidence of localized hard deposits between the tubes and the scalloped bar supports.
These deposits were also noted during RE013 and showed no evidence of Ldditional growth. Additionally, a small crack was observed in the eighth partial drilled suppt.-L plate which showed no apparent change from the previous inspection.
ABB-CE personnel also noted a failed weld on the feedwater nozzle liner support bracket which resulted in a loose feedwater nozzle liner.
Foreign material found during the inspection were a piece of debris from the secondary manway gasket and a wire approximately 8 inches in length. The overall condition of the steam generators was determined to be good. No evidence of erosion was noted on the feed trains or steam separators.
The inspectors also reviewed the ABB-CE Steam Generator Secondary Side Visual Inspection Report, CSE-92-303, Revision 1, dated October 1992.
The report provided an extensive photographic illustration of the secondary internals.
Review by the inspectors indicated that the overall surface conditions appeared good, with no visible evidence of degradation or significant corrosion product builcup. The amount of chemical deposits was reported to be slightly less than the previous inspection.
3.2 Foreion Material Exclusion (FME)
The licensee's FME program was ascertained to be governed by Standing Order S0-M-10, " Foreign Material Exclusion." Compliance with this standing order was noted to be mandatory during activities involving breaching the steam generator primary manways, secondary handholes, and secondary manways.
The current revision, Revision 13, dated September 15, 1993, was compared against prior revisions, with differences noted.
Prior revisions of the standing order did not require the logging of material into and out of the FME i
controlled area to ensure material accountability.
The current revision made it mandatory that logs be used for work activities in the vicinity of the reactor vessel cavity area, and also when tools would be left in an FME area.
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Logs were not required to be retained, either currently or historically, which precluded assessment of the effectiveness of FME controls during performance of secondary side work activities in the steam generators during RE0 13 and REO 14. The inspectors questioned why these records were not retained, and were informed that a need had not been established for retention of the records and that specific emphasis was placed during RE014 on verification of appropriate implementation of Fht controls during conduct of work activities.
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3.3 Conclusions I
Contractor inspection of Steam Generator A during RE0 13 appeared to
have been well performed for the documented inspection scope, with the
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results indicating the overall condition of the steam generator to be good.
Current FME controls were considered satisfactory. The effectiveness of
FME during performance of secondary side work activities in the steam
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-11-generators during RE0 13 and RE0 14 could not be assessed due to the non-retention of control logs.
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4 REVIEW 0F TUBE EXAMINATION HISTORY, PROGRAM REQUIREMENTS, AND DATA
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4.1 Review of Tube Examination History Prior to unit operation, the licensee performed a limited baseline eddy current examination of 4 percent of the tubes in each steam generator using a single frequency bobbin coil probe. Minor mechanical imperfections were noted.
In 1975 (RE0 1), single frequency bobbin coil examinations were performed on a 4.5 percent sample of tubes in both steam generators, with no evidence of degradation noted. No evidence of degradation was also noted. in i
1976 (RE0 2), during single frequency bobbin coil examination of an 8 percent sample of tubes in Steam Generator B.
A limited non-Technical Specification examination of Steam Generator A was performed in 1977 (REO 3), to assess the tubes which exhibited minor imperfections during the baseline examination in-
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1973. No evidence of degradation was noted.
The first evidence of tube denting was identified in 1978 (REO 4) during single frequency bobbin coil examination of a 10 percent sample of tubes in Steam Generator A.
As discussed in Section 2.4, three tubes were preventively plugged.
Multi-frequency bobbin coil examinations were performed for the first time in
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1981 (REO 6) on a 6.5 percent sample of tubes in Steam Generator B.
Magnetite denting was identified.
Similar results were'obtained in 1982 (REO 7) during multi-frequency bobbin coil examinations of a 6 percent sample of tubes from both steam generators.
In March and May 1984 (i.e., RE0 8 and the forced outage resulting from the rupture of Tube L29R84 in Steam Generator B), all accessible tubes were
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examined by the multi-frequency bobbin coil method.
In addition, a baseline profilometry was performed by eddy current examination on a sample of
approximately 150 tubes in Steam Generator A and approximately 200 tubes in j
Steam Generator B, in order to allow better quantification of denting during
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future examinations. As discussed in Section 2.4, eight tubes in Steam Generator A and seven tubes in Steam Generator B were plugged following these examinations. An approximate 20 percent sample of the tubes from both steam generators was examined by multi-frequency bobbin coil in 1985 (RE0 9), with the results indicating continued dent growth and active IGSCC.
Twenty percent samples from both steam generators were examined by multi-frequency bobbin coil in 1987 (RE0 10) and 1988 (RE0 11), with no evidence of
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further degradation being noted.
In 1990 (RE0 12), the bobbin coil sample size was increased to approximately 34 percent of the tubes in both steam generators, with no tubes requiring plugging. Approximately 27 percent and 25 percent of the ttbes in both steam generators.were examined, respectively, by
bobbin coil in 1992 (RE0 13) and 1993'(RE0 14). One tube, as discussed in Section 2.4, required repair in Steam Generator B in RE0 14. One indication
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-12-was found by bobbin coil examination during RE0 14 in Tube L125R8 near the third vertical support, for which the depth could not be accurately determined. The indication could not be found by MRPC examination, and was reported as a possible indication to be tracked in future inspections. MRPC examinations of tube expansion transition areas were also performed in response to Information Notice 90-49 during REO 13 and REO 14 on an approximately 20 percent sample from both steam generators.
(The actual sample size in Steam Generator B in REO 14 was 17 percent). No evidence of circumferential defects was noted during these examinations.
4.2 Review of Examination Procram Reauirements
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4.2.1 Current Program The inspectors reviewed the eddy current program requirements which were contained in:
(1) " Steam Generator Eddy Current Data Interpretation Guidelines," Revision 1; (2) Procedure OPPD-410-004, " Procedure for Multifrequency Examination of Nonferromagnetic Steam Generator Tubing Using MIZ-18A Equipment," Revision 5; (3) Procedure OPPD-410-005, " Procedure for Control of Eddy Current Data for use With Multiforth or Eddynet Acquisition Systems," Revision 1; and (4) " Fort Calhoun Steam Generator Instructor Manual," Revision 0.
The inspectors also compared the current program against prior program requirements and the recommendations contained in Electric Power Research Institute (EPRI) NP-6201, "PWR Steam Generator Examination Guidelines," Revision 3.
The current program was found to be in general conformance with EPRI NP-6201 recommendations, with the exception of the absence of any criteria for noisy data. Dual independent analysis of data was
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required and the program suitably addressed resolution of differences in calls by analysts. The inspection scope, which is discussed below, was considered
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comprehensive. The data interpretation guidelines were viewed as a strength by the inspectors.
Review of the choice of tubes to be inspected in RE0 14 showed that it was appropriately influenced by previous degradation experience at FCS and other similar CE steam generators.
Because of problems experienced at.other CE-design steam generators in regions where tubes intersect the edge of drilled supports, 87 tubes (50 percent) in Steam Generator A and 89 tubes.(50 percent)
in Steam Generator B were inspected from this location with the bobbin coil.
Also, due to concerns about tubes in the steam blanket region, 48 tubes in this region in both steam generators (20 percent) were inspected with the bobbin coil. All tubes that were dented (to the extent that passage of a 0.560-inch probe was restricted) were inspected with the bobbin coil, as were all previous indications.
In addition to the tubes inspected because of suspected degradation, 931 tubes in Steam Generator A and 929 tubes in Steam Generator B were selected randomly for bobbin coil inspection from the population of tubes that was not inspected either in RE012 or RE013. MRPC examinations were performed on 20 percent and 17 percent random samples, respectively, in Steam Generators A and B of the hot leg side expansion
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transition areas of tubes that were not previously inspected in RE013.
In addition, MRPC was used to inspect previous indications in 13 tubes in both steam generators and 25 dented intersections and U-bends in Steam Generator B.
All the analysts used in the 1993 inspection were either Level IIA or Level III certified analysts. Appropriate criteria had been established for site-specific training and testing of the analysts. The inspectors noted, however,
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during the program review, that the data analysis guidelines and the training and examination test tapes had been developed by ABB-CE, the organization
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responsible for the RE014 data acquisition and primary and secondary data l
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analysis. The inspectors noted that the licensee relied significantly on its contractor, and provided no independent technical oversight during outage examinations. The inspectors reviewed the certification and testing records
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for the analysts that had previously been reviewed and accepted by the
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licensee. No problems were noted during this review.
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 problems. The sample used for this review wasBulletin 89-01, " Failure of Westinghouse Steam Generator 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 Bulletin 89-01 was not applicable to FCS and that the licensee's evaluation and response to Information Notices 90-49 and 91-67 were appropriate.
4.2.3 Eddy Current Program Oversight The inspectors requested to see available records pertaining to licensee oversight of eddy current contractor activities. Three Quality Control inspection reports (93-2359, 93-2389, and 93-2446) were provided for the current outage in response to this request.
The inspectors noted from review of the inspection reports that the surveillance attributes were general in nature, with the text of the documents providing only limited information on how contractor performance activities were assessed and what measurement criteria were used. The inspectors also ascertained that the licensee did nct have any staff that were certifiad in eddy current examination. As discussed in Section 4.2.1, the licensee appeared to be placing a major reliance on its contractor for execution of the eddy current examination program. The absence of independent technical oversight by the licensee was considered a weakness.
4.3 Review of Tube Examination Data The NRC consultant reviewed a sample of bobbin coil and MRPC data that were obtained from the current examinations.
Included in this sample were the data obtained from the tube that was plugged, Tube L69R80, and that from the tube
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-14-which showed a bobbin coil indication that was not detectable by MRPC examination, Tube L125R8. No observations were made which would bring into question the final " calls" made by the ABB-CE analysts. The NRC consultant noted that the number of indications detected during RE014, that were below the 40 percent plugging limit, increased over that four.d in REO 13. Table 2 shows the comparative numbers.
Table 2 SIZE OF STEAM GENERATOR A STEAM GENERATOR B INDICATION INDICATIONS INDICATIONS RE0 13 RE0 14 RE0 13 RE0 14
<20 PERCENT
21
48 20-40 PERCENT
3
12 The NRC consultant concluded that the increase in reported indications was more indicative of heightened sensitivity by the ABB-CE analysts in the evaluation and documentation of small indications, rather than denoting the onset of further degradation.
4.4 Conclusions Eddy current sample sizes consistent with current EPRI recommendations
have been examined by the bobbin coil method since 1985 (RE0 9).
- MRPC examinations were performed in response to Information Notice 90-49 of a 20 percent sample of hot-leg side tube axpansion transition areas during RE0 13 and RE0 14, with no evidence of circumferential cracking found.
The data interpretation guidelines were viewed as a program strength.
- Site-specific training and testing of analysts were given during RE014 by the licensee's contractor.
The absence of independent technical oversight by the licensee of the
eddy current examination program was considered a weakness.
5 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 tubesheet crevices, tube support plate crevices, and sludge
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-15-piles.
Impurities known to contribute to tube denting (i.e., squeezing of tubes at tube supports or tubesheets as a result of the pressure of corrosion products) are chlorides, sulfates, and copper and its oxides.
Pitting of steam generator tubes has been attributed to the presence of copper and concentrated chlorides. Concentrated sulfates and sodium hydroxides are believed to be major causes of IGSCC and intergranular attack (IGA) in steam generator tubes.
Iron oxide tube deposits and sludge promote local boiling and concentration of impurities leading to damage mechanisms such as IGSCC and IGA.
5.1 Procram Evolution The inspectors reviewed the licensee's secondary chemistry control program for FCS.
It was ascertained that initial chemistry controls utilized phosphate secondary water treatment. All volatile secondary water treatment replaced phosphate treatment, however, in September 1973 and has been utilized throughout commercial operation of the unit.
Initial secondary water chemistry requirements were based on the CE chemistry manual and included specified blowdown values for pH range, conductivity, boron, chlorides, I
oxygen, silica, alkalinity, and hardness.
Early changes that were viewed as
'
significant by the inspectors included the addition of a sodium limit (10 ppb)
for feedwater in 1977 and the reduction in 1978 of permissible steam generator chlorides from 10 ppm to 0.1 ppm.
Following the tube rupture in May 1984 in Steam Generator B, the licensee revised its chemistry limits to conform to EPRI secondary water chemistry guidelines. The inspectors also noted that, in addition to progressively adopting more stringent water chemistry requirements after the tube failure, other major changes in practice were made by the licensee.
The most significant of these changes were considered by the inspectors to be:
the implementation of boric acid soaks prior to exceeding 30 percent power; the raising of feedwater hydrazine limits, after replacement in 1985 of copper l
alley tubing in the low pressure feedwater heaters with stainless steel
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tubing; the use, starting in 1987, during refueling outages of a demineralizer skid to improve the quality of condenser hotwell water and, thus, facilitate
,
meeting chemistry limits more rapidly during start-up; and the use since 1986 of morpholine additions.
The inspectors compared the current secondary water chemistry program requirements against the criteria contained in EPRI NP-6239, "PWR Secondary Water Chemistry Guidelines," Revision 2 dated December 1988, and EPRI TR-101230, " Interim PWR Secondary Water Chemistry Recommendations for IGA / SCC Control," dated September 1992. The program requirements, which were contained in Chemistry Administrative Procedure CH-AD-003, " Plant Systems Chemical Limits and Corrective Actions," Revision 4, were found to fully conform to the EPRI guidelines with respect to scope of chemistry parameters, analytical frequency, limits for critical parameters, and required actions when critical parameters were exceeded.
l
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-16-The inspectors additionally noted that the licensee had established normal steam generator limits (i.e. 5 ppb) for chloride, sulfate, and sodium, during operation at greater than 5 percent reactor power, which were significantly below the >20 ppb threshold values stipulated by both the EPRI documents and Procedure CH-AD-003 for the first required actions. The inspectors concluded that this approach was commendable, and should result in lower average impurity levels and minimal deviations above formal action limits. The inspectors ascertained that studies had also been instituted of cation-to-
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anion ratios present in crevices using hideout return data.
If successful, this approach could ultimately result in the development of water chemistry criteria that would assure the maintenance of a preferred neutral or slightly acidic environment in steam generator crevices.
5.2 Secondary Side Chemistry History The inspectors reviewed the available history of the FCS steam generators with respect to significant chemistry events and compliance with the EPRI secondary water chemistry guidelines. Details on off-normal chemistry are discussed below in Section 5.5.
During this review, the inspectors were informed tNat no water chemistry records were available for the time period prior te 1983, thus precluding any assessment of the effectiveness of implementation of chemistry controls for approximately the first 10 years of plant operation. Accordingly, no
information was available for the majority of the period prior to the 1984 tube rupture. Trending of chemistry information was limited in scope and had i
included reactor power level for only approximately the last 2 years, thus j
making it difficult to meaningfully assess earlier trend data. The licensee i
also did not have any form of data compilation that would allow t eady interpretation of overall historical chemistry performance. Sampling review by the inspectors of the available trend information, and microfilm records for the years 1983-1991, indicated that impurity values were generally well within the procedural limits in effect at the time of a specific analysis.
The inspectors obtained historical information from the licensee for each i
steam generator pertaining to sludge removal and copper (Cu)/ iron (Fe) ratio values. The available historical information on analysis and trending of
'
steam generator secondary side sludge deposits was contained in a number of reports of which the most recent was for Cycle 13, Report 2000151-MCC-92-014,
" Fort Calhoun Steam Generator Deposit Analysis Report," Revision 1.
The sludge samples were removed from the top of the tubesheet before the steam
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generators were cleaned using the sludge lancing process. The steam i
generators were first cleaned using sludge lancing after Cycle 8 during the 1984 outage. The information regarding the weight of the sludge deposits
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removed from the two steam generators for Cycle 8 through Cycle 14 was reviewed and discussed with the licensee. The steam generator sludge data
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obtained between 1981 and 1993 is summarized in Table 3.
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Table 3
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STEAM GENERATOR SLUDGE ANALYSIS-STEAM SLUDGE REMOVED
.Cu/Fe COMMENTS.
j GENERATOR weight,'1bs RATIO
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CYCLE 6 A
4.3 No sludge lancing l
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1981 OUTAGE NONE performed before
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B 4.3 1984.
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i CYCLE 7 A
7.3.
No sludge lancing 1982 OUTAGE NONE performed before
B 6.0 1984.
i CYCLE 8 A
3.7 First^ time use of
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1984 OUTAGE 696 TOTAL
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B 4.5
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CYCLE 9 A
0.6 Replacement of 1985 0UTAGE 750 TOTAL-feedwater heater l
B 0.9 tubes with stainless
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steel.
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CYCLE 10 A
0.8'
Started using boric
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1987 OUTAGE 814 TOTAL acid and morpholine B
0.7 during Cycle 10.
l CYCLE 11 A
0.7 i
1988 OUTAGE 877 TOTAL
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B 0.3
CYCLE 12 A
0.3 1990 OUTAGE B
0.3
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l CYCLE 13 A
0.2
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1992 OUTAGE 294 TOTAL B
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CYCLE 14 A
No Data 1993 OUTAGE
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B The sludge Cu/Fe ratios listed in Table 3 indicate that high copper transport into the steam generators occurred during the-first 10 years of-plant operation, which was attributable to continuing corrosion of the copper bearing materials in the condensate and feedwater systems, such as, copper alloy tubes in the feedwater heaters and Muntz metal (60 percent' copper and 40 percent zinc) for the tubesheet material in the condenser. The Cu/Fe ratio.
was significantly reduced in Cycle 9 which was the cycle following the first
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use of sludge lancing for cleaning the steam generators.
In 1985, the' copper
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alloy tubes in the feedwater heaters were replaced with. stainless steel tubes to further reduce ingress of copper into the steam generators. The Cu/Fe ratio has continued to decrease following the institution of sludge lancing and feedwater heater tube replacement.
The quantity of sludge removed from the steam generators each cycle has significantly decreased since 1988 which may be attributed to the improvements made,n water chemistry controls.
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5.3 Ouality Assurance Assessment of the Secondary Water Chemistry Proaram The inspectors reviewed several licensee audit and surveillance reports pertaining to the secondary water chemistry control program. The reports
,
included seven audits performed during the period November 1982 through June 1992, and six surveillances performed during the period of April 1991 to
October 1993. The inspectors determined that the scope of the audits and
surveillances were comprehensive and appropriate for evaluation of-the implementation of the water chemistry program. The. inspectors' review of the audit and surveillance findings did not indicate any significant adverse
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findings which would bring into question the quality of the water chemistry j
program.
5.4 Chemistry Laboratory Instrumentation and In-Line Process Chemistry Analyses The inspectors toured the turbine building and observed the equipment used for secondary water chemistry control which included the amine mixing tank, the hydrazine mixing tank, the boric acid mixing tank, and the secondary sampling panel of in-line process chemistry analyzers. The inspectors also toured the chemistry laboratory and observed the analytical instrumentation used for analyzing grab samples. The inspectors verified that the necessary instrumentation was installed in the process lines or available in the laboratory for the analysis of the diagnostic and control parameters specified in the secondary water chemistry control program. The inspectors also verified that the secondary plant sampling process lines for the blowdown piping, feedwater heaters, and condensate pumps were located on the discharge side and monitored the various parameters of the secondary water specified in Section 9.13 of the Updated Safety Analysis Report.
The. inspectors noted that a concerted effort was made by the licensee to periodically upgrade the in-line process and laboratory instruments needed to perform the required chemical analyses. The most recent equipment upgrade was the replacement of in-line electronic equipment for monitoring the secondary water discharged from the three condensate pumps and two feedwater heaters. The upgrade was described in Engineering Change Notice ECN 93-326 and included replacement of the existing analyzers for specific conductivity, cation conductivity, pH, sodium, and dissolved oxygen with new improved equipment. With the exception of the dissolved oxygen analyzer, installation of. the new equipment was completed prior to the outage. The oxygen analyzer was scheduled to be installed after the outage. All these analyzer upgrades were efforts made by the licensee to enhance their ability to monitor secondary water chemistry conditions which could affect the steam generators.
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5.5 Off-Normal Secondary Chemistry History i
The inspectors noted during review of the data discussed in Section 5.2, that
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minor chemistry out-of-specification conditions were promptly corrected.
Licensee personnel informed the inspectors that significant out-of-specification chemistry conditions were documented on incident reports in
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accordance with Standing Order S0-R-4, " Station Incident Reports." The l
inspectors reviewed the current revision of the standing order, Revision 41,
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and confirmed that provisions were included for issue of an incident report when chemistry exceeded the action level limits of Chemistry Administrative Procedure CH-AD-0003.
No out-of-specification conditions were observed by the inspectors during review of incident reports which were considered to be of a type or magnitude that could contribute to degradation of the steam generators.
It was noted, however, that the earliest incident report for a
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chemistry deviation was dated April 1989, which indicated that the-available
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data pertained to only a small fraction of the operating history of the plant
and that the standing order had not been used in previous years for.
i documenting chemistry deviations. The inspectors also noted that the incident report system did not readily provide a complete printout of chemistry deviations, with only part of the history being printed out when Event Code CH (representing chemistry) was used for sorting the information.
The reasons
for the incomplete information were subsequently found to be related to a lack i
of uniformity in the assignment of event codes, with a variety of codes other
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than CH being applied to chemistry deviations. The inspectors informed i
licensee personnel that this lack of uniformity in assignment of event codes was considered a weakness, and had the potential for negatively impacting corrective action program trending activities.
5.6 Conclusions Since commercial operation of FCS, the secondary water chemistry program
!
requirements have been progressively upgraded to incorporate industry guidelines as they were made available. The current program requirements were comprehensive and reflected the most recent EPRI information.
Following the tube rupture in May 1984, the licensee implemented major
changes in practice. These changes included boric acid treatment of the secondary side of the steam generators, raising of feedwater hydrazine limits after replacement of copper alloy tubing with stainless steel in the low pressure feedwater heaters, commencement of morpholine additions, and the use during outages of a demineralizer skid to improve j
the quality of condensate prior to plant startup.
l Absence of records precluded any assessment of the effectiveness of
+
chemistry controls prior to 1983.
A sampling review of analytical data from 1983 to present indicated that
impurity values were generally well within the procedural limits in
effect at the time of a specific analysis.
Review of overall historical
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chemistry performance was impacted, however, by only limited trend
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information being available.
No out-of-specification chemistry conditions were noted in the incident
report system that were of a type or magnitude which would be expected to contribute to tube degradation.
Chemistry deviations had, however, only been entered in this system since 1989 and had not been uniformly
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classified as such. This practice, which was considered a weakness, I
resulted in the inability to readily establish the total population of chemistry deviations in the system.
Sludge removal quantity and Cu/Fe ratio trends indicated progressive
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improvement in secondary water chemistry controls.
l Progressive upgrades of in-line process and laboratory instruments have
been made to enhance secondary water chemistry monitoring capabilities.
6 INSERVICE INSPECTION - OBSERVATION OF WORK Als WORK ACTIVITIES (73753)
The objectives of this inspection were to ascertain whether performance of.
i inservice inspection (ISI) examinations and repair or replacement of
,
l components were accomplished in accordance with regulatory and ASME Code j
requirements, as well as correspondence between the NRC and the licensee j
l concerning relief requests.
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l 6.1 ISI Proaram Plan The inspectors reviewed the licensee's ISI Program Plans for the 1983-1993 and i
1993-200310-year intervals (i.e., the second and third 10-year intervals for FCS). The inspectors ascertained that the licensee was committed to the ASME Section XI Code, 1980 Edition up to and including Winter 1980 Addenda, for the second 10-year interval. Licensee staff indicated during discussions on the
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l ISI Program Plans that it was planned to upgrade to the 1989 Edition of the i
ASME Section XI Code for the third 10-year interval. During this refueling outage, the licensee was completing the third period of the second 10-year
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interval for the ISI program. Review of both ISI Program Plans by the l
inspectors indicated that changes to the plans concerning component-selection have been properly documented and approved. The inspector reviewed several relief requests and found no problems.
l The inspectors also noted the following improvements to the ISI program:
(1) The licensee has established an ISI computer data base which lists all welds in the 10 year ISI Program Plan, and (2) The licensee's ISI group has now assumed all responsibilities from contractors for the ISI Program Plan.
i Records of examinations were found to be easily retrievable.
Isometric drawings and photographs of components were also available for inspection l
l
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-21-personnel to review, which aided the inspection personnel in the preparation and planning of the job activity.
6.2 Personnel Oualifications and Certifications The inspectors reviewed the ASNT-TC-1A qualifications and certifications of the Ebasco Level I and Level II personnel parforming the inspections. The qualification and certification records pr
'ly reflected the employer's name, person certified, activity qualifici perform, level of certification, effective priod of certification, Level 11: signature certifying the individual, and the annual visual acuity and color vision examination.
No discrepancies were identified.
6.3 Work Observations The inspectors witnessed five liquid penetrant (PT) examinations, five manual ultrasonic (UT) examinations, one magnetic particle (MT) examination, and visual (VT-3) examinations of two pipe supports. The inspectors determined by interview and observation of the NDE personnel performing the examinations that they were knowledgeable of procedural requirements and NDE techniques used. The five manual UT examinations were performed on Steam Generator B welds (e.g., dollar weld and meridional weld). Two of the PT examinations were performed on Steam Generator B Class I hot and cold leg nozzle-to-pipe circumferential welds.
The other three PT examinations were performed on a nearby 3-inch Class I high pressure safety injection line. One NT examination was observed on a Class 2 branch connection below Atmospheric Dump Valve TCV-909-2 on a 36-inch main steam line.
UT calibrations were satisfactorily performed according to applicable procedurer, and UT instruments were found to be calibrated for screen height linearity and amplitude control linearity.
The inspectors observed the preparation and use of proper UT distance amplitude correction curver.
The inspectors verified that surface preparation and the temperature of metal surfaces were satisfactory. The inspectors also verified that cor:ect size, frequency, and angles of the search units (transducers) were used and that the scanning techniques, scanning sensitivity, direction, rate of search unit movement, overlap, and coverage were consistent with procedural requirements.
The inspectors observed that a system calibration check was performed prior to
.
the examination to verify the instrument sensitivity and sweep range
'
calibration. No discrepancies were identified by the inspectors.
The inspectors observed that NDE personnel verified the magnetic field adequacy before performing the MT examination. The inspectors noted the identification of the UT couplant, PT, and MT materials used during the examinations and verified that these materials were approved by the licensee
,
for use. The inspectors observed the oversight of work activities by the
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Authorized Nuclear Inservice Inspector.
The inspectors observed VT-3 examinations of two Class 3 supports on a 2-inch portion of the main steam system.
These supports are exempt by Code
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-22-requirement IWC-1200, subparagraph (c) because the piping is less than 4-inches nominal. However, the licensee elected to inspect this line because it ties into the Class 2 auxiliary feedwater system.
The inspectors found that NDE personnel performing the examinations and evaluating results were certified at the appropriate level for tha applicable activity.
The ISI Program was being effectively implemented in accordance with procedural and ASME Code requirements. Management involvement was evident in these areas.
6.4 Code Repair or Replacement
,
There were no Code repair activities in progress at the time of the inspection. There was one Code replacement activity on safety-related
,
I Component Cooling Water Outlet Valve HCV-443. The valve's old internals were replaced with new internal parts to improve valve control. Observations of and discussions with craft personnel indicated that they were knowledgeable of the work to be performed and procedural requirements. Approved procedures were included in the work package. Quality Control was present monitoring the replacement activities for this valve. The craft personnel were observed to be performing the work in accordance with the work instructions.
Review of the work instructions by the inspectors indicated, however, that the
work instructions, as discussed below, did not give clear guidance on all the work activities to be performed.
The work instructions were noted to not include any installation
instructions for the valve packing kit. Discussions with the
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I responsible craftsman indicated that he was trained in the repair and installation of Fisher valves and appeared knowledgeable. The kit,
,
which contained several parts of various thicknesses, was considered by the inspectors, however, to be of sufficient complexity as to warrant assembly instructions for even a well-trained craftsman. The licensee
'
l informed the inspectors that packing instructions should have been included in the work package; however, this task was associated with the
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skill of the craft. The absence of instructions additionally precluded the inspectors from determining if the parts were assembled corr 6ctly in the field.
Work instructions referenced generic Procedure PE-RR-VX-0410S,
" Inspection And Repair Of Safety Related Fisher 'ES' Control Valves,"
Revision 3, for the removal and installation of parts, but did not,
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however, reference the engineering change notice which changed the old internals to the new internhls. Discussions with the licensee revealed that the work had been previously stopped because the craftsmen incorrectly thought that they had acquired the wrong parts.
Inclusion of the engineering change notice in the issued work package would have i
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i precluded this misunderstanding. The engineering change notice was
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l subsequently added to the work package.
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l The two examples of insufficient work instructions discussed above were i
considered by the inspectors to be a weakness and an area warranting.
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i additional licensee attention. The licensee agreed that they have had
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problems.with work packages in the past not containing sufficient
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instructions, and that they are planning to set up a process management team
j to review work process control in 1994.
6.5 ISI Procedures and Records Review
-)
The inspectors reviewed the NDE procedures associated with the type of ISI
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examinations being performed for consistency with the requirements of the'1980
)
Edition of ASME Code,Section XI. The procedures were observed to contain
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sufficient details and instructions to perform the intended examinations.
NDE reports were properly completed and turned in for. review by the NDE..
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supervisor and the Authorized Nuclear Inservice Inspector.
i The inspectors also selected components from the' previous inspection intervals
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l to determine if the licensee had been following the program as committed to.
i for the first 10 year interval. The inspectors selected records.for the
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l
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pressurizer head welds, and the reactor coolant pumps ISI hydrostatic and leak i
test performed during the first 10 year interval.
Records were available for
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j review that indicated that the licensee had performed the examinations as required by the ISI Program and ASME Code' requirements.
i 6.6 Conclusions
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The licensee has made various improvements to the ISI program which have
facilitated overall planning and control of examination activities.
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i Contractor NDE personnel were found to be appropriately. qualified e
and performing examinations in accordance with procedural requirements.
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The ISI Program was being effectively implemented, and management j
attention was evident.
Replacement of internal parts for Valve' HCV-443 was-performed by. a
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qualified craftsman. However, the relevant work instructions did not..
clearly identify all work to be performed.
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ATTACHMENT 1
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1 PERSONS CONTACTED l
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1.1 Licensee Personnel
- +*R. Andrews, Division Manager, Nuclear Services
- C. Bloyd, Special Services Engineering
- + C. Boughter, Supervisor, Special Services Engineering i
+ J. Cate, Special Services Engineer
- G. Cavanaugh, Licensing Engineer
- +*J. Chase, Plant Manager i
- +*G. Cook, Supervisor, Station Licensing
- +*S. Gambhir, Division Manager, Production Engineering
- +*J. Gasper, Manager, Training
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- +*P. Hammer, ISI Administrator
- +*J. Herman, Acting Manager, Nuclear Licensing and Industry Affairs
- +*R. Jaworski, Manager, Station Engineering
+ W. Jones, Senior Vice President i
- +*L. Kusek, Manager, Nuclear Safety Review j
+ D. Lippy, Licensing Engineer i
- R. Lippy, Inservice Inspection Coordinator
+ B. Lisowyz, Senior Design Engineer
- + T. McIvor, Manager, Nuclear Projects j
- J. O'Connor, Manager, Design Engineering-Electrical
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- +*W. Orr, Manager, Quality Assurance / Quality Control
- +*T. Patterson, Division Manager, Nuclear Operations
- + R. Phelps, Manager, Design Engineering
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K. Saltzman, Authorized Nuclear Inservice Inspector
- + F. Smith, Supervisor, Chemistry j
ABB - Combustion Enaineerina
+ R. Maurer, Manager, Nondestructive Examination NRC Personnel
R. Azua, Resident Inspector
- S. Bloom, Project Manager
- P. Harrell, Chief, Technical Support Staff
- W. McNeill, Reactor Inspector j
- R. Mullikin, Senior Resident Inspector
+ C. Thomas, Acting Deputy Director, Division of Reactor Safety In addition to the personnel listed above, the inspectors contacted other
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personnel during this inspection period.
- Denotes those persons that attended the exit meeting on October 8, 1993.
+ Denotes those persons that attended the exit meeting on October 22, 1993.
- Denotes those persons that attended the exit meeting on November 5, 1993.
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2 EXIT MEETING Exit meetings were conducted on October 8, October 22, and November 5, 1993.
During these meetings, the inspectors reviewed the scope and findings of the report. The licensee stated in the October 8, 1993, exit meeting that the instructions for the installation of valve packing should have been included in the work package; however, the task of installation is associated with the
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skill of the craft. The licensee stated in the November 5,.1993, exit meeting
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that a need had not been established for retention of FME logs, and that specific emphasis had been placed during REO 14 on verification of
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implementation of FME controls during conduct of work activities.
Information marked as proprietary by ABB-CE was reviewed during this inspection. No information was included in the inspection report that was considered t
proprietary.
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ATTACMENT 2-i
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Documents Reviewed Durino Inservice Inspection Inservice Inspection Program Plans for the 1983-1993 and 1993-2003 Intervals
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Maintenance Work Order (MWO) 924711 l
l Reactor Coolant Pumps 10 Year Inservice Hydrostatic'and Leak Test (1st-Interval)
Isometric Drawing Nos. A-06, A-07, A-09, A-22, A-32, B-34, and D-01.
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Engineering Change Notice 93-452 l
UT Calibration Data Sheets 1-001, 1-002, 1-003, 2-001, 2-002, 2-003, FC-90-UT-083, FC-90-UT-084, and FC-90-UT-085.
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Indication Notification Report No. INR-93-001 and INR-93-002.
l UT Instrument Certification No. EL-0444, EL-0436, EL-0451, EL-0426, EL-446 and EL-0432.
I Certification 111 story Of Ebasco Personnel i
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Relief Request Nos. 84-99,87-115, 91-377 and 93-0171..
Procedures
FC-UT-2, " Ultrasonic Examination Of Class l'and 2 Vessel Welds", Revision 3 FC-VT-3/4, " Visual Examination: VT-3 And VT-4 (Limited)", Revision 2 I
FC-UT-10, "UT Examination For Laminar And Planar Reflectors, Material Thickness, And Geometric Conditions", Revision 1 FC-VT-1, " Visual Examination: VT-1", Revision 2 FC-PT-1, " Liquid Penetrant Examination (Solvent Removable Method)," Revision 2 FC-MT-1, " Magnetic Particle Examination Of Welds And Bolting," Revision 3 FC-UT-7, " Ultrasonic Examination Of Class 1 and 2 Vessel Welds Less Than Or
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Equal To 2 Inches," Revision 2
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FC-UT-1, " Ultrasonic Examination Of Class 1 and 2 Piping Welds Joining Similar and Dissimilar Materials," Revision 5 l
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