IR 05000413/1987029
| ML20235E859 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 09/17/1987 |
| From: | Hughey C, Kahle J, Ross W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20235E850 | List: |
| References | |
| 50-413-87-29, 50-414-87-29, IEIN-86-106, IEIN-87-036, IEIN-87-36, NUDOCS 8709280298 | |
| Download: ML20235E859 (9) | |
Text
{{#Wiki_filter:UNITED STATES [Se nrog% ' NUCLEAR REGULATORY COMMISSION ' .. ^ [\\ REGION 11 p g j 101 MARIETTA STREET, N.W.
ATLANTA, GEORGI A 30323
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%,,,..* SEP 171987 , Report Nos: 50-413/87-29 and 50-414/87-29 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Docket Nos.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-48 Facility Name: Catawba 1 and 2 Inspection Conducte
August 31-September 4, 1987 d /[a //h Inspectors:_ Date Signed W. J C. A $/qhey~ O YW Ob /d> l'ff ? ' '/ D(te Signed Approved b _ [[L 9 E /7 7 B. Kahle, Section Chief Dat Signed ,. Ivision of Radiation Safety and Safeguards " SUMMARY ' Scope: This routine unannounced inspection was counducted in the areas of plant chemistry and IE Notices related to erosion / corrosion.
Results: No violations or deviations were identified.
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- v' ' v REPORT DETAILS 1.
Persons Contacted-Licensee Employees
- R. F. Wardell, Superintendent Technical Services
- J. W. Cox, Station Training Manager
- R, H. Charest, Station Chemist R. Biswas, Chemist, Corporate Staff C. Bolin, Primary Chemistry Supervisor M. J. Drust, Environmental Chemistry Supervisor H. J. Dameron, Chemist, Clamistry Staff
- A. G. Duckworth, Technical Services Training Director
- J. Green, Chet'stry Training Coordinator E. Haack, Chemical Engineer, Chemistry Staff .P. J. Helton, Scheduling Engineer, Quality Assurance K. Johnson, Chemist, Corporate Staff M. Kowalewski, Chemist, Chemistry Staff M. McCree, Instructor, Technical Services Training B. McNeil, Chemisc, Chemistry Staff A, Nietering, Chemical Cngineer, Chemistry Staff R. Painter, General Supervisor, Chemistry J._ Reeves, Supervisor, Mechanical Maintenance C. Thierrien, Support Staff Supervisor, Chemistry NRC Resident Inspectors
- K.
VanDoorn SRI '*M. Lesser RI
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on September 4, 1987, with those persons indicated in paragraph above. The inspector described the areas inspected and discussed the inspection findings. No dissenting comments were received from the licensee.
The licensee did not identify as proprieta ry any of the material provided to or reviewed by the inspector during this inspection.
I 3.
Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.
4.
Plant Chemistry (79701) At the time of this inspection, Catawba Unit I was operating at 100*J power l in its second fuel cycle approaching a planned refueling / maintenance L , _ _ _ - _ _ _ _ _ _ _ _ _
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l: ! L L outage scheduled for October 1987. Catawba Unit 2, approaching its first refueling planned for December 1987, was being returned to full power-following an unplanned outage to replace a reactor coolant pump seal. The- ! inspectors reviewed the plau. chemistry _ controls and operational controls affecting plant chemistry during the last 12 months. This review focused primarily on the licensee's effor ts to maintain secondary water' chemistry controls within the-guidelines recommended by the Steam Generator Owners Group (SG0G).
Discussions were also held concerning planned cleaning, l maintenance, and inspection activities of steam generators and reactor coolant systems (RCS) during previous and upcoming outages.
ReviewchUnit1and2ReactorCoolantChemistryControls a.
Since the last inspection in this area (Inspection Report Nos.
50-413/86-12 and 50-414/86-35 September 11, 1986) Unit I had ' completed its first refueling and had been operational, with periodic short shutdowns, since November 1986.
Unit 2 had completed init41 power ascension testing and was in its first fuel cycle following a three-month outage in the Fall of 1986 to replace the main generator.
(1) Technical Specification 3/4.4.4 requires that the concentrations of dissolved oxygen, chloride and fluoride in the reactor coolant systems be maintained below 0.10 ppm, 0.15 ppm and 0.15 ppm respectively. An audit by the inspectors revealed that these chemistry variables had been maintained well below Technical Specification Limits in both units.
(2) During the upcoming outages of both units induced crud bursts were to be performed by adding hydrogen peroxide to the reactor coolant systems.
This action is designed to reduce out-of-core radiation / contamination levels, by solt. bili zi ng fission and activation products deposited on out-of-core metal surfaces, and thus decrease doses encountered by workers as well as enhance visibility during refueling operations. Extensive work is to be performed in and around the Unit I steam generators during the upcoming refueling outage, so the crud burst will be performed with the RCS filled and a reactor cooling pump circulating the water.
During the refueling outage for Unit 2 the licensee is not planning to perform any major maintenance on the steam generators.
Therefore, plans were being made to limit the regions of the RCS to be cleaned by crud burst by draining the reactor coolant to "mid plane" and cycling the water with an RHR pump. This procedure will reduce the critical path time for the outage while reducing radiation levels at the refueling bridge but not in the vicinity of the steam generator.
The licensee plans to investigate the effectiveness of the " filled" versus the "mid plane" methods for meeting the ALARA concept and for decreasing down time by continuing to use the " filled" method for Unit 1 and the "mid plane" method for Unit 2 i during the next three fuel cycles.
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. .. - . ) v ( . . . . -3 (3) To reduce the potential for primary side stress corrosion cracking of steam generator tubes. the licensee was planning to take the following preventative actions.
(a) During the upcoming refueling outage all.of. the tubes in the D-3 steam generators are to be shot peened,.to a distance of twenty-three inches above. the bottom of the tube sheet on the hot leg side, to eliminate residual stresses remaining from steam generator construction.
The inspectors -were informed that shot peening of tubes 'in Unit -2 steam generators was not being planned because the D-5 steam generators in this unit had been stress relieved during assembly.
(b) Hydrogen overpressure in the RCS will be reduced to 251 5 cc/kg (from 25-50 cc/kg) to minimize the possibility that this type of cracking may be affected by hydrogen.
(c) The guidelines recently developed by the Electric Power Research Institute (EPRI) for controlling the pH of the reactor coolant had been endorsed and incorporated into chemistry procedures.
b.
Review of Units 1 and 2 Secondary Chemistry Controls and System Operations (1)-General Since the last inspection both units had maintained secondary water ~ quality within the guidelines recommended by the Electric Power Research Institute (EPRI) and the Steam Generator Owner's Group (SG0G).
This was evidenced by the fact that very little " hideout return" to the steam generator bulk solutions during cooldowns and heatups had been detected.
(2) Main Condenser There had not been any leaks of circulating water into the condenser in either unit since the last inspection.
Sulfur hexafluoride (SF ) leak detection systems had been installed in
both units.
Portable sonic instrumentation was also being used by chemistry and operations personnel to detect and reduce above-the-waterline air inleakage into the condensate.
As a result, . dissolved oxygen the condenser and feedwater have been l ! maintained well below 5 ppb in both units.
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. ~4-(3) _ Condensate Cleanup Systems Because of resin leakage problems with the originally installed DeLaval condensate filter / demineralized elements, sintered metal elements (Pall Porous Metal membrane) had been installed.
In general, the new elements had been effective; however, there had.
been some fouling problems on the elements that resulted in improper filter precoating in fouled areas.
Retention of resin bead " fines" had been improved by adding a flocculent to the powdered resin prior to precoating the. filter elements, thereby essentially eliminating transport of these " fines" to the steam generators.
The low resin leakage had contributed to the maintenance of low hideout return levels.
The conductivity of the polisher-effluent in both units had usually remained approximately 0.06 us, i.e., essentially pure water.
(4) Steam Generators Curing the past year the cation conductivity of the water in the steam generators of Unit i had varied between 0.13 and 0.15 uS, This high purity reflected not only the purity of the feedwater but also the ' effectiveness of the high blowdown rate (110 gpm per steam generator) in removing soluble and insoluble impurities from the steam generators.
The licensee recovered the blowdown water through a cleanup system that recycled essentially pure water (cation conductivity of 0.06. uS) back to the hotwell of the condenser.
Unit 2 blowdown flow rates had been increased from 65 gpm to 90 gpm per generator.
Westinghouse had approved a further increase from 90 gpm to 130 gpm; however, the licensee was concerned that excessive pipe whip on the blowdown lines might prevent such an increase, At a blowdown rate of 90 gpm cation conductivity of the steam generator water was being maintained between 0.18 and 0.19 uS.
The cation conductivity of the effluent of the blowdown cleanup system of this unit was also 0.06 uS.
Sludge lancing had been performed on all four steam generators on Unit I during the last refueling outage. A total of 101 lbs.
of sludge was removed (about 25 lbs. per generator). The sladge composition was mainly iron and copper (Units 1 and 2 both have moisture separator / reheater tubes fabricated from a copper alloy).
During the upcoming Unit 1 outage steam generators IA and ID t were to be sludge lanced while IB and 1C will be lanced during the next refueling outage. All four steam generators in Unit 2 ______ - _ _ -
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will be sludge lanced during the.next refueling outage of this unit.
Eddy current testing of all Unit 1 steam generators was performed during the first refueling outage in August 1986. Of the tubes selected for inspection, no. indications requiring tube plugging were noted. The only tuoes that are currently plugged are those that failed hydrostatic testing during plant construction.
Because of scheduling opportunities during an unplanned shutdown of Unit 2 during August 1987 (for RCP seal repair) selected tubes of steam generators 2A and 2D were inspected prior to the end of the present (first) fuel cycle. No indications requiring tube plugging were noted.
Again, the only tubes that had been plugged in this unit were those that-failed hydrostatic testing during plant construction.
The. inspectors were informed that Unit I was suspected of having a primary-to-secondary tube leak of approximately 0.2 gallons per day as detected by Xe-133 measurements out of the steam jet air ejector discharge.
The licensee planned to execute a "hotsoak" of all steam generators during the cooldowns preceding each unit's refueling - outages.
The purpose of these soaks is to reduce hideout return; i.e., chemical contaminants that have hidden out in steam generator crevice areas during power operation and which return to the bulk liquid as the temperature is-reduced. The steam generator bulk liquid will be held between 300 F and 350 F while maintaining maximum blowdown for 4 hours or until steam generator blowdown cation conductivities are decreased to less than 2.0 uS and sulfate and ph'osphate concentrations to less than 100 ppb.
The inspectors noted that power transients had had very little effect on the cation conductivity values of blowdown from either unit.
This was an indication that very little hideout return existed in the steam generators.
(5) Summary The inspectors observed that the licensee had effectively maintained primary chemistry well within technical specification limitations and secondary chemistry well within the limits recommended by the SGOG.
Through the installation of improved I condensate polisher elements, increase of Unit 2 steam generator l blowdown rates, effective blowdown polishing, high integrity ' condenser tubes, and the incorporation of EPRI/SGOG action levels into abnormal operating procedure (AP/0/5500/34 " Secondary Chemistry Out-of-Specification") the licensee had i i
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6' greatly' enhanced the ability to maintain contaminants in the feedwater and steam generator water ~ at very low levels.
.c.
Review of the Licensee's Chemistry Control Program-During the period. since the last inspection. in this area the licensee's overall capability -to monitor and control chemistry was considered' to have improved considerably.
The staffing level had remained stable, and on-the-job training (0JT) in both analytical and operational procedures had increased in effectiveness.
Significant changes in responsibilities had been made within the support staff and among laboratory supervisory personnel. Also, the secondary instrument laboratory -had been completed and was equipped with a state-of-the-art inline ion chromatograph for continuous monitoring of key secondary chemistry parameters.
Training of chemistry personnel.was being carried out both by the chemistry staff (0JT) and by 'a recently organized onsite corporate training. department.
New technicians continued to receive basic instructions in chemistry, plant systems, and related topics at an offsite corporate training center.
.The new onsi.te training department was developing a curriculum related to continuing and retraining subjects, including needs that had been identified by the chemistry staff. At the time of the inspection, however, only one lesson plan for power chemistry (primary and secondary chemistry) had been developed.
Training within the Chemistry staff was being focused on qualifying each technician in " mandatory" tasks; i.e., procedures and operating duties where qualification was required bcfore a technician could work alone'on back shifts. The inspectors discussed in detail a' perceived need to expedite the qualification of all members of the chemistry staff to the level necessary to comprthend and carry out the stringent chemistry control recommended by the SGOG and to operate the state-of-the-art analytical equipment that had been obtained for diagnosis and control of plant chemistry.
The inspectors reviewed data related to control of analytical measurements performed during the last year.
The licensee had maintained an acceptable quality control program that had been expanded to include analyses performed with a bench-top ion chromatograph.
However, the inspectors were informed that use of this instrument would soon be discontinued, and all analyses of such parameters as sodium, chloride, and sulfate would be performed by the inline ion chromatograph that had a built in, computerized, quality control program.
The inspectors also audited data acquired in the primary and secondary laboratories during the last year.
All Technical Specifications related to ionic contaminants in the primary coolant [ had been met.
U kewise, the quality of water in the secondary coolant system had been significantly better than the criteria in the SGOG guidelines - again an indication of the low amounts of sludge
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and hideout return in the steam generators.
These data were maintained in a computerized bank that was considered by the licensee to meet the requirements of technical specifications for storage of data. The inspectors found the computerized data bank to be slow to access and to provide information that frequently required refining through repetitive retrievals.
Consequently, this method of information management was considered to be unwieldy for short-term trending and for prompt use by plant management.
The licensee recognized these problems but did not have a remedy at this time.
No violations or deviations were identified.
d.
Biological Fouling i The scope of this inspection module had been expanded during the past year to incorporate a review and assessment of new types of problems resulting from corrosion or degradation of seconda ry system components caused by microbiological (e.g., asiatic clams or corbiculae) and microbiological (bacteria) species.
Both Catawba units obtain make-up water for circulating and service water systems from Lake Wylie. Although asiatic clams are known to inhabit Lake Wylie, no significant problems resulting from larvae transport attachment and subsequent shell growth nad been noted by the licensee in raw water systems.
The licensee continued to be on guard for signs of these asiatic clams. As one precaution, a gaseous , i chlorination system had been installed to kill clam larvae in the make-up water to the Fire Protection System. This static wet system was initially chlorinated in June 1987.
No indications of microbiologically induced corrosion (MIC) had been detected in any Catawba raw water systems.
However, mud deposits were found in shell-side of the containment spray heat exchangers.
Even though no identified MIC problems now exists, iron oxidizing, sulfate reducing-and slime-forming bacteria are known to be present in the raw water. A program to reduce the possibility for bacterial corrosion in the piping and heat exchangers of raw water systems was being followed using the following criteria: Keep raw water systems as clean as possible (chemical clean as necessary), Eliminate stagnant conditions by maintaining flow rates, and Monitor for indication of MIC through a regular sampling and inspection program, t ! - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _
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IE Notice 86-106 - Feedwater Line Break and IE Notice 87-36 - Significant- " Unexpected Erosion of Feedwater Lines As a result of the issuance of Information Notice No. 86-106, Feedwater Line Break and Information Notice No. 87-36, Significant Unexpected Erosion of. Feedwater Line, the licensee had initiated a pipe erosion control program to monitor pipe wall thinning in potential problem areas.
A corporate committee was developing a document designed to give all Duke Power Co. Nuclear Power Plants guidance for initiating and/or expanding site specific inspection programs. At Catawba, some ultra-sonic testing of piping was. performed in 1983 based on an earlier pipe rupture at the Oconee facility and on problems noted at the McGuire f acility. At the time of this inspection, no additional testing had been performed as the result of the Surry event (i.e., in single phase systems) but such a program was under development. The licensee planned to. inspect as many of 142 potential prcblem areas as possible in each unit during the upcoming outages. Catawba Station Procedure PT/0/B/4600/18, Periodic Inspection of Piping Wall. Thickness, had been developed and was in the approval process.
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