IR 05000327/1987033

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Insp Repts 50-327/87-33 & 50-328/87-33 on 870518-20.No Violations Noted.Major Areas Inspected:Plant Layup,Plant Chemistry & IE Notices86-106 & 86-108
ML20215L661
Person / Time
Site: Sequoyah  Tennessee Valley Authority icon.png
Issue date: 06/01/1987
From: Kahle J, Ross W
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20215L651 List:
References
50-327-87-33, 50-328-87-33, IEB-82-02, IEB-82-2, IEIN-86-106, IEIN-86-108, NUDOCS 8706260138
Download: ML20215L661 (9)


Text

{{#Wiki_filter:. / So afog% UNITED STATES NUCLEAR REGULATORY COit4 MISSION [ ,$ REGION ll g ,j 101 MARIETTA STREET, N.W.

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, JUN 0 81987

Report Nos.: 50-327/87-33 and 50-328/87-33 i Licensee: Tennessee Valley Authority , 6N38 A Lookout Place s 1101 Market Street Chattanooga, TN 37402-2801' Docket Nos.: 50-327 and 50-328 License Nos.: OPR-77 and DPR-79 Facility Name: Sequoyah Inspection Conducted: May 18-20, 1987 8/ b Inspector: f

W. J./ 6ss' Date Signed Approved by: - [[. h-/-27 et g J. B. Kahle, Section Chief Date Signed r Division of Radiation Safety and Safeguards l SUMMARY Scope: This routine, announced inspection was conducted in the areas of plant layup, plant chemistry, and IE Notices 86-106 and 86-108.

Results: No violations or deviations were identified.

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.. .. REPORT DETAILS 1.

Persons Contacted licensee Employees L. M. Nobles, Plant Manaoer ~

  • H. R. Rankin, Manager of Projects
  • B. S. Willis, Superintendent of Operations and Technical Support W. L Williams, Chemistry Group Manager
  • D. G. Amos, Radiochemical Laboratory Supervisor J. Anthony, Operations Supervisor

, J. Bates, Corporate Chemistry Program Manager ! D. Cross, Shift Engineer i D. Goetcheus, Steam Generator Project Manager R. Phillips, Materials Engineer Nuclear Regulatory Commission K. Jenison, Senior Resident Inspector

  • Attended exit interview 2.

Exit Interview The inspection scope and findings were summarized on May 20, 1987, with those persons indicated in Paragraph 1 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 i as proprietar,y any of the material provided to or reviewed by the ! inspector during this inspection.

3.

Licensee Action on Previous Enforcement Matters Thissubjectwasnotaddressedintheinspection.

4.

Plant Chemistry This inspection consisted of a re-assessment of the degree to which both Sequoyah units had been protected against degradation of the primary ' coolant pressure boundary since both units were shutdown in August 1985.

In addition, the inspector reviewed activities taken by the licensee since the inspection in February 1986 (see Inspection Report No. 86-14) to upgrade the design of the, plant and to improve the Chemistry Control program to minimize corrosion during plant operation.

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a.

Layup of Unit 1 and Unit 2 (1) Unit 1 As discussed in Inspection Report 86-14 during, the initial six months after shutdown Unit 1 underwent routine refueling maintenance as well as major modifications that required the steam generators to be drained.

These activities continued

throughout 1986.

Consequently, the steam generators had been cycled through periods when they were filled with chemically i treated water under an atmos)here of nitrogen and other periods i when the steam generators hac been drained and were open to air.

' As reported in Ins aection Report 86-14 ' the condensate and feedwater lines in Jnit 1 had been drained during the initial six-month period of the extended outage so that feedwater heaters 1, 2, and 3 and the MSR tube bundles could be replaced.

During the subsequent fifteen months the hotwell-condensate-feedwater train had been in wet layup with the demineralized , water treated with ammonia and hydrazine.

Water was pumped

through this train as far as the feedwater isolation valve and then back to the hotwell to reduce the possibility of general corrosion of the carbon steel, pipe.

However, the effectiveness of this layup procedure was diminished by two factors.

First, the presence of hydrazine in the water had little effect on the ] , oxygen content because the water in the hotwell was being a continually saturated with. air and the ambient temperature of the water did not favor the reduction of dissolved oxygen by hydrazine.

A second problem was the licensee's inability to cycle water in the steam generator and in the entire hotwell-condensate-feedwater train at the same time because of a design deficiency in the steam generator recycling system.

Consequently, whenever the water in the steam generator was being circulated (approximately twenty-four hours per week) the water in the hotwell had to be recycled through an abbreviated . ' loop that left part of the feedwater lines temporarily in a stagnant condition.

The condensate polishers had been bypassed since the units had shutdown.

Consequently, the purity of the layup water had been continually degrading as the result of buildup of solids.

An audit of chemistry data acquired during the period March 1986-March 1987 indicated that the desired control of the hotwell-condensate-feedwater chemistry had not been maintained, e.g., much of the time the pH was not within 8.8-9.2 limits (no ammonia results were available for comparison); hydrazine residuals were only infrequently > 0.5 ppm in contrast.to a desired concentration of 25 to 50 ppm; and the concentration of dissolved oxygen was 4 to 5 ppm rather than < 100 ppb as > recommended by the SG0G Guidelines.

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3 ' i When this unit had been shutdown, the high pressure carbon steel pipes (steam lines, extraction steam lines, heater drains and vents) had been drained and left 'op'en to air.

The licensee ,' stated that these lines had been inspected to ensure no moisture accumulation [had] occurred."

The reactor coolant system had remained filled' with i demineralized water with approximately 2,000 ppm of boron for j reactivity control.

Technical Specification limits for . chloride, fluoride, and dissolved oxygen -had been maintained.

'! ' Because of the absence of lithium hydroxide, the pH of the reactor coolant had ranged from 4.5 to 5.2.

Such a low pH was

acceptable for stainless steel systems but would have caused ' general corrosion of carbon steel pipe.

l (2) Unit 2 This unit had been shutdown in August 1985 and both the steam generator and condensate-feedwater pipe had been placed in chemically-controlled layup conditions in anticipation of a short outage.

When startup was delayed in early 1986 the steam generators had been drained for 30 days (May-June) to allow the steam generators to be sludge lanced and the J-tubes 'to be replaced.

These generators were again drained and refilled in July 1986 to reduce the concentration of dissolved copper that had built up.

Sebsequently, the steam generators had again been placed in wet layup in anticipation of startup.

The condensate-feedwater had been recirculated in wet layup until November 1985, when this train was drained. (until April 1986) to allow changeout of Nos.1 and 2 feedwater heaters.

Subsequently, the MSR tube bundles had also been replaced.

Since October 1986 this train had been in normal wet - layup with the condensate polishers bypassed.

As in Unit I the high pressure steam and drain lines were drained in August 1985 and layed-up in an air environment.

The reactor coolant system also was layed up with borated (2,000 ppm boron) water being cycled by an RHR pump.

(3) Future Plans for Layup In March 1987 EPRI adopted dry layup for extended outages and published a reference document that contained proven plant'layup and equipment preservation techni, ques.

Personnel from the Tennessee Valley Authority authorea significant portions of this document.

As the result of its background work the licensee is proposing to place the following components of Unit 1 in dry layup by approximately August 198.. ..

l - main steam - turbines and MSRs

- feedwater heater shells condenser /hotwell - - condensate i feedwater - Dehumidifiers had been acquired that will provide 600 standard cubic feet per minute (SCFM) of heated and dehumidified air that is calculated to be able to remove ~ 250 gallons of water (as humid air) per day.

Preliminary activities will include the development of procedures, construction of ducts and skids, and i draining and cleaning the hotwell.

. Plans were also being made to place the main steam lines, MSRs, and turbines in Unit 2 in dry layup; however, these plans will be contingent on the startup date for this unit.

j i All steam generators in both units are scheduled to remain in j wet layup using All Volatile-Treatment (AVT) Chemistry Control

of pil and oxygen until startup.

(4) Assessment Until the recent publication of.the EPRI document, Plant Layup and Equipment Preservation Sourcebook, the nuclear industry had very little chemistry and environmental control guidance during U , construction and outages.

As stated in this document "as... operating plants experienced outages of significant length, the component damage and system contamination occurring during this , idle time has become greater, to the extent that plant startup

schedules or the ability to keep the plant operational are sometimes affected."

For several reasons neither the steam generators nor the low and high pressure carbon steel components of the secondary water cycles of the two Sequoyah units had been layed up effectively since August 1985.

The principal reason for this deficiency was the inability of the licensee to exclude air from wet / humid systems during this period.

This problem was identified in Inspection Report 86-14, but had been exacerbated during the intervening 15 months before the current inspection.

The licensee had bee 1 unwilling or unable to provide enhanced protection because piant modifications continued to be scheduled as the outages were extended.

Long-term layup in a dry condition had not been considered consistent with tentative startup schedules.

As the consequence, it is predicted that widespread oxidation of all carbon steel components has occurred during the past 21 months and will require extended startup cleanup of the low-and high, pressure pipes of the secondary system.

The inspector was informed that approximately four weeks will be scheduled for such cleanup,iod 'only between although the most current schedule specified a cleanup per q i

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July 29-August 8, 1987.

SimIlsrly..layup of the steam generators at relatively high pH levels (9.a-10. 5) resulted in the dissolution of significant amounts of copper from the inner i surfaces of the steam generators.

This copper was thought to have been transported from copper alby tubes in feedwater heaters, the MSRs, and, possibly,7from the main' condenser of each unit and should be removed bef6re startup tcr minimize copper induced stress corrosion of the steam generators.

) General oxidation (rusting) of carbon steel systems will be reduced or stopped when the environments of these systems become dehumidified; however, the iron oxide (he.v.atite) already formed .i on the surfaces of these systems should be'r'ema/ed so that more resistive films of magnetite can be developed during' p'lant startup under controlled chemistry -conditio,s.

The NRC i inspector discussed with licensee representatives the need for i special attention to be given to regions that may have been stagnant, partially filled with water, or subjectid to earlier erosion / corrosion by wet steam.

If either or both of the Sequoyah units remains shutdown for significantly longer periods, the licensee should consider the protection of other components, such as pumps and valves that may degrade faster in dry environments than under wet conditions.

b.

Component Modifications and Inspections I During the 15 months since Inspection 86-14 the licensee..had continued to make modifications in the design and operation of some of the components of the secondary water system that impact the effectiveness of chemistry control.

These activities are-summarized as follows: (1) Cooling Water Systems The inspector was informed that bacteria had been identified in the lake water that is used for condenser cooling and in the Emergency Raw Cooling Water (ERCW) System.

Microbiological induced corrosion (MIC) had resulted in pinhole leaks in welds associated with ERCW piping.

The licensee had initiated a system-wide program to identify and control potentially detrimental biological conditions in the various reurvoirs of the Tennessee River that are used for cooling water for the four t TVA nuclear plant sites.

This program will be coordinated with layup programs.

(2) Condensate Polishers The inspector was im'ormec that the condensate palishers had been bypassed throughout the extended outages.

The licensee did not consider the condcnsate cleanup systems to be effectively a =

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,- , e' . o ) ' ' " > t , [[ ', i[ / maintaining high purity feedwiter because 'of the difficulties y inVoNec/ in preventing leakagb 'of sodium as well as regenerant .' chemicaM; e:g'.', hydroxide &nd sulfate ions.

The demineralizers will-be use'd to clean up all caroon steel systems during startup ' and.will t).en be replaced with new cation and anion resin beds.

before plant"startup..The licehsee informed the inspector that consideration-was. being given to bypassing 'the condensate l polishers if the purity of th'e feedwater could be kept within j ' the limits recommended by the Steam Generator Owners Group ,, (SG0G) by use of steam generator-blowdown alone. -The inspector discussed alternatives of improving the regeneration procedures i so that 100% polishing could be. continued with the goal of ' achieving feedwater of maximum purity.

1 (2) Feedwater Heaters J l As; previously discussed, the copper alloyEtubes in Feedwater i Heater Nos.1, 2 and 3 had been replaced with stainless steel.

tubes..However, the other four heaters in each unit still had

copper alloy tubes that will continue to be a source of copper and.a-potential source of stress related corrosion in the steam generators.

The inspector was informed that the : remaining copper. alloy tubes would be replaced during future, refueling outages.

(3) Moisture Separatoi Reheaters All of the copper alloy tubes in the MSRs-had been replaced with

stainless steel tubes while the two units had been shutdown.

' (4) Steam Generators

During the extended outages for both units the licensee had' " replaced the "J" tubes in "the feedwater rings because of i erosion / corrosion at the base of the carbon steel tubes.

The replacement tubes were fabricated from alloy 600 (inconel) to i

Drevent future degradation.

~ , fhe Row 1 tubes in all steam generators ha'd been heat treated to < reduce stress levels in the U-bends where stress-induced ! crycicing had been encountered.

As the result of eddy-current testing of l steam generator tubes in Unit 2 in August 1986, no i tube plugging limits (40% through-wall indications) were ' . identified; however, 24 tubes in Rows 1, 2, and 3 (mostly Row'1) were preventatively plugged. due1 to ' the. detection of-nonquantifiable U-bend imperfections.

While both units were shutdown the licensee elected to sludge lance the four steam generators, in May 1986, even though this < ' unit had o>erated less than eight months-since the steam generators lad last been sludge lanced.

Although the earlier ! . . .l

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cleaning had removed - relatively. small amounts of sludge.

(~.125-145 poundsF from each" steam generator, considerably more oxide sludge had been removed in. the followup lancings, i.e.,)- 231 pounds, 475 pounds, 323 pounds, and 303 pounds. (wet weight from steam generators 1, 2, 3, and.4 respectively.

Also, as discussed earlier,.significant amounts of copper :were subsequently. removed in July 1986 by bleed and feed procedures.

-These data indicated.that either. the lancing during the last refueling outage'had not,been as efficient as previously thought or else oxidation of carbon steel )ipe -and copper alloy .feedwater. heater (and MSR). tubes hac been progressing at an undesirably. high rate during.the initial eight months of operation after.the refueling outage.

c.

Water Chemistry Program Through discussions with. members of. the licensee's corporate and plant chemistry staffs the inspector reviewed the status of the.

elements of the Sequoyah water chemistry program in relation to' peasible restart of Unit 2 within the next three months.

Since the .nspector's last' site visit major organihtional changes had been made in both plant-management and the chedistry group.

Rather than reporting to the Plant Manager through the Engineering Department the Chemistry Group Manager and his staffncurrently were reporting to the Superintendent of 0perations and Technichl Support.

The Chemistry' Group had also been reorgaitized into five groups with

responsibilities 3 in the tsilowing areas: - environmental c'oncerns, radiochemic41 labdratoFu training, ' pQnning and1s;dministration. quality control; technical supp) ort s The - majority (40 of the 56 member staff under the Chemistry Group Manager was under the Radiochemical Laboratory Supervisor and the three laborator supervisors (analyticil,- countihg room, and instrumentation) ywho report to him.' Chemis'try control will be provided by twenty four analysts'who will be divided into five shifts supervised by six shift supervisors.; In addition to sup, port proviaed by an eight member group of specialists on the chemistry staff, the licensee will be able to use the resources of a newly, appointed Corporate Chemistry Prog"am Manager.

i, The inspector was informed that the last year had been used to initiate ~ adecuacy reviews of other elements of the chemistry pro, gram (e.g., procec ures, training, and equipment): in. an effort to achieve desired levels of chemistry control during shutdown and startup, as well as to improve the long-term capabilities of the Chemistry Group.

The inspector stressed the advdritages of regaining maximum stability' in all elements of the chemistry' program prior to restart of the-plant.

No violations or deviations were identified.

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5.

Information Notice (IEN) 86-106, Feedwater Line Break

i The inspector reviewed the licensee's activities that had been taken in response to this Notice related to the erosion / corrosion and subsequent rupture of carbon steel feedwater lines at the Surry Nuclehr Power Plant in December 1986.. This review showed that an inspection program had been i implemented to identify wall thinning in suspected pipe and other components that appeared to be vulnerable to erosion / corrosion because of material composition, water chemistry, flow velocity, flow path geometry, J and fluid temperature.

So far these inspections had not revealed any ] major' damage to the condensate-feedwater system, although isolated damage-was found in Unit 2 feedwater regulating valves.

The corresponding areas in Unit I had not been inspected.

The licensee had initiated a similar surveillance program in 1984 to monitor the extraction steam systems of both units.

Recent examinations of heater drains and vent systems in Unit 2 identified two phase flow damage at one elbow and minor damage on two vent lines.

All degraded fittings were scheduled to be replaced with more resistant material by May 1987.

q Previous experience had revealed significant damage to the bases of carbon steel "J" tubes in the steam cenerator feedring where water velocity" exceeded 20 feet per second.

The inspector was informed that all "J { tubes had been replaced with inconel tubes that had been built up at the i base to increase resistance to erosion.

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Information Notice 86-108, Degradation of Reactor Coolant System Pressure Boundary Resulting From Boric Acid Corrosion The inspector established that the licensee had verified that all nozzles and piping in the main reactor coolant loops and injection lines had been fabricated from stainless steel and therefore, were less vulnerable to boric acid attack than the ferritic, components discussed in this Notice.

< Action previously taken in response to IE Bulletin 32-002 and SOER 84-005 ' had resulted in the development of procedures for determining leakage and leak rate from borated water systems and for establishing the consequence of such leakage.

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