IR 05000327/1988038

Insp Repts 50-327/88-38 & 50-328/88-38 on 880725-29.No Violations or Deviations Noted.Major Areas Inspected:Plant Chemistry,Corrosion Control & Pipe Wall Thinning

ML20154R200
Person / Time
Site:	Sequoyah
Issue date:	09/15/1988
From:	Kahle J, Marston R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20154R153	List: IR 05000327/1988038 ML20154R149
References
50-327-88-38, 50-328-88-38, NUDOCS 8810040195
Download: ML20154R200 (12)

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.j. ...,k y' UNITED STATES E NUCLEAR REGULATORY COMMISSION

'E REGION ll

/ 101 MARIETTA ST ,,,,, ATLANTA. GEORGIA 30323 SEP 151968 Report Nos.: 50-327/88-38 and 50-328/88-38 Licensee: Tennessee Valley Authority 6N38 A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name: Sequoyah 1 and 2 Inspection Conducted: July 25-29, 1988 Inspector:

R. R. Marston s W

' Date Signed Accompanying P nnel: W. J. Ross Approved b : M d [ c 2 A ct

.B Iahle, Section Chief 9//hN Dhte Signed iv sion of Radiation Safety and Safeguards SUMMARY Scope: This routine, unannounced inspection was in the areas of plant chemistry, corrosion control, and pipe wall thinnin Results: The licensee had maintained good chemistry control of Sequoyah Unit 2 during the startup of this unit after an extended outag Considerable attention and resources were being directed towards such key secondary water system conponents as the steam generators, condensate polishers, and makeup water treatment plant as well as to increased surveillance for pipe thinnin The Essential Raw Cooling Water System was continuing to be degraded by microbiological induced corrosio The licensee was initiating actions to restart Unit 1. The secondary coolant system and steam generators of this unit were still layed up dr Major elements of the licensee's chemistry control program (such as stabilizing staffing, finalizing procedures, and implementing online analytical instrumentation) were still not complet However, the licensee's program met the intent of Technical Specifications, Generic Letter 85-02, and the SGOG/EPRI guidelines for PWR chemistry contro The use of a single, crowded laboratory to implement radicchemistry analyses, trace-level non-radiochemistry analyses, and environmental chemistry work was considered to be less than adequate, h$kU$DOCKObObO$27 o PDC

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2 SEP 15BB3 No violations, deviations, or program weaknesses (other than stability of staffing)wereidentifie . J

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REPORT DETAILS l Persons Contacted

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4 Licensee Employees .

D. Adams, Technical Support Supervisor, Chemistry Group J. Barker, Instrumentation Supervisor, Chemistry J. Bates Manager, Corporate Chemistry Support Group

*D. Briggs, Supervisor, Materials Technology

*R. Burch, Chemistry Supervisor, Chemistry Group E. Camp, Mechanical Engineer, Steam Generator Group

• D. Craven. Assistant to the Plant Manager E. Elam, Mechanical Engineer, Steam Generator Group

• G. Fiser, Manager, Chemistry Group l

• D. Goetcheus, Manager, Steam Generator Group '

M. Ira, Chemical Engineer, Corporate Chemistry Support Group ,

D. Kelley, Manager, Water and Waste Process Group M. Koss, Engineer, Materials Technology P. Maclaren, Process Control Supervisor, Chemistry Group

W. Nestle, Chemist, Corporate Chemistry Support Group j B. Roberts, Engineer, Materials Technology j W. Williams, Chemical Engineer, Water and Waste Process Group j Other licensee employees contacted during this inspection included chemistry, technicians, and administrative personne

NRC Resident Inspectors

K. Jenison j *P. Harmon i l l * Attended exit interview  ! Plant Chemistry (79701)  !

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This inspection was a continuation of a program designed to assess the ;

j licensee's capability to prevent degradation of the primary coolant i

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pressure boundary, in particular, as well as other plant components from ;

corrosion and/or erosion. During this inspection major mphasis was given '

I to the status of the secondary coolant system of Unit c after restart of

! this unit from an extended outage during which this system had been layed up wet, in addition, because of major changes that had been made in the i chemistry staff during the past six months, the principal elements of the

licensee's water chemistry program were reviewed and assessed for their effectiveness in providing the level of chemistry control reconrended for l PWRs by the Steam Cenerator Owners Group (SG0G) and the Electric Power '

Research Institute (EPRI).

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a. Effectiveness of Components in Providing Protection Against Corrosion and Erosio At the time of this site visit, Unit 2 was operating at essentially full power after restart, in May 1988, from an extended outage (since August 1985). The licensee plans to restart Unit 1 (in its fourth fuel cycle) in the near future, and then reduce the power level of Unit 2 so as to extend the current fuel cycle (that was interrupted by the outage) until the e.',d of 1988. Unit I remained in dry layup throughout this inspection; consequently, the status of the components of this unit was not addresse By means of discussion with cognizant licensee personnel and through an audit of chemistry control data, the inspector reviewed the performance of the major components of the Unit 2 secondary cooling cycle during the period since the last inspection in this area in May 1987 (see Inspection Report Nos. 50-327/87-33 and 50-328/87-33).

During all of this period the secondary cooling cycle had been layed up wet, under AVT (all-volatile treatment) chemistry control, with chemically treated water in the Steam generators, and chemically treated water in the condensate /feedwater lines circulating in a

"long cleanup cycle" but bypassing the condensate polisher (1) Main Condenser During the past year, the li:ensee took two positive actions to ensure the integrity of the main condenser as a barrier against ingress of potentially cerrosive species in the condenser cooling water (water fret the Tennessee River /Chickamauga Reservoir). On December if, 1987, a new Technical Instruction (TI-111 Sequoyah Nuclear P, int Condenser Integrity Program) was issued. This instruction wis written, in part, to meet she intent of NRC Generic 1.etter 85-02 to enhance overall condenser integrity and promote sttam generator preservatio Responsibilities were shared by the Operations Group (for operating and monitoring cond.1ser condition), the Mechanical Maintenance Group (for inspect 99 and cleaning the condenser's tube sheets, water boxes, and tsbes), the Chemistry Group (for establishing chemistry criteria for controlling operating parameters for the condensers), and the System Engineering Section (for monitoring unit pow r levels to determine if condenser leaks have caused reduct U ns in power).

Also in Dr.cember 1987, the licensee itrformed eddy current tests (ECT) on approximately five percent 'f the 58,860 condenser tubes in Unit 2 to ascertain the exte.'t of attack on the 90-10 copper-nickel tubes that may have *esulted from debris (e.g., pitting or other forms of under-Jeposit attack).

Although these tests indicated widespread n11 loss damage, further examination of two pulled tubes did n3t confirm these data. However, evidence of pitting was observed and attributed J

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to reduced water flow through the tubes and waterboxes. No condenser tubes were plugged as the result of these ECTs; however, the licensee planned to place increased emphasis on maintaining flow and inspection / cleaning of condenser tube i During the interval since startup of Unit 2 no water leaks had been observe Consequently, the quality of water in the condenser hotwells and condensate remained high (e.g., ,

concentrations of sodium, chloride, and sulfate less than 1 ppb).

Inleakage of air into the condenser was relatively high (greater i than 30 SCFM) throughout this period; however, these leaks did ,

not adversely affect the dissolved oxynen concentratien of the i hotwell water (typically less than 3 ppb). Leakage of air in the cendenser was considered to be detrimental to the -

copper-nickel condenser tubes and possibly to the low pressure turbine rotors and disks. Consequently, the licensee had an >

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cngoing program to identify and repair air leak '

(2) Essential Raw Cooling Water (ERCW) System During the extended outages microbiologically induced corrosion (MIC) had been observed extensively throughout the ERCW piping, especially in weld region The licensee had repaired or t replaced sections in Unit 2 that had through-wall indications (i.e., weeping of ERCW water) prior to this unit's return to :

power. However, the inspector was told that more recent tests :

had identified new leaks (ten in Unit 2 and seven in Unit 1) in ;

stainless steel ERCW line ;

The licensee stated that MIC attack had been observed also at l some of the licensee's other nuclear power plants, consequently, '

a comprehensive search for an effective biocide had been ,

initiated at the corporate leve During the interim, the ERCW l water at Sequoyah was being chlorinated (to obtain a residual I chlorine level between 0.2 and 2.0 ppm) in an attempt to control :

the of tensive microorganisms. At the time of this inspection '

plans were being made to augment the chlorination agent (sodium hypochlorite) with water-soluble compounds that contained ;

bromine and a dispersan The inspector was informed that '

samples of materials that will come in contact with this experimental mixture of biocides had been tested for corrosiveness and determined to be acceptable. The licensee agreed ta keep the NRC apprised of all chemicals being used and the results of corrosion rate measurements being taken during these studies. This matter will be followed as an inspector followupitem(IFI) 50 327, 328/88-38-0 (3) Water Treatment PlantiMakeup Water System As will be discussed further in Paragraph 2.a(4) of this report, the licensee continued to require large amounts of demineralized

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water for regenerating condensate ' polishers as well as for 6 l makeup purposes. At the time of this inspection the output of ,

i the water treatment plant was being adversely affected by ;

l mechanical problems related to the agitator in the clarifier l tank, Consequently, sufficient demineralized water ,

(approximately 50,000 gallons per polisher) was not available to i

! maintain all six condensate polisher beds regenerated and !

J available. The licensee was actively pursuing the cause of the t

mechanical problems with the agitator and attempting to return

the equipment to operatio .

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The product of the water treatment plant was stored in two l

Condensate Storage Tanks (CST), one for each unit. The CST for ;

Unit 1 still had a bladder and nitrogen sparging system that ,

j kept the dissolved oxygen content of the water at less than !

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50 pp (The Unit 2 CST no longer had a bladder but still had a ;

J sparging system.) During this inspection period the cation I

conductivity of the Unit 2 CST water exceeded the licensee's !

administrative limit (i.e. , 0.2-0.3 umho/cm vs a limit of l

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0.15umho/cm). This problem was attributed, in part, to ingress t l of air (carbon dioxide) as the volume of water in the CST was l drawn down during periods when the water treatment plant was t j inoperable, i (4) Condensate Cleanup System  !

l Through a review of startup chemistry data, the inspector f observed that cleanup of the secondary coolant system had j i progressed very efficiently. As mentioned before, throughout ;

i most of the extended outage the icw-pressure lines in the l

! secondary coolant system (condensate-feedwater) had been layed i

up by circulating chemically treated water through the "long I j cycle." During this time the high pressure steam and drain l t lines had been drained but not dehumidified. When the i I

condensate polishers were placed back in service, irrinedtately !

before startup began, they removed both soluble and insoluble !

impurities so effectively that a lengthy "chemistry hold" was l

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not needed when the plant reached powe !

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As the power level increased additional cleanup of the high !

! pressure as well as low pressure lines was achieved by blowing l

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down the steam generators (to waste or cycled back to the l j condensate line) and cycling the drain lines back to the !

j condense Consequently, a second mandated ' chemistry hold' at !

1 30 percent power also had been very brief because the quality of

! the feedwater met the criteria prescribed for combined feedwater j from condensate and feedwater heater drain l l

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Once the plant had reached full power, the licensee had not '

) been able to maintain full-flow polishing of the condensate l because the required five polisher beds could not always be !

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i maintained regenerate However, partial-flow polishing of the I

condensate, including all of the steam generator blowdown j stream, had been maintained with at least two polishers. The l principal cause of the regeneration problem bad been the I shortage of demineralized water and difficulties involved with efficient separation of sulfuric acid from the regenerated ,

resin The chemistry staff had been devoting significant attention to ensuring very high quality feedwater for the steam generators '

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while of 9.0 using )such

- 9.2 that thehigh concentrations cation of amonia polishers resins of the condensate (to ensure a pH -

became saturated with ammonia after a few days use. The polishers were being regenerated whenever sodium concentrations in the feedwater exceeded 1 ppb in an effort to stay below the i sodium limit (20 ppb) established by Westinghouse and the SGOG l for the steam generator wate In an effort to improve the detection of sodium, as well as chloride and sulfate "throw", c the licensee was installing an in-line ion chromatograph to !

monitor the effluents of the individual polisher (5) Feedwater Heaters As reported in Inspection Reporu Nos. 50-327/87-33 and 50-328/87-33 (dated May 1987), the copper-nickel tubes in the ,

high and intermediate pressure feedwater heaters had been replaced by stainless steel tubes during the early part of the extended outage. The inspector could not confirm definite plans !

for the similar replacement of tubes in the four low-pressure l feedwater heater Consequently, the remaining copper-nickel '

heater tubes must be considered a potential source of copper i corrosion products that will be transported to the steam generator (6) The Steam Generators l The steam generators in Unit I had been placed in dry layup !

since the last inspection in this area while those in Unit 2 i remained filled with chemically-controlled and circulating water until restart of this uni In April 1988, a primary-to-Secondary leak had been detected in the "U-bend" region of a .

Row I steam generator tube in Unit 2. All Row 1 tubes were '

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subsequently plugged as a precautionary reasure until these :

tubes could be heat treated for primary stress corrosion crack in (All the Row 1 tubes in the Unit I steam generators !

had already been heat treated.)

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, Recently (July 1988), all plugs in steam generator tubes in Unit I had been removed and full-tube eddy current tests (with an improved probe) had been made of 3263 tubes in the four steam j generator As the result of these tests 62 tubes were l

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t ii replugged because of U-bend indication Also one tube was i staked and plugged as the result of further analysis by L Westinghouse in response to IE Bulletin 88-02 (February 1988), !

relating to the tube break in July 19M. at the North Anna  !

Nuclear Power Plant. A similar analysis of Unit 2 tubes had i been scheduled for the next refvating outage in early 1989. In ;

addition, revisions had been made to maintenance and operations i procedures to upgrade monitoring for primary to secondary leak The limit for radiation releases through such leaks also had j been lowered from 1.0 uti/g to 0.75 uC1/ (7) MoistureSeparatorReheaters(MSR) l During the extended outage, the copper-nickel tubes in the MSRs i of both Sequoyah units had been replaced with stainless steel !

tubes. This action had been taken to increase the efficiency of i the MSRs as well as to eliminate these tubes as a potential i source of copper corrosion products that could be transported to !

the steam generators and initiate tube dentin ;

(8) Pipe Wall Thinning As a followup of IE Notice 86-106 and IE Bulletin 87-01 related ,

to the pipe rupture at the Surry Nuclear Power Pir.nt in i December 1986, the inspector reviewed actions being taken to i prevent pipe rupture at Sequoyah. During the past ye3r two new l surveillance instructions had been issued to cover ultessenic :

testing of localized arets in extraction steam lines as wei! as l feedwater/ condensate piping and turbine / heater drain lines, f5e i inspector reviewed these instructions and also the results of a !

inspection program for Unit 2. Seventy pipe areas (in both i single-and two-phase systems) had been examined for wall i thinning by ultrasonic testin Two areas on the condensate- !

feedwater lines and one area on the high pressure operating vent j lines were found to have been damaged. Significant thinning was 3 found downstream of the 12-inch feedwater valves. All of the damaged pipe sections were subsequently replace The licensee was also trying to minimizo general corrosion of carbon steel pipes by modifying AVT chemistrj control to provide less acidic environments in both sing!e and two-phsse line Even though the secondary coolant system contains copoer-  ;

containing components (condenser tubes and feedwater heater

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tubes) that are more conducive to corrosion at increased concentrations of ammonia, the licensee had increased the pH ,

limits of the feedwater to 9.0- This actior had further !

complicated the operation of the condensate polishers because '

the cation resins were being saturated (loaded) with amonia  !

more quickly and required regeneration more frequently. In an l effort to achieve high pH levels in two-phase lines, such as '

extraction steam lines, as well as in water-solid lines the f

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7 l licensee's corporate chemistry group had initiated an L investigation into use of morpholine as part of AVT chemistry control. Infonnation repoited by EPRI and individual utilities

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f has showa that morpholine may provide increased control because !

I of its greater solubility in the liquid phase of two-phase '

systems. The licensee is directing its study, in part, towards establishing the effect of morpholine on structural materials and ion exchange resin This study will be tracked as IFl 50-327, 328/88-38-02, Feasibility of Using Morpholine for Secondary Chemistry Contro (9) Conclusions The cleanliness of the setondary coolant cycle at the end of the ,

extended outage for Unit 2, as reflected by the short "chemistry ;

hulds" during startup, indicated that the wet layup procedures ;

followed during the cutage had been effective in minimizing '

corrosion. Likewise the integrity of the condenser had been maintained by circulating river water through the tubes ,

throughout the outage. However, the chemical treatment program ,

for the ERCW system had not been effective and continued to require priority attentio The approaching startup of Unit I will require the licensee to make a similar assessment of the '

effectiveness of a wet or drained layup program for two years '

followed by dry layup of the secondary coolant system during the last year. This sub, lect will be designated IFl 50-328/88-38-03, Assessment of the Effectiveness of Unit 1 Layu The licensee was able to maintain chemistry control of both the ,

primary and secondary coolant systems much more effectively than the criteria recommended by the SGOG and EPRI. However, because i of past and potential design / materials problems (especially the i use of copper alloy heat exchanger tubes) and transport of iron and copper corrosion products the licensee was continuing to !

devote considerable resources to protecting the steam ,

generator The additional need to minimize general corrosion :

and thinning of carbon steel pipe had placed constraints on :

plant design and operation, as well as chemistry contro i Consequently, the licensee had taken the additional positive actions of replacing copper alloy components, and enhancing ,

surveillance of the condenser, steam generator, and piping, b. Effectiveress of the Licensee's Water Chemistry Program During his last inspection in May 1987 (see inspection Report Nos. 50-327/87-33 and 50-328/87-33), the inspector had observed that the Chemistry Group had undergone a major reorganization since the extended outage began. The new organization had begun a review and upgrade of the various eierrents of the Sequoyah Water Chemistry Program. However, the licensee had again completely reorganized the Chemistry Group durit.g the past year. All of the maragerial and

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J f i supervisory positions had been filled with new personne The

Chemistry Manager continued to report directly to the Plant Manage j t

i The Chemistry Group currently consisted of 58 personnel including a !

, four-person Environmental Section, a 37-person Chemistry Section, an [

, 11-person Technical Support Section, and a two-person Process Control !

l Section. The Chemistry Section was further divided into three groups i

dedicated to analytical responsibilities (e.g., primary and secondary [

] control, counting room work, and instrumentation specialists). The :

seven shift supervisors and 18 laboratory analysts under the i

). Analytical Supervisor had been grouped into six rotating shif t crew [

Each crew had at least two ANSI qualified analysts in addition to an !

I ANSI qualified shift supervisor. The two analytical chemists and two [

i analysts under the Instrumentation Supervisor were experienced TVA r

! chemistry employees who had been trained as specialists and dedicated (

l to the state-of-the-art manually operated and in-line analytical -

i instrumentation (e.g., icn chromatographs, atomic absorption {

l spectrophotometer, and total organic carbon analyzer). The other t analysts were being, or had been, qualified to perform the remaining !

< analyses involved in primary and secondary chemistry (but not in ['

l counting room activities). A two-year training program, on-the-job

] and classroom, had been designed for this purpos l In addition to the Technical Support Section within the Chemistry I

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i Group, the Sequoyah chemistry program was being supported by a :

{ recently organized corporate chemistry staff. This staff had been !

l involved in the development of a corporate policy statement j 3 (ONP-POL-5.8) and a corporate directive (ONP-DIR-S.8) that '

established philosophy, directions, responsibilities, etc., for the chemistry programs for all TVA nuclear power plants. The inspector reviewed the implementing document for Sequoyah ($tandard Practice t i SQE22 - Sequoyah Nuclear Plant Chemistry program, Revision 10) and ;

] confirmed that the Sequoyah Water Chemistry Program endorsed the (

1 principal philcsophical and technical guidelines recomended by the f i SG0G and EPRI. Consequently, this program was considered to neet the !

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i intent of Generic Letter 85-02. However, the inspector observed that l procedure SQE22 had undergone six revisions during the last l 18 month Also a new corporate standard was being developed to provide further guidance for establishing an acceptable chemistry

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program at each TVA site. The inspector expressed concern that the I

continuing revamping of key elements of the Sequoyah Chemistry l Program would delay development of a stable program and the type of

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chemistry control recommended by the SG0G. The licensee recognized this concern, but considered further changes as bel.19 necessary steps toward achieving an acceptable program, i

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As indicated by the appointment of a Process Control Supervisor, the licensee was emphasizing the need for quality control of all aspects i of the chemistry program to meet the stringent criteria recomended j by the SG0G (as well as by EPRI and the NSSS vendor. Westinghouse) to i prevent corrosio The inspector reviewed the elements of the l

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chemistry quality control program with the process control supervisor and with other supervisory personnel. The inspector also requested that the chemistry staff analyze a series of samples prepared for the NRC by the Brookhaven National 1.aborator These samples were aqueous solutions of chemistry species typically monitored in PWR The purpose of this request was t) make an independent evaluation of and precision and, where relevant, to identify causes for '

i accuracy (i.e., procedure, instrument calibration, comprehension and errors

technique of the analyst). The samples were analyzed in triplicate bythreedifferentanalysts(wherepossible),

i These analyses had not been ccmpleted at the end of the inspection; l bewever, a preliminary assessment indicated that results obtained by ,

i ion chromatography were close to the values established by Brookhaven analysts. These data will be provided to the inspector when all analyses have been completed, and an assessment of the results will

< be issued in a later inspection report. This item will be tracked as

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IF1 50-327, 328/88-38-04 Evaluation of the Non-Radiological

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Confirmatory Measurement Results.

1 The inspector considered the environment within the chemistry  ;

laboratory to reflect a level of professionalism and housekeeping  !

! conducive to good analytical / process chemistr The Chemistry Group l j was equipped with state-of-the-art analytical instrumentation. The j inspector observed two specific conditions within the laboratory that j were brought to the attention of the chemistry personne Both ;

primary and secondary chemistry analyses were being perforned within

the limited space of a single laboratory, thereby reducing control of

! contamination by the radioactive primary samples. Similarly, the i

limited laboratory bench space was essentially covered with analytical instruments and left very little space for other 3

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l activities, such as sample preparation. Especially on the day shift there were as many as five to ten personnel working in the restricted I l area of this laborator Conclusion During this part 9f th0 inspection no violations or deviations were [

identified. The licensee was considered to be sati,factorily l implementing the major elements of the SG0G guidelines and to be t abreast of current corrosion technology. The Chemistry Staff had ,

controlled plant chemistry effectively during the startup of Unit I

The inspector reemphasized the need for stability in staffing,  ;

continuing qualification and requalification of all personnel as t l individuals and as a cohesive team, increased emphasis on quality

, control, making more effective use of in-line instrumentation, and i taking precautions to prevent contamination of the limited laboratory l t spac ,

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3. Followup on NRC Information Notices (92701) (Closed) Information Notice 327.328/88-IN-22: Disposal of Sludge from Ontite Sewage Treatment Facilities. The inspector reviewed documentation which showed that the licensee had reviewed the Notice, acknowledged its applicability, and considered that the subject was not an inmediate problem for the plant, i (Closed) Information Notice 327,326/63-IN-31: Steam Generator Tube l Rupture Analysis Deficienc Tra inspector reviewed licensee

documentation which showed that TVA had been notified of the problem l described in the Information 40tices by Westinghouse in l December 198 The licensee re&nalyzed the Steam Generator Tube Rupture event, using conservative assumptions. As a result of this analysis, the licensee made a commitment to the NRC to institute an interim administrative limit of 0.75 microcuries per gram dose equivalent iodine in the primary coolant (Technical Specification limit was 1.0 microcuries per gram), and to notify NRC if the limit is exceede . Exit Interview The inspection scope and results were summarized on July 29, 1988, with those persons indicated in Paragraph 1. The inspector described the areas l inspected and discussed in detail the inspection result Proprietary I information is not contained in this report. Dissenting comments were not l received from the licensee.

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