ML20084P183

Affidavit of AB Cutter,Supporting Applicant Motion for Summary Disposition of Joint Contention VII Re Steam Generators.Related Correspondence

ML20084P183
Person / Time
Site:	Harris
Issue date:	04/25/1984
From:	Cutter A CAROLINA POWER & LIGHT CO.
To:
Shared Package
ML20084P102	List: ML20084P094 ML20084P120 ML20084P133 ML20084P149 ML20084P163 ML20084P172 ML20084P183 ML20084P188
References
OL, NUDOCS 8405170441
Download: ML20084P183 (37)

Text

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DOCKETEF USNRC UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION $04 MAY17 '

BEFORE THE ATOMIC SAFETY AND LICENSING BOARD i.Ditc&s

. r ., -r ." F S E C P 3RnNCH In the Matter of )

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CAROLINA POWER & LIGHT COMPANY ) Docket Nos. 50-400 OL

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AND NORTH CAROLINA EASTERN MUNICIPAL ) 50-401 OL POWER AGENCY )

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(Shearon Harris Nuclear Power Plant, )

Units 1 and 2) )

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AFFIDAVIT OF ALAN B. CUTTER County of Wake )

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State of North Carolina )

Alan B. Cutter, being duly sworn according to law, deposes snd says as follows:

1. I am employed by Carolina Power & Light Company

("CP&L") as Vice President for Nuclear Engineering and Licens-ing. In this capacity I am responsible for providing engineer-ing and licensing support to all CP&L nuclear power units, including studies and modifications to improve their perfor-mance and reliability. My business address is 411 Fayetteville Street, Raleigh, North Carolina 27602. A summary of my profes-sional experience and qualifications is contained in l l

9405170441 840516 PDR ADOCK 05000400 C PM i

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Attachment A to this affidavit. I was an executive member of the Counterflow Steam Generator Owners Review Group ("CSGORG")

which evaluated the proposed modifications to Westinghouse D-4, D-5 and E Steam Generators. I have personal knowledge of the matters contained herein and I make this affidavit in support of " Applicants' Motion for Partial Summary Disposition of Joint Contention VII (Steam Generators)."

2. This affidavit supplements the Affidavit of Thomas F.

Timmons ("Timmons Affidavit") and the Affidavit of Glenn E.

Lang ("Lang Affidavit"), also made in support of partial summary disposition of Joint Contention VII. Those affidavits set forth, inter alia, Westinghouse Electric Corporation's

(" Westinghouse") recommendations to CP&L with respect to reduc-tion of flow-induced tube vibrations in the D-4 steam genera-tors, utilization of All Volatile Treatment ("AVT") water chem-istry in the Harris Plant steam generators and utilization of a loose parts monitoring system at the Harris Plant. In my affi-davit I will discuss CP&L's adoption of Westinghouse's recom-mendations and also describe CP&L's implementation of other programs that ensure the integrity of the Harris Plant steam generators.

3. Section A of this affidavit verifies that CP&L has implemented Westinghouse's recommendations for design modifica-tions that will reduce flow-induced vibration in the D-4 steam generators.

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4. Section B of this affidavit verifies that CP&L will use AVT water chemistry in the Harris Plant steam generators and describes the design modifications and operating procedures 1 that will ensure the efficacy of AVT in controlling corrosion processes in the Harris steam generators.

5. Section C of this affidavit describes the procedures that will be implemented at the Harris Plant to ensure that loose parts do not enter the steam generator system and also verifies that CP&L will use a loose parts monitoring system de-signed by Westinghouse.

6. Section D of this affidavit describes the (1) Techni-cal Specifications for steam generator tube leakage and (2) monitoring capability to detect steam generator tube leaks, which together ensure that degradation in steam generator tubes will be detected prior to a tube rupture.

Section A

7. Westinghouse has recommended that CP&L modify the Harris Plant steam generators by: 1) expanding 124 tubes at the baffle location and 2) bypassing approximately 18 percent of the flow from the main feedwater nozzle to the auxiliary feedwater system. Timmons Affidavit at 1 28.

8. CP&L has implemented the changes recommended by Westinghouse. CP&L has also committed to implementation of Regulatory Guide 1.121 concerning minimum tube wall thickness sr

4 and plugging criteria for expanded tubes and in-service inspec-tions performed after six and twelve effective full power months. See Timmons Affidavit at 1 41.

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9. I concur in Mr. Timmons' belief that the design modi- l fications recommended by Westinghouse and implemented by CP&L will reduce tube vibration so that tube wear will not signifi-cantly affect the structural integrity of the Harris steam gen-erator tubes. My concurrence is based, in part. on my experi-ence as an active membe- of the steering committee of CSGORG, which was formed in February 1983 for the sole purpose of inde-pendently investigating the technical basis and acceptability of the Westinghouse preheater steam generator tube vibration problem resolution. The Technical Review Committee of the CSGORG, with the support of outside specialized consultants and EPRI experts, has performed an in-depth and thorough investiga-tion of the tube vibration problem and the Westinghouse pro-posed modifications, including a review of the extensive substantiating data, both experimental and in-plant, operation-al data. The Technical Review Committee issued its independent technical report in July 1983 which was reviewed and endorsed by the NRC Staff and was subsequently issued in October 1983 as Appendix B to NUREG-1014. In addition, my acquaintance and fa-miliarity with the detailed aspects of the technical investiga-tion and the substantiation of the adequacy of the design mod-ification, have stemmed from my working relationship with Dr.

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M. G. Zaalouk, who currently reports directly to me and who served as the Chairman of the Technical Review Committee of the CSGORG.

Section B

10. The corrosion problems experienced in pressurized water reactor ("PWR") steam generators have been attributed ei-ther to the utilization of phosphate steam generator water chemistry or as a result of impurities in feedwater interacting with materials in the steam generator and/or balance of second-ary plant. In an effort to minimiz~ the potential for such problems, CP&L has reviewed solutions proposed in steam genera-tor integrity summary reports, EPRI guidelines, and Westinghouse and other consultants' recommendations. CP&L has evaluated its corrosion prevention measures and implemented equipment and systems modifications designed to ensure the efficacy of AVT steam generator water chemistry at the Harris Plant.

11. CP&L will implement corporate AVT water chemistry guidelines in accordance with the EPRI and Westinghouse guidelines, insofar as they apply to the Harris Plant. The major elements of these guidelines can be summarized as fol-lows:

(a) The guidelines establish strict speci-fications and action levels on chemis-try parameters such as conductivity, Q

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chloride, sodium, oxygen and metal corrosion products in the steam gener-ators and feedwater to the steam gen-erators.

(b) The action levels establish strict time limits for return to specifica-tion or require appropriate load re-ductions or shutdowns to prevent steam generator corrosion; (c) The guidelines set forth recommended trouble shooting procedurcs and op-erating actions to determine the cause of out-of-specification conditions and to return conditions to specification requirements; (d) The guidelines include requirements which specify chemistry data analysis trending and forecasting methods to preclude violations of chemistry spec-ifications. Computerized data manage-ment and mathematical forecasting techniques will be used to refine the EPRI and Westinghouse guidelines.

Implementation of these guidelines is illustrative of CP&L's commitment to the preservation of the Harris Plant steam gener-ator integrity.

12. AVT water chemistry, when applied with appropriate guidelines, as described above, will eliminate the phenomenon of phosphate wastage, mitigate or substantially reduce the probability of denting, cracking, intergranular attack and sludge buildup, and maximize the protection of the Harris steam generators from corrosion. These conclusions are based on the recommendations of Westinghouse, EPRI and industry consultants and are corroborated by industry experience with AVT water chemistry.

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13. In addition to the use of AVT water chemistry, CP&L has incorporated certain design changes to implement effective AVT chemistry and ensure the integrity of the steam generators ,

1 at Harris. These modifications are discussed in the following paragraphs and are described in greater detail in an internal 1

CP&L memorandum which provides a " Status Report" on " Steam Gen-erator Integrity Concerns" (Attachment B hereto).

14. The partially-rolled steam generator tubes have been modified to be rolled through the full length of the tubesheets to eliminate the possibility of crevice corrosion in the tubesheet. Attachment B, table 1, 1 3.a.

15. CP&L will implement the use of integrally-grooved condenser tubesheets to monitor and eliminate circulating water intrusion into the condensate system. This is in accordance with Westinghcuse's recommendation that the ingress of impurities into condensate be minimized. See Attachment B, table 1, V 2.f.

16. Copper-nickel condenser tubes will be utilized in lieu of admiralty condenser tubes. This design modification was dictated by the change from lake cooling to cooling tower circulating water and results in much improved condenser tube integrity. Copper-nickel condenser tubes will lower the copper l

corrosion products introduced into the feedwater system. See Attachment B, table 1, 1 2.c. CP&L has also implemented a deep-bed, full-flow condensate polisher which can trap copper

1 corrosion products before entry into the feedwater stream.

Westinghouse has confirmed that copper-alloy condenser tubes, such as those at the Harris Plant, utilized in conjunction with a efficient deep-bed, full-flow condensate polisher are accept-able, and that the risk of steam generator tube corrosion in such systems is low. See Attachment B at 9-10. In combination with the integrally-grooved condenser tubesheets, these modifi-cations will attain recommended EPRI and Westinghouse specifi-cations.

17. CP&L is proceeding to design and install a recirculating wet lay-up system (with nitrogen overpressure) for the steam generators for use during outages. The original Harris Plant Unit 1 design did not include provisions for recirculating the steam generator water inventory during out-ages. The Wet Lay-up System will allow independent recirculation of each steam generator in either direction, thus providing a capability of accurately controlling steam genera-tor water chemistry during idle periods and, thereby, reducing the general surface corrosion of the internal carbon steel sur-faces. Dry lay-up connections to condenser vacuum and nitrogen overpressure are features that will also be included in the Wet Lay-up System to provide protection when Wet Lay-up conditions are inappropriate. See Attachment B at 8-9.

18. The Harris Steam Generator Blowdown System will in- l clude an electromagnetic filter (" EMF") as an additional 1

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measure of water chemistry control to remove impurities in the blowdown and allow recirculation. See Attachment B at 10.

19. In addition to the design modifications described  !

above, CP&L will implement an operational water chemistry con-trol program that monitors and maintains appropriate water chemistry conditions.

20. The ability to monitor water chemistry and ensure the long-term integrity of the Harris steam generators will be fur-ther enhanced by the increase of sampling points in the second-ary steam cycle. See Attachment B at 10.

21. CP&L also intends to implement oxygen control mea-sures to minimize air in-leakage to the Condensate System and remove air from the Feedwater System. See Attachment B at 4-8.

These measures will include the following modifications and practices:

(a) Oxygen levels are included in the chemistry guidelines and action lim-its.

(b) An aggressive oxygen in-leakage con-trol program utilizing in-leakage de-tection techniques (i.e., freon, heli-um or sulfur hexaflouride) will be employed.

(c). A condenser neck bellows water seal will be installed, prior to start-up, at the turbine-condenser expansion joint. In the event of air 1 in-leakage, the water seal, utilized j with appropriate instrumentation and j

control,.will detect and control' leak- i age until the rubber expansion joint can be repaired during an outage. See Attachment B at 5.

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(d) Spray nozzles will be provided in the makeup line from the condensate stor-age tank to the hotwell. A connection at the condenser shell at Elevation 295' will be utilized to inject the condensate above the condenser tube bank and provide additional deaeration for the water from the condensate storage tank. See Attachment B at 8.

(e) The demineralized water and condensate storage tanks will be equipped with rubber seals (bladders) to control the ingress of air and thus oxygen into the system.

22. In summary, steam generator secondary side corrosion at the Harris Plant will be minimized by a combination of sys-tem / equipment modifications and operating procedures, which will maintain recondary systems water chemistry within ctrict limits. Additionally, the amount of corrosion of the Harris steam generators is expected to be significantly less than that experienced at plants using sea water or brackish water because 4

of a lower incidence of intrusion of contaminants such as chlo-rides, sulfates and sodium.

Section C

23. In November, 1982 the Institute of Nuclear Power Operations-("INPO") issued Significant Operating Experience Re-port 82-12, entitled " Steam Generator Tube Rupture Caused by Loose Parts on Secondary Side," which provides design, mainte-nance, inspection, and training recommendations to preclude the introduction of foreign material into the system.

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24. CP&L has committed to an extensive effort to employ the INPO recommendations and prevent the introduction of for-eign material into the steam generators at the Harris Plant.

This effort began at the inception of the construction phase and will continue throughout plant operation.

25. Throughout the Harris Plant construction phase, sys-tem / component cleanliness is controlled by Construction Work Procedure 113. Plant personnel (including contract personnel) involved with steam generator repair and maintenance receive training which emphasizes the importance of preventing miscel-laneous objects (wire, tools, welding rods, etc.) from being left in steam generators. During plant construction, the en-trance into steam generators is closely monitored through the use of construction maintenance procedures. Additionally, CP&L complies with the requirements of ANSI N45.2.8-1975 as it is endorsed by " Quality Assurance Requirements for Installation, Inspection, and Testing of Mechanical Equipment and Systems" Regulatory Guide 1.116, Revision O (June 1976), with the clari-fications set forth in the Shearon Harris FSAR, S 1.8. CP&L also complies with "QA Requirements for Cleaning of Fluid Sys-tems and Associated Components of Water-Cooled Nuclear Power Plants" Regulatory Guide 1.37 (March 1973), and "QA Require-ments for Packaging, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants" Regulatory Guide 1.38, Revision 2 (May 1977), with the clarifications set 1

8 forth in FSAR 5 1.8. The aforementioned inspection, mainte-nance, cleanliness, and procedural controls will ensure compo-nent/ system cleanliness and preclude the introduction of for-eign materials in the Harris steam generators during the Harris Plant construction phase.

26. Prior to plant operation, additional start-up testing, procedural controls, and personnel training will con-tribute to the overall effort to prevent loose parts from ei-ther entering the reactor coolant system or breaking free from the structure within the reactor coolant system. The reactor internals will be subjected to preoperational vibration testing during hot functional testing, see FSAR $ 3.9.2.4, and the re-actor vessel and its internals will experience post hot func-tional test inspections. Those tests / inspections will ensure that flow-induced vibration does not produce loose parts in the reactor coolant system.

27. A fiberoptics system, which will utilize existing sludge lancing ports in each steam generator, will be used to inspect for loose parts in the secondary side of the steam gen-erators prior to and after hot functional testing. See Attachment B at 10-11.

28. Subsequent to hot functional testing, maintenance procedures for work on the reactor coolant pressure boundary and refueling maintenance will include strict closeout instruc-tions. Personnel involved in reactor coolant pressure boundary 4

maintenance / repair, refueling and fuel-handling operations will be trained in the importance of closecut procedures, material and tool inventory control, and the necessity of reporting lesse objects known to or suspected to have been dropped into the reactor coolant system.

29. CP&L complies with "QA Program Requirements (Opera-tion)" Regulatory Guide 1.33 Revision 2 (February, 1978), with the clarifications stated in FSAR S 1.8.

Additionally, Section 17.2 of the FSAR describes the QA program that will assure the quality of all safety-related items and activities during the operations phase. These activ-ities include plant operation, maintenance, repair, in-service inspection, refueling, modifications, testing, and inspection under the operating license. These QA programs will ensure that loose parts do not enter the reactor coolant system during operations, and, therefore, that the integrity of the steam generator system is maintained.

30. In addition to the preventive measures described above, a Westinghouse Digital Metal Impact Monitoring System

("DMIMS") has been procured for the purpose of detecting loose objects in the reactor coolant system and steam generator sec-ondary side. The efficiency and reliability of this loose parts monitoring system is described in detail in the Lang Af-fidavit. The DMIMS to be installed at the Harris Plant will have two sensors located on the outer shell of each steam

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generator, one thirty inches above and one thirty inches below the tubesheet, as indicated in Figure 1 of the Lang Affidavit.

A description of the DMIMS and its operational procedures and the evaluation of the DMIMS for conformance to Regulatory Guide 1.133 previously has been submitted to the NRC, via LAP-83-508 dated October 28, 1983 (Attachment 1 to the Lang Affidavit).

The NRC Staff has completed its review of this submittal, and found the DMIMS acceptable. See " Safety Evaluation Report Re-lated to Shearon Harris Nuclear Power Plant, Units 1 and 2 i

(NUREG-1038)" (November 1983) at 9 4.4.4.

31. If the presence of a loose part is detected, the no-tification of the confirmation of a loose part will be made to the NRC in accordance with the Harris Plant Technical Specifi-cations.

32. In summary the combination of site construction cleanliness controls, personnel training, QA surveillance, fiberscope inspection at start-up and the installation of the DMIMS provides a high level of confidence that loose parts will not be introduced into the reactor coolant system or steam gen-erator secondary side during the construction, start-up, and operational phases at the Harris Plant and of the prompt detec-tion of any such unlikely occurrence.

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Section D

33. The Harris Plant will be allowed by its Technical Specifications to operate with only a very small amount of steam generator tube leakage. First, this leakage is limited to 500 gallons per day through any one steam generator (about

.35 gpm), and second, the specific activity of the secondary coolant is limited to 0.10 microcuries/ gram Dose Equivalent Iodine-131 (Technical Specifications, $$ 3.4.6.2 and 3.7.14).

If either of these limits remains exceeded, Technical Specifi-cations require shutting down the reactor to determine the cause of and repair the leak.

34. Steam generator tube leakage would be detected by the Reactor Coolant Inventory Balance which will be calculated daily when the plant is above 200HF. Also, the Control Room Operator would be aware of abnormal make-up rates because of an audible indication in the main control room of the operation of the Reactor Make-up System (FSAR 9 9.3.4.1.2.3).

35. Activity in the secondary coolant, which would be in-dicative of a tube leak, would be detected by the Steam Genera-tor Blowdown Monitors (ESAR $ 11.5.2.7.1.3) and by the Condens-er Vacuum Pump Effluent Monitor (FSAR S 11.5.2.7.2.9). See also FSAR S 5.2.5.3.6. Technical Specifications also require sampling and analysis of the secondary coolant for gross activ-ity at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

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36. Thus the Technical Specification limits regarding operations with steam generator tube leaks combined with'the various~ ways of detecting steam generator tube leaks -- indica-tive of a possible tube crack or through-wall corrosion --

allow for early detection of steam generator tube degradation-before tube integrity itself is in any way significantly breached. , ,-

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f U'h:'w_ /J, egy Alan B. Cutter I Subscribed and sworr. to before me this /4 % day of May, 1984 l/2.tu e / 4<x, .c Notary Public c)

My commission expires: 6' ,4 5'- [ /

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' ATTACHMENT A i A. B. Cutter - Vice President i Nuclear Engineering & Licensing Department j l

BIRTH DATE: December 16, 1934 EDUCATION AND TRAINING:

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B. S. Degree in Chemical Engineering, University of Rochester, Rochester, New York - June 1956 M. S. Degree in Nuclear Science and Engineering, Carnegie-Mellon University, Pittsburgh, Pennsylvania - June 1972 Advanced Nuclear Power Training Course, U. S. Navy, New London, Connecticut and West Milton, New York - October 1963 Several graduate courses in Nuclear Engineering at University of Idaho, National Reactor Test Site Extension - 1966-1967 Tuck Executive Program, Amos Tuck School of Business, Dartmouth College, Hanover, New Hampshire - 1978 Numerous short courses in Project Management, Architect-Engineer Management, and General Management Techniques -

Westinghouse Electric Corporation, Pittsburgh, Pennsylvania EXPERIENCE:

June 1956 - May 1967: U. S. Navy June 1956 - Naval Officer aboard small combatant. Responsible for gunnery, deck and anti-submarine warfare. Member of decommissioning detail.

February 1958 - Technical Instructor, U. S. Navy Fleet Sonar School in Anti-Submarine Warfare.

June 1959 - Under instruction at Officer Submarine School.

January 1960 - Duty aboard diesel-electric submarine.

Management of Engineering Department during overhaul and operation.

October 1967 - Under instruction at Advanced Nuclear Power School.

April 1962 - Under instruction at Nuclear Power Training Unit, West Milton, New York. Qualified Engineering Officer of the Watch, S3G Prototype.

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October 1962 - Assistant Engineer (main propulsion) aboard ballistic missile submarine under construction, and during i initial operations. Responsible for main propulsion and power generation equipment, reactor plant, and all associated systems. Duties included training and management of personnel, preparation of test and operating procedures, verification of

. contractors' work, conduct of start-up test programs, develop-j ment and supervision of preventive and corrective maintenance

programs. Qualified as Engineering Officer of the Watch.

SSW Plant.

January 1965 - Chief Engineer, SlW Prototype, Naval Reactor Facility, Idaho. Directed operating crew of over 100 in training, operation, maintenance, and overhaul activities.

Responsible for operator qualification program. Conducted reactor system chemical decontamination program; major system overhaul; testing and recovery program after major modifications and redesigned core installation. Qualified as Engineering Officer of the Watch, SlW Prototype.

June 1967 to March 1980 - Westinghouse Electric Corporation, Pittsburgh, Pennsylvania June 1967 - Project Manager, Nuclear Steam Supply System.

Total responsibility for schedule, technical adequacy, and profitability for Westinghouse on three pressurized water reactor projects (Prairie Island 1 and 2, Kewaunee).

Central point of contact between company and utility customers and company and Architect-Engineer. Exercised decision authority on in-house design and procurement efforts, and over subcontractors. Major accomplishment was completion of design and licensing effort, and supply of all major components to the project sites in advance of construction needs.

October 1971 - Program Manager, Fast Flux Test Facility.

l Directed implementation of the reactor systems designer scope of effort at Westinghouse Advanced Reactors ' Division.

Responsible to Project-Manager-(Hanford Engineering Development Lab) for planning, scheduling, financial management, budgeting, procurement, and engineering activities at Westinghouse-Advanced Reactors Division.

March 1973 - Program Manager, Clinch River Breader Reactor.

Directly supervised a staff of 20 managers and professionals controlling the~ planning, scheduling, financial management, cost estimating, cost control, engineered cost reduction and change control activities for the' program covering Westinghouse Advanced Reactor Division's engineering, design,'and procure-ment'of the.CRBR Nuclear Island. Responsible for total. manage-

4 ment and control of the programs of the major systems sub-contractors (Atomics International and General Electric).

Developed overall management requirements guide to interrelate in a common mode, cost, schedule, and engineering design control for the three systems designers, the Architect-Engineer, Project Management Corporation, and the responsible government agency. Developed and maintained effective working relationships among major participants, including negotiating and managing subcontracts with normally competing factors.

June 1975 - Director, Iran Projects. Total responsibility for development and implementation of a six plant turnkey nuclear program, including infrastructure, in Iran (estimated value $8 billion). Developed scope and responsibility des-criptions. Conducted in-country surveys to establish credible cost basing, potential construction contractors, and scope of in-country labor and material availability. Reviewed potential Architect-Engineers and their reference designs for technical -

desirability and applicability of reference plant to high seismic, dry cooling environment.

October 1976 - Manager, Projects Operations. Supervised a group of 34 management and professional personnel providing a broad range of control and support functions to a group of full-scope turnkey power plant projects, both nuclear and fossil, at overseas locations. Participated in development and negotiation of scope and contract terms for construction contractors and Architect-Engineers. Provided executive interface with Architect-Engineers, NSSS equipment supplier and other major contractors for resolution of project level problems and development of recovery plans. Provided standard scheduling and progress management systems. Established corporate position on total plant scope post-Three Mile Island modifications. Provided generic technical solutions to plant problems to attain maximum benefit of replication.

Developed standards for field installation and procurement.

Established mechanisms and methods for upgrading plants under construction for revised regulatory requirements. Provided engineering support for modifications to operating units.

April 1980 to Present - Carolina Power & Light Company, General Office, Raleigh, North Carolina April 1980 - Employed as Manager, Nuclear Power Plant Engineer-ing Department. Responsible for engineering and procurement of engineered equipment and material for new nuclear power generating units, and engineering for studies and modifications to improve performance and/or reliability of existing nuclear power generat-ing units; and for effective management of human and. economic resources of the Nuclear Power Plant Engineering Department and contacts with Architect-Engineering firms.

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f January 1981 - Department name changed to Nuclear Plant Engineering.

March 18, 1981 - Elected Vice President, Nuclear Plant Engineering Department.

August 1983 - Department name changed to Nuclear Engineering

& Licensing. Responsible for providing the engineering and licensing support to all Company nuclear power units; including studies and modifications to improve their performance and reliability.

STEAM GENERATOR RELATED EXPERIENCE Mr. Cutter is responsible for the engineering, specification, and procurement of replacement steam generator heat exchanger assemblies for the Robinson Nuclear Project, and is responsible for identifying, scoping, engineering and designing the sup-port system modifications being implemented at Robinson to -

ensure maximized lifetime of the replacement units.

Mr. Cutter was the CP&L executive member of the Counterflow Steam Generator Owners Review Group, which performed an independent technical review of the Westinghouse modification program for the Model D4, D5 and E preheat steam generators.

In this capacity, he reviewed the results of the Technical Review Committee deliberations and the Owners Group report and participated in technical presentations with Westinghouse and the NRC, PROFESSIONAL SOCIETIES Profe.sional Engineer, North Carolina, Registration No. 10065 American Nuclear Society

ATTACllMENT B s

P e See Carnuna Power & Light Company Company ccmooneense g g RIDE-103-11X-XIX 1DfFD440242 RXS0-101-104-XIX MAY 15 584 ME40RANDUM T0; Mr.1. A. Watson PRIDI: A. B. Cutter

SUBJECT:

Report on Steam Generator Concerns for 5frNPP Attached is a report en the above subject, which documents design deciefons to assure that state-of-the-art technical information has been reviewed, evaluated, and utilized as appropriate to improve the SHNPP steam generators and associated support systems.

Assistance in identifying and in resolvine steam generator concerns was solicited and input received by cognizant costpany organizations. We believe that the results of this cooperative effort will assure a high degree of reliability and eatended life for th SiO4PP steam generators.

s i LIL/ RAS / jam (9156)

Attachment cc: Dr. T. S. Ellesen Mr. J. Barnese Hr. L. I. Ioflin Mr. M. A. McDn.ffie Nr. 3. NeManus Mr. J. L. Willis Mr. 5. R. Zimmerinen Mr. B. H. Webster D r. M. O. Zaalouk l

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I STEAM GENERATOR INTEGRITY CONCERNS

! SHEARON HAPRIS NUCLEAR POWER PLANT UNIT 1 4

DECISIONS AND ACTIONS i.

i A STATUS REPORT

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. ATTACHMENT TO HNPD-840242 l

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e CONTENTS I. Executive Summary . . . . . . . . . . . . . . . . . . . . 1 I

II. Background . . . . . . . ... ........ . ... . 2 I III. DISCUSSION . . . . . . . . . ...... ... ... . . 3 A. Introduction . . . . .... .......... . . 3 B. Air In-Leakage Control and Oxygen Removal . .. .. 3 C. Corrosion Control . .. .. .. ........ . . 8 D. Miscellaneous Modifications ..... .. .... . 10 .

E. Comparison of SENPP Unit 1 and HER Unit 2 ... .. 12 Modifications l IV. ConcluSfons . . . . . . . . . ...... . ..... . . 15 V. References . . . . . . . ......... ..... . . 17 i

e I. Executive Summary This SHFPP Unit I report summarizes the decisions and actions that resulted from industry and corporate steam generator  !

integrity concerns. In addition, this report:

0 Responds to the December 1982 NPED paper that compiled known steam generator problems and possible solutions from internal sources, INPO documents, EPRI studies, govern-ment-sponsored research, and other nuclear industry sources O compares existing plant design against the original design and potential upgrades 0 Discusses the rationale for recent systems and equipment change /no change decisions made in response to indus-try-proposed solutions ,

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O Evaluates differences between SHNPP Unit I and H. B. Robinson Unit 2 modifications 0 Documents that actions taken throughout the project history are adequate to ensure the proper operation of SHNPP Unit I and do not preclude the incorporation of additional steps as may be warranted by operating experi-ence.

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i II. Background l

Steam generator problems experienced by operating PWR plants have resulted in numerous recommendations for plant design, mate. rials, and operations changes. The problems encountered (e.g., tube wastage, denting) are primarily due to the corro-sion induced by improper water chemistry control and inadequate oxygen control. Many of the industry proposed solutions initially address water chemistry maintenance within more restrictive limits than those which were allowed in the past.

Oxygen control, both from preventing oxygen ingress into the condensate and feedwater cycle and from assuring adequate removal through deaeration and hydrazine scavenging, and the use of more corrosion-resistant materials in the various stages of the steam and feedwater systems are also recommended.

Industry proposed solutions, to ensure the maintenance of steam generator integrity, have been summarized in Electric Power Research Institute (EPRI) and Westinghouse Steam Generator ,

Owner's Group (SGOC) reports (References 1 through 7). .

The CP&L system has not been immune to the industry problems.

H. B. Robinson Unit 2 has experienced steam generator tubesheet crevice corrosion, tube vastage, intergranular attack, and U-bend failures, that resulted in reduced plant power output.

To prevent further problems, replacement steam generators have been purchased and equipment and system modifications have been implemented or are planned.

As the various steam generator problems were experienced in operating plants, systems and equipment modifications were implemented on the SHNPP Unit 1 project (Reference 8). Table i provides a gestalt summary of the current status of SHNPP Unit I steam generator integrity maintenance by relating the present SHNPP Unit I design to problem characteristics, causes, indus-try proposed solutions and the original design.

l The first major changes tc SHNPP Unit I design were related to water chemistry and the minimization of corrosion product formation. These changes included:

0 Use of AVT water chemistry rather than phosphate treatment (Westinghouse recommendation - Reference 9) 0 Addition of deep bed, full flow condensate polishers

{ (Reference 10) 0 Removal of copper from the feedwater heaters and installa-tion of electromagnetic filters (ENF) in the blowdown iines of each steam generator (Reference 11) 0 Increase in the maximum blowdown rate per steam generator from 50gpa to 300gpa (Reference 8) i 0 Use of copper-nickel rather than Admiralty condenser tubes l (resulted from lake cooling to cooling tower circulating j water change) 9 _m - -.- ._ _ , _ _ , . , _

8 ,

9

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y I Additionally, integrally-grooved condenser tubesheets wey,e incorporated to monitor and uliaine.t ycirculating water intru-

,The partial-sion into the condensate system (Reference @betitly eclied ly-rolled steam generator tu'us were subseq ' '

through the full length of tha tubesheets. (

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't Section III of this report' di.ecusses the investightio t initi- s

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ated as a result of: i s

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0 Corporate concerns (References 12,13) for ' assuring plant

• operating reliability; y- '

O Recently published sus.aaries of the multi-faceted charac- il teristics of the stear-ghaeratbr concerns which ou*lin.t ,

additional system and\nquipment modifications which could prevent /mitigata corrosion problem consegtences.

1 x ',\ ,

Section III also provides: ,

L O Moredetaileddiscussionso'itheactio.id*,takento%bteand '

the racionale for the decisioos I

1. 1 .

O A discussion of the'SHNPP Unit 1 modifications as compared to those at HBR Unit 2 Cncluding the reasons for diffir-ent approaches t.tke'n on 4:he two plants) and the possibil-ity of future medifications, i

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CllARACTERisTICS OF STEAM ENERATOR IWfEGRITY P908LFMS -

SNNFP UNIT I MODIFICATIONS TO OselCINA!,FASICN Page 1 of 3

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SHNPp #1 OgSICN peast.r>t INDUSTRY PROr0 SED .

ORICINAL PRESEfff AgCOB00E800gG ACTION CHARACTERISTIC 3 CAUSP. Souffl0NS Pfeosphate AVT Motatain strict cinpelstry Thtmaing Phosphate chemistry AVT claestetry I. control.

No condeneste pollehere Deri bed full flow assee required,

2. arattag Crevice corroatos netween tubes a. Elleinste 07 from provided condensate pollehere and support plates feedwater Carbon steel with les cleanse None recommended,

b. SS TS b E)sacrefott liotes circular holes

c. Eltelnete Ce from Adetralty condenser 90-10. 70-30 Cu-Mt Retain Cu-Ni la condenser.

feedwe.er tubes condenser tubee See JLocueoloa.

Admiralty LP heater 304 statalese steel tubes tubes in all heaters 90-10 Cu-Ni HP heater 439 statatees steel tubes tubes in NER 90-10 Cu-Ni MSR 81o condensate pollehere Deep bed full flow Ilone registred.

provided condensate pollehere e Motatain strict cheelstry

d. titeinste Cl from feed- Phosphate AVT water control.

No condensate polishere Deep bed full flow None required.

pravided condemoste polishere Corroston-reetstant Carbon eteel with 10 0 change leone recommended.

e.

" support plates circular holes Carbon eteel solid tube Integrelly-grooved Air leakage test of

f. Improved condenser integrity sheets aluntnue bronse condenser and eseociated Admiralty tubes tubeeheets, ICTS oubeteoepheric locatione, preneurtsstion eyetoe Partially-rolled tubes Full rolled None required.

3. Tabe cracklag in corroston product concentration a. Full rolling in TS TS crevice resten la law flew restoe b. Meter cheststry control 50gpa blowdown and flash 300gpe/SC; electro- Isome required.

tanit per steen generator essnette filter See 2.C gee 2.C see 2.C

c. Elleinate Cu free feedveter 10e change liene required.

d. Toprove sludge removal Four aceses' holes (2*

dia.) above tdbeeheet

' < ___. _. _ al

s 4

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I Page 2 of 3 s

SHNPP $1 DESIGN d

PROSLPJG INDUSTRY PROPOSED C. CHARACTERISTICS -

CAUSE. Sol.IrflowS ORICINAL PRESENT ascopectNDgD ACTIOff

_4-~

4. Tuber cracking in Residual stresses in manufacture e. Strees relieve tiehee Inco el tubes -not heat no change U-tube restoe (first eight U-bend arut tuine Carrosion products la feedwater la manufacture treateJ rous) to be strees relieved regione in place if technology le

% developed and work can be acceeplished without schedule tapact (Ref. 15) 4 t

b. Feedwater chaelstry Phosphate AVF Metatata strict chnetstry control Condensate polisher control.

- $. Intergraaelar Corrosion' a. Chestetry control in Phosphate AVT corrosion attack operation and pite tag 0, tagrees during stagnant b. Chestetry control No wet lay-up eystem SC wet lay-up system Installettoe of systee (noastrees perlede during wet lay-up destan in process recommended, laduced)

c. Heat treat inconal 600 See 4.a See 4.s See 4.s tubee

6. Preheater fluw ~ 6 3 prenester design Westinghouse proposal Nodel D-4 steam W proposal for W recommendettoa vi brat ion- generator - hydraulle espea- implemented, induced tube stoa of tubes wear in B & D support plates in pre-heater section

- Split feedwater flow (183 bypass to aus. feeduster nosele) 7 Romage from Foreign material tatroduced e. Erection closeliness Upgraded ette com-foreign meterial during manufacture, erection, controle struction cleenti-la system operettoe mese.

Q4 surve111ence

b. Fiberecope taspection Ilo systes la procurement Accomplished.

et start-up budget for 1984

c. LPet instellation Part of bene ISSSS con- Espand capacity to Install systee, tract for RCS include SC secondary side installation complete in 1984

Page 3 of 3 SMNFP #1 DESIGN PRotLEM INDUSTRY PROPOSED Olt tCINAL PR$$ElrF RECOsWENDgO ACTION ORARACTERISTICS CAUSE SOLifTIONS Replacement of steam M/A N/A 'qplement preweetattwo

8. SC Deterioretton All of the above weeures la I through 7 regetring generators above.

replacement Walkdoun system to deter- Air in-leakage Utillae summary and perfom

9. Air la-l.eakage Valves, joints, flanges not summary complete associated testing to (relates to tight eine sources and correction required locate air leaks.

denting)

Incorporate unter seal at to-blae espaastoa joint.

Diaphrase la CST.

Spray nossle in condeneste return line.

e

III. Discussion A. Introduction gAs part of the ongoing comparison between SHNPP Unit i system design and industry operating experience, reviews of proposed solutions recommended in various steam genera-tor integrity summary reports have been made. Since the problems are basically corrosion induced, evaluations were made of oxygen control and corrosion prevention measures.

Oxygen control measures investigated were those required to prevent air in-leakage to the condensate system and those required to remove air from the feedwater system.

Corrosion prevention measures included material changes and lay-up procedures. Several auxiliary equipment modifications were also evaluated.

Subsections B, C, and D are subdivided such that each .

industry proposed solution is followed by a discussion of .

the decisions and actions taken on SENPP Unit 1. Sub-section E compares SENPP Unit I and HBR Unit 2. This subsection is subdivided by affected equipment such that reasons for differences may be clearly explained.

B. Air In-Leakage Control and Oxygen Removal B.1 Install packless valves to redace air in-leakage.

System piping connections to the plant condenser provide numerous potential air in-leakage sites, especially through valve packing glands. Replacement of these valves with packless type (bellows seal or metal diaphragm) valves is a proposed industry solution to eliminate-several hundred air in-leakage locations (Reference 6).

Due to the costs, schedule, and lead-time require-ments of this proposed solution, packless valves are not recommended at this time as a means to reduce air in-leakage to the condensate system. A stepwise approach is recommended. The systems and equipment l

l l

5 l

l

• t that will be exposed to subatmospheric conditions during operation have been tabulated. This informa-tion will be used to develop the plant air leak test procedure that will indicate the degree of condenser system vacuum integrity.

Subsequently, options for corrective measures will exist which can be evaluated to reduce measured air in-leakage to acceptable limits. The equipment modifications available include tightening of the existing packing, replacement of existing packing with Teflon or similar packing material, and replace-ment of chronic leakers with packless-type valves.

(Note: Replacement with packless valves applies only to two-inch and smaller valves).

For larger valves, modifications available include larger packing glands to accommodate dual sets of packing material, improved packing material, and a .

water seal at the packing gland leak-off connection .

of double-packed valves.

Additionally, instrumentation connections can be sealed with resin putty, epoxy, and plastic sealants to reduce air in-leakage.

Equipment changes are not recommended until after the air-leak test is performed.

B.2 Install water seal at turbine-condenser expansion joint.

The turbine-condenser expansion joint is a major contributor to air in-leakage (Reference 6).

Neoprene materials, such as that in the SHNPP condenser, can develop leaks that are incapable of being corrected during operation due to the joint ,

location in a constricted area. EPRI recommends the installation of a water seal around this joint. With appropriate instrumentation and control, the water seal will detect and control leakage in the event of failure until the rubber expansion joint can be repaired during an outage.- A water seal is recom-mended,for installation prior to start-up, as this is the optimum time to make the necessary modifications in the turbine-condenser joint before the expansion membrane is put in place. This change will be implemented.

B.3 Install deaerating feedwater heaters.

l A deaerating feedwater heater can be used to replace one of the stages of extraction feedwater heaters in

. the process cycle. It can provide' improved air

1 l

2 I

removal in the feedwater train during plant start-up conditions.

Reference 5 lists the advantages of deaerating heaters as reducing oxygen concentrations to the 10 ppb and lower range during start-up and to the i 1-5 ppb range during operation. Since oxygen intru-sion will be controlled by other methods (e.g.,

improved condenser deaeration, air in-leakage con-trol), no additional advantage is gained by use of deaerators.

The same reference indicates the expected cost for the installation of a s!ngle deaerator (including pumps, valves, piping, and steel erection) in a 1,100 Mwe plant to be in the $1.3 million range (1980 dollars). Houston Lighting & Power Company has taken this step on its South Texas Project Plant. Initial cost data on the changeover to deaerators is $18 .

million for two units. -

To install deaerators in Unit 1, the plant thermal performance will have to be reanalyzed to determine the deaerator design conditions and the impact on plant equipment and piping redesign. This type of change is drastic at Unit 1 becaure of the plant redesign at this stage of construction. The instal-lation of deaerating feedwater heaters is not recom-mended for Unit I because of the limited potential for enhancement of oxygen control beyond the steps

, already taken.

. B.4 Provide means to deaerate condensate storage tank in the event the air bladder fails or does not provide sufficiently low 0 2

1***1**

Four options are mentioned in Reference 6 to reduce air in-leakage into the condensate storage tank.

These options and their feasibility for SHNPP are:

O Stainless steel floating cover with seal at l wall - The SENPP CST design with inlet i

nozzles that extend inward and downward into the tank interior precludes this option. The existing CST has a ~ rubber diaphragm on the water surface, which serves the same function as the floating i

Cover.

0 Nitrogen blanket - The SHNPP CST is an

atmospheric tank. To provide N verPres-2 sure, a large supply of N, will be required to account for water level fluctuations during operation. Tank design will have to l be modified to seal tank vent and to provide overpressure relief. The large

t .

volumes of Ny anticipated prevent consid-eration of tnis option.

O Vent to condenser - The CST is atmospheric

! design and will not accommodate vacuum conditions above the diaphragm surface.

~

0 Hydrazine injection - This is a physically plausible option. The hydrazine system is capable of supplying adequate hydrazine to scavenge dissolved oxygen. Supply points to the tank and assurance that adequate mixing occurs would have to be provided.

Of the plants using the options mentioned, only one plant was capable of maintaining oxygen in the CST near the suggested level of 5 ppb. This plant used a floating stainless steel cover in conjunction with a vacuum degassifier and employed hydrazine injection during 0 excursions. Degassifiers were used with 2 ~

limited success on the plants surveyed. Degassifiers have been found generally to be costly and to require

~

a long time to deaerate large CST volumes.

Reference 5 indicates that the optimal range for the scavenging effectiveness of hydrazine is in the 200-300F range. The temperature range for the CST (60-120F) is one in which it will take extremely long time periods for the hydrazine to be an effective oxygen scavenger. Furthermore, the condensate transferred to the hotwell could pass through the condensate polisher during normal operation, where the deep beds will remove the hydrazine. The resi-dance time in the CST and through the hotwell vill be insufficient for the hydrazine to react effectively.

A further point to be made is that the SHNPP design-employs degassifiers in the plant water treatment system to provide demineralized water to the demineralized water storage tank and the condensate storage tank. Design oxygen level for these storage tanks is 0.1 ppa (100 ppb). Therefore, additional dilution and deaeration in the condensate and feedwater system are required to attain a level of approximately 5 ppb. Dilution will be inherent,'but will vary with the volume of'make-up added. De-l aeration of make-up will be accomplished via spraying into the air removal zone (refer to B.5) of the condenser.

i Since hydrazine scavenging is considered ineffective l in the temperature range of the CST, additional j hydrazine injection points are not recommended at this time. This does not preclude future i

l l \

todifications if tha othat meccuras recommend:d or scplcysd in tha preccat decign (o.g., irprcvad condenser integrity, hydrazine injection in the feedwater) are not sufficient to meet the dissolved oxygen limits.

B.5 Provide spray nozzles in the makeup line from the condensate storage line to the hotwell to scrub out 0.3 The condensate storage tank makeup return to the condenser is a 6" diameter line that enters the condenser shell at a level approximately 6' above the hotwell level false bottom and terminates in a spray pipe. This nozzle is not, however, at a location that provides the best deseration of the condensate.

A connection at the condenser shell at Elevation 295' has been evaluated as acceptable for use to inject the condensate above the condenser tube bank and provide additional deaeration for the water from the CST. The change is being implemented.

B.6 Inerting the condenser with N2 Prior to start-up to -

reduce entrained 02*

Because of the large volume of the condenser (approx-imately 132,000 ft.8) and the high probability of maintenance on the turbine or condenser during outages, inerting of the condenser has been given minimal consideration. Entrained oxygen should be manageable by a combination of options including refilling tne condenser with deaerated condensate, recirculating the condensate during start-up, hydrazine scavenging in the feedwater system, and condenser deaeration.

Again, if these measures are insufficient, this option can be reconsidered in the future.

C. Corrosion Control C.1 Provide for wet recirculating lay-up of steam genera-l tors during outages with an N verPressure.

2 The original design for SHNPP had no provisions for recirculating the steam generator water inventory ,

during outages. CP&L is proceeding to design and '

install a steam generator wet lay-up system that

provides for independent recirculation of each steam generator in either direction. The lay-up system will provide a method to control steam generator chemistry accurately and thereby reduce the general surface corrosion of the internal carbon steel

-N

surfaces. The system also provides for dry lay-up connections to condenser vacuum and to N7 ove rpres-sure. The design has taken industry pro 51 ems into account and follows industry recommendations (Reference 18). The design provides for future installation of extended capabilities. If future conditions warrant, the system can be expanded to include: additional filtration, heat exchanger for quicker cooldown, and a blowdown demineralizer for water cleanup.

C.2 Retube condenser with noncopper tubes.

Reference 14 addresses the recommendation concerning condenser tube replacement with titanium tubes (present tubes are copper-nickel). Consideration of the costs for the outages anticipated with the use of Cu-Ni tubes and titanium tube replacement now or after several years of operation leads to tha conclu-sion to retain Cu-Ni tubes in the present system.

Proper operation that assures the maintenance of ,'

chemistry conditions during operation can lead to satisfactory operation with the existing condenser tube material.

Reference 5 provides data from four operating PWR plants (Kewaunee, Davis-Besse, Ginna, and Trojan) that have been able to maintain the dissolved oxygen level in the feedwater below 5 ppb. All four plants employ copper-alloy condenser tubes (including Admiralty). At Kewaunee, copper alloys are found in the feedwater heaters, condenser, and one MSR. Three use condensate polishers and one has an installed deaerating feedwater heater. The number of SG tubes damaged due to wastage or denting is minimal (see Table 2).

The plants employ a variety of means to control air in-leakage during operation including: floating steel cover in CST; maintenance of tightly packed valves; monitoring of air removal rate; degassifier upstream of CST. In addition, various procedures are followed during outages and lay-up of the systems to j reduce corrosion. These include: wet lay-up of systems; purging systems with dry air while still I warm to remove moisture; recirculation of the conden-sate through polishers and deaerating heaters until water chemistry is within operating limits.

l This operating experience with plants similar to

, SENPP Unit I supports the contention to retain the l

! present design, implement those modifications that

_9

can be readily accommodated at the present stage of construction, and initiate operating procedures that will result in maintenance of water chemistry within strict recommended limits. The present design and materials are acceptable because they will be sup-ported with an operational program that monitors and maintains appropriate water chemistry conditions.

The same commitment to a strict operational program,

with regards to chemistry, would be required regard-less of materials used in the condenser and balance .

of the secondary plant.

1 Westinghouse (Reference 19) has confirmed that copper alloy tubes in the condenser in conjunction with efficient deep bed, full flow condensate polishers can be acceptable and the risk of steam generator tube corrosion is low.

l j

C3 Provide electromagnetic filtration in blowdown, condensate, or feed systems. .

As previously shown in Table 1, an electromagnetic filter (EKF) is part of the SG blowdown system. If future conditions warrant, additional features can be incorporated, as discussed in Section C.1 concerning the steam generator wet lay-up system.

t D. Miscellaneous Modifications D.1 Add sampling points for feed, condensate, and steam.

A decision has been made to increase the sampling

points in the secondary steam cycle. The provision of sampling points will increase the ability to

monitor water chemistry and ensure the long-term integrity of the steam generators.

D.2 Install loose parts monitor.

The loose parts monitor system has been supplied as part of the Westinghouse base NSSS contract. The sensors mounted in the vicinity of the steam genera-tor tubesheets (one above, one below) have the

, capability to detect loose parts on the secondary i

side within approximately three feet of the~ sensor installation.

D.3 Fiberoptic inspection for foreign objects prior to start-up.

A fiberoptic system is in the procurement budget for 1984. This system will utilize the existing sludge

, lancing ports to inspect for loose parts in the steam l

d S

generators. Inspections are being planned prior to and after hot functionals.

D.4 Provision for additional handholes for sludge lancing access.

Four access holes (two inches diameter) presently l

~

exist above the tubesheet on each steam generator.

Additional handholes are desirable and were given consideration. However the apparent benefit compared to the cost to provide the handholes does not warrant their addition. Should operational experience demonstrate their value, additional manholes can be added at a later date.

D.5 Replacu Model D-4 steam generator with new Model 51F (nonpreheat HBR type) to provide same design features as HBR replacement bundles and eliminate prehester flow vibration as a problem. i CP&L management has accepted the Westinghouse ree- .

] ommendation for mitigating the preheater section vibration problem. The NRC has issued a Safety Evaluation Report (Reference 20) which supports the acceptability of this approach. The solution con-i.

sists of the following:

l 0 Hydraulic expansion of 124 tubes at the B and D support plates in the preheater i_ section of SGs 1 and 3 and 122 tubes in SG 2 O Split feedwater flow to the steam generator with 18% of the feedvater externally bypassed to the auxiliary feedwater nozzle.

i j Implementation of the steam generator piping modi- I fications will be completed by the end of the-first

quarter of 1984. Corrosion control measures are discussed in Section III. Effective corrosion control will negate the necessity of material changes l in the SHNPP steam generators.

/

D.6 Development of a conceptual plan to replace steam l generators.

l This~is the most extreme of corrective measures.

Emphasis is presently being placed on preventive I measures to eliminate or minimize the sources of j

problems causing concerns about steam generator integrity. With appropriate plant operating proce-dures and strict chemistry monitoring and control, l replacement of steam generators should not be I

L p-l ___

necessary. Sketches SK-2165-N-49 (1971),

SK-2165-M-50 (1971), and SK-2165-N-414 (2 sheets 1978) show results from prior studies relative to steam generator removal and replacement.

D.7 Stamping tubesheet to identify tubes.

Prior to addy current examination, the steam genera-3 tor tubesheets will be stamped for identification.

, This will improve the efficiency with which addy

{ current testing can be performed in a radioactive i area.

E. Comparison of SHNPP Unit 1 and BBR Unit 2 Modifications.

l The problems of steam generator integrity are common to l PWRs of the type at HBR Unit 2 and SENPP Unit 1. Tables  ;

3A and 3B provides a comparison of the modifications made at these two plants to prevent steam generator problems.

i The modifications made at SHNPP Unit 1 are basically .

similar to those made at HBR Unit 2 except in a few instances. A discussion of the bases and decisions j relevant to these differences follows:

E.1 Steam generator modifications.

1 HBR Unit 2 has purchased replacement steam generators

, that include the following improvements: stainless steel Type 405 support plates with quatrefoil tube holes, thermally-treated Inconel tubes, 4

stress-relieved tubes in U-bend region, and larger and additional handholes.

The SHNPP Unit I steam generators are the original j Model D-4s and have not been modified except as 4

discussed in Section D.5 for the preheat section l

vibration problem. The first two of the improvements l

can only be accomplished by changeout of the staan j

generator. The existing support plates are carbon i steel with round holes; four handholes are provided j above the tubesheet. In-situ stress relieving of the j U-bend region has been suggested and Reference 15

discusses laboratory results; but until the j state-of-the-art can be guaranteed to adequately 1 - stress relieve these tubes, it is not recommended. I The other preventive measures upstream in the l

feedwater train (e.g. , chemistry control, copper '

! removal, air removal), should minimize corrosion j damage to these areas in the steam generator.

i

!' E.2 Copper alloy tubes in condenser; condensate pump.

bronze impe11ers.

j l

The decision to retain copper-nickel condenser tubes at SHNPP Unit I was based on the elimination of copper throughout the balance of the system (e.g.,

MSR, feedwater heaters), the existence of a conden-sate polisher which can trap copper corrosion prod-ucts before they enter the feedvater stream, the impact of the change on Unit I construction, and the fact that the change can still be made economically around the tenth year of operation if operating experience warrants it. Plants with similar mate-rials have operated successfully when a program of ,

strict chemistry control was maintained, (Section C.2).

Copper has been eliminated from the condensate and feedwater system, where no further copper corrosion product removal technique exists (e.g., MSR drains are pumped forward directly to the steam generators and the MSR tubes were changed over to stainless steel). While the condenser tubes comprise a large surface area, condensate polishers function as ,

filters, as well as ion exchangers (Reference 5) and can remove corrosion product solids at efficiencies of 90% and greater (Reference 16). Furthermore, the corrosion rate of copper is temperature and oxygen dependent (Reference 17). Since the temperature in the condenser is the lowest in the feedwater train and since air in-leakage and oxygen removal are being controlled, the copper corrosion rate from the condenser tubes should be minimal. Any copper corrosion products should be filtered by the condensate polishers.

l 4

Therefore, the combination of copper-alloy elimina-I tion plus corrosion product removal techniques should be sufficient to mitigate subsequent corrosion in the steam generators. Since the amount of copper has been substantially reduced, no change was recommended to the bronze impellers on the condensate pumps. Any small amount of copper release should be picked up by the condensate polishers (Reference 8).

E.3 Degassifier provided to recirculate condensate storage tank.

This was given consideration at SHNPP Unit 1 but proved to be of limited value. Discussion of CST deaeration (Section B.4) indicated limited success with degassifiers at operating plants. A degassifier in the existing water treatment system provides domineralized water for plant systems. The design oxygen level for SHNPP Unit 1 in the domineralized water storage and condensate storage tanks is 0.1 ppm-- one-fifth the design level of HBR Unit 2.

a

2 The addition of condensate return spray nczzles.

imp' roved condenser integrity, and hydrazine injection into the feedwater stream should combine to maintain '

. oxygen levels in the acceptable range.

l The degassifer was added to the HBR makeup water treatment system and brings HER into consonance with the SMKPP design. The HBR design has additional flexibility by providing the ability to desassify the condensate storage tank by recirculation. The recirculation feature was provided for before commit-ting to install a protective diaphragm on the HBR i condensate storage tank. Should SHNPP operational data indicate that a degassifier is warranted, it can i

be accomplished af ter the plant is operational with no greater impact to operations than while the plant

. is under construction.

E.4 Hydrazine injection in turbine cross-under piping and into CST. .

~

l The use of hydrazine is intended to control trace amounts of oxygen and to supplement mechanical j deseration in the system. Hydrazine is neither a 1

substitute for proper deseration nor a cure for i excessive air leakage. The effectiveness of hydrazine injection is dependent upon the injection

points (specifically the temperature and available

! reaction time). The temperature in the cross-under

! piping is near the decomposition temperature of

! hydrazine (approximately 400*F) and the transit time

, is so short that little scavenging may occur.

Hydrazine decomposes into ammonia, which has

! potentially detrimental effects on copper alloys.

l Therefore, the turbine cross-under piping injection

point is not recommended for SHNPP Unit 1.

j Injection into the SHNPP Unit 1 CST was previously discussed in Section B.4. Ineffectiveness of j hydrazine at low temperatures (below 100*F) was deemed noc to provide substantial added benefit to i the hydrazine injection system already in existence.

t Hydrazine is injected into the condensate system downstream of the condensate booster pumps. This is an optinua injection location and the effectiveness of the hydrazine injection will be monitored during operation.

Therefore, the incorporation of additional hydrazine injection points at this time is not recommended. If the CST injection point is required in the future, the modification can readily be accomplished.

t

TABLE 2

SUMMARY

OF STEAM CINERATOR TUBE PROBLEMS FROM SEVERAL PWR PLANTS OPERATING WITH COPPER-ALLOT CONDENSER TUBES Plant Kevaunee Troj an Davis-Besse Cinna Mwe 535 1130 962 490 NSSS W W B&W W Operation 12/73 11/75 1977 9/69 Deaerator No No Yes No Cu-Alloy Condenser Yes Yes Yes Yes Cond. Po.lisher No Yes Yes Yes .

~

Air Removal, scfm 3-4 10-15 30-50 3-4 Condensate 02 . ppb 5-10 5-10 20-25 10 Feedwater 02 . ppb 5 2 5 5

No. of leaking tubes 0 12 No data 6 Tubes plugged, f/2 0 368/7 No data 237/4 4

Sources:

1. EPRI NP-3020, PWR Secondary-System Oxygen Control Measures, July 1983

2. Nuclear Steam Generator. Transplant Total Rises EL&P, September 1982

TABLE 3A COMPARISON OF SYSTEMS AND EQUIPMENT MODIFICATIONS AT SHNPP UNIT 1 AND HBR UNIT 2 IN RESPONSE TO STEAM GENERATOR INTEGRITY CONCERNS l

STEAM GENERATOR IMPROVEMENTS HBR2 SHNPPI

1. Stainless steel support plates with quatrefoil yes no holes

2. Tubes in U-bend region stress relieved yes no

! 3. Two handholes above flow distribution baffle yes no 4.

Thermally-treated Inconel tubes yes no ,

5. Full-depth roll in tubesheet yes yes

6. Recirculating wet lay-up nozzles provided yes yes i 7. Increased capacity blowdown nozzles provided yes yes (up to 300 gpm/ generator)

8. Four access handholes above tubesheet yes yes

9. Loose parts monitoring system yes yes I

l l

l

. TABLE 3B COMPARISON OF SYSTEMS AND EQUIPMENT MODIFICATIONS AT SHNPP UNIT 1 l AND RBR UNIT 2 IN RESPONSE TO STEAM CENERATOR INTEGRITY CONCERNS l

Condensate and Feedwater Train Improvements HER2 SENPPI

1. Copper tubes replaced in:

A) heaters yes yes B) MSR yes yes C) condenser yes no

2. A) Degassifier provided for makeup water to condensate storage tank yes yes B) To recirculate condensate storage tank _

contacts through degassifier yes no .

3. Hydrazine injection in turbine cross-under yes no piping and into CST

4. New impellers in condensate pumps to remove yes no copper

5. Integrally-grooved condenser tubesheets yes yes

6. Deserating nozzles on condensate storage tank yes yes makeup line in hotwell

7. Bladder in condensate storage tank yes yes (planned)

8. Steam generator bypass for cleanup during yes yes start-up

9. Filtration of blowdown, condensate, or feedwater Not currently yes systems planned, but subject to further eval-untion

10. Install loosa parts monitor yes yes

11. Deep bed condensate polishing system yes yes

12. Enlarged secondary sampling system yes yes I

13. Enlarged chemical addition system yes yes

14. Perform fiberoptic inspection for foreign yes yes object prior to start-up

15. Inerting condenser with N Prior to start-up no no 2

16. Install deaerating feedwater heaters no no l

l

17. Install bellows-seal valves to reduce air no no in-leakage O

- --. - . . . .= .-.

IV. Conclusion Throughout the design and construction of SHNPP Unit 1, appropriate actions have been taken to ensure steam generator l integrity. Additional evaluations have been made in response l to recent industry proposed solutions and corporate concerns rela'ed t to various aspects of these corrosion and chemistry-induced problems.

Steam generator integrity maintenance involves a combination of oxygen and corrosion control system / methods. SHNPP Unit I will employ several methods for oxygen control:

O Monitoring of potential in-leakage sites to determine extent of condenser systems integrity O Condenser neck bellows water seal O Condensate return spray nozzle. .

, Corrosion control measures include:

1 0 Integrally-grooved condenser tubesheets and improved tube materials 0 AVT water chemistry control O Use of wet lay-up system (with N2 backup) for steam generators during outages of sufricient length.

! O Electromagnetic filter in steam generator blowdown lines 0 Full flow condensate polishers j 0 Sampling points on secondary system.

This combination of systems and equipment modifications, coupled with operating procedures for maintenance of secondary '

systems water chemistry within strict limits, should be more than adequate to maintain steam generator integrity. However, the present design can readily accommodate additional improve-ments which may result from improved technologies, or specific operating experience.

l Differences in the implementation of systems and equipment modifications between SHNPP Unit I and HBR Unit 2 result from the inherent differences between an operating plant and one under construction. For instance, at HBR Unit 2 the decision

involves replacement of a relatively old steam generator with a l model that incorporates state-of-the-art improvements. At SHNPP Unit 1 the existing steam generator has never been used,

{

it already has several improvements compared to those which have exhibited problems in service, and is accessible for some modification. Also, the timing of industry recommendations relative to specific project problems impacts a project's ability to respond. For example, the cost / benefits and ability to upgrade a piece of equipment that has yet to be purchased versus a piece of equipment that is installed and operating are obviously different.

In conclusion, the actions taken throughout the SHNPP Project history are adequate to ensure Unit 1 operability and do not preclude the incorporation of additional steps as may be warranted by operating experience.

O

f V. Refcr:ncto

1. EPRI NP-481, Steam Plant Surface Condenser Leakage Study, Vols. I and II, January 1977

2. EPRI NP-2062, Steam Plant Surface Condenser Leakage Study

)

Update, May 1982 j

3. 'EPRI NP-1467, Assessment of Condenser Leakage Problems.

August 1980

4. EPRI NP-1468, Corrosion-Related Failures in Power Plant Condensers, August 1980

5. EPRI NP-3020. Evaluation and Improvement of PWR Secondary System Oxygen Control Measures, July 1983

6. EPRI NP-2294, Design Guide to Minimize Oxygen-Induced Corrosion, March 1982

7. Steam Generator Technology Transfer Package, EPRI Research Project S205-1, March 1983 ,

8. Memo, M. C. Zaalouk to L.1. Loflin, EPS Steam Generator Working Group, PPED-78245 dated February 14, 1978

9. Steam Generator Water Chemistry, CQL-2426, August 19, 1974

10. Steam Generator Water Chemistry Study, Ebasco, October 1974

11. A Study of System and Equipment Design Modifications Recommended to Minimize PWR Steam Generator Tube Wastage.

Ebasco, hkrch 1976

12. Memo, A. B. Cutter to C. Bently, et. al., Maximizing Steam Generator Integrity, NPED-821947 dated December 21, 1982

13. Memo, J. L. Willis to A. B. Cutter, SHNPP Steam Generator Integrity, SENPPA-83-167 dated February 15, 1983

14. Condenser Upgrade Recommendation, Memo NPED-831148

15. EPRI NP-3056 In-Situ Heat Treatment and Polythionic Acid Testing of Inconel 600 Row 1 Steam Generator U-Bends.

April 1983

16. EPRI NP-2703, Salem Unit 1 - Denting Mitigation Program:

Implementation of Improved Oxygen, Chloride, and Copper Control, October 1982

17. EPRI NP-2654, Effects of Hydrazine and pH on the Corrosion of Copper-Alloy Materials in AVT Environments with Oxygen, i

December 1982 f

18. EPRI NP-2993 Evoluctien of Steam Cenarctor Fluid Mixing During L:y-up, May 1983

.' 19. Letter, R. L. Whitney to L. I. Loflin, Use of Copper Alloys, CQL-7596 dated October 4, 1983

20. NUREG-1014 Safety Evaluation Report Related to D4/D5/E t Steam Generator Design Modification, October 1983 '

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