ML14175A907

Safety Evaluation Report Related to Steam Generator Repair at H.B. Robinson Steam Electric Plant Unit No. 2.Docket No. 50-261.(Carolina Power and Light Company)

ML14175A907
Person / Time
Site:	Robinson
Issue date:	11/30/1983
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-1004, NUDOCS 8401090198
Download: ML14175A907 (49)

Text

NUREG-1 004 Safety Evaluation Report related to steam generator repair at H. B. Robinson Steam Electric Plant Unit No. 2 Docket No. 50-261 Carolina Power and Light Company U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulal

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NUREG-1004 Safety Evaluadon Report related to steam generator repair at H. B. Robinson Steam Electric Plant Unit No. 2 Docket No. 50-261 Carolina Power and Light Company U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation November 1983

ABSTRACT A Safety Evaluation Report was prepared for the H. B. Robinson Steam Electric Plant Unit No. 2 by the Office of Nuclear Reactor Regulation. This report con siders the safety aspects of the proposed steam generator repair at H. B.

Robinson Steam Electric Plant Unit No. 2. The report focuses on the occupa tional radiation exposure associated with the proposed repair program. It con cludes that there is reasonable assurance that the health and safety of the pub lic will not be endangered by the conduct of the proposed action, such activi ties will be conducted in compliance with the Commission's regulations, and the issuance of this amendment will not be inimical to the common defense and security or the health and safety of the public.

H. B. Robinson 2 SER iii

CONTENTS Page ABSTRACT PRINCIPAL CONTRIBUTORS.............................................

vii ABBREVIATIONS......................................................

ix

1.0 INTRODUCTION

1 1.1 History of Steam Generator Operation.......................

1-2 1.2 Reasons for Steam Generator Repair.........................

1-3 2.0 SCOPE OF WORK TO BE PERFORMED..................................

2-1 2.1 Removal and Reinstallation Operations......................

2-1 3.0 EVALUATION....................................................

3-1 3.1 ASME Code Application.....................................

3-1 3.2 Quality Assurance Program...................................

3-1 3.3 Component Design Modifications...................

3-2 3.3.1 Flow Distribution Baffle.............................3-2 3.3.2 Blowdown System......................................

34 3.3.3 Steam Generator Tubes................................3-4 3.3.4 Offset Feedwater Flow Distribution...................

3-8 3.3.5 Support Plates.......................................

3-8 3.3.6 Tubesheet Welds........

3-9 3.3.7 Tube Lane Blocking Device............................3-9 3.3.8 Access Ports.........................................

39 3.3.9 Inspection Port...................................... 39 3.3.10 Additional 2-Inch Nozzle.............................3-11 3.3.11 Piping, Equipment Interference Removal, and Replacement..........................................

3-11 3.3.12 Steam Generator Upper Lateral Restraints.............

3-11 3.3.13 Steam Generator Mid-Section Replacement..............

3-13 3.3.14 Prevention of Loose Parts...........................

3-13 3.3.15 Additional Corrosion-Related Aspects ofRepair......

3-14 3.3.16 Post Repair Tests and Evaluations To Assure Integrity of the Reactor Coolant System and Compliance With Applicable Codes....................

3-15 3.3 Summary........

3-16 4.0 HANDLING OF HEAVY LOADS..........................................

4-1 4.1 Return to Normal Operation 4-1 4.2 Return to Service Testing 4-2 H. B. Robinson 2 SER v

CONTENTS (Continued)

Page 5.0 RADIOLOGICAL CONSIDERATIONS.....................................

5-1 5.1 Background............................................

5-1 5.2 Occupational Exposure......................

5-1 5.3 ALARA Considerations........

5-2 5.4 Summary................................................... 5-4 6.0 TRANSIENT AND ACCIDENT ANALYSIS..................................

6-1 6.1 Introduction...............................................

6-1 6.2 LOCA Analysis.............................................

6-1 6.2.1 Summary...........................................

6-2 6.3 Locked Rotor...............................................

62 6.3.1 Summary.............................................

6-3 7.0 RADIOLOGICAL CONSEQUENCES OF POSTULATED ACCIDENTS...............

7-1 7.1 Accidents During Operation With Repaired Steam Generators..

7-1 7.2 Accidents During the Repair Effort.........................

7-1 7.2.1 Rigging Accidents - Impact on Safety-Related Systems/Structures/Components.......................

7-1 7.2.2 Steam Generator Lower Assembly Drop.................

7-2 7.2.3 Cutting of the Reactor Coolant Piping.......

7-3 7.2.4 Accidents Initiated by External Events..............

7-3 7.3 Summary..................................................

7-3 8.0 PHYSICAL SECURITY ASPECTS........................................

8-1 9.0 SPECIAL LICENSING CONDITIONS....................................

9-1

10.0 CONCLUSION

S.....................................................

10-1

11.0 REFERENCES

11-1 FIGURES 3.1 H. B. Robinson Unit No. 2:

Steam Generator Lower Assembly......

3-5 3.2 H. B. Robinson Unit No. 2:

Flow Distribution Baffle and Blowdown...................

3-6 3.3 H. B. Robinson Unit No. 2:

Tube-to-Tubesheet Juncture..........

3-7 3.4 H. B. Robinson Unit No. 2:

Quatrefoil Tube Support Plate.......

3-10 3.5 Typical Generator Upper Assembly for All Three H. B. Robinson Unit No. 2 Steam Generators Showing Piping Cuts in Main Steam and Feedwater Lines............................................

3-12 TABLES 3.1 Applicable Regulatory Guides and ANSI Standards for CP&L QA Program.........................................................

3-3 3.2 Steam generator design data (per steam generator)...............

3-4 H. B. Robinson 2 SER vi

PRINCIPAL CONTRIBUTORS G. Requa Project Manager Division of Licensing L. Frank Materials Engineering Branch Division of Engineering B. Mann Reactor Systems Branch Division of Systems Integration J. Rajan Mechanical Engineering Branch Division of Engineering R. J. Serbu Radiological Assessment Branch Division of Systems Integration B. K. Singh Auxiliary Systems Branch Division of Systems Integration J. Spraul Quality Assurance Branch Division of Engineering P. Wu Chemical Engineering Branch Division of Engineering M. Wohl Accident Evaluation Branch Division of Systems Integration H. B. Robinson 2 SER vii

ABBREVIATIONS ALARA as low as reasonably achievable ANSI American National Standards Institute ASLB Atomic Safety and Licensing Board ASME American Society of Mechanical Engineers AVT all volatile treatment BEIR Advisory Committee on the Biological Effects of Ionizing Radiation, National Academy of Sciences/National Research Council CFR Code of Federal Regulations CP&L Carolina Power & Light Company DNBR departure from nucleate boiling ratio ECCS emergency core cooling system EFPM-effective full-power month ENC Exxon Nuclear Corporation EPRI Electric Power Research Institute FR Federal Register GDC General Design Criterion HBR-2 H. B. Robinson Steam Electric Plant Unit No. 2 HEPA high-efficiency particulate air ICRP International Commission on Radiation Protection ID inside diameter IGA intergranular attack LOCA loss-of-coolant accident LOOP loss of offsite power NRC U.S. Nuclear Regulatory Commission OD outside diameter PCT peak clad temperature PWHT post-weld heat treated PWR pressurized water reactor QA quality assurance RCP reactor coolant pump SCC stress corrosion cracking SG steam generator SGTP steam generator tube plugging SLB steam line break UNSCEAR United Nations Scientific Committee on the Effects of Atomic Radiation H. B. Robinson 2 SER ix

SAFETY EVALUATION REPORT RELATED TO STEAM GENERATOR REPAIR AT H. B. ROBINSON STEAM ELECTRIC PLANT UNIT NO. 2

1.0 INTRODUCTION

By letter dated July 1, 1982, Carolina Power and Light Company (CP&L, or the licensee) submitted a letter of intent to repair the three steam generators (SGs) at the H. B. Robinson Steam Electric Plant Unit No. 2 (HBR-2). The let ter briefly described CP&L's intended program and informed the NRC that a Preliminary Steam Generator Repair Report would be submitted on September 1, 1982. CP&L made a determination that "this repair will be an allowable activ ity under 10 CFR 50.59, not requiring NRC issue of a Safety Evaluation Report."

CP&L made this determination based on the fact that NRC review and evaluation of previous SG replacements had shown.the absence of unreviewed safety issues.

The Preliminary Repair Report was submitted by CP&L letter dated September 16, 1982. By letter dated November 18, 1982, the NRC staff informed CP&L that the staff first had to review and approve these repairs, and that the CP&L letter of July 1, 1982 as supplemented by the letter dated September 16, 1982 was con sidered as an application for a license amendment. The staff's letter also notified CP&L that proposed issuance of an amendment associated with this action was being published in the Federal Register. Publication in the Federal Register took place November 24, 1982 (47 FR 53157).

On.January 6, 1983, CP&L submitted its report entitled "Fina-1 Steam Generator Repair Report."

This report has been supplemented by Revision 1, dated March 31, 1983, and supplemental material to Revision 1, May 5, 1983. The report describes a proposed program to repair the three steam generators at HBR-2 by replacing the lower assembly, including the tube bundles, of each generator.

On March 24, 1983 a special prehearing conference was held at Florence, South Carolina. On April 12, 1983, the Atomic Safety and Licensing Board issued a Memorandum and Order which ordered, among other things, that the petitioner, Hartsville (Group), be admitted as a party intervenor in the proceeding.

On December 26, 1982, Concerned Fools of Darlington County filed a petition for leave to intervene and requested an opportunity for hearings in this matter.

On December 27, 1982, the Hartsville Group filed a petition for leave to inter vene and requested an opportunity for hearing in this matter. An Atomic Safety and Licensing Board (ASLB) was established on January 5, 1983 to rule on peti tions for leave to intervene and/or requests for hearing and to preside over the.proceeding in the event that a hearing was ordered.

On June 10, 1983, the Director, Office of Nuclear Reactor Regulation, directed that an Environmental Statement (ES) be prepared for the amendment application regarding the repair of the HBR-2.steam generators. In September 1983, the Draft Environmental Statement (NUREG-1003) was issued for comment. A Final Environmental Statement (FES) was issued in November 1983.

H. B. Robinson 2 SER 1-1

1.1 History of Steam Generator Operation H. B. Robinson Steam Electric Plant Unit No. 2 (HBR-2) began commercial opera tion on March 7, 1971. Like almost all units with U-tube design steam genera tors, it began operation using a sodium phophate secondary water chemistry treatment. This treatment was designed primarily to remove precipitated or suspended solids by blowdown and was successful as a scale inhibitor.

Eddy current testing began in 1972, when steam generator tube leaks occurred.

Upon determining the cause to be caustic corrosion, feedwater chemistry speci fications (the sodium to phosphate ratios) at HBR-2 were adjusted to ensure that acceptable caustic conditions would be maintained in the steam generator.

HBR-2 and San Onofre Unit 1 had not experienced phosphate wastage at the rate experienced at other plants using phosphate chemistry during the period when the other PWRs converted to all-volatile-treatment (AVT) chemistry control in the secondary system. Therefore, in 1975, HBR-2 chose not to switch from a sodium phosphate treatment to an AVT chemistry for the steam generator secon dary coolant, since the steam generator condition would not be significantly improved and might possibly be degraded. Instead, actions were taken such as "sludge lancing" during outages to remove sludge buildup occurring on the steam generator tubesheet, and tube support plates. In addition, condenser air inleakage was more stringently monitored and controlled. Eddy current inspec tion of tubes during outages was continued to determine tube condition and to monitor the status of tube degradation.

Based on Electric Power Research Institute (EPRI) recommendations, HBR-2 con tinued to monitor condenser inleakage strictly and to make other modifications to the system to assist in alleviating the inleakage problem. Among these modifications the feedpoint for hydrazine, an oxygen scavenger, and injection into the feedwater system were changed.

In 1980, HBR-2 began experiencing problems with stress corrosion cracking in tubes near the tubesheets. As a result of a high level of stress corrosion cracking activity above the tubesheet area observed during the August 1981 eddy current inspection, licensing conditions were imposed for the balance of Cycle 8 operations. The conditions included periodic steam generator primary to secondary hydrostatic tests and more stringent limits on allowable primary to secondary leakage (a definition of terms and general explanation of the corro sion phenomena discussed here may be found in NUREG-0886, "Steam Generator Tube Experience," February 1982).

HBR-2 shut down as a result of a 0.3-gpm leak on July 30, 1981. Inspection of the leaking tube revealed that a through-wall stress corrrosion crack above the top of the tubesheet elevation was the source of the leak. In addition, evidence of general intergranular attack was observed below the top of the tubesheet in the crevice region. The crack above the tubesheet had an axial orientation and was approximatley 0.8 inch long. The low leakage rate has been attributed to the restraining effect of the hard sludge on the tube, a phenome non similar to one that was observed previously at San Onofre Unit 1. In August 1981, based on advice from Westinghouse and from data obtained by EPRI that correlated temperature to the corrosion phenomenon, HBR-2 began operating at a H. B. Robinson 2 SER 1-2

50% power level to reduce the hot-leg temperature. In November 1981, HBR-2 began operating on an NRC-approved reduced Tave program to reduce stress corro sion cracking.

An eddy current inspection performed during the refueling operation for cycle 9 core reload, during March and April 1982, indicated that the reduced temperature operation since November 1981 had been successful in sharply reducing the stress corrosion cracking activity above the tubesheet. However, the inspection also indicated an acceleration of phosphate wastage corrosion during the reduced power operating cycle (Cycle 8).

Therefore, an additional operating limit of 6 effective full-power months (EFPMs) was imposed on the plant. After 6 EFPM operation, the unit was to be shut down for a steam generator inspection to ensure that further progression of wastage did not become excessive. Since the reduced temperature operation was successful in reducing stress corrosion cracking, the licensing condition for primary to secondary steam generator hydrostatic testing imposed in 1980 was removed.

The operation of HBR-2 continues to be subject to operating restrictions such as reduced power level, stringent limits for primary to secondary leakage, and additional inspection and reporting requirements in the event that the unit is shut down because of leakage in excess of the limits in the Technical Specification.

The licensee took additional actions to assist in controlling tube deteriora tion. These actions included removing of copper from the feedwater system and condenser, improving inspections to identify and correct existing and potential leakage paths into the condenser, and relocating the condensate makeup line to the hotwell to provide better oxygen removal.

The May 1983 eddy current inspec tion was performed on 100% of the unplugged tubes. As a result of this inspec tion, 16 tubes were plugged in the A steam generator, 139 in B, and 208 in C.

In 1982 a total of 196 tubes were plugged; in 1981, 401 tubes; in 1980, 314 tubes; in 1979, 38 tubes; and prior to 1979, 324 tubes.

1.2 Reasons.for Steam Generator Repair The steam generators at Carolina Power and Light Company's H. B. Robinson Unit 2 have experienced significant corrosion-related phenomena that require periodic inspection and plugging of steam generator tubes to ensure their continued safe operation as discussed in Section 1.1 above. At the present time, HBR-2 is being operated at reduced power to retard the rate of SG tube degradation.

Projections of industry experience and CP&L experience at HBR-2 indicate the possibility of increasingly frequent inspection intervals and a permanent reduc tion of unit power. As of May 1983, tube plugging for various reasons has resulted in removing about 16.7% of the steam generator tubes from continuing service at the HBR-2 plant.

Because of the continuing tube degradation problems, the certainty of additional tube plugging that will result in continuing power reduction, and the economic considerations for operating with substantially reduced heat transfer capacities on Unit 2, CP&L submitted a proposal for the replacement of the degraded por tions of the steam generators. This replacement would increase availability and reliability of the plant and permit the plant to return to full power operation.

H. B. Robinson 2 SER 1-3

2.0 SCOPE OF WORK TO BE PERFORMED The steam generator repair program proposed by CP&L is essentially identical to the steam generator repairs completed by the Florida Power and Light Company for Turkey Point Units 3 and 4, and essentially similar to the repairs conducted at Surry Power Station Units 1 and 2. Each of the plants contains two Westing house three-loop pressurized water reactors (PWRs).

Each plant began operation using a sodium phosphate secondary water chemistry treatment: H. B. Robinson Unit 2 in June 1971 and Turkey Point in late 1974. The Turkey Point repair program was approved June 24, 1981 and repair commenced in June 19, 1981 for Unit 3 and was completed April 7, 1982. Unit 4 repair commenced October 16, 1982 and was completed May 16, 1983.

2.1 Removal and Reinstallation Operations The repair will consist of replacing the lower assembly of each steam generator including the shell and the tube bundle and refurbishing the upper assembly.

The old lower assembly will be removed from the containment building through the existing equipment hatch and transported to a special storage facility that will be constructed on the H. B. Robinson site.

Before the repair work begins, the unit will be shut down. The reactor vessel head will be removed for defueling. All of the normal procedures for fuel cool ing and fuel removal will be followed. The fuel will be removed from the reac tor and placed in the spent fuel storage facility, and then the reactor vessel head will be replaced. The primary system piping will be drained after defuel ing is completed. The equipment hatch will be opened and access control will be established. Approximately the top 2 to 3 feet of the biological shield walls and a portion of a missile shield wall adjacent to steam generator A will be removed to provide access to the steam generators. Guide rails will be installed for transporting the lowef'assembly through the equipment hatch.

During this preparatory work, the cutting of system piping will begin. This will include cutting and removal of sections of steam lines, feedwater lines, and miscellaneous smaller lines for the service air and water and the instru mentation system. The steam generator will then be cut at the transition cone, and the upper shell and internals will be removed and will be refurbished. A shield cover will then be welded to the lower assembly at the transition cone cut. After the channel cut at the bottom, the lower assembly will be lifted to the working level where a shield cover will be welded to the bottom of the lower assembly.

Following this, the steam generator lower assembly will be lowered and placed in position on a transport mechanism. This mechanism will carry the assembly through the equipment hatch. A mobile crane will lift the lower assembly onto a transporter that will carry it to the steam generator storage facility on the site. The other two steam generator lower assemblies will be lifted from their location, welded shut, and lowered through the equipment hatch in the same man ner that the first steam generator was removed.

H. B. Robinson 2 SER 2-1

After removal and storage of the steam generator lower assemblies, their replace ments will be transported from the temporary storage location to the equipment hatch. The same equipment used to remove the lower assemblies will be used to install the new assemblies onto the existing channel heads. The steam generator lower assembly will be reinstalled and rewelded to the existing channel head.

The upper assembly with its refurbished internals will be mounted on the lower assembly. After welding the two assemblies together, the secondary piping will be reconstructed. Following these major repair activities, cleaning, hydro static testing, baseline inservice inspections, and preoperational testing of instruments, components, and systems will be performed. Then the reactor will be refueled and startup tests wi.11 be done. The performance of the repaired steam generators will be tested for moisture carryover and verification of thermal and hydraulic characteristics.

H. B. Robinson 2 SER 2-2

3.0 EVALUATION Several modifications have been made to the steam generators to increase the circulation ratio. The circulation ratio is the total tube bundle flow divided by the feedwater flow and is inversely proportional to the steam quality leav ing the tube bundle. As the ratio increases, the lateral flow velocity also increases and thus reduces the number of tubes exposed to low velocity flow and the potential for sludge formation. Low steam quality in the bundle reduces the number of tubes exposed to local steam blanketing and reduces the number of potential areas of chemical impurity concentration.

The modified model 44F steam generators will match the design performance of the originally installed model 44 steam generator. However, several design modifications have been incorporated that do not alter mechanical performance and FSAR parameters. These design features are intended to provide better flow distribution, additional bundle access, minimize the potential for second ary side corrosion, and facilitate maintenance and reliability of the steam generators.

3.1 ASME Code Application The original steam generators were designed and fabricated to the requirements of the 1965 Edition of the ASME Code,Section III including all addenda through Summer 1966. The replacement lower assemblies will be fabricated to the require ments of the 1980 Edition of the ASME Code,Section III including all addenda through Winter 1980. Design of the steam generators will be consistent with the original design of the reactor coolant system as well as the upper shell assembly of the.steam generators which will not be replaced and is acceptable.

None of the requirements imposed on the replacement lower assemblies will inhibit the capability of the steam generators to meet the performance and FSAR safety requirements.

3.2 Quality Assurance Program The quality assurance (QA) program for the steam generator repair at the H. B.

Robinson Steam Electric Plant Unit No. 2 is described in Section 3.7 of the Carolina Power &*Light Company (CP&L) report submitted by letter dated January 6, 1983. The program is applicable to all activities to be conducted for the steam generator repair including design, disassembly, removal, fabrication, installa tion, inspection, and return-to-service testing.

The staff has reviewed this information to verify that the QA commitments are acceptable for the proposed steam generator repair work. NRC acceptance criteria are (1) whether QA program commitments previously found acceptable' by the NRC will be applied to the steam generator repair, or (2) if new commitments are presented, they are at least as stringent as the existing commitments to ensure that the QA program is not degraded.

H. B. Robinson 2 SER 3-1

CP&L has the overall responsibility for the QA program for the steam generator repair. The CP&L QA program, described in CP&L letters to the NRC dated March 18, 1981 and August 4, 1981, is applicable to this work. In accordance with this program, CP&L will approve the QA programs of Westinghouse and its onsite con tractors. CP&L will ensure implementation of these programs commensurate with the scope of work to verify conformance with the requirements of 10 CFR 50 Appendix B. CP&L QA personnel will audit and provide surveillance to ensure that all activities are conducted in accordance with applicable codes, stand ards, and regulations.

The Westinghouse QA program for the design, fabrication, and installation is described in WCAP-8370.

The application of regulatory guides for QA is addressed in the CP&L QA pro gram. The regulatory guides and ANSI Standards listed in Table 3.1 are con sidered applicable.

On the basis of its review and evaluation of Section 3.7 of the referenced CP&L report, the staff concludes that CP&L has described a QA program which is acceptable for the steam generator repair at the H. B. Robinson Steam Electric Plant Unit No. 2.

3.3 Component Design Modifications Interfaces between the steam generators and plant components and systems will be maintained. Dry and wet weights of the steam generators will remain approxi mately the same as will the center of gravity; therefore, no changes to present supports or their configuration are considered necessary. Since the replacement lower assemblies have been designed to incorporate changes based on field experi ence, a number of minor changes in specific components have been made which could affect thermal hydraulic performance of the unit. In order to maintain the original thermal hydraulic conditions, heat transfer surface parameters had to be adjusted. As a result of changes in the support plate configuration, the number of tubes decreased from 3260 to 3214. Design data for the steam generators are presented in Table 3.2. These data allow comparison between the original steam generator and the replacement units. The thermal data of each steam generator will remain the same as thermal data of the original steam generators.

The replacement lower assembly, shown schematically in-Figure 3.1 includes the following features.

3.3.1 Flow Distribution Baffle A flow distribution baffle, located approximately 23 inches above the tubesheet has a cut-out center section and oversized drilled tube holes. Shown in Figure 3.2, the baffle plate directs the flow across the tubesheet and then up the center of the bundle through the center cut-out. The design is sized to mini mize the number of tubes exposed to sludge. Consistent with this purpose, the design causes the sludge to deposit in and near the center of the bundle at the blowdown intake. The flow distribution baffle plate material is ferritic stain less steel.

H. B. Robinson 2 SER 3-2

Table 3.1 Applicable regulatory guides and ANSI standards for CP&L QA program Document Title Date Endorses Regulatory Guide 1.37 Quality Assurance Requirements for Cleaning of 3/73 N45.2.1 Fluid Systems and Associated Components of Water Cooled Nuclear Power Plants 1.38 Quality Assurance Requirements for Packaging, 3/73 N45.2.2 Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants 1.39 Housekeeping Requirements for Water-Cooled 3/73 N45.2.3 Nuclear Power Plants 1.58 Qualification of Nuclear Power Plant Inspection, 9/80 N45.2.6 Examination, and Testing Personnel, Rev. 1 1.64 Quality Assurance Requirements for the Design of 10/73 N45.2.11 Nuclear Power Plants 1.74 Quality Assurance Terms and Definitions 2/74 N45.2.10 1.88 Collection, Storage, and Maintenance of Nuclear 8/74 N45.2.9 Power Plant Quality Assurance Records 1.94 Quality Assurance Requirements for Installation, 4/75 N45.2.5 Inspection, and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants 1.144 Auditing of Quality Assurance Programs for Nuclear 1/79 N45.2.12 Power Plants 1.146 Qualification of Quality Assurance Program Audit 8/80 N45.2.23 Personnel for Nuclear Power Plants ANSI Standard N45.2.8 Supplementary Quality Assurance Requirements for 1975 Installation, Inspection, and Testing of Mechani cal Equipment and Systems for the Construction Phase of Nuclear Power Pladts N45.2.13 Quality Assurance Requirements for Control of Pro-4/74 curement of Items and Services for Nuclear Power Plants, Draft 2, Rev. 4 H. B. Robinson 2 SER 3-3

Table 3.2 Steam generator design data (per steam generator)

Design Original Replacement Design pressure, reactor coolant/steam, psig NC Reactor coolant hydrostatic test pressure (tube side), psig 3106 NC Hydrostatice test pressure, shell side, psig 1356 NC Design temperature, reactor coolant/steam, OF 650/556 NC Steam conditions at 100% load, outlet nozzle:

Steam flow, lb/hr 3.37 x 106 NC Steam temperature, OF 518.2 NC Steam pressure, psia 800 NC Feedwater temperature at 100% load, oF 441.5 NC Overall height, ft-in.

63-1/6 NC Shell OD, upper/lower, in.

166/127 NC Shell thickness, upper/lower, in.

3.5/2.62 NC U-tube OD, in.

0.875 NC Tube wall thickness (nominal), in.

0.050 NC Number of manways/ID, in.

3/16 NC Number of handholes/ID, in.

2/6 6/6 Number of U-tubes 3260 3214 Tube length (largest U-bend), in.

397.5 NC Total heat transfer surface area, ft2 44,430 43,467 Reactor coolant water volume, ft3 928 925 Reactor coolant flow, lb/hr 33.8 x 106 NC Secondary side volume, ft3 4729 4715 Secondary side mass no load, lb 134,000 137,000 Secondary side mass 100% power, lb 92,000 91,000 Center of gravity (from support pads), fin.

25/3.6 NC 3NC

= no change.

33.3.2 Blowdown System The blowdown system will have a higher capacity than the present blowdown sys tem.

Each steam generator will be designed to have two 2-inch internal blow down pipes.

The blowdown rate from each steam generator is varied as required by chemistry conditions in the feedwater and as monitored in the blowdown.

Continuous blowdown of the steam generator provides a mechanism for constantl~y removing impurities from the secondary water system and steam generators.

The internal blowdown location is coordinated with the baffle plate design so that the maximum intake is located where the greatest amount of sludge is expected to deposit.

3.3.3 Steam Generator Tubes 3.3.3.1 Tube Expansion The tubes are expanded to full depth of the tubesheet holes.

They are tack rolled and welded as shown in Figure 3.3 and tested for gas leakage.

H. B. Robinson 2 SER 3-4

TRANSITION CONE TRUNION SEISMIC LUG LOWER SHELL BARREL QUATREFOIL TUBE SUPPORT PLATE. (6) k WRAPPER 7/8" 0.0.

8LOWOOWN PtPE Wrapper FLOW DISTRIBUTION Access.

BAFFLE HANO HOLE Opening STUB BARREL TUBE LANE BLOCK Figure 3.1 H. B. Robinson Unit No. 2:

Steam generator lower assembly H. B. Robinson 2 SER 3-5

SLOWDOWN PIPE HOL ALONG TUBE LANE FTBT BAFFLE CU TOUT I

FLOW DISTRIBUTION BAFFLE HOT LEG COLD LEG Figure 3.2 H. B. Robinson Unit No. 2:

Flow distribution baffle and blowdown H. B. Robinson 2 SER 3-6

FULL DEPTH EXPANSION woMINALY FLUSH WEL Figure 3.3 H. B. Robinson Unit No. 2:

Tube-to-tubesheet juncture H. B. Robinson 2 SER 3-7

The benefits of the hydraulic expansion process are the reduction of the cold working caused by the mechanical hard rolling and the lower residual stresses at the transition of the expanded to unexpanded region of the tubes. Analyses and experiments have shown these tensile stresses to be of the order of 20 ksi on the outside surface and 20-30 ksi on the inside, which are about half the stresses for a mechanical roll.

3.3.3.2 Heat Treatment of Tubes In addition to the change to hydraulic expansion, the tubing material was also changed to take advantage of the increased corrosion resistance of thermally treated Inconel 600 to stress corrosion cracking (SCC) and intergranular attack (IGA) in both primary and secondary environments.

In addition the tubes in the innermost eight rows of the tube bundle will be stress relieved after bending to reduce residual stresses and reduce the potential for primary side stress corro sion cracking. The occurrence of SCC and IGA, which has been observed in some partially expanded units is expected to be minimized by the combination of the full depth hydraulic expansion and the thermal treatment of the Inconel 600 tubing.

The staff has examined the results of model boiler tests in which heat-treated Inconel 600 tubes were hydraulically expanded into simulated tubesheets.

For accelerated time testing these tube/tubesheet models were exposed at steam gen erator, hot-leg, operating temperatures in a severe caustic corrosive medium.

Although steam generators do not operate in severe caustic environments, this environment provides an accelerated test condition for determining susceptibil ity to corrosive degradation.

Extended tests in this environment did not produce corrosive attack upon the Inconel 600 tubes that had been thermally treated and hydraulically expanded into a simulated tubesheet.

3.3.4 Offset Feedwater Flow Distribution An offset feedwater flow distribution will be provided in the replacement unit.

Feedwater flow within the steam generator is modified so that approximately 80%

of the flow is directed to the hot-leg side of the bundle and the remaining 20%

of the flow is directed to the cold-leg side of the bundle. This reduces the steam quality in the hot-leg side of the bundle and raises the steam quality in the cold-leg side. The effect of these changes in steam quality is to shift the point of highest steam quality at the tubesheet elevation toward the center of the bundle. The point of highest steam quality has the lowest density and is, therefore, a likely region for chemical concentration and sludge deposition.

This area is utilized for location of the blowdown intake. Feedwater flow dis tribution is accomplished by providing a greater number of flow paths on the por tion of the feedwater ring which traverses the hot-leg side of the tube bundle.

3.3.5 Support Plates 3.3.5.1 Materials To reduce the potential for tube denting, the tube support plate material has been changed from carbon steel to ferritic stainless steel, in the replacement steam generators. Corrosion in the crevice between the tube and tube support H. B. Robinson 2 SER 3-8

plate has led to denting of the steam generator tubing in that area. Alterna tive support plate materials have been evaluated, and SA-240 Type 405 ferritic stainless steel has been selected as the optimum material for this application.

This material is ASME Code-approved and is resistant to corrosion. In addition, SA-240 has a low wear coefficient when paired with Inconel and has a coefficient of thermal expansion similar to carbon steel.

Corrosion of SA-240 results in an oxide which has approximately the same volume as the parent material, whereas corrosion of carbon steel results in oxides which have a larger volume than the parent material.

In addition to the tube support plates, the baffle plate will be constructed of SA-240 Type 405 stainless steel.

3.3.5.2 Quatrefoil Support Plate Design The quatrefoil tube support plate design, illustrated in Figure 3.4, consists of four flow lobes and four support lands. The lands provide support to the tube during operating conditions; the lobes allow flow around the tube. The quatrefoil design directs the flow along the tubes to minimize steam formation and chemical concentrations at the tube-to-tube support plate intersections.

The quatrefoil support plate design has a lower pressure drop and results in higher average velocities along the tubes, minimizing sludge deposition. The combination of higher velocities in the support plate region and corrosion resistant material should minimize the potential for support plate corrosion.

3.3.6 Tubesheet Welds Flush tube-to-tubesheet welds will be provided in the replacement lower assem blies. Elimination of the protruding tube stub of the original design results in lower entry pressure losses and, therefore, a lower pressure drop in the primary loop. In addition, a possible location of radioactive crud build-up is avoided with this design. This is ill'ustrated in Figure 3.3.

3.3.7 Tube Lane Blocking Device A tube lane blocking device consisting of a series of plates is provided to limit flow in the tube lane. Recirculating water exiting at the bottom of the wrapper will tend to preferentially channel to the tube lane and bypass part of the tube array. The plates prevent the tube bundle bypass.

3.3.8 Access Ports Additional access ports have been provided in the lower assemblies. Four 6-inch access ports will be located slightly above the tubesheet, approximately 900 apart. Two 6-inch access ports will be located on the tube lane, between the flow distribution baffle and the first tube support plate. The addition of these access ports should permit additional inspections of the tubesheet and flow distribution baffle and assist in sludge lancing.

3.3.9 Inspection Port One 3-inch inspection port is located on the lower shell transition cone at an elevation slightly above the top tube support plate of the tube bundle. This port, located on the tube lane centerline, permits inspection of the support plate and tubing U-bend area.

H. B. Robinson 2 SER 3-9

SUPPORT PLATE SECT ION Figure 3.4 H. B. Robinson Unit No. 2:

Quatrefoil tube support plate H. B. Robinson 2 SER 3-10

3.3.10 Additional 2-Inch Nozzle A 2-inch nozzle will be added to the upper shell to facilitate wet layup of steam generators. The nozzle can also be used in conjunction with other systems to circulate water through the steam generator during periods of layup.

3.3.11 Piping, Equipment Interference Removal, and Replacement It will not be necessary to remove any mechanical equipment in order to provide access to the steam generators or to provide a movement pathway. The major piping that must be removed is the sections of main steam and feedwater lines connecting to each steam generator. Both lines will be cut at the steam genera tor nozzles and in the vertical runs at an elevation convenient to the operating door. No cuts will be made until the remainder of the piping system has been temporarily stabilized and restrained. The locations of the cuts are shown in Figure 3.5. All open ends of cut piping will be capped and/or plugged to ensure cleanliness during the repair program.

Other piping to be removed and/or relocated include the following:

(1) Steam generator blowdown piping, as required.

(2) Vent piping, as required.

(3) Sections of small bore service air, instrument air, and fire protection lines, which are supported by the mezzanine to be removed for steam generator clearance, will be relocated before the mezzanine is removed.

Piping systems will be removed by machine cutting with remotely controlled equipment or with the option of flame cutting where limitations or advantages warrant. Where flame cutting is employed, proper treatment of heat-affected cut materials will be included in the procedures.

The instrumentation lines associated with level transmitter and sensing will be temporarily disconnected and/or removed and stored in the containment area.

No major pieces of electrical equipment and control equipment will require removal or relocations.

Short sections of permanent ventilation duct must be removed to provide ade quate working room at the channel heads of steam generators A and B. The duct work is of welded construction and the removed portions will be salvaged and reinstalled without modification.

3.3.12 Steam Generator Upper Lateral Restraints Seismic restraint for the steam generator is provided by a ring girder located just below the operating deck. The ring permits movement to accommodate ther mal expansion, but is prevented from lateral motion by traveling in guides.

Hydraulic snubbers control movement in the direction of the thermal expansion.

It may be possible to remove and reinstall the lower generator sections wi-thout dismantling the restraints. The clearances are close, however, and attempts to take field measurements during a previous outage did not resolve the question completely.

H. B. Robinson 2 SER 3-11

Limi Covr Ar V4%o Jamv PeiaeTo Cur C.ui L..IL I / ;;

01 i

Figure 3.5 Typical generator upper assembly for all three H. B. Robinson Unit No. 2 steam generators showing piping cuts in main steam and feedwater lines H. B. Robinson 2 SER 3-12

Plans will be prepared to effect the replacement either with or without dis mantling the restraint structure. The decision will be made later as to the method when access can be obtained for precise measurement of both the rings and the replacement generator sections. A model of the area and the upper restraint has been made to aid in the development of a plan in the event that the restraint ring must be dismantled.

3.3.13 Steam Generator Mid-Section Replacement After steam and feedwater.piping connections to the steam dome have been removed (either by machine or flame cut) the steam dome will be parted by use of a track mounted torch cutting unit at the site of the original weld between dome and transition cone. Sufficient material will be left to allow a finish weld pre paration cut to be made before reinstallation. The inside wrapper will also be parted by flame cutting and the entire assembly will be removed. After removal of the steam dome, a metal shield will be welded in place over the open end of the lower steam generator section. The lower assembly will be separated from the channel head by track-mounted machine cutting methods for the circumferen tial cut, following a plasma arc of the original weld between channel head and tubesheet.

Where flame cutting is used, appropriate preheating will be used to ensure integrity of the component. After the removal of the existing lower assembly, the channel head and divider plate will be machined to the appropriate contour for the replacement weld. Portable milling equipment is available for this operation and will be utilized. Preparation for steam dome weld will be manual.

The weld joint design for the channel head will generally follow the methods used at Turkey Point and will permit most of the welding to be performed from outside the vessel.

After the existing lower channel head has been "weld prepped," a new steam gen erator lower assembly will be lowered into position and welded, followed by the replacement of the reworked moisture separator dome.

The stress relief heat treatment of joints will take into account the previous total accumulative soak time of the existing steam generator component to ensure full compliance with ASME Code requirements. Welded joints shall be locally post-weld heat treated (PWHT) by electrical resistance heating at the tempera ture of 11250F +/- 250F to provide stress relief. During preheating and PWHT, thermocouples and insulation shall be utilized for maximum temperature control and to limit heating of other areas and components.

3.3.14 Prevention of Loose Parts CP&L will develop special procedures to ensure cleanliness and preclude the entry of foreign parts or objects into the steam generator components during disassembly and reassembly. Physical barriers with access control will be installed to prevent any inadvertent entry when the steam generators are open.

Sign-in and sign-out logs for personnel, tools, and equipment will be maintained by access control.

Tubesheet protection will be installed before installation, and special procedures will address removals and inspection hold points as H. B. Robinson 2 SER 3-13

required. Tube bundle and downcomer openings will be protected and access con trol established at secondary manways for controlling entries as noted above when systems are open. Before and during removal of these physical barriers, access control will be established to verify that no foreign objects enter those systems as they are being opened.

Before putting the unit back into service, a boroscopic inspection of the second ary side of the steam generator will be conducted to ensure that no objects have gained entry or remain in place. Mechanical severance of the secondary piping systems and immediate plugging will be a requirement of the procedures and physical inspection hold points will be required to fit-up and weld-out.

In addition, contractor personnel will be trained relative to CP&L cleanliness policy and procedures. QA surveillance personnel will ensure that all procedures including hold points are strictly adhered to.

3.3.15 Additional Corrosion-Related Aspects of Repair In addition to reviewing the design changes of the new lower steam generator assemblies, the staff has reviewed the following corrosion-related areas of concern:

(1) secondary water chemistry monitoring and control program, (2) the decontamination process used in preparing surfaces for joining or repair, (3) layup conditions for portions of the secondary and primary systems to be reactivated, (4) the criteria for the startup condition of metal surfaces in the reassembled secondary water system, and (5) the storage conditions of the degraded and removed portions of the steam generators.

A major modification to minimize corrosion is the control of secondary water chemistry from phosphate chemistry to all-volatile treatment (AVT). The licensee has committed to a secondary secondary water chemistry monitoring and control program consistent with the guidelines described in EPRI Special Report NP-2704-SR, October 1982.

The decontamination of the steam generator and secondary system surfaces that are to be joined or repaired will be accomplished using techniques which are the same as those used during normal plant operation and will be performed by normal repair and maintenance procedures.

The normal procedures require flush ing the surfaces with water and then wiping with an absorbent cloth.

If any further decontamination of the surface is necessary, an abrasive method with boric acid crystals in a water slurry will be used. This procedure will not introduce materials that are deleterious to the reactor coolant system or secondary water system.

The parts of the primary system being refurbished or replaced will be kept in a wet layup condition using borated demineralized water with hydrazine addition and/or nitrogen blanketing, as appropriate, to prevent the intrusion of oxygen.

This corrosion control in storage should be adequate to prevent corrosion de gradation of primary system surfaces.

Layup of secondary systems such as the feedwater system and condenser will be dry. These systems will be drained and dried with air in accordance with normal plant maintenance practice.

Careful draining and drying of these secondary systems should be adequate to prevent corrosion degradation during system layup.

H. B. Robinson 2 SER 3-14

The steam generators are sealed and protected against moisture during shipment.

During installation the steam generator is open to the normal containment atmos phere but no fluids are allowed within the assembly. Thus, there is assurance the steam generator surfaces are acceptably clean and not degraded.

The lower assembly removal procedures require that the assembly be drained and sealed before it is moved out of the containment. Three-inch-thick steel closure plates will be welded over the top of the lower assembly at the girth cut location, over the inlet and outlet reactor coolant nozzles, and over all other vessel penetrations to seal the assembly. This procedure is adequate to prevent the leakage of radioactive material to the outside environment because of internal corrosion during the period when the replaced lower assemblies will be stored on site.

3.3.16 Post Repair Tests and Evaluations To Assure Integrity of the Reactor Coolant System and Compliance With Applicable Codes The preoperational and startup test program is being developed but many details remain to be determined. The objective of the test program will be to ensure

-that the plant is returned to safe and reliable full power operation. The steam generator replacement program will comply with the requirements of Section XI of the ASME Code and the plant Technical Specifications. These basic require ments will assure the integrity of the reactor coolant systems.

Subsection IWB-5222 of Section XI of the ASME Code identifies the required test pressure as a function of test temperature. Also, Technical Specification 3.1.2 (Heatup and Cooldown) provides limit curves on the allowable combination of pressure and temperature in the primary system. Based on these requirements, the ASME Section XI test pressure would be about 2307 psig. However, Technical Specifications 3.1.2.1.e and 4.3.1 will set the test pressure at 2335 psig for the primary system.

The inspections during the pressure test will satisfy Subsection IWA-5246 of Section XI of the ASME Code and assure that the pressure boundary is acceptable.

The steam generator replacement project is primarily for the purpose of replac ing the three steam generator tube bundles; any other work to be performed is not anticipated to be major. Thus the preoperational testing will be oriented to this component and will not be as extensive as the testing involved in start up of a plant. The testing will satisfy the H. B. Robinson Technical Specifica tions.

The testing and inspection will involve cleaning, checkout of the fuel-handling equipment, pressure testing, checkout of important instrumentation, and functional testing. The purposes of the functional tests are as follows:

Thermal Expansion Testing:

To verify that the steam generators can expand and contract without obstruction during heatup to operating conditions and return to cold shutdown conditions. This testing will also include observation of the affected piping and instrumentation.

SG Water Level Stability and Control Testing:

To verify stability of the auto matic level control system including step load changes.

H. B. Robinson 2 SER 3-15

SG Thermal Output and RCS Flow Testing:

To measure RCS flow using primary and secondary calorimetrics and to measure the SG thermal output at steady-state conditions.

SG Moisture Carryover Testing:

To verify that the moisture carryover in the steam leaving the SGs satisfies the design/performance requirements.

3.4 Summary The design of the new steam generator lower assemblies will be consistent with the design performance of the lower assemblies being replaced. However, several design features that.do not alter the mechanical performance and FSAR parameters are included in the new lower assembly design. These modifications include a flow distribution baffle, improved internal blowdown design, tube expansion in tubesheet, offset feedwater distribution, quatrefoil tube support plates, tube lane blocking device, and access ports.

Staff evaluation of these modifications indicates that these design features should provide better flow distribution, provide additional tube bundle access, and minimize the potential for secondary side corrosion. The replacement lower assemblies including the modified com ponents will meet the requirements of Sections III and XI of the 1980 Edition of the ASME Code including all addenda through Winter 1980.

The staff evaluation to determine the impact of the repair activities on the components, piping, mechanical equipment, cables, ducts, and instruments indi cates that the impact should be minimal.

The stress relief heat treatment procedures of the welded joints are in compliance with ASME Code requirements.

Adequate measures have been taken to minimize stresses on clad components dur ing cutting, welding, and stress relief heat treatment.

On the basis of staff's evaluation of the corrosion aspects of the modifications discussed above, the staff concludes that:

(1) the design modifications and material changes in the replacement steam generators will reduce the potential for corrosion degradation, (2) the procedures and controls to be used in the repair/replacement program.are adequate to reduce the potential for corrosion degradation of the reassembled primary and secondary coolant systems during layup and subsequent operation, and (3) there is reasonable assurance that the removed portions of the steam generators.will not degrade by corrosion during the long term.

The staff, therefore, concludes that the steam generator repair/replacement pro gram is acceptable from the corrosion aspect and the secondary water chemistry monitoring and control program meets the requirements of GDC-14. In addition the staff concludes that changes in steam generator mechanical design, thermal hydraulics, materials selection, tube fabrication techniques, and changes in secondary system design, water chemistry, and operation appear to be the effec tive solutions to steam generator problems previously encountered at HBR-2.

The post-repair preoperational and startup test program proposed by the licen see is considered adequate. This program will comply with the plant Technical Specifications and will assure the integrity of the reactor coolant system.

The testing will include verification of the pressure integrity of the primary system, free piping movements during thermal expansion, and other design/

performance parameters. Based on its review, the staff concludes that this preoperational test program is acceptable.

H. B. Robinson 2 SER 3-16

4.0 HANDLING OF HEAVY LOADS The staff has reviewed the HBR-2 Steam Generator Repair Report for the handling of heavy loads as follows.

The existing polar crane will be modified to make the special heavy lifts required during the replacement of the steam generators. Although the crane is to be upgraded/modified to a temporary capacity of 210 tons, the nameplate rating (155 tons) will not be changed and therefore the present rating of 155 tons will remain the same. The licensee indicates that heavy load handling activities for the steam generator replacement will not begin until all the fuel has been removed from the containment and stored in the spent fuel pool.

In addition, the primary system piping within the postulated steam generator lower assembly drop zone will be drained. Thus, there are no offsite dose considerations resulting from the dropping of heavy loads during the repair phase.

4.1 Return to Normal Operation In response to the staff's concern for assuring that the polar crane can safely handle heavy loads once normal plant operation begins (after completion of the repair program), the licensee-committed to the following:

(1) Special heavy lifts during the steam generator repair project will meet the guidelines of ANSI B30.2.0-1976, Section 2-3.2.1, concerning handling of special heavy lifts. Records of special heavy lifts will be maintained in.project records as part of the steam generator repair program.

(2) At the completion of the steam generator repair project, and before return ing the crane to normal service, a general visual inspection of the crane will be made in accordance with ANSI B30.2.0-1976, Section 2-2.1.3. How ever, the crane parts will not be disassembled for the inspection. The licensee has indicated that an operational test will be performed in accordance with Section 2-2.2.1 of ANSI B30.2.0-1976. In response to the staff's request that a rated load test also be performed in accordance with Section 2-2.2.2 of ANSI B30.2.0-1976, the licensee stated that this test is not required since no modifications will be made to the crane after the special heavy lifts which are in excess of the 155-ton rating are completed.

(3) During the licensee's response in (2) above, the licensee also indicated that before returning the crane to normal service a fatigue analysis will be provided to verify that the special lift of 210 tons to be performed 6 times during the repair program had not caused any unacceptable damage or degradation of the crane.

The staff has reviewed the licensee's response and concludes that the above responses adequately address staff concerns in the area of heavy loads handling during the steam generator repair program for restoration of the polar crane to normal service, and are, therefore, acceptable.

H. B. Robinson 2 SER 4-1

4.2 Return to Service Testing The licensee indicated in the repair report that the main feedring will be replaced as part of the steam generator repair program. The modifications to be made to the feedwater system include removal and reinstallation of a segment of feedwater piping external to the steam generator (in order to permit the steam generator to be removed), and replacement of the steam generator feedring, the thermal sleeve between the feedring and shell nozzle, a short segment of the feedwater nozzle, and the feedring supports. The new feedring assembly will have J nozzles which will provide a top (upward) discharge of the feedwater after installation. These J nozzles serve to reduce the possibility of draining of the feedring should the water level drop below the level of the feedring.

The feedwater piping itself also incorporates features to reduce waterhammer.

potential.

The existing feedwater piping immediately external to all three steam generators has a horizontal length of about 3 feet 6 inches, and then turns downward for a distance of about 20 feet. This arrangement reduces the space for formation of a steam pocket and thus limits the chance of a water hammer from steam bubble collapse. Following replacement of the steam genera tor lower assemblies and reinstallation of the steam domes, the feedwater piping will be restored to its pre-replacement configuration.

The licensee maintains that the above features are sufficient to reduce the potential for waterhammer without the need for a feedwater waterhammer test.

The staff has reviewed CP&L's response and concludes that it does not suffi ciently resolve staff concern. It is the staffs position that further veri fication is necessary in order to show that no unanticipated problem caused by waterhammer would result when the new steam generators are,in service and an auxiliary feedwater system demand occurs. Therefore, as discussed with and agreed to by the licensee, the licensee will verify that no waterhammer occurs as part of normal startup testing when auxiliary feedwater is being supplied to the new steam generators. Performance of this verification will resolve staff concerns with regard to waterhammer.

H. B. Robinson 2 SER 4-2

5.0 RADIOLOGICAL CONSIDERATIONS

5.1 Background

The staff evaluated the radiation protection measures established by Carolina Power and Light Company (CP&L) for the steam generator replacement program at the H. B. Robinson Steam Electric Plant Unit No. 2 (HBR-2), including those features intended to ensure that doses will be-maintained as low as is reason ably achievable (ALARA). The bases for the staff's review are the criteria outlined in Regulatory Guide 8.8, "Information Relevant to Ensuring That Occupa tional Exposures at Nuclear Power Stations Will Be As Low As Is Reasonably Achievable."

The licensee has provided information regarding its steam generator replacement program in its January 6, 1983 submittal, and Revision 1, dated March 31, 1983 of the "H. B. Robinson Unit No. 2 Steam Generator Repair Report," and in re sponses to the staff's requests for additional information dated June 3, 1983 and July 15, 1983. Additional information considered by the staff includes the NRC Health Physics Appraisal and subsequent related health physics inspections conducted at HBR-2. The licensee's plans and programs for ALARA/radiation pro tection are consistent with guidance in Regulatory Guide 8.8 and are acceptable.

The licensee will utilize methods that minimize individual and collective doses through the use of preplanning, access control, personnel monitoring, radiation and contamination surveillance, airborne radioactivity control, radwaste control, training, pretask dose assessment, source reduction via decontamination and shielding, and evaluation of similar Surry and Turkey Point experiences.

5.2 Occupational Exposure The licensee anticipates repairing its HBR-2 steam generators by replacing the lower portion (tube bundle) of the existing units with new assemblies. This will involve the cutting of the steam generators at the top of the transition cone and at the channel head below the tubesheet, with the subsequent installa tion and rewelding of new assemblies in a manner similar to that employed suc cessfully for the Turkey Point steam generator replacements. The licensee has evaluated several options for disposing of the removed lower assemblies, and has selected long-term, intact, onsite storage in a temporary storage facility.

The dose estimated by the licensee for the generator replacement task at HBR-2 is 2120 person-rems, including about 30 person-rems anticipated for storage.

The licensee's estimates were derived from anticipated man-hours in known radia tion fields for all tasks planned. This methodology is acceptable, and the dose estimates are consistent with doses observed for similar steam generator repair-work in the industry. Dose expended is expected to be offset by dose reductions and savings over the next 9 years through successful completion of the project.

H. B. Robinson 2 SER 5-1

5.3 ALARA Considerations The licensee has planned a variety of techniques to be employed for dose reduc tion during the replacement project. These are backed by a management commit ment for a strong ALARA posture, and by facility-implementing procedures. The licensee has committed to maintaining both onsite and offsite doses to ALARA levels for the steam generator replacement project. During the replacement project, the licensee will perform general area decontamination in containment, as well as primary surface decontamination in the steam generator to reduce potential doses to workers and minimize exposure of workers to radioactive materials. The use of temporary shielding to reduce exposure from radioactive systems and equipment, "hot spots," and components of the steam generators will also be employed. Valves and piping that significantly contribute to work area dose rates will be evaluated for removal and replacement, shielding, or decon tamination. Low-dose-rate "wait areas" will be designated to minimize doses to workers during those times when they were not actively involved in the repair work.

Regulatory Guide 8.8 recommends that preparation and planning actions be com pleted before workers enter radiation areas (Sections C.1.b and C.3.a). The licensee has provided a commitment to complete planning and preparations (i.e.,

to identify specific applications and finalize details) before the initiation of the steam generator replacement task for the following ALARA/radiation pro tection measures planned for the steam generator replacement task, as follows:

(1) general area decontamination (November 1, 1983),

(2) primary surface decontamination (completed, July 15, 1983),

(3) -use of temporary shielding (before-start of outage),

(4) use of specialized tools (December 1, 1983),

(5) removal of selected valves and piping (completed, July 15, 1983),

(6) establishment of low-background wait areas (completed, July 15, 1983),

(7) establishment of laydown areas (before start of outage),

(8) training and training facilities for plant and contractor personnel (before initiation of related tasks),

(9) access control (completed, July 15, 1983),

(10) equipment decontamination and decontamination facilities (before start of outage),

(11) engineering controls which preclude the need for respiratory protection (November 1, 1983),

(12) dose tracking (completed, ongoing throughout outage).

H. B. Robinson 2 SER 5-2

The licensee has :reviewed outage sequences utilizing ALARA coordinators to determine the specific applications of the above measures. Laydown and "wait areas" have been or will be clearly identified and prepared for the task start, including provisions for decontamination, temporary shielding, posting, and access.

Radiation,-contamination, and airborne radioactivity surveys will be conducted as necessary to determine radiation protection measures. The licensee has ade quate numbers of portable air-sampling instruments available for the replace ment task as discussed in Regulatory Guide 8.8, Section C.4, and has verified that HBR-2 counting facilities will be adequate for the anticipated increased surveillance activities as in Regulatory Guide 8.8, Section C.4.

The licensee will use respiratory protection equipment and the containment ven tilation system to control airborne radioactivity. Engineering controls which preclude the need for respiratory protection equipment [e.g., contamination con trol devices, local HEPA (high-efficiency particulate air) ventilation, flexible ducting, and tents] as recommended in Regulatory Guide 8.8, Section C.2.d will be utilized and specific applications will be identified before the start of the outage. A program for ALARA internal and external contamination as a part of existing procedures will be provided consistent with Section C.2.d of Regula tory Guide 8.8 in order to reduce potential doses to workers who receive detect able internal contamination, as well as to minimize the number of workers who become externally contaminated. Decontamination facilities adequate for the replacement task will be provided.

The licensee will also provide extensive training for workers that will empha size ALARA measures. The licensee has committed that adequate training facili ties and training personnel will be available to conduct the committed training before initiation of the related tasks for all persons working in radiation control areas. The training program to be conducted by the licensee includes measures to familiarize workers with their tasks, tools, equipment, and opera tional and radiological procedures by use of job-specific training, dry-run training, and mockup training.

Methods for handling and processing radioactive wastes, and the impacts of these wastes, have been evaluated. Radwaste reduction techniques and training have been planned for the outage.

The licensee has committed to measure and evaluate the progress of the steam generator replacement task through dose tracking and ongoing radiological assessment of specific tasks by radiological engineers/ALARA coordinators as is recommended in Regulatory Guide 8.8, Sections C.1 and C.3.

In order for the NRC staff to evaluate the radiological results of the replace ment project, and to determine if additional or different radiological controls need to be considered, the licensee will perform a radiological assessment as follows.

(1) The collective occupational dose estimates will be updated each 90-day period. If the updated estimate exceeds the person-rem estimate by more than 10%, the licensee will provide a revised estimate, including the reasons for such changes, to the NRC with the 90-Day Progress Reports.

H. B. Robinson 2 SER 5-3

(2) A final report shall be provided to the NRC within 60 days after completion of the repair. This report will include (a) a summary of the occupational dose received by major task, (b) a comparison of estimated doses with the doses actually received, (c) a discussion of ALARA measures employed, and (d) a summary of decontamination efforts and radwaste generation.

(3) Interim reports which summarize each 90-day period of the repair effort shall be provided to the NRC within 60 days of the completion of each such period.

5.4 Summary The overall programs and commitments for ALARA/radiation protection for the HBR-2 Steam Generator Replacement Program are acceptable and consistent with Regulatory Guide 8.8. Implementation of these commitments and programs will be further evaluated by the NRC staff to verify that they are complete and in place before initiation of the task and that they are effectively implemented throughout the course of the program.

H. B. Robinson -2 SER 5-4

6 TRANSIENT AND ACCIDENT ANALYSIS 6.1 Introduction This section contains the -staff's evaluation of the HBR-2 safety analyses presented in CP&L's January 6, 1983 report for operation of this unit with replacement steam generator lower assemblies including the lower shell, transi tion cone, the tube bundle, wrapper, and other internals. Minor differences between the original and replacement assemblies, which could have a small effect on the safety analyses, include a 2% decrease in total heat transfer area, and a 4% decrease in the steam generator primary pressure drop. HBR-2 is now oper ating at reduced temperature, flow, and power because of extensive tube plugging (up to 20%). Replacement of steam generator lower assemblies will enable opera tion of HBR-2 at rated conditions.

This section of the present report includes the.staff's evaluation of the loss of-coolant accident (LOCA) and locked rotor accident analyses. The following accidents and transients are not adversely or significantly affected by the proposed replacement and are, therefore, not further discussed:

loss of reactor coolant flow, excessive load transient, chemical and volume control system mal function, startup of an inactive reactor coolant loop, reduction in feedwater enthalpy, loss of external electrical load, loss of normal feedwater, loss of ac power, steam generator tube rupture.

With regard to the steam line break (SLB) analysis, the staff noted (NRC, July 23, 1982) that the Exxon Nuclear Corporation (ENC) SLB model appeared deficient in not considering asymmetric core temperatures, nor the mass input and primary system cooldown due to accumulator actuation or safety injection system input. The staff required that the licensee provide additional informa tion that justifies the adequacy and conservatism of the ENC model utilized in the SLB analysis before the next refueling. The licensee provided this informa tion by letter dated October 5, 1983.

6.2 LOCA Analysis In its January 6, 1983 report the licensee indicates that the consequences of a limiting break LOCA with the replacement steam generator would be bounded by the results of the LOCA analysis in the Exxon Nuclear Corporation (ENC) report of September 8, 1980, performed for different levels of steam generator tube plugging (SGTP). However, there appeared to be a discrepancy between the values for peak clad temperature (PCT) for the limiting break LOCA at rated conditions between the ENC analysis of September 8, 1980 and a subsequent analysis sub mitted for Cycle 9 reload (ENC, March 1982). At the meeting of May 6, 1983 on the subject of HBR-2 steam generator replacement, the licensee confirmed that the results of the ENC report of September 8, 1980 were out of date, since this analysis as well as previous ENC analyses assumed an erroneous location for the low-pressure safety injection connection to the main loop. This was corrected in the ENC report of August 6, 1981, which incorporates the results of revised H. B. Robinson 2 SER 6-1

refill and reflood calculations. The results in the August 6, 1981 report are consistent with ENC's March 1982 report with regard to PCT for rated conditions.

The analyses in the August 6, 1981 report were performed for 10% and 15% SGTP, and for peaking factors (F ) of 2.2 and 2.32. Both these analyses and the ones in the September 8, 1980 ENC report indicate that the effect of tube plugging on PCT is relatively minor, and that of varying FQ is very significant. The highest calculated PCT is 21850 F for an F of 2.32 and 15% SGTP. For these conditions the total zirconium/water reaction is less than 1% and the maximum local zirconium/water reaction is less than 9%. The HBR-2 Technical Specifica tion limit for F is 2.2 including uncertainties. The analyses were performed Q

using the ENC WREM-IIA model. A discharge coefficient (CD) of 0.8 was assumed, as previous analyses had shown this to be limiting (ENC, December 1976). The analyses assume loss of offsite power and failure of one diesel generator, resulting in the unavailability of one emergency core cooling system (ECCS) pump train. As concluded in the SER for Cycle 9 operation (NRC, July 23, 1982),

inclusion of the NUREG-0630 cladding swelling and rupture correlations into the HBR-2 analysis would not result in predictions that exceed ECCS acceptance criteria.

6.2.1 Summary On the basis of the information discussed and the above evaluation, the staff concludes that the LOCA ECCS analysis in ENC's August 6, 1981 report, performed for rated conditions with 10% and 15% SGTP, meets the acceptance criteria for 10 CFR Part 50.46, and will apply to the replacement steam generator as well.

The LOCA analysis is therefore acceptable.

6.3 Locked Rotor The most applicable analysis for this accident is found in ENC's report of June 22, 1979. Exxon's pressurized thermal shock PWR2 transient simulation model was utilized. The analysis assumed seizure of one reactor coolant pump (RCP) from 102% of full power (2346 MWt) three-loop operation, at a nominal system pressure of 2220 psia and reactor inlet temperature of 550.50 F. A beginning-of-life moderator temperature coefficient of +2.0 percent millirho per 'F was conservatively utilized. Reactor trip on low primary flow occurred at 1.25 seconds. The pressure peaked at 2269 psia and minimum DNBR (departure from nucleate boiling ratio) was 1.58 (1.40 with rod bow).

By comparison, the HBR-2 Final Safety Analysis Report (FSAR) on locked rotor analysis, prepared by Westinghouse, provided more conservative results. The peak pressure was 2440 psia for three-loop operation and 2540 psia for two-loop operation.' Slightly less than 10% of the fuel rods reached a DNBR lower than 1.3. PCT reached 18100 F and a small amount of zirconium/water reaction occurred.

Neither analysis assumed loss of offsite power (LOOP), and both assumed that all but the seized RCP keep operating. The staff asked the licensee to justify using the ENC analysis as the base case for evaluation of this accident, and to clarify the differences between the two analyses. The staff further requested that the licensee justify the assumption that the nonaffected RCPs keep oper ating, and that the analysis complied with GDC-17. The results of sensitivity analyses regarding the effects of LOOP were to be provided.

H. B. Robinson 2 SER 6-2

With regard to the comparison between the Exxon and Westinghouse analyses, the licensee's response stated that Westinghouse used a heat flux hot channel factor (F Q) of 3.23 and an enthalpy hot channel factor (FAH) of 1.77, resulting in an initial DNBR value of 1.63 and a minimum DNBR value of 0.82 occurring 2 seconds after transient initiation. The corresponding Exxon values in ENC's most recent analysis for rated conditions (June 22, 1979) are 2.62 and 1.58 for F and FAH, respectively.

The analysis of June 22, 1979 resulted in an initial DNBR value of 2.3 and a minimum DNBR value of 1.58. The difference between the Westinghouse and Exxon calculated minimum DNBR values is attributed to the different peaking values assumed in the two analyses. The peaking values used in the Exxon analysis, while lower, are still bounded by the HBR-2 Technical Specification limits of 2.2 for F and 1.55 for FAH. If LOOP were to occur with resulting coastdown of the two intact RCPs, the minimum DNBR value would be about 1.3.

The licensee indicates that the June 22, 1979 calculations predict low system pressure in order to obtain conservative minimum DNBR predictions. Since the more conservative FSAR analysis predicts peak pressure values substantially below the design limit (2750 psia), the system would not be overpressurized as a result of this accident.

6.3.1 Summary On the basis of the information discussed above and the additional information provided by the licensee, the staff concludes that the locked rotor analysis indicates acceptable DNBR and peak pressure values and is, therefore, acceptable.

H. B. Robinson 2 SER 6-3

7.0 RADIOLOGICAL CONSEQUENCES OF POSTULATED ACCIDENTS 7.1 Accidents During Operation With Repaired Steam Generators The repaired steam generators will not significantly affect the dose consequen ces of accidents involviog the secondary system. The accidents involving signif icant dose consequences Are the main steam line failure, steam generator tube failure, and control rod ejection. The only design change that affects the accident dose consequences is a 0.3% increase in the volume of the secondary side of the steam generator. The reactor coolant system parameters which affect these accidents will not be changed significantly by the repaired steam generators. These parameters include reactor coolant leakage to the secondary system and the reactor cooldown period. The major dose contribution is from reactor coolant leakage into the secondary system during the accidents.

Specifically, in both the steam generator tube failure and control rod ejection accidents, the increased volume of the secondary system provides for more dilu tion of the activity which leaksifrom the reactor coolant side.

Because the reactor coolant system parameters have not changed substantially, the total reactor coolant side release time and volume will not change. Therefore, the increased secondary volume should result in a negligible change in doses.

Similarly, the reactor coolant system parameters which affect the main steam line failure accident also remain essentially unchanged. Assuming the same concentration of radionuclides (pre-existing inleakage of reactor coolant),

the increased mass of the secondary side will result in a slight increase in offsite doses. The contribution to the doses from additional reactor coolant inleakage during the accident itself would be unchanged. Because the secondary volume increases by 0.3% and most of the dose is a result of "fresh" reactor coolant inleakage, the total offsite dose will increase by much less than 0.3%.

This slight increase in total offsite dose will not result in substantive changes in any estimated consequences of these accidents or exceeding of 10 CFR Part 100 guidelines since the effect of the small secondary volume increase on the evaluation of relevant accident consequences remains very small.

7.2 Accidents During the Repair Effort 7.2.1 Rigging Accidents -

Impact on Safety-Related Systems/Structures/

Components The licensee has stated that administrative procedures and precautions will be established to minimize the likelihood of rigging and equipment-handling 'acci-.

dents which could result in damage to any system, structure, or component important to safe operation and maintenance of HBR-2. These precautions include training of equipment-operating personnel, additional protection of buried piping and duct banks where necessary along the steam generator trans fer paths, controls on transfer paths and equipment speed, and controls on lift heights, travel directions, location, and swing arcs for both loaded and unloaded cranes.

H. B. Robinson 2 SER 7-1

The licensee has performed analyses to determine the ability of the (1) contain ment building and associated equipment hatch area and (2) spent fuel storage building to withstand a strike by a falling crane boom. These analyses indi cated some potential damage to the containment shell and temporary construction facilities near the spent fuel storage building in the event a 100-foot-long, 25,000-pound crane boom should fall.

Administrative controls will be imple mented to minimize the likelihood of occurrence of these types of damage.

Analyses indicate that, should a special railcar loaded with a lower steam gen erator assembly overturn, no safety-related equipment or structures required to maintain safe shutdown or cool the spent fuel would be affected. Analyses per formed to determine the effects of a runaway railcar containing a steam genera tor lower assembly indicate that the containment equipment hatch could sustain unacceptable damage because of impact from the postulated runaway car. The licensee will, therefore, establish administrative controls to greatly reduce the likelihood of this occurring. These will be (1) installation of a derail device on the temporary rail spur, (2) provision of positive restraint during transport of the railcars (loaded or unloaded), and (3) brakes applied and chocks installed between the rails and wheels of stationary railcars.

Load handling and rigging operations involving the steam generator lower assem blies will be conducted in areas sufficiently removed from the refueling and primary water storage tanks that there is negligible potential for.damage to this equipment or an interruption of makeup water to the spent fuel storage pool from a load drop or rigging accident during the replacement program. Addi tionally, the fuel will be in offloaded configuration during the period of steam generator repair. The licensee has, therefore, concluded that no evalua tion need be performed for damage to these structures/components. The staff concurs with this conclusion and, further, concludes that there will be no radioactive release to the environment should these hypothetical accidents occur.

7.2.2 Steam Generator Lower Assembly Drop The steam generator lower assembly, after having been secured, can undergo a hypothetical accidental drop to the ground during removal through the equipment hatch, or during transport to the storage building. If such a drop should occur outside containment, the welded plate over the primary side might be breached. To assess the radiological consequences of such an accident, the staff has made a number of conservative assumptions. If it is assumed that 10% of the solid radioactive corrosion products contained within the steam generator are released following impact (31 curies), and that of this amount 1% will consist of particulates of diameter less than 1 micron, the resulting maximum radiological consequence at the exclusion area boundary would be 67 mrem (assuming a diffusion and transport atmospheric relative concentration of 1.7 x 10-3 sec/m 3 ). This is a very small fraction of the guideline lung dose limit inferred from ICRP-26 (International Commission on Radiation Pro tection, January 1977) and the 10 CFR Part 20 guideline of 5 rems. A similar drop occurring inside containment would result in a substantially lower dose because of the very circuitous path to the environment.

H. B. Robinson 2 SER 7-2

7.2.3 Cutting of the Reactor Coolant Piping For this cutting, performed with a welding torch, the staff has conservatively postulated total vaporization of the radioactive corrosion products in the kerf area, some 3.5 x 104 microcuries. Even if it is assumed that all of this radio activity can be inhaled (without benefit of filtration and aerosol formation and deposition) the lung dose would be less than 0.3 mrem, an even smaller frac tion of the 10 CFR Part 20 inferred lung dose guidelines.

7.2.4 Accidents Initiated by External Events No combustibles will be stored in the steam generator storage building. Thus, fire in this building with any subsequent releases of contained radioactive corrosion products is not credible.

The steam generator storage building is located at an elevation 6 feet above the top level of the dam at Lake Robinson. The dam would be expected to yield before a flooding condition in the storage building area could begin to mani fest itself.

The steam generator storage building will be constructed of reinforced concrete with adequate wall thickness to reduce the exposure rate at the building sur face to 1 mrem per hour. It is not qualified as seismic Category I, or designed to resist tornados or tornado missiles. Even if the building were to collapse onto the stored steam generator's lower assembly, it is not expected that radio active particulate crud released to the environment would exceed that for the lower assembly drop accident. The same argument would apply for tornado strike effects and tornado missile impact. Additionally, no stored lower assembly section is likely to become airborne in a tornado because of the massive weight of the assembly. Finally, the staff has assessed external accident initiators related to steam generator repairs and storage at a number of plants (Turkey Point, Surry, Point Beach, and H. B. Robinson) and has found very low likelihood of both accident and radiological consequences from such initiators.

7.3 Summary The staff finds, therefore, that accidents initiated by the events discussed above would not result in offsite radiological consequences exceeding those of a steam generator lower assembly drop outside containment, which is well within guidelines inferred from 10 CFR Part 20 and therefore acceptable.

H. B. Robinson 2 SER 7-3

8.0 PHYSICAL SECURITY ASPECTS Carolina Power and Light Company has an approved HBR-2 Nuclear Plant Physical Security Plan in accordance with the provisions of 10 CFR 50.54(p). The details of the plan are Safeguards Information and are, therefore, being withheld from public disclosure.

H. B. Robinson 2 SER 8-1

9.0 SPECIAL LICENSING CONDITIONS The following temporary license conditions will be imposed before and during the repair program.

(1) All fuel shall be removed from the reactor pressure vessel and stored in the spent fuel pool before the steam generator repair task is initiated.

(2) Before the steam generator repair task is initiated, the following planning and preparation (i.e., specific applications identified and details final ized) shall be completed in accordance with Regulatory Guide 8.8.

(a) general area decontamination, (b) primary surface decontamination, (c) use of temporary shielding, (d) use of specialized tools, (e) removal of selected valves and piping, (f) establishment of low-background wait areas, (g) establishment of laydown areas, (h) training and training facilities for plant and contractor personnel, (i) access control, (j) equipment decontamination and decontamination facilities, (k) engineering controls which limit the need for respiratory protection consistent with ALARA (1) dose tracking.

(3) Interim reports which summarize each 90-day period of the repair effort are to be provided to the NRC within 60 days of the completion of each such report period.

(4) The collective occupational dose estimates will be updated each 90-day period. If the updated estimates exceed the person-rem estimate by more than 10%, the licensee will provide a revised estimate, including the reasons for such changes, to the NRC with the 90-Day Progress Reports.

(5) A final report shall be provided to the NRC within 60 days after repair completion. This report shall include the following:

(a) a summary by major task of the occupational dose received, (b) a comparison of estimated doses with the doses actually received, (c) a discussion of ALARA measures employed, and (d) a summary of decontamination efforts and radwaste generation.

H. B. Robinson 2 SER 9-1

10.0 CONCLUSION

S The staff has concluded, on the basis of considerations discussed above, that:

(1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (2) such activities will be conducted in compliance with the Commission's regulations and the issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public.

H. B. Robinson 2 SER 10-1

11.0 REFERENCES

Atomic Safety and Licensing Board, April 12, 1983, Memorandum and Order, "Report on Special Prehearing Conference Held Pursuant to 10 CFR 2.751a,"

ASLBP No. 83-484-03LA.

American National Standards Institute, B30.2.0-1976.

American Society of Mechanical Engineers, "Boiler and Pressure Vessel Code,"

1965 Edition,Section III (including all addenda through Summer 1966).

, 1980 Edition,Section III (including all addenda through Winter 1980).

, 1980 Edition,Section XI, Subsection IWB-5222 (including all addenda through Winter 1980).

, 1980 Edition,Section XI, Subsection IWA-5246 (including all addenda through Winter 1980).

Carolina Power and Light Company, March 18, 1981, Letter from E. E. Utley to

0. G. Eisenhut, NRC,

Subject:

Quality Assurance Program.

, August 4, 1981, Letter from E. E. Utley to D. G. Eisenhut, NRC,

Subject:

Qualification of Inspection Examination and Testing and Audit Personnel.

, July 1, 1982, Letter from E. E. Utley to S. A. Varga, NRC, proposing to repair the three steam generators at HBR-2.

, September 16, 1982, Letter from E. E. Utley to S. A. Varga, NRC, submitting "Preliminary Steam Generator Repair Report."

, January 6, 1983, "H. B. Robinson Unit No. 2, Final Steam Generator Repair Report" (Revision 1, March 31, 1983; Supplement to Revision 1, May 5, 1983).

June 3, 1983, Letter from S. R. Zimmerman to S. A. Varga, NRC,

Subject:

Request for Additional Information, "Final" Steam Generator Repair Report.

, July 11, 1983, Letter from S. R. Zimmerman to S. A. Varga, NRC,

Subject:

Request for Additional Information, "Final" Steam Generator Repair Project.

, July 14, 1983, Letter from S. R. Zimmerman to S. A. Varga, NRC,

Subject:

Response to Request for Additional Information for Environmental Impact Statement.

July 15, 1983, Letter from S. R. Zimmerman to S. A. Varga, NRC,

Subject:

Request for Additional Information, "Final" Steam Generator Repair Report, Revision 1.

H. B. Robinson 2 SER 11-1

July 25, 1983, Letter from S. R. Zimmerman to S. A. Varga, NRC,

Subject:

Supplemental Information to Request for Additional Information for Environmental Impact Statement.

October 5, 1983, Letter from E. E. Utley to S. A. Varga, NRC,

Subject:

Cycle 10 Operation and Pressurized Thermal Shock Information.

Concerned Fools of Darlington County, December 26, 1982, Petition to Intervene and Request for Hearings.

Electric Power Research Institute, Special Report NP-2704-SR, "PWR Secondary Water Chemistry Guidelines," October 1982.

Exxon Nuclear Corporation, December 1976, "LOCA Analyses for HBR-2 Using WREM Based PWR ECCS Evaluation Model with Reduced LPSI Flow, Steam Generator Plugging and Increased Upper Heat Temperature," ENC Report XN-76-54.

June 22, 1979, "Review of Plant Transient Analysis for Positive Moderator Temperature Reactivity Feedback for HBR-2," ENC Report XN-NF-79-42.

September 8, 1980, "ECCS and PTS Analyses for HBR-2 Reactor with 6%, 10%

and 15% Steam Generator Tube Plugging," ENC Report XN-NF-80-43.

August 6, 1981, "LOCA ECCS Analysis for HBR-2 Reactor for Revised Safety Injection Location," ENC Report XN-NF-81-54.

, March 1982, "ECCS and Plant Transient Analyses for HBR-2 Reactor Operating at Reduced Primary Temperature," ENC Report XN-NF-82-18.

Hartsville Group, December 27, 1982, Petition to Intervene and Request for Hearing.

International Commission on Radiation Protection, January 1977, "Recommenda tion of the ICRP," ICRP Publication 26.

U.S. Nuclear Regulatory Commission, July 23, 1982, Letter from S. A. Varga to J. A. Jones, CP&L, transmitting Amendment 71 and SER for cycle 9 operation.

, November 18, 1982, Letter from S. A. Varga to E. E. Utley, CP&L, informing applicant that NRC prior review and approval of repairs was necessary.

, November 24, 1982, Notice of the Proposed Issuance of Amendments, Federal Register, 47 FR 53157.

, NUREG-0630, "Cladding, Swelling and Rupture Models for LOCA Analysis,"

April 1980.

, NUREG-0886, "Steam Generator Tube Experience," February 1982.

NUREG-1003, "Draft Environmental Statement Related to Steam Generator Repair at H. B. Robinson Steam Electric Plant Unit No. 2," September 1983.

H. B. Robinson 2 SER 11-2

Regulatory Guide 8.8, Revision 3, "Information Relevant to Ensuring That Occupational Radiation Exposures at Nuclear Power Stations Will Be As Low As Is Reasonably Achievable," June 1978.

Westinghouse Electric Corporation, WCAP-8370, "Westinghouse Water Reactor Division Quality Assurance Plan," Revision 9A, October 31, 1979.

H. B. Robinson 2 SER 11-3

NRC FORM 335

1. REPORT NUMBER (Assignedby DDCj (7-77)

U.S. NUCLEAR REGULATORY COMMISSION BIBLIOGRAPHIC DATA SHEET NUREG-1004

4. TITLE AND SUBTITLE (Add Volume No., if 4propriate)

2. (Leave blak)

Safety Evaluation Report Related to Steam Generator Repair at H. B. Robinson Steam Electric

3. RECIPIENT'SACCESSIONNO.

Plant Unit No. 2 Docket No. 50-261

7. AUTHOR(S)

5. DATE REPORT COMPLETED MONTH YEAR November 1983

9. PEfRFORMiNG ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code)

DATE REPORT ISSUED Division of Licensing MONTH YEAR Office of Nuclear Reactor Regulation November 1989 U. S. Nuclear Regulatory Commission

6. (Leave blank)

Washington, D.C. 20555

8. (Leave blank)

12. SPONSORING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code)

Same as 9.

f11.

CONTRACT NO.

13. TYPE OF REPORT PERIOD COVERED (Inclusive daIes)

15. SUPPLEMENTARY NOTES

14. (Leave blank)

Doc8.

(Leav blank)

16. ABSTRACT (200 words or less)

A Safety Evaluation Report was prepared for the H. B. Robinson Steam Electric Plant Unit No. 2 by the Office of Nuclear Reactor Regulation.

This report con siders the safety aspects of the proposed steam generator repair at H. B.

Robinson Steam Electric Plant Unit No. 2. The report focuses on the occupa tional radiation exposure associated with the proposed repair program. It con cludes that there is reasonable assurance that the health and safety of the pub lic will not be endangered by the conduct of the proposed action, such activi ties will be conducted in compliance with the Commission's regulations, and the issuance oT this amendment will not be inimical to the common defense and security or the health and safety of the public.

17. KEY WORDS AND DOCUMENT ANALYSIS 17a. DESCRIPTORS 17b. IDENTIFIERSIOPEN-ENDED TERMS

18. AVAILABILITY STATEMENT

19. SECURITY CLASS (This report)

21. NO. OF PAGES Unlimited Unclassified

20. SECURITY CLASS (This page)

22. PRICE Uncdhssified s

NRC FORM 335 (777)

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