ML020310200
| ML020310200 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, Catawba, McGuire  |
| Issue date: | 01/28/2002 |
| From: | Rani Franovich Division of Regulatory Improvement Programs |
| To: | Tuckman M Duke Energy Corp |
| References | |
| Download: ML020310200 (14) | |
Text
January 28, 2002 Mr. M. S. Tuckman Executive Vice-President Nuclear Generation Duke Energy Corporation PO Box 1006 Charlotte, NC 28201-1006
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE MCGUIRE NUCLEAR STATION, UNITS 1 AND 2, AND CATAWBA NUCLEAR STATION, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (LRA)
Dear Mr. Tuckman:
By letter dated June 13, 2001, Duke Energy Corporation (Duke) submitted for Nuclear Regulatory Commission (NRC) review an application, pursuant to 10 CFR Part 54, to renew the operating licenses for the McGuire Nuclear Station, Units 1 and 2, and Catawba Nuclear Station, Units 1 and 2. The NRC staff is reviewing the information contained in this license renewal application and has identified, in the enclosure, areas where additional information is needed to complete its review. Specifically, the enclosed request for additional information (RAI) is from the following section(s) of the LRA:
Appendix B, Aging Management Programs (Mechanical Systems)
Please provide a schedule by letter, or electronic mail for the submittal of your response within 30 days of the receipt of this letter. Additionally, the staff would be willing to meet with Duke prior to the submittal of the response to provide clarification of the staffs request for additional information.
Sincerely,
/RA/
Rani L. Franovich, Project Manager License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket Nos. 50-369, 50-370, 50-413 and 50-414
Enclosures:
As stated cc w/encl: See next page Mr. M. S. Tuckman Executive Vice-President Nuclear Generation Duke Energy Corporation
PO Box 1006 Charlotte, NC 28201-1006
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE MCGUIRE NUCLEAR STATION, UNITS 1 AND 2, AND CATAWBA NUCLEAR STATION, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION
Dear Mr. Tuckman:
By letter dated June 13, 2001, Duke Energy Corporation (Duke) submitted for Nuclear Regulatory Commission (NRC) review an application, pursuant to 10 CFR Part 54, to renew the operating licenses for the McGuire Nuclear Station, Units 1 and 2, and Catawba Nuclear Station, Units 1 and 2. The NRC staff is reviewing the information contained in this license renewal application and has identified, in the enclosure, areas where additional information is needed to complete its review. Specifically, the enclosed request for additional information (RAI) is from the following section(s) of the LRA:
Appendix B, Aging Management Programs (Mechanical Systems)
Please provide a schedule by letter, or electronic mail for the submittal of your response within 30 days of the receipt of this letter. Additionally, the staff would be willing to meet with Duke prior to the submittal of the response to provide clarification of the staffs request for additional information.
Sincerely,
/RA/
Rani L. Franovich, Project Manager License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket Nos. 50-369, 50-370, 50-413 and 50-414
Enclosures:
As stated cc w/encl: See next page DISTRIBUTION:
See next page Document Name: C:\\Program Files\\Adobe\\Acrobat 4.0\\PDF Output\\Duke RAI - Mechanical -
AMP.wpd OFFICE PM:RLEP:DRIP LA:DRIP SC:RLEP:DRIP BC:RLEP:DRIP NAME RFranovich EGHylton PTKuo CIGrimes DATE 01/24/2002 01/23/2002 01/28/2002 01/28/2002 OFFICIAL RECORD COPY
McGuire & Catawba Nuclear Stations, Units 1 and 2 Mr. Gary Gilbert Regulatory Compliance Manager Duke Energy Corporation 4800 Concord Road York, South Carolina 29745 Ms. Lisa F. Vaughn Duke Energy Corporation 422 South Church Street Charlotte, North Carolina 28201-1006 Anne Cottington, Esquire Winston and Strawn 1400 L Street, NW Washington, DC 20005 North Carolina Municipal Power Agency Number 1 1427 Meadowwood Boulevard P. O. Box 29513 Raleigh, North Carolina 27626 County Manager of York County York County Courthouse York, South Carolina 29745 Piedmont Municipal Power Agency 121 Village Drive Greer, South Carolina 29651 Ms. Karen E. Long Assistant Attorney General North Carolina Department of Justice P. O. Box 629 Raleigh, North Carolina 27602 Ms. Elaine Wathen, Lead REP Planner Division of Emergency Management 116 West Jones Street Raleigh, North Carolina 27603-1335 Mr. Robert L. Gill, Jr.
Duke Energy Corporation Mail Stop EC-12R P. O. Box 1006 Charlotte, North Carolina 28201-1006 Mr. Alan Nelson Nuclear Energy Institute 1776 I Street, N.W., Suite 400 Washington, DC 20006-3708 North Carolina Electric Membership Corporation P. O. Box 27306 Raleigh, North Carolina 27611 Senior Resident Inspector U.S. Nuclear Regulatory Commission 4830 Concord Road York, South Carolina 29745 Mr. Virgil R. Autry, Director Dept of Health and Envir Control 2600 Bull Street Columbia, South Carolina 29201-1708 Mr. C. Jeffrey Thomas Manager - Nuclear Regulatory Licensing Duke Energy Corporation 526 South Church Street Charlotte, North Carolina 28201-1006 Mr. L. A. Keller Duke Energy Corporation 526 South Church Street Charlotte, North Carolina 28201-1006 Saluda River Electric P. O. Box 929 Laurens, South Carolina 29360 Mr. Peter R. Harden, IV VP-Customer Relations and Sales Westinghouse Electric Company 6000 Fairview Road - 12th Floor Charlotte, North Carolina 28210 Mr. T. Richard Puryear Owners Group (NCEMC)
Duke Energy Corporation 4800 Concord Road York, South Carolina 29745 Mr. Richard M. Fry, Director North Carolina Dept of Env, Health, and Natural Resources 3825 Barrett Drive Raleigh, North Carolina 27609-7721 County Manager of Mecklenburg County 720 East Fourth Street Charlotte, North Carolina 28202 Michael T. Cash Regulatory Compliance Manager Duke Energy Corporation
McGuire Nuclear Site 12700 Hagers Ferry Road Huntersville, North Carolina 28078 Senior Resident Inspector U.S. Nuclear Regulatory Commission 12700 Hagers Ferry Road Huntersville, North Carolina 28078 Dr. John M. Barry Mecklenburg County Department of Environmental Protection 700 N. Tryon Street Charlotte, North Carolina 28202 Mr. Gregory D. Robison Duke Energy Corporation Mail Stop EC-12R 526 S. Church Street Charlotte, NC 28201-1006 Mary Olson Nuclear Information & Resource Service Southeast Office P.O. Box 7586 Asheville, North Carolina 28802 Paul Gunter Nuclear Information & Resource Service 1424 16th Street NW, Suite 404 Washington, DC 20036 Lou Zeller Blue Ridge Environmental Defense League P.O. Box 88 Glendale Springs, North Carolina 28629 Don Moniak Blue Ridge Environmental Defense League Aiken Office P.O. Box 3487 Aiken, South Carolina 29802-3487
Request for Additional Information McGuire Nuclear Station, Units 1 and 2, and Catawba Nuclear Station, Units 1 and 2 B.3.4 Borated Water Systems Stainless Steel Inspection B.3.4-1The LRA proposes that one of twelve possible inspection locations at each plant will be inspected volumetrically as part of the Borated Water Systems Stainless Steel Inspection program (monitoring & trending). Stainless steel (SS) has demonstrated susceptibility to intergranular stress corrosion cracking (IGSCC) in low-temperature borated water systems in pressurized water reactors, particularly in stagnant lines, at weld heat-affected zones (HAZs), involving weld procedures that resulted in sensitization of the stainless steel in the HAZs. Since IGSCC has a wide range of induction and propagation rates, depending on degree of sensitization, local stresses, and specific impurities at a given location, justify why only a one-time inspection is sufficient. Also, since not all welds, stress patterns, and impurity levels and species are necessarily similar, justify why inspection of only one of twelve locations adequately represents the durability of material at the other eleven locations and explain the process for inspection population expansion should aging effects be identified.
B.3.4-2The LRA proposes that a one-time inspection be performed and that no actions are to be taken to trend inspection results (monitoring & trending). The LRA also states that if an engineering evaluation determines that the aging effects, identified during the one-time inspection, will not result in a loss of the components intended function(s) during the period of extended operation, then no further action will be required. Industry experience has shown that, under this environment, SCC damage tends to result in leaks that are somewhat localized. In this light, explain the basis for not performing future inspections at those locations in which aging effects have been identified in order to ensure that degradation predictions made in the engineering evaluations remain valid (detection of aging effects and monitoring & trending).
The staff and applicant participated in a conference call on October 25, 2001. A summary of this conference call was issued December 12, 2001. During this conference call, the applicant indicated that engineering judgment would be applied to determine if corrective actions are warranted based upon the results of the one-time inspection. Provisions for programmatic oversight would be established at the time the results of the inspection are obtained, and the inspection results, as well as corrective actions taken by the applicant (licensee), would be subject to NRC inspection at the appropriate time in the future. The staff requests information necessary to determine the appropriateness of not performing future inspections at those locations in which aging effects have been identified in order to ensure that degradation predictions made in the engineering evaluations remain valid (detection of aging effects and monitoring &
trending). In particular, the staff requests that the applicant describe the criteria for (1) assessing the severity of the observed degradation, and (2) determining whether or not corrective action is necessary.
B.3.4-3The LRA states that the parameters inspected by the borated water systems stainless steel inspection program are pipe wall thickness, as a measure of loss of material, and evidence of cracking (parameters monitored or inspected). Will the inspections be also looking for evidence of pitting? If so, discuss the inspection technique(s) that will be used to reliably identify the presence of pits (monitoring & trending).
B.3.6 Chemistry Control Program B.3.6-1In the LRAs description of the Chemistry Control Program, two aging effects were specified: loss of material and cracking. However, in addition to these two effects, the water chemistry environment could cause fouling of the heat transfer surfaces in heat exchangers. Tables 3.1-1 through 3.4-1 of the LRA show that this could occur in the following heat exchangers:
Auxiliary Building Ventilation System: shutdown panel area air conditioning unit condenser tubes Component Cooling (KC) System: heat exchanger KC, heat exchanger containment spray (NS) pump motor cooler, heat exchanger chemistry and volume control system (NV) centrifugal charging pump bearing oil cooler, and heat exchanger safety injection (NI) pump bearing oil cooler.
Control Area Chilled Water System: control room area chiller (evaporator tubes)
Control Area Ventilation System: air handling units heat exchangers Diesel Generator (D/G) Cooling Water: D/G engine cooling water heat exchanger, D/G engine cooling water turbocharger intercoolers, and D/G engine jacket water coolers Spent Fuel Cooling System: heat exchangers Waste Gas System: hydrogen recombiner heat exchangers Explain why fouling of the heat transfer surfaces in the above listed heat exchangers are not classified as an aging effect managed by the chemistry control program.
B.3.6-2In the LRA, the applicant stated that the chemistry control program is controlled by the site program manuals, which are based on the guidance contained in several sources including the Electrical Power Research Institute (EPRI) chemistry guidelines. Specify to what extent the procedures in the site program manuals deviate from the EPRI guidelines for secondary water chemistry.
B.3.6-3Specify the acceptance criteria for fuel oil and specify the standards used in developing these acceptance criteria.
B.3.6-4Specify any deviations in the parameters monitored for each of the four chemistries specified in the LRA from the parameters specified in the corresponding standards of EPRI chemistry guidelines.
B.3.12.2 Mechanical Fire Protection Component Tests and Inspections B.3.12.2-1 The application states in Section B.3.12.2, Mechanical Fire Protection Component Tests and Inspections-Monitoring and Trending, of the LRA that a sample of sprinklers are either inspected or replaced after 50 years of operation.
Describe the basis for the sampling process. Also, provide the rationale for either inspection or replacement of only some of the sprinklers after 50 years of operation.
B.3.12.2-2 With regard to the monitoring and trending activities, fouling of hose station valves and sprinklers are managed by flow tests and flushes which are governed by Selected Licensee Commitment (SLC) 16.9.1(a)(iii) at Catawba and Testing Requirement (TR) 16.9.1.3 at McGuire. What are the differences between these two requirements?
B.3.12.2-3 With regard to the monitoring and trending activities, the integrity of the sprinkler branch lines is assured by sprinkler system flow tests which are governed by Selected Licensee Commitment TR 16.9-2(a)(iv)(1) at Catawba. This test is not governed by Selected Licensee Commitment at McGuire, but is performed to satisfy a specific plant procedure. Specify the governing requirements for this test at McGuire and how these requirements differ from those at Catawba, and why.
B.3.12.2-4 With regard to the monitoring and trending activities, explain the basis for the sample disassembly inspection program for managing the fouling of sprinkler branch lines. Specifically, explain how the sample of branch lines is selected (basis for selection) and how the number of branch lines to be sampled is determined (basis for sample size).
B.3.12.2-5 The staff proposes to revise the Fire Protection system aging management program inspection criteria in NUREG-1801 for wall thinning of piping due to corrosion. Each time the system is opened, oxygen is introduced into the system, and this accelerates the potential for general corrosion. Therefore, the staff recommends that a non-intrusive means of measuring wall thickness, such as ultrasonic inspection, be used to detect this aging effect. The staff recommended action in this regard is that, in addition to an ultrasonic inspection of the fire protection piping before exceeding the current licensing term, the applicant perform ultrasonic inspections immediately after the 50-year service life sprinkler head testing, in accordance with NFPA 25, Section 2.3.3.1, and at 10-year intervals thereafter.
Verify whether or not the aging management program inspection criteria for Fire Protection system piping at Catawba/McGuire conforms with the staff position, as outlined above.
B.3.12.2-6 Describe the environmental and material conditions that exist on the interior surface of below-grade FP piping. If these conditions can be demonstrated to be similar to the conditions existing in the above-grade FP piping, then the inspections in the above-grade piping may be extrapolated to evaluate the interior conditions of the below-grade piping. If not, additional inspection activities may be needed to provide the reasonable assurance that the intended function of below-grade FP piping will be maintained consistent with your current licensing basis for the extended operation.
B.3.15 Fluid Leak Management Program B.3.15-1 The staff observed that there is no mention of strategies that address leak management for component segments that are not accessible to visual inspection (monitoring and trending). The staff and applicant discussed this observation during a conference call on October 25, 2001. A summary of the conference call was issued on December 12, 2001. During the conference call, the applicant indicated that the condition of material in accessible areas is considered indicative of material in inaccessible areas. The staff requests the applicant to discuss any provisions for inspecting potentially vulnerable, inaccessible locations for boric acid corrosion that were documented in their response to Generic Letter 88-05.
B.3.16 Galvanic Susceptibility Inspection B.3.16-1 The LRA states that the galvanic susceptibility inspection will involve inspection of a select set of carbon steel-stainless steel couples at each site (monitoring and trending). Since the galvanic susceptibility inspections are one-time inspections of a given sample that are intended to provide objective evidence that the applicable aging effects are being adequately managed, explain how the sample size will be selected in order to ensure that the inspection population is representative for all systems listed in the galvanic susceptibility inspection program scope.
The list of systems includes nuclear service water, which is large, complex, usually with multiple materials, subject to a variety of environments, that may change over time, including flowing and stagnant water, microbiological species, etc. The mechanisms include localized (e.g., pitting) and uniform corrosion.
Given these complexities, justify that limiting the proposed inspections to carbon-stainless steel couples provides sufficient evidence in regards to the potential aging degradation of all galvanic couples in nuclear service water and other systems.
B.3.16-2 The LRA describes the acceptance criterion for the galvanic susceptibility inspections as no unacceptable loss of material that could result in a loss of the component intended function(s) as determined by engineering evaluation.
Describe the criteria that will be used to define unacceptable loss of material and how the acceptance criteria will ensure that the component functions are maintained under all CLB design loading conditions during the period of extended operation. Also, describe the analysis methodology that will be used to evaluate the inspection results against the acceptance criteria.
B.3.16-3 The scope of the galvanic susceptibility inspection program is indicated to include all galvanic couples exposed to gas, unmonitored treated water, and raw water environments in the McGuire and Catawba systems listed (scope).
However, the proposed implementation involves only measurements on carbon steel-stainless steel couples (parameters monitored or inspected), based on an assumption that this couple represents a worst case, based on expectations from the galvanic series (monitoring and trending). The relative position in the series can shift, depending on specific environments, and the position of stainless steel in the series depends on whether the material is active or passive.
Additionally, copper alloys are listed as relevant materials. Could the CS/SS couple measurements provide favorable results that fail to address the galvanic phenomena that may be degrading other materials?
B.3.16-4 The LRA states that the parameter inspected by the galvanic susceptibility inspection program is pipe wall thickness (parameters monitored or inspected) and inspections will be performed using a volumetric examination technique. As an alternative, visual examination will be used should access to internal surfaces become available (monitoring and trending). The staff and applicant discussed this observation during a conference call on October 25, 2001. A summary of the conference call was issued on December 12, 2001. During the conference call the applicant indicated that their intent was not to substitute a volumetric test with a visual inspection. The applicant acknowledged that a visual inspection does not provide the same level of confidence that a volumetric examination provides. The staff is satisfied with this response. However, since the LRA states that a visual inspection could be used as an alternative to volumetric testing, the staff requests the applicant to clarify the statement in the LRA.
B.3.17 Heat Exchanger Activities B.3.17-1 Are the flow rates in the heat exchanger system being measured to ensure that the flow rates are below the threshold of susceptibility for flow-induced corrosion for the materials in the Catawba and McGuire heat exchangers?
B.3.22 Liquid Waste System Inspection B.3.22-1 In section B.3.22 of the LRA, under monitoring & trending, the applicant stated that the selection of the specific areas for inspection for the system material/environment combinations will be the responsibility of the system engineer. Discuss the selection criteria that will be used by the system engineer for the inspection of the specific areas.
B.3.22-2 The acceptance criteria for the liquid waste system inspection program are: (1) no unacceptable loss of material or cracking for stainless steel components, and (2) no loss of material for carbon steel and cast iron components, that could result in a loss of the component intended function(s) as determined by engineering evaluation. Describe the criteria for (1) assessing the severity of the observed degradations and (2) determining whether corrective action is necessary.
B.3.24 Preventive Maintenance Activities B.3.24-1 The LRA describes the scope of the preventive maintenance activities and states that it is applicable to several systems (diesel generator fuel oil, exterior fire protection, interior fire protection, nuclear service water system and standby shutdown system) in addition to the intake and discharge piping of the condenser circulating water system. The various elements of the aging management program (parameters monitored or inspected, monitoring and trending, acceptance criteria and operating experience) address only the condenser piping with no reference to the other systems (e.g. underground portion of the emergency diesel generator and standby shutdown diesel generator fuel oil storage tanks and stainless steel piping and valves) that are within the stated scope of the preventative maintenance activities. Describe how the aging management program is implemented for these other systems, which may consist of smaller diameter piping. Describe operating experience for these systems and the experience to date in application of the preventative maintenance activities to these systems.
B.3.24-2 Raw water carries with it sediments and debris that deposit on the bottom of the pipes. If areas of the pipe are obscured by sediments and debris, the coating inspection activities would be compromised (monitoring and trending). Are areas of the pipes obscured by deposits? If so, are special measures applied to facilitate the coating inspection?
B.3.24-3 The acceptance criteria for the preventive maintenance activities are no visual indications of coating defects including but not limited to blistering, peeling, or missing coatings that reveal corrosion of the piping as determined by Engineering. Describe the criteria for (1) assessing the severity of the observed degradations and (2) determining whether corrective action is necessary.
B.3.28 Selective Leaching Inspection B.3.28-1 The LRA states that a Brinnell hardness test or an equivalent test will be performed on one cast iron pump casing in the exterior fire protection system at each site and that this test will be indicative of selective leaching for all cast iron components in all the systems listed in the selective leaching inspection program scope (monitoring and trending). Provide the basis for concluding that the inspection of a single pump casing in the exterior fire protection system at each site will be indicative of the state of selective leaching in all cast iron components in all raw water systems.
B.3.28-2 The LRA states that Brinnell hardness tests or equivalent tests will be performed on a sample of brass valves at each site in the interior fire protection system and that these valves selected for inspection should be (interpreted to mean will be) those that are continuously exposed to stagnant or low flow raw water environments. The LRA also states that the results of this inspection will be applied to the brass components exposed to raw water environments in the remaining systems listed in the selected leaching program scope (monitoring and trending). Describe the analyses or evaluations that will be used to determine the sample size. Also, provide a basis for concluding that brass valve bodies in the interior fire protection system will be indicative of the state of selective leaching in all brass components in all raw water systems.
B.3.28-3 The LRA describes the acceptance criterion for the selective leaching inspections as no unacceptable loss of material that could result in a loss of the component intended function(s) as determined by engineering evaluation.
Describe the criteria that will be used to define unacceptable loss of material and how the acceptance criteria will ensure that the component functions are maintained under all CLB design loading conditions during the period of extended operation. Also, describe the analysis methodology that will be used to evaluate the inspection results against the acceptance criteria.
B.3.29 Service Water Piping Corrosion Program B.3.29-1 The LRA describes the parameters monitored or inspected as part of the service water piping corrosion program to be wall thickness measurements as an indicator of loss of material (monitoring & trending). What methods (e.g.,
codes/standards or industry guidelines) are used to select the UT procedures and the number/grid of locations to be inspected?
B.3.29-2 The LRA describes the scope of the service water piping corrosion program and states that it is applicable to several systems (nuclear service water, containment spray, diesel generator cooling water, etc.). The description of operating experience in the LRA makes only a general statement of typical corrosion rates, which range from 3 to 5 mills per year. Provide examples for corrosion rates for specific systems, and examples of how measurements have been used to determine frequencies of re-inspection and to expand the number of locations for wall thickness measurements.
B.3.32 Sump Pump Inspection B.3.32-1 The acceptance criterion for the sump pump inspection program is no unacceptable loss of material that could result in the loss of the component intended function(s), as determined by engineering evaluation. Describe the criteria for (1) assessing the severity of the observed degradations and (2) determining whether corrective action is necessary.
B.3.34 Treated Water Systems Stainless Steel Inspection B.3.34-1 The LRA states that because of the higher starting level of contaminants in the Catawba drinking water system, cracking or loss of material is more likely to occur in the Catawba drinking water system than in the containment valve injection water or solid radwaste systems. Therefore, the inspection results from the Catawba drinking water system are proposed to be bounding (monitoring &
trending). Three factors have been identified that promote stress corrosion cracking of stainless steels: (1) metallurgical (e.g., sensitization), (2) stress level, and (3) environmental (e.g., level of contaminants). The basis for the proposed Catawba treated water systems stainless steel inspection program only focuses on one of these three factors, namely environment. Discuss how the metallurgical and stress level factors were considered in the system susceptibility comparisons performed by Duke or, justify why these factors were not considered.
B.3.34-2 The LRA describes the acceptance criterion for the treated water systems stainless steel inspection program as no unacceptable loss of material that could result in a loss of the component intended function(s) as determined by engineering evaluation (acceptance criteria). Describe the criteria that will be used to define unacceptable loss of material and how these acceptance criteria will ensure that the component functions are maintained under all CLB design loading conditions during the period of extended operation. Also, describe the analysis methodology that will be used to evaluate the inspection results against the acceptance criteria.
B.3.36 Waste Gas System Inspection B.3.36-1 In section B.3.36 of the LRA, under Monitoring & Trending:
(a) The applicant stated that the waste gas system inspection will use a volumetric technique to inspect four sets of material/environment combinations.
Describe the four sets of material/environment combinations.
(b) The applicant stated that the selection of the specific areas for inspection for the above material/environment combinations will be the responsibility of the system engineer. Discuss the selection criteria that will be used by the system engineer for the inspection of the specific areas.
(c) In items (1) through (4), the applicant described the inspection criteria for cases where no parameters are known that would distinguish the susceptible locations at each site. Describe the inspection criteria, including the sample size, that will be used for those cases where the parameters are known that would distinguish the susceptible locations at each site.
B.3.36-2 The acceptance criteria for the waste gas system inspection program are no unacceptable loss of material or cracking that could result in a loss of the component intended function(s) as determined by engineering evaluation.
Describe the criteria for (1) assessing the severity of the observed degradations and (2) determining whether corrective action is necessary.
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Division of Regulatory Improvement Programs COVER PAGE DATE:
January 21, 2002
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE MCGUIRE NUCLEAR STATION, UNITS 1 AND 2, AND CATAWBA NUCLEAR STATION, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION ORIGINATOR:
Rani Franovich SECRETARY:
S. Chey
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/ /02 2.
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P. T. Kuo
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