ML100190042

Summary of Telephone Conference Call Held on 1/8/2010, Between the U.S. NRC and Nebraska Public Power District Related to a Clarification for Certain Responses to Requests for Additional Information for Cooper Nuclear Station

ML100190042
Person / Time
Site:	Cooper
Issue date:	02/03/2010
From:	Tam Tran License Renewal Projects Branch 1
To:	Nebraska Public Power District (NPPD)
Tran T, NRR/DLR, 415-3617
References
Download: ML100190042 (16)

Text

February 3, 2010 LICENSEE: Nebraska Public Power District FACILITY: Cooper Nuclear Station

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON JANUARY 8, 2010, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION STAFF AND NEBRASKA PUBLIC POWER DISTRICT RELATED TO CLARIFICATIONS FOR CERTAIN RESPONSES TO REQUESTS FOR ADDITIONAL INFORMATION FOR COOPER NUCLEAR STATION LICENSE RENEWAL The U.S. Nuclear Regulatory Commission staff and representatives of Nebraska Public Power District (the applicant) held a telephone conference call on January 8, 2010, to discuss clarifications for certain responses to requests for additional information for Cooper Nuclear Station license renewal. provides a listing of the participants and Enclosure 2 contains a brief description of the conference call.

The applicant had an opportunity to comment on this summary.

/RA/

Tam Tran, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosures:

As stated cc w/encls: See next page

ML100190042 OFFICE PM:RPB1:DLR LA:RPOB:DLR PM:RPB1:DLR BC:RPB1:DLR PM:RPB1:DLR T. Tran NAME T. Tran S. Figueroa B. Brady B. Pham (Signature)

DATE 01/21/10 01/22/10 01/23/10 02/02/10 02/03/10 Memorandum to Nebraska Public Power District from Tam Tran dated February 3, 2010

SUMMARY

OF TELEPHONE CONFERENCE CALL HELD ON JANUARY 8, 2010, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION STAFF AND NEBRASKA PUBLIC POWER DISTRICT RELATED TO CLARIFICATIONS FOR CERTAIN RESPONSES TO REQUESTS FOR ADDITIONAL INFORMATION FOR COOPER NUCLEAR STATION LICENSE RENEWAL DISTRIBUTION:

HARD COPY:

DLR RF E-MAIL:

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LIST OF PARTICIPANTS TELEPHONE CONFERENCE CALL COOPER NUCLEAR STATION LICENSE RENEWAL APPLICATION January 8, 2010 PARTICIPANTS AFFILIATIONS B. Brady U.S. Nuclear Regulatory Commission (NRC)

T. Tran NRC B. Pham NRC D. Pelton NRC A. Sheikh NRC J. Medoff NRC G. Purciarello NRC S. Gardocki NRC B. Lehman NRC E. Wong NRC C. Yang NRC D. Bremer Nebraska Public Power District (NPPD)

W. Victor NPPD C. Parkyn, NPPD K. Thomas NPPD J. Sweley NPPD D. Lach Entergy Nuclear Operations, Inc. (Entergy)

A. Cox Entergy R. Ahrabli Entergy J. Lingenfelter Entergy T. Ivy Entergy A. Taylor Entergy ENCLOSURE 1

COOPER NUCLEAR STATION LICENSE RENEWAL APPLICATION (Brief description of the conference call)

The U.S. Nuclear Regulatory Commission (NRC or the staff) and representatives of Nebraska Public Power District (NPPD or the applicant), held a telephone conference call on January 8, 2010, to discuss clarifications for certain responses to requests for additional information (RAIs) listed below.

1. Clarification for RAI B.1.15-7(d) Response Under the program description of the Fatigue Monitoring Program (B.1.15-7), the license renewal application (LRA) states, the program ensures the validity of analyses that explicitly assumed a fixed number of thermal and pressure transients by assuring that the actual effective number of transients does not exceed the assumed limit. The staff notes that the applicant relies on transient cycle monitoring to fulfill its Fatigue Monitoring Program. However, there was no description or discussion regarding how Cooper Nuclear Station (CNS) has been and will be monitoring the severity of pressure and thermal (P-T) activities during plant operations. It is essential that all thermal and pressure activities (transients) are bounded by the design specifications (including P-T excursion ranges and temperature rates). Furthermore, cycles of all significant thermal events should be captured and logged. Therefore, the staff issued RAI B.1.15-7, by letter dated May 1, 2009, requesting the applicant to:

• Describe the procedures that CNS uses for tracking thermal transients.

• Confirm that all monitored transient events are bounded by the design specifications.

• Specify the time (years) over which actual transient monitoring and cycle tracking activities took place.

• Provide a histogram of cycles accrued for normal start and normal shutdown transients.

In its response to RAI B.1.15-7(d), dated June 15, 2009, the applicant provided the histogram of cycles accrued for normal startup and normal shutdown transients.

Based on its review, the staff found that the histogram received on June 15, 2009, contains insufficient information for the staff to perform a safety evaluation. The histogram covers merely 12 years, 1996 through 2007, although the plant has been in operation for 35 years, 1974 through 2009. For clarification, the staff held a telephone conference call on September 29, 2009, requesting the applicant to provide complete histogram that covers the entire plant operating history to date (through November 21, 2006 as indicated in LRA Table 4.3-1). On October 8, 2009, the applicant provided new histograms which cover the entire history of the plant operation through 2007. Based on its review, the staff found inconsistency between the accrued cycles shown in the histogram and the cycles reported in LRA.

Specifically, LRA Table 4.3-1 shows 181 cycles for normal startup. However, the histogram indicates that (through end of 2006), the normal startup transient has occurred 183 184 times, approximately three cycles higher than what the LRA shows.

Furthermore, the histogram shows significantly larger number of cycles for the startup transient than for the shutdown transient, throughout the entire operating history. For example, as of end of 2006 for the normal shutdown transient, the histogram shows 77 cycles accrued whereas LRA Table 4.3-1 reports 175 cycles. Clarification for all the inconsistency described above is ENCLOSURE 2

necessary. It is also necessary that the applicant provides the basis to support the use of the accrued cycles shown in LRA Table 4.3-1, where 181 cycles for the normal startup and 175 cycles for the normal shutdown are reported versus what the histogram shows, 184 and 77 cycles, respectively.

The staff requested explanations and the applicant provided the clarifications, as follow:

• Explain the large difference between the accrued startup and shutdown cycles.

Applicants clarification: Shutdowns due to transients are not generally counted as normal shutdowns. Some events may be counted in more than one category. That is why the total number of shutdowns does not equal the total number of startups as shown on the histogram.

• Explain the inconsistence between the accrued cycles shown in the histogram and those shown in LRA Table 4.3-1, where 181 cycles and 175 cycles are shown for normal startup and normal shutdown, respectively. But for the normal startup transient, the histograms numbers are slightly higher (by three cycles, approximately). This is non-conservative. For the normal shutdown transient, the LRA Table 4.3-1 shows more cycles than what the histogram indicates. Please explain.

Applicants clarification: The information in Table 4.3.1 was based on data through November 21, 2006. The information in the histogram includes data through 2007. The number of shutdown events in Table 4.3.1 includes turbine trips and manual scrams.

That information is presented separately in the histogram.

• Based on the information contained in the histogram, the 60-year projected cycles shown in LRA Table 4.3-1 appears on the non conservative side. Provide the basis and equations used for the 60-year cycle projections.

Applicants clarification: The projection is reasonable based on the 2006 data used. The Fatigue Monitoring Program will provide reasonable assurance that the number of cycles will not exceed the allowable number of cycles.

• Revise the histogram to show only normal startup and normal shutdown transients. This is just a recommendation. The histogram as it is not suitable for publication (to safety evaluation report [SER]).

Applicants clarification: The information can be provided that way, but it would not give an accurate picture of the plants operating history. The histogram was never intended for publication in the SER since it is not part of the plants Fatigue Monitoring Program and was only provided as a visual aid for the reviewer.

2. Draft RAI B.1.30-3, Small Bore Socket Weld In a letter dated November 16, 2009, NPPD provided response to the staffs RAI issued on October 15, 2009. In its response, NPPD provided additional clarification regarding RAI B.1.30-1 previously issued by the staff. It stated that prior to 2004, NPPD [CNS]

experienced socket weld cracking. However, it did not clearly indicate it was a Class 1 weld.

Note that the information has not been provided to the staff before, not in its LRA, nor during the staff on-site aging management program (AMP) audit.

Based on NUREG-1801,Section XI.M35, should previous plant operating experience revealed aging in its American Society of Mechanical Engineers (ASME) Code Class 1 small bore piping, periodic inspection will be proposed, as managed by a plant-specific AMP.

If the subject socket weld was of ASME Code Class 1, please provide a plant-specific AMP to address the aging effects in Code Class 1 small bore piping including socket welds, or provide technical justification why periodic inspection and a plant-specific AMP is not necessary.

Due to schedule conflict of key staff availability, this agenda item was deferred, for this conference call.

3. Clarification for RAI B.1.10-1 Response In NPPD letter NLS2009040, dated June 15, 2009, the applicant responded to RAI B.1.10-1 related to the containment sand bed region. The applicant explained that the potential source of moisture which could enter the sand bed region is refueling water after the refueling cavity is filled during refueling outages. Potential leakage is removed through drain lines which are alarmed to alert operations.

The applicants response discussed leakage through the drywell-to-reactor building bellows.

However, it did not clearly explain how CNS is addressing the possibility of leakage through the refueling cavity liner. Leakage through the liner could initiate and propagate corrosion in the exterior of the drywell shell.

The staff requested the applicant to clarify how the possibility of leakage through the refueling cavity wall liner is being addressed. Include the inspections that are conducted to identify the potential source of leakage through the liner that could enter the space between the drywell shell and the shield wall concrete, and corrode the exterior surface of the drywell shell (significant leakage could also affect the shell in the sand bed region).

The applicant provided the following clarifications:

Applicants draft response: As discussed in response to previous RAI B.1.10-1, potential refueling cavity leakage at the refueling seal and bellows area is removed through drain lines, preventing water from entering the sand bed region. As further discussed in the response, leakage through the liner in the area above the bellows would enter the trough area below the refueling bellows assembly and flow from there into the drain system with the flow alarm that is further discussed in the response, the applicant has not experienced flow alarms during previous refueling outages. If leakage through the refueling cavity liner bypasses the seal and bellows area and enters the annulus between the drywell shell and shield wall concrete, it would migrate to the sand bed region and be detected flowing from the eight sand bed region drain lines in the torus room. As previously discussed in response to RAI B.1.10-1, the CNS drywell sand bed region is equipped with eight drain lines to drain water from the region in case of a leak when the refueling cavity is filled. The CNS drywell sand bed region drain lines are

inspected for any signs of leakage during the refueling outages while the refueling cavity is filled. Routine observation during refueling operations and monitoring of the refueling bellows drain system and associated alarm have indicated no leakage of the refueling cavity liner at CNS. Furthermore, no evidence of moisture potentially causing corrosion of the drywell shell has been identified In the future, if any evidence of refueling liner leakage is identified, CNS will determine additional inspections and other corrective actions, as appropriate.

A vacuum test of four out of eight lines in 1993 verified that the drain lines are unplugged and are functioning properly. However, to ensure the lines remain obstruction free, so that potential refueling liner leakage can be detected, the applicant has committed to perform an additional vacuum test of all eight sand bed drain lines prior to the period of extended operation.

The staffs review of the applicants draft response: The staff clarified its concern as follows. For small leaks in the cavity liner, it would not be detectable as flow from the drain lines, but it would be sufficient to migrate to the upper drywell and cause undetected corrosion. The staff was concerned that interim staff guidance License Renewal Interim Staff Guidance (LR-ISG) 2006-01 would not be met.

Follow-up: The applicant indicated that it was not credible to postulate a smart leak that was not detectible as drainage.

Subsequent to the conference call the applicant revisited LR-ISG-2006-01, Plant-Specific Aging Management Program for Inaccessible Areas of Boiling Water Reactor Mark I Steel Containment. While Recommended Action (5)(a) specifies scoping and aging management review (AMR) of components which could be potential sources of moisture (such as reactor cavity pool liners), the context of this recommendation is if moisture has been detected or suspected on the exterior of the drywell shell. At CNS, moisture on the drywell shell has been neither detected nor suspected, thus the ISG does not specify the AMR for the CNS reactor cavity liner. Nonetheless, the applicant has included the reactor cavity liner within scope of license renewal and has performed an AMR of the liner. The applicant has committed to enhance the Structures Monitoring Program to include the reactor cavity liner. Accordingly, visual inspections are performed at intervals of no greater than five years to verify the structural integrity of the liner. In summary, the applicant believes there is reasonable assurance that the effects of aging on the reactor cavity liner will be properly managed.

4. Clarification for RAI 3.5-1 Response In NPPD letter NLS2009062, dated September 24, 2009, the applicant responded to RAI 3.5 -1 related to CNS concrete design. The applicant explained that the CNS concrete mix was established based on Method 2 of ACI 318-63. The applicant further explained that the maximum permissible water-cement ratio was 0.71 for concrete with 3000 psi and 0.52 for concrete with 4000 psi strength.

It would be technically difficult to achieve 3000 psi and 4000 psi concrete with air-entrainment and water-cement ratios of 0.71 and 0.52 respectively.

The staff request the applicant to provide evidence that would confirm that the in-situ concrete strengths are above the minimum specified strengths. The evidence may consist of the results of the strengths obtained during the trial mix design, and/or those obtained during the production tests, as required by Method 2 of ACI 318-63.

The applicant provided the following clarifications:

Applicants draft response: Actual test data for 3000 and 4000 psi concretes were sent via e-mail (Agencywide Documents Access Management System [ADAMS] Accession No. ML100330600) to the NRC.

The staffs review of the applicants draft response: The staff is reviewing the concrete test data.

This issue will be characterized as a Confirmatory Item pending completion of that review.

5. Clarification for RAI B.1.11-1 Response Title 10 of the Code of Federal Regulations Part 50 (10 CFR 50), Appendix J allows for two options, A or B, either of which will meet the requirements for containment leak rate testing.

The CNS LRA discusses three exemptions to the requirements of 10 CFR Part 50, Appendix J.

These exemptions were granted based on the use of Option A, and reference regulatory requirements related to Option A of Appendix J; however, the applicant has stated Option B will be used during the period of extended operation.

The staff requested the application to explain how the three exemptions to Option A apply to the procedures that will be used for Option B during the period of extended operation.

The applicant provided the following clarifications:

The first two exemptions on Type B and C testing, discussed in the LRA, Section B.1.11, Containment Leak Rate Items 1 and 2, were granted by the NRC prior to 1995 (i.e., prior to existence of Option B to 10 CFR 50 Appendix J). Amendment 180, issued March 3, 2000, authorized the use of Option B for CNS. Page 4 of the staff's safety evaluation for Amendment 180 discussed the relocation of the two exemptions to new Section 5.5.12, "Primary Leakage Rate Testing Program". Thus the previous exemptions were re-approved for Option B. The third exemption discussed in the LRA, Section B.1.11, Containment Leak Rate Item 3, was approved for CNS with Amendment 226. This amendment was an exemption from Sections III.A and III.B of 10 CFR 50, Appendix J, Option B, to exclude main steam isolation valve leakage from the overall total leakage rate (TAC NO. MD0570). Therefore, the three exemptions noted in LRA B1.11 remain applicable to the CNS Containment Leak Rate Program, which utilizes 10 CFR 50 Appendix J, Option B, and the guidance in NRC Regulatory Guide 1.163 and Nuclear Energy Institute 94-01. The CNS Containment Leak Rate Program will continue to perform its intended functions consistent with the current licensing basis through the period of extended operation.

6. Scoping and Screening Drawings Clarification In the applicants RAI response letter, November 30 2009, , page 14 or 16, the applicant states valve bodies 1"V353X (20CV) and 1"V253X(218) on drawing 2049, sh 4 (see below). Is 1"V253X(218) really a check valve or a manual gate valve?

Was the description supposed to say 1" CH -3 upstream piping rather than downstream piping.

The applicant provided the following clarifications:

In the RAI response, NPPD did not represent both valves as being check valves, rather, they are CF valves (CF stands for condensate filter system designator). 1V253X(218) is, in fact, a manual globe valve.

In responding to the RAI, NPPD was attempting to describe the piping that was in scope from the previously highlighted portion on the drawing to where it departs the reactor building and enters the radwaste building. Technically speaking, the system flow does originate from the 24 condensate header to CF demin supply in the radwaste building (B&R Dwg 2035 SH01),

therefore this portion of line which was the subject of the RAI question, is more correctly described as upstream in relation to CF valves, 1"V353X (20CV)] and 1"V253X(218).

Follow-up: The staff indicated it was satisfied with this response and that this issue is resolved.

7. Standard Review Plan for License Renewal Applications for Nuclear Power Plants (SRP-LR)

Section 3.4.2.2.7, Item 1 - Loss of Material/pitting and crevice corrosion (Boiling-Water Reactor Water Chemistry)

LRA Table 3.4.2-2-5 addresses the loss of material due to pitting and crevice corrosion of the stainless steel rupture disk in the Extraction Steam System exposed to treated water >140°F. In LRA Table 3.4.2-2-5, the applicant proposed to manage this aging process for this component exposed to this environment through the use of its AMPs Water Chemistry Control-BWR and One-Time Inspection (LRA B.1.39 and B.1.29) under Generic Aging Lessons Learned (GALL)

Report Item VIII.C-1. The applicant stated that for the component, material, and environment combination listed, the component is consistent with the GALL Report item for component, material, environment, and aging effect, and the applicants AMP is consistent with the GALL Report (LRA Note A).

The staff reviewed LRA Table 3.4.2-2-5 against the criteria in SRP-LR Section 3.4.2.2.7.1, which states that the water chemistry control AMP relies on monitoring and control of water chemistry to manage the effects of loss of material due to pitting and crevice corrosion.

However, control of water chemistry does not preclude corrosion at locations of stagnant flow conditions. Therefore, the GALL Report recommends that the effectiveness of the water chemistry program should be verified to ensure that corrosion is not occurring. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion is not occurring and that the components intended function will be maintained during the period of extended operation.

The staff notes that the applicant classifies the stainless steel rupture disk in the Extraction Steam System as an LRA Note C item (component different from, but consistent with, the GALL Report) with respect to aging processes managed by GALL Report Items VIII.A-11, VIII.A-13, and VIII.E-31. This classification is made despite that fact that the above three GALL Report items, as well as Item VIII.C-1 referred to here, all pertain to piping, piping components, piping elements (VIII.A-11 and VIII.A-13) or piping, piping components, piping elements, tanks, and heat exchanger components (VIII.E-31 and VIII.C-1). The staff requests the applicant to explain why the rupture disk is assigned two different LRA Notes classifications in LRA Table 3.4.2-2-5.

The applicant provided the following clarification:

When comparing the plant AMR results for a given component to a specific table line in NUREG-1801, LRA Note A or C is applied when the material, environment, aging effect and program are all consistent. When these elements are consistent, the choice between LRA Note A and C depends on whether the component is the same as, or different from NUREG-1801.

When making this determination NPPD considers not only the type of component (e.g., piping component, heat exchanger etc.), but the system in which the component resides. This approach has been used for all of the NUREG-1801 comparisons presented in the LRA Section 3 tables.

The component of interest in this particular case is a rupture disk in the extraction steam system.

NUREG-1801, Table VIII.C presents AMR results for a generic extraction steam system.

Consequently, lines for the rupture disk (as a piping component) that were compared to Table VIII.C, use a Note A since both the component type and system match.

However, NUREG-1801, Table VIII.C does not have all the combinations of material, environment, aging effect and program to fully represent the rupture disk AMR results. So lines from tables associated with other systems are used for comparisons. Lines for the rupture disk are compared to lines from Table VII.E3, for the reactor water cleanup system, Table VIII.A, for the steam turbine system; and Table VIII.E, for the condensate system. Note C is used for each of these comparisons since the system is different.

One line for the rupture disk is compared to a line from Table VIII.I, Common Miscellaneous Material/Environment Combinations. Since this table represents all steam and power conversion systems, including the extraction steam system, LRA Note A is also applied to this line.

8. Clarification for B.1.40-1 Response LRA Section B.1.40 (Water Chemistry ControlClosed Cooling Water) states that it is consistent with GALL XI.M21 (Closed-Cycle Cooling Water System) with one exception that impacts the following GALL program elements: parameters monitored or inspected, detection of aging effects, monitoring and trending, and acceptance criteria. Specifically, this exception states that the applicants AMP B.1.40 does not include performance and functional testing proposed by GALL XI.M20.

The staff reviewed this exception to the GALL Report and noted that the applicant took the exception because it considers performance testing and monitoring to be of little value in managing effects of aging on long-lived passive closed cooling water (CCW) system components. The applicant cited Electric Power Research Institute Reports TR-107396 and 1007820 to support its contention that such performance monitoring is typically part of an engineering program rather than a water chemistry program. The applicant further stated that the passive intended functions of pumps, heat exchangers and other components will be adequately managed by the closed cooling water chemistry and one-time inspection programs.

In its review, the staff found that the applicant did not provide adequate information to demonstrate consistency with GALL XI.M21, Program Element 4 (Detection of Aging Effects),

which states: Degradation of a component due to corrosion or stress corrosion cracking (SCC) would result in degradation of system or component performance. The extent and schedule of inspection and testing should assure detection of corrosion or SCC before the loss of the intended function of the component. Therefore, by letter dated May 1, 2009, the staff issued RAI B.1.40-1 requesting the applicant to indicate how and under what AMP the monitoring and functional testing of the closed water system components is to be carried out. If monitoring and functional testing is not carried out, the applicant was asked to justify why it is not considered necessary.

The applicant responded by letter dated June 15, 2009, and repeated its position that performance monitoring is typically a part of an engineering program, which would not be a part of water chemistry. The applicant again stated that functional and performance testing verifies that component active functions can be accomplished and is of little value in detecting loss of passive functions due to such aging effects as loss of material. The applicant further stated that passive intended functions of pumps, heat exchangers, and other components will be adequately managed by its Water Chemistry Control - Closed Cooling Water and One-Time Inspection programs through monitoring and control of water chemistry parameters and verification of absence of aging effects.

The staff noted that the applicant experienced pitting corrosion in components of its reactor equipment cooling (REC) system in the 1990s as a result of closed-cycle cooling system water chemistry excursions. The staff also noted that the applicant more recently experienced closed system water chemistry excursions during the period 2003-2004, during which time the dissolved oxygen level in the turbine equipment cooing (TEC) and REC systems averaged six ppm (saturation) for more than one year. This compares with a maximum level of 50 ppb specified in the applicants procedures. A similar excursion of shorter duration occurred in 2006.

In view of the fact that aging-related damage has occurred in the applicants REC system in the past and subsequent significant water chemistry excursions have also occurred in both the TEC and REC systems, the staff feels that substantial measures are required to verify that further corrosion-related aging of the applicants closed-cycle cooling water system has not occurred.

The staff notes that GALL XI.M21, Program Element 5 (Monitoring and Trending) states that internal visual inspections and performance/functional tests are to be performed periodically to demonstrate system operability and confirm the effectiveness of the program. The staff finds that the applicants proposed use of its One-Time Inspection AMP (LRA B.1.29) does not provide adequate verification.

The staff requested the applicant to provide additional information to demonstrate that closed cooling water system operability and the effectiveness of the applicants Water Chemistry Control - Closed Cooling Water AMP are being verified on a periodic basis.

The applicant provided the following clarifications:

This was discussed in a telephone conference call on November 9, 2009, where the applicant disagreed with the staffs assertion that provisions of GL 89-13 must be applied to CNS closed cooling water systems, because of the oxygen excursion. The staff stated that a commitment to periodic testing is prudent and warranted; and the issue is an open item.

Subsequent to the conference call, the applicant re-reviewed LRA Section B.1.40 (Water Chemistry Control - Closed Cooling Water). It was noted that while an exception was taken to GALL Section XI.M21 (Close-Cycle Cooling Water System) for periodic performance and functional testing, no exception was taken for the periodic internal visual inspections discussed in XI.M34 Elements 3 and 5. Internal visual inspections will be performed during the period of extended operation when CCW boundaries are opened. These inspections are in addition to the one-time inspection program inspections to verify effectiveness of the water chemistry control program.

9. Clarification for RAI 3.3.2.2.6-3 Response During the site audit and in subsequent RAI dated June 29, 2009 (ADAMS Accession No. ML091600284), the staff requested that the applicant provide additional details on neutron-absorbing materials in the spent fuel pool, the inspection of Boral coupons, the applicable aging management programs, and operating experience.

The applicant responded to the RAI in a letter dated July 29, 2009 (ADAMS Accession No.ML092160083). In the response to the RAI, the applicant also provided information on relevant industry and operating experience. The applicant addressed staff concerns regarding scheduling of inspections and neutron attenuation testing of Boral coupons. The applicant confirmed that the surveillance inspections of the Boral coupons will be performed every eight years. In addition, the applicant stated that the rationale to not evaluate the change in neutron-absorbing capacity was due to operating experience from neutron attenuation testing of coupons conducted in 1982 and 1992. The testing indicated no loss of neutron attenuation properties.

After reviewing the applicants response to the RAI, the staff determined that more information was needed to accept the justification that there is no change in neutron absorbing capacity of Boral in the spent fuel pool and that there is no need for further neutron attenuation testing. As a result, the staff and the applicant held a teleconference on September 21, 2009, to clarify the responses to the RAI; subsequently, the staff identified additional needs for information as follows:

• Explain in more detail why the bulged coupons are not representative of the racks? Has this been confirmed by testing?

Applicants response: The bulged coupons are not representative of the condition of the racks as the results of the 1992 testing pointed to the shearing of the coupons when they were reduced in size as the cause and the racks were not sheared in this manner. It is unknown what confirmation could be obtained by other testing as there has been no bulging noted in the racks and the bulged coupons attenuation testing results revealed no loss of neutron absorption capability.

• Explain the increase in the weight and thickness of 196-A-4-2 prior to 1992 when it was reported.

Applicants response: The surveillances prior to 1992 reported the weight and thickness of 196-A-4-2. It was deemed in 1992 that these increases required further evaluation, which was done at that time. The documentation does not indicate how the results prior to 1992 were explained. The coupons are dried prior to measurement, so that is a potential source of explanations but the personnel performing the prior examinations are not available to query as to whether there were any issues with the drying evolution.

• The last sentence of 3c mentioned that the racks are routinely examined. Please describe how this is accomplished.

Applicants response: CNS routinely exams rack cells in which fuel will be staged for outages for foreign material. This is accomplished visually by using a camera to examine the location in the rack.

• It is unclear as to whether or not B-10 areal density measurement is no longer performed or in the future, neutron attenuation testing/blackness testing will be performed as a corrective action. Please clarify.

Applicants response: Areal density measurement was never routinely performed as part of the surveillance. It was performed as a corrective action on the coupons when the normal surveillance indicated a potential problem. Future testing is discussed below.

CNS has not performed rack blackness testing in the past.

• The staff would like to discuss the consistency of the CNS Boral Monitoring Program with the ISG 2009-01.

Applicants response: The initial review of the draft ISG 2009-01 indicates that the CNS program is consistent with the methods of testing in the document (visual, physical measurements, attenuation testing) and the CNS program is performed on a more frequent basis than described by the document. The document states that the licensee program needs to take into account the licensees operating experience with the material and the CNS program has done that by using a graded approach when issues arise during performance of the surveillance.

CNS experience with Boral has generally been acceptable. CNS has moved fuel in every rack in the past few years to support security order requirements and dry storage preparation needs.

CNS has never, in all those fuel moves, experienced any binding or indication that swelling or bulging has occurred in any rack cell. CNS has regularly performed monitoring of the sample coupons and has rigorously evaluated the issues seen with those coupons. This past performance is an indication of how CNS would perform during the period of extended operation. CNS is currently discussing internally the staffs position that coupon attenuation testing should be performed prior to the period of extended operation and intends to formulate a position for the staff to consider by February 5, 2010.

Follow-up: Subsequent to the telephone conference call, the applicant elected to commit to enhance the Neutron Absorber Monitoring Program to include neutron attenuation testing of representative sample coupons at least once every 10 years during the period of extended operation; to verify there is no loss of neutron absorbing capacity of the Boral material.

Cooper Nuclear Station cc:

Mr. Ronald D. Asche Deputy Director for Policy President and Chief Executive Officer Missouri Department of Natural Resources Nebraska Public Power District P.O. Box 176 1414 15th Street Jefferson City, MO 65102-0176 Columbus, NE 68601 Senior Resident Inspector Mr. Gene Mace U.S. Nuclear Regulatory Commission Nuclear Asset Manager P.O. Box 218 Nebraska Public Power District Brownville, NE 68321 P.O. Box 98 Brownville, NE 68321 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission Mr. John C. McClure 612 E. Lamar Blvd., Suite 400 Vice President and General Counsel Arlington, TX 76011-4125 Nebraska Public Power District P.O. Box 499 Director, Missouri State Emergency Columbus, NE 68602-0499 Management Agency P.O. Box 116 Mr. David Van Der Kamp Jefferson City, MO 65102-0116 Licensing Manager Nebraska Public Power District Chief, Radiation and Asbestos P.O. Box 98 Control Section Brownville, NE 68321 Kansas Department of Health and Environment Mr. Michael J. Linder, Director Bureau of Air and Radiation Nebraska Department of Environmental 1000 SW Jackson, Suite 310 Quality Topeka, KS 66612-1366 P.O. Box 98922 Lincoln, NE 68509-8922 Ms. Melanie Rasmussen Radiation Control Program Director Chairman Bureau of Radiological Health Nemaha County Board of Commissioners Iowa Department of Public Health Nemaha County Courthouse Lucas State Office Building, 5th Floor 1824 N Street 321 East 12th Street Auburn, NE 68305 Des Moines, IA 50319 Ms. Julia Schmitt, Manager Mr. Keith G. Henke, Planner Radiation Control Program Division of Community and Public Health Nebraska Health & Human Services R&L Office of Emergency Coordination Public Health Assurance 930 Wildwood Drive 301 Centennial Mall, South P.O. Box 570 P.O. Box 95007 Jefferson City, MO 65102 Lincoln, NE 68509-5007

Cooper Nuclear Station cc:

Mr. Art Zaremba, Director of Nuclear Mr. Dave Lach Safety Assurance LRP Entergy Project Manager Nebraska Public Power District Entergy Nuclear P.O. Box 98 1448 S.R. 333, N-GSB-45 Brownville, NE 68321 Russellville, AR 72802 Mr. John F. McCann, Director Mr. Stewart B. Minahan Licensing, Entergy Nuclear Northeast Vice President Entergy Nuclear Operations, Inc. Nuclear and Chief Nuclear Officer 440 Hamilton Avenue Cooper Nuclear Station White Plains, NY 10601-1813 72676 - 648A Avenue Brownville, NE 68321 Mr. Mike Boyce Cooper Strategic Initiatives Manager Cooper Nuclear Station 72676 - 648A Avenue Brownville, NE 68321 Mr. Dave Bremer License Renewal Project Manager Cooper Nuclear Station 72676 - 648A Avenue Brownville, NE 68321 Mr. Bill Victor License Renewal Project Licensing Lead Cooper Nuclear Station 72676 - 648A Avenue Brownville, NE 68321 Mr. Garry Young License Renewal Manager Entergy Nuclear 1448 S.R. 333, N-GSB-45 Russellville, AR 72802 Mr. Alan Cox License Renewal Technical Manager Entergy Nuclear 1448 S.R. 333, N-GSB-45 Russellville, AR 72802