ML022460102

E-mail from J Chung, NRR to Fm Reinhart, NRR, PRA Perspective in Technical Assessment Report

ML022460102
Person / Time
Site:	Davis Besse, Oconee, Cook
Issue date:	02/06/2002
From:	Chung J Office of Nuclear Reactor Regulation
To:	Reinhart F Office of Nuclear Reactor Regulation
References
FOIA/PA-2002-0229
Download: ML022460102 (62)

Text

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ýte~ver. _ong - i-*perspective in i ecnnicai Assessmem MP,1 Lpr rage -1 zIteIIII peispectiie cn ial IoIgl-IrIIIII smill nn lse ag II A From: Jin Chung 1 ;\,,it t4.

To: F. Mark Reinhart A*)tt1..

Date: 2/6/02 1:37PM

Subject:

PRA perspective in Technical Assessment REport here is my first draft input, which include three plant-specific insights. The three plants are D.C. Cook, Davis Besse, and Oconee. Please provide me with comments by no later than February 20, 2002.

CC: Steven Long

/

Informaton in this record was deleted in accordance with /he Freedom of Information Act, exemptions FOIA- ,,

3_W;i6'(ý hl --01 ng - techass.wp e1 Long- techssiwpd-a 4.0 SYSTEMS AND RISK DISCUSSION 4.1 Accidents Associated with CRDM temperature has been bounded. The Housing Failure analyses are also performed assuming the highest-worth control rod assembly fails to Two classes of accidents are applicable to insert, in some cases, and that all control the failure of a CRDM housing: the reactivity rods fail to insert in other cases. The results insertion due ejection of a control rod and a of the analyses must meet the acceptance loss of coolant accident (LOCA). Each is criteria specified in 10 CFR 50.46, part of the design basis for a nuclear power specifically that neither the peak cladding reactor. temperature does not exceed 2200OF (1204.4 OC) nor that there is oxidation of 4.1.1 Control Rod Ejection Accident more than 17% of the fuel cladding.

All PWRs must analyze the ejection of a Preliminary evaluations of representative control rod drive assembly, for which each hardware configurations indicate that the NSSS has a unique name, and the separation of a control rod drive mechanism subsequent reactivity insertion. Control rod housing does not present any new or drive housing failures and leaks are different thermal-hydraulic phenomena.

evaluated based on longitudinal as well as However, the circumferential CRDM nozzle circumferential failures. The nuclear design cracking at ONS-2 and ONS-3 raises is such that the energy deposited in the fuel concerns about potential safety implication rods adjacent to the rod that is postulated to on adequacy of public protection, where the be ejected will not exceed 280 cal/g (1.17 thermal-hydraulics of the event with this kJ/g), the failure threshold for uranium break size was analyzed but the risk and dioxide, zirconium-clad fuel. A typical rod initiation of the crack-induced CRDM failure ejection analysis is performed considering an were not analyzed.

average core channel and a hot region.

Each is also performed for the maximum The staff examined various aspects of the allowed rod bank insertion at a given power CRDM failure phenomena, including level. Appropriate safety analysis margins potential collateral damages and the event are added to the ejected rod worth and hot mitigation options. The objective was to channel factors to account for calculational identify potential worst case scenario and uncertainties. The results are then provided bounding event, and to understand risk for analyses at beginning of cycle - full insights associated with CRDM nozzle power, beginning of cycle - zero power, end cracking so that an appropriate level of of cycle - full power, and end of cycle - zero attention could be given to the issue. The power. staff focused its review on the crack initiation and propagation phenomena 4.1.2 Loss of Coolant Accident (LOCA) leading to a failure of the CRDM VHP and Anticipated-Transient-Without-Scram nozzle and the consequent LOCA when the (ATWS) circumferential through-wall cracks are All PWRs must analyze a spectrum of propagated to a point that the reactor LOCAs ranging from full double-ended coolant system pressure inside the reactor guillotine separation of the largest reactor vessel would eject the CRDM. The loss of coolant pipe to the smallest size break, coolant depends on the size of the break, and may range from a leak to a large break LOCA, depending on the design 1

Page 2 Ji LSteve Long - techass.wpd I dimensions of the relevant components, considered as medium size LOCA. This collateral damages, and failure mechanisms. size of breaks was considered as a part of design basis accident scenario and If the CRDM VHP nozzle breaks and yet the evaluated accordingly for potential fuel control rod does not eject completely out of failures under the 10 CFR 50, Appendix K, the vessel penetration, leaving a relatively as opposed to the containment performance small flow area at the vessel head, for large break LOCA.

equivalent to and less than about 1/ inch (1.27 cm) in diameter. This size leak could Large break LOCAs occur with break sizes be controlled by the normal charging and 6 inches (15.24 cm) in diameter or larger.

makeup system, and would be unlikely to This scenario would not be likely since it result in a core damage event. would require rii6ietlan two CRDM ejections simultaneously. Large breaks A small break LOCA would occur if the remove the decay heat through the breaks, CRDM housing is somehow partially ejected and only inventory makeup is of important.

from the reactor vessel penetration or the hole is partially blocked, leaving an In summary, the most likelihood limiting equivalent flow area between Y2 inch to 2 accident sequence would be the medium inches (1.27 to 5.08 cm) in diameter (up to size LOCA as the upper CRDM is separated 3.14 in2 (20.25 cm2 ) cross section). This by the circumferential cracking, and break size would be least likely break, unless subsequently ejected out of the vessel the broken CRDM is partially pushed out of penetration due the hydraulic force of the the vessel penetration, lodged in the vessel reactor coolant. Once a medium size LOCA penetration, or debris inside of the vessel occurs, the injection for inventory makeup partially blocks the opening. The size of would be from RWST (or BWST for B&W such break would not be large enough to plants) or upper head accumulators initially.

depressurize the system before core damage However, sooner or later, the plant operator occurs, nor remove sufficient energy to cool must switch from the injection mode to the RCS. Therefore, for a successful mitigation recirculation mode, drawing water from the of this size LOCA it would need other means containment sump as the makeup water of removing energy and the RCS must be tank is depleted. This switch over is depressurized if low pressure injection is plant-specific, and may require either needed. manual operation or automatic switchover.

The CE plants are normally automated for A medium break LOCA size is generally the swapping operation.

considered to be 2 to 6 inches2 (5.08 to 15.24 2 cm) in diameter (up to 28.3 in or 182.58 cm The common cause failures of pumps and in cross section). This size break would be valves, and potential operator failures of the most likely break once the separated timely switch over to recirculation are the upper part of the CRDM begins upward major risk contributors to failures of the motion under the large RCS pressure. Even event mitigation, and consequently, the if the circumferentially cracked nozzle is conditional core damage probability (CCDP) ejected from the vessel penetration but the is relatively high for such failures. This control rod drive shaft somehow lodged and insight is based upon plant-specific stuck in the vessel penetration, the flow area Individual Plant Examination (IPE) under the would be sufficiently large enough to be GL 88-20. Data from these studies indicate 2

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the CCDP, given that a medium size LOCA decision making, and provides guidance to has occurred, falls in the range of I E-3 to identify a "special circumstance" in which IE-2. compliance with Commission regulations does not implicitly address a safety issue for Core damage contribution from the adequate protection of the public. It anticipated-transient-without-scram provides a process for the staff to consider (ATWS)-type events or the reactivity whether a "special circumstance" exists perturbation is practically negligible. which may rebut the presumption that However, potential complications can occur compliance with the regulations provides due to collateral damage to other CRDMs, or adequate protection of public health and blockage of the emergency core cooling safety. Although developed as a tool for recirculation sump, or delay in switch over to staff reviews of license amendment sump recirculation, and projectiles from the requests, the process in the RIS is CRDM failure inside containment. Such appropriate for other regulatory decision complications may increase the risk making purposes because it addresses the associated with a CRDM failure. fundamental requirement for operation of a nuclear reactor: there is reasonable 4.2 Risk Perspectives and Adequate assurance of adequate protection for the Protection public health and safety.

The Commission Policy on use of A "special circumstance" is present if probabilistic approach was published in compliance with current regulatory Federal Register Vol. 60, No. 158, "Use of requirements does not provide appropriate Probabilistic Risk Assessment Methods in means to detect and protection against Nuclear Regulatory Activities: Final Policy degradation of plant hardware, and Statement' on August 16, 1995. It affirms deficiency of plants operation, and thus, that probabilistic risk assessment (PRA) assure the structural integrity and protect methods can be used to derive valuable against a severe accident. Failure of the insights, perspective, and general regulations to require adequate protection conclusions as a result of an integrated that could lead to a failure of structural examination of facility design, response to integrity, and consequently a severe initiating events, expected interactions accident, constitutes a risk factor addressed among structures, systems, and by the Regulatory Guide (RG) 1.174, "An components, and with its operating staff. It Approach for Using Probabilistic Risk endorses the use of the risk insights in Assessment in Risk-Informed Decisions on conjunction with regulatory requirements and Plant-Specific Changes to the Licensing the defense-in-depth philosophy in the Basis."

decision making process.

In the RG 1.174 a "special circumstance" The Regulatory Information Summary (RIS) exists and acceptable if the following five principle criteria are met:

01-002, "Guidance of Risk-Informed Decision making in License Amendment Reviews" (1). It meets current regulations. This first dated January 18, 2001, further clarifies criterion addresses the licence conditions some of the ambiguity of NRC's policy on the and the requirements of 10CFR50.55a.

implementation and use of PRA. The RIS addresses safety principles of risk-informed (2). It is consistent with "defense-in-depth 3

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philosophy," The second criterion must be temporary risk ceiling of 10-3 per reactor satisfied because, compliance with the year for temporary configuration-specific regulations may not be adequate to prevent CDF, and for which the NRC neither the failure of the reactor coolant pressure endorses nor disapproves. However, Table boundary, one of the three barriers to release in the section 11.3.7.2 established risk of radioactive materials from the reactor management action thresholds based on core. quantitative considerations for incremental core damage probability (ICDP) and (3). It maintains sufficient safety margin, For incremental large early release probability CRDM cracking. The compliance with the (ILERP) for the configuration-specific risk.

ASME Code, Section Xl, inservice inspection The ICDP or ILERP can be evaluated by requirements fails to satisfy the third principle integrating the -a"DF6? LERP over the time of maintaining safety margins since it cannot duration of the temporary configuration.

be assured that pressure boundary leakage would be detected prior to a gross failure of a (5). Finally, the basis for the risk estimate is vessel head penetration nozzle. monitored using performance measurement strategies. the fifth principle is satisfied if (4). Itresults in only a small increase in core the basis for any analysis that shows risk damage frequency. The fourth principle levels below Regulatory Guide 1.174 addresses application of the numerical numerical guidelines are based on guidance in the RG 1.174, which further assumptions that can be verified and are provides for an acceptable level of change in capable of detecting the form of degradation risk for a given change in licensing condition, being modeled.

consistent with the Commission safety goal.

The extension of temporary plant operations Summarizing the above, it would be under the adverse conditions, such as appropriate to use risk insights for decision existence of CRDM cracking but with an making process under the fourth and fifth assurance of safety margin and acceptable principles. The regulatory guides cited here remedial actions, may be evaluated based recommend to use mean values for the on the temporary risk addressed in the RG numerical guidelines.

1.182 under the 10CFR50.65 maintenance rule.

4.3 Probabilistic Risk Assessment Regulatory Guide 1.182, "Assessing and Managing Risk before Maintenance Activities 4.3.1 CDF and LERF at Nuclear Power Plants" May, 2000, was aimed to monitor the overall effectiveness of The frequency of the LOCA initiation the licensee maintenance programs, and depends on the likelihood of a crack and its established methods that are acceptable to circumferential propagation, followed by a NRC staff. As an attachment to the RG CRDM VHP nozzle failure. Thus, an 1.182, Section 11, "Assessment of Risk increase in plant risk would depends on the Resulting from Performance of Maintenance frequency of the CRDM failure and the Activities," dated February 11, 2000, of likelihood of the recovery failure from the NUMARC 93-01, "Industry Guideline for event.

Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," specifies The quantitative understanding of a crack 4

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--..i Siteven Long - techass.wpdPage 5 initiation requires appropriate evaluation of appropriate safety margin, will help guide fracture phenomena based on the the staff to take appropriate courses of probabilistic fracture mechanics. The actions on the issue in order to maintain mitigation of the event or the CCDP, given public health and safety. Such actions the initiation of the nozzle failure, would should include risk management in terms of require understanding of optional success prediction, prevention, control, and paths and their failure probability of the mitigation of the CRDM nozzle cracking mitigation systems as well as operator issue. From a short-term risk standpoint, actions to prevent continuous progression of compensatory measures may be prudent for the LOCA event, which would ultimately lead the high susceptibility plants.

to core damage.

RG 1.174 provides numerical guidelines for 4.3.2 Probabilistic Fracture Mechanics acceptable level of increase in core damage and Initiating Event Frequency frequency (CDF) as a result of plant adverse event, as given in Figures 3 and 4 for CDF One of the major objectives of PFM and large early release frequency (LERF) evaluation is to demonstrates that the PFM respectively. As a sample application of the model represents VHP nozzle cracking and acceptance guidelines in RG 1.174, for a failure phenomena accurately, and an medium break LOCA with 1E-3 CCDP, the appropriate analysis of the model initiating event frequency of 1E-2/yr or higher parameters in the crack initiation model is could result in an unacceptable increase in employed. However, high degree of CDF ifplants baseline CDF lies between uncertainty in the parameters for estimating 1E-5/yr and I E-4/yr. the probability of crack occurrence and size of circumferential cracks raises more The point estimates of crack initiation and questions than answers. Such uncertainty propagation risk numbers at this time would prevents the staff from concluding that the be very unreliable due to lack of knowledge probability of gross nozzle failure is and absence of verifiable inspections sufficiently small, and the resulting whether or not cracks existed and their conditional core damage probability would severity, if it did exist. In fact, additional satisfy the numerical guidance in criterion 4 information on the environment, material of the RG 1.174.

properties, residual stress and evaluation of cracking are needed as input to reliable There are more than one approache fracture mechanics models. However, some employed by both industry and NRC to risk informed insights are estimated utilizing evaluate the flaw initiation and the rate of a operating experience and probabilistic crack propagation, either using the fracture mechanics work performed by ANL. inspection findings or an appropriate PFM As noted in Section ..... circumferential crack model. Use of the verified cracks and other lengths as large as 1650 have been found in known data tends to give relatively larger one of the high susceptibility plants ....[insert flaw rates as compared with the results Jack's other comments]. The effort to based on statistical analysis employing estimate the initiating event frequency will Weibull distribution and parametric continue as additional data become available evaluation. The materials characteristics in the future. The initiating event frequency and exposure temperature and time plays a of the CRDM cracking, along with proper major role on the flaws. However, the high consideration of the defense-in-depth and degree of uncertainty leads staff to believe 5

6 .,Steven Long - tecnass.wpCI Page 6 j, 6 "t ve Lon. - t c l s.... ........ IiI iii aIIge that frequent qualified inspections could the issue discussed above, such as use of provide more realistic and accurate picture of linear or non-linear crack size distribution, the flaw initiation and distribution of the crack critical circumferential crack size for failure, sizes. initial flaw verses crack growth rate, and RCS temperature. The stress profiles may The industry and NRC appear to agree on dictate the crack growth rates, if given same the crack propagation model in general, other conditions. Failure to conduct although there are subtle differences in inspections of the reactor VHP nozzles in a details and applications. Some of such manner that is sufficient to detect the extent disagreement include the initial shape, of degradation caused by a mechanism location, size, and distribution of the cracks known to be degrading other similar plants as well as associated stress profiles, impact in that portion of- Vessel and prior to a of residual stress, and resulting crack significant reduction in safety margin could propagation. increase risk significantly as well as the associated uncertainty. Based on a The bounding study of crack growth rate licensee response submitals, Staff appears to be the analyses based on the performed a sensitivity study, and the result heat 69, the worst case for a material indicated that a good qualified inspection characteristics, using linear distribution of the may impact on the initiation frequency as initial crack sizes and a 95/50 crack growth much as five times.

curve. At present, utility supported by Industry in general chose to use 50 percentile median curve, which tends to give 4.3.3 Event Mitigation and CCDP approximately 2.5 times slow growth rate.

Staff believes that truth lies somewhere A typical success criteria to mitigate a between two but closer to heat 69 and 95 medium break LOCA is dictated by timely percentile curve. injection of cooling water to replace the RCS loss through the break, providing core Summarizing the above, staff believes that cooling and coverage. Because of the the predicted leak rates may be represented limited amount of water stored in a borated by Weibull leak initiation model with upper water storage tank and continuous need to 95% projection with1.5 Shape Factor unless remove decay heat beyond the capacity of otherwise the Shape parameters are scaled the stored water, the core cooling water or modified with appropriate justification. source has to be swapped over to a new NRC internal study by a contractor indicated makeup water source (such as sump) that it would be prudent to use 95/50 before the stored water runs out. Most likelihood projection for a crack growth rate PWR plants may have been designed to as opposed to median 50/50. Where, 95/50 perform the switchover automatically represents 95% population (data) with 50% (particularly CE design) or manually from confidence level. Again, NRC staff believes the control room. However, they often that the crack growth rate should be based requires equipment lineup and/or valve on the worst heat, heat 69, with the upper 95 opening/closure, and reset breaker percentile (95/50) bounding projection interlocks from outside of the control room.

instead of 50/50 median or 75% estimates.

For the LOCA due to the CRDM failure, the There are several unresolved issues beside major risk contributors, therefore, are 6

LSteven Long - techass.wpd Page 7 L Lon Ive I s ~Iehp IIIIIIII I IIIIIIII IInll P giinln'eII human failure(s) of switchover from core damage probability (CDP), and is injection-to-recirculation phase in timely calculated using a mean, time-averaged manner, followed by failure(s) of high and value from a long term cumulative core low pressure injection phase. damage probability, which includes both emerging and scheduled maintenance risk.

Reliability and failure rates of hardware may It may also include other factors that may not be easy to improve permanently within a influence plant configurations and relatively short time period. But the associated operational risk. In general, availability of the hardware and reduction of other than plant modifications, the on-line human errors can be minimized by reducing and emerging maintenance works, or even on-line maintenance and surveillance surveillance tests, are considered as temporary riskconutors and expressed activities with additional or dedicated operator using well written procedures. as incremental CDP (ICDP). Therefore, the temporary risk contributors are dependent According to the IPE database, the CCDPs on plant configurations and varies with time, for PWR plants are in the range of 102 to 103 and would return to a baseline risk as soon for a medium LOCA with a few outliers. The as the temporary risk contributors are CCDP values from IPE daiabase are removed.

tabulated in Tables 4.1, 4.2 and 4.3 for B&W, CE and Westinghouse designs respectively. The temporary increase of core damage probability has been addressed in the EPRI "PSA Applications Guide," August 1995, 4.3.4 Temporary Configuration Risk and which was the source reference document Shutdown Delay for the guidelines in RG 1.174 and RG 1.182, and was the driving factor under the When a plant safety-related equipment is a(4) requirements of the maintenance rule out-of-service temporarily, the plant risk 10CFR50.56. The RG 1.182, "Assessing would be increased temporarily until the and Managing Risk before Maintenance downed equipment is restored. Similarly, Activities at Nuclear Power Plants", May, when a plant with a known deficiency 2000, was intended for managing extends its operation for a short period of short-duration or transitional risk, and its time, the incremental risk by the deficiency attachment 2 provided numerical guidelines during the extended operating period may be for ICDP and ILERP for temporary risk considered as an additional temporary risk. increases.

However, one of the most difficult issue is how to deal with the degraded situation and It restricted any increase in cumulative assessment of potential or projected risk. As increase of core damage probability greater a conservative approach, it would be prudent than 106 for temporary changes, again to treat the degraded function or component using mean values. For CRDM cracking, as a failure if the degraded situation can not the cumulative core damage probability due be identified by conventional inspection to the cracks can be obtained based on the techniques and a complete failure is increase of CDF as a result of the CRDM suspected or imminent prior to scheduled cracking until the corrective actions are outage. taken and the deficiency is removed. Such increase in CCDP may be obtained by A CDF is normally based on an annualized integrating time-dependent initiating event 7

j,6teven Long - tecnass.wpo Page 8 j St ve on te n -~p "PagIIII I II IIIIeII III III III frequency from the probabilistic fracture only. They are an input to an overall picture mechanics. of the risk change although they plays an important role to put the change into an If the increase in CDF value for appropriate context in big picture, as a part CRDM-induced MLOCA by 10-5 per year, it is of the five principles discussed in section considered non-risk-significant temporary 4.2.

increase if the plant operates with the event configuration for less than 5.6 weeks since For CRDM cracking issues, there are the ICDP during this period would be less concerns related to the nature of the than 106. epistemic uncertainty, such as the confidence associated with the risk analysis Furthermore, it would be prudent to take and consideratioftf details for the certain compensatory measures to reduce a decisionmaking process. where, such plant CCDP temporarily. Some of the details may include 1). the parametric measures may include the following steps: issues in the modeling initiating events such as Poisson or PFM model, 2). the modeling

1. Reduction of the vessel temperature uncertainty associated with human by reducing RCS temperature. The performance, common cause failures, temperature reduction may slow CRDM failure phenomena, Poisson and down the crack initiation and Binomial models for running and on-demand propagation rates. failures of components, and 3).

completeness of modeling due to

2. Minimizing on-line activities to reduce unanalyzed events, and shutdown temporary risk configurations (i.e., operations as examples.

reducing on-line maintenance), and Certain specific guidelines were given in the

3. Reduction of CCDP by increasing a RG 1.174, such as use of mean risk values reliability of plant systems with or mean distribution for numerical multiple trains and by reducing assessment. Because of such specific potential human errors during plant approaches recommended in RG 1.174, it operation (i.e., training or additional can be shown that undesirable artificial operators with clearly written margin or unexpected and unqualified instructions). This step may even factors can be embedded and thus maked reduce the CCDP affecting other in the risk values. This is not consistent with accident sequences, and thus, would the intent of the RG when the numerical reduce the baseline risk). guidelines are applied to the quantitative risk values derived from a median or even higher percentile value or distribution are 4.3.5 Integrated Decision Making and used. Furthermore, certain compensatory Uncertainty measures may be taken during plant operation but not reflected in the risk model.

It is important to characterize the impact of In such cases, the numerical guidelines in uncertainty in the risk analysis, and to the RG should be qualified and the impact recognize them for the decisionmaking of such measures should be characterized process. In fact, the decision should not be qualitatively. Also, such arguments should made by the numerical values of the PRA be considered in the decisionmaking 8

j, .*eelL~f)g - 1~eC, EaS$.wpQ trage tl j EeVCfl LOfl9 - tecnd.wpo rage i process. safety concern. Specifically, the findings indicate that circumferential cracks outside One conflicting aspect of using RG 1.174 for of the J-groove welds can occur, in contrast the CRDM risk assessment process is that to an earlier conclusion that the cracks the crack growth rate was evaluated based would be predominantly axial in orientation.

on median or 75 percentile distribution by The findings indicate that cracking of the J industry, and staff recommended to use groove weld metal can precede cracking of more bounding 95%. Now, this would the base metal. These findings raise apparently introduce additional uncertainty questions regarding the industry approach, for using the threshold guideline given in the developed in generic responses to GL RG 1.174 97-01, that utilizes PWSCC susceptibility modeling based-&Mie base metal conditions and do not consider those of the

6.0 DESCRIPTION

OF BULLETIN weld metal. Further, the findings at ONS2 2001-01 and ONS3 highlight the possible existence of The discoveries of cracked and leaking Alloy a more aggressive environment in the 600 VHP nozzles at four PWRs raised CRDM housing annulus following concerns about the potential safety through-wall leakage; potentially highly implications and the prevalence of cracking concentrated borated primary water could in VHP nozzles in PWRs. Therefore, on become oxygenated in this annulus and August 3, 2001, the NRC issued NRC possibly cause increased propensity for the Bulletin 2001-01 "Circumferential Cracking of initiation of cracking and higher crack Reactor Pressure Vessel Head Penetration growth rates.

Nozzles" to all holders of operating licenses for PWRs. The purpose of the bulletin was to These occurrences reinforce the importance request information related to the structural of conducting effective examinations of the integrity of the reactor pressure vessel head RPV upper head area (e.g., visual penetration nozzles at PWR facilities. under-the-insulation examinations of the Specifically, the NRC requested information penetrations for evidence of borated water on the extent of VHP nozzle leakage and leakage, or volumetric examinations of the cracking found to date, inspections and CRDM nozzles), and using appropriate NDE repairs undertaken to satisfy applicable methods (such as PT, UT, and eddy-current regulatory requirements, and the basis for testing) to adequately characterize cracks.

concluding that their plans for future Because of plant-specific design inspections will ensure compliance with characteristics, there is no uniform way to applicable regulatory requirements. perform effective visual examinations of the RPV head at PWR facilities. However, one 6.1 Summary of Bulletin aspect of conducting effective visual examinations that is common to all PWR The recent identification of circumferential plants is the need to successfully distinguish cracking in CRDM nozzles at ONS2 and boric acid deposits originating with VHP ONS3, along with axial cracking in the J nozzle cracking from deposits that are groove welds at these two units and at ONSI attributable to other sources.

and ANO1, has resulted in the staff reassessing its conclusion in GL 97-01 that The Electric Power Research Institute cracking of VHP nozzles is not an immediate Report TP-1 001491, Part 2, "PWR Materials 9

LGtieven Long - tecnass.wpa Page 10 j Lteven Long tecnass.wpa

- Page iQi Reliability Program Interim Alloy 600 Safety model has limitations, such as large Assessments for US PWR Plants (MRP-44), uncertainties and no predictive capability, Part 2: Reactor Vessel Top Head the model does provide a starting point for Penetrations," uses an assessment of the assessing the potential for VHP nozzle relative susceptibility of each PWR to cracking in PWR plants. The following OD-initiated or weld PWSCC based on the paragraphs characterize the suggested operating time and temperature of the gradation of inspection effort for the penetrations. Based upon this simplified subpopulations of plants noted above.

model, each PWR plant was ranked by the MRP according to the operating time in For the subpopulation of plants considered EFPY required for the plant to reach an to have a low susceptibility to PWSCC, effective time-at-temperature equivalent to based upon a su-0tibility ranking of more ONS3 at the time the above-weld than 30 EFPY from the ONS3 condition, the circumferential cracks were identified in early anticipated low likelihood of PWSCC 2001. From the results of the susceptibility degradation at these facilities indicates that rankin g model, the enhanced examination beyond the current population of PWR plants can be divided into requirements is not necessary at the several subpopulations with similar present time because there is a low characteristics: likelihood that the enhanced examination would provide additional evidence of the

"* those plants which have propensity for PWSCC in VHP nozzles.

demonstrated the existence of PWSCC in their VHP nozzles For the subpopulation of plants considered (through the detection of boric acid to have a moderate susceptibility to PWSCC deposits) and for which cracking can based upon a susceptibility ranking of more be expected to recur and affect than 5 EFPY but less than 30 EFPY from additional VHPs; the ONS3 condition, an effective visual

"* those plants which can be considered examination, at a minimum, of 100% of the VHP nozzles that is capable of detecting as having a high susceptibility to and discriminating small amounts of boric PWSCC based upon a susceptibility acid deposits from VHP nozzle leaks, such ranking of less than 5 EFPYs from as were identified at ONS2 and ONS3, may the ONS3 condition; be sufficient to provide reasonable

"* those plants which can be considered confidence that PWSCC degradation would as having a moderate susceptibility to be identified prior to posing an undue risk.

PWSCC based upon a susceptibility This effective visual examination should not ranking of more than 5 EFPYs but be compromised by the presence of less than 30 EFPYs from the ONS3 insulation, existing deposits on the RPV condition; and head, or other factors that could interfere with the detection of leakage.

the balance of plants which can be considered as having low susceptibility based upon a For the subpopulation of plants considered to have a high susceptibility to PWSCC susceptibility ranking of more than 30 based upon a susceptibility ranking of less EFPYs from the ONS3 condition.

than 5 EFPY from the ONS3 condition, the Although the industry susceptibility ranking possibility of VHP nozzle cracking at one of 10

1,Stever, Long - iecnass.wpo Page 11 j Steven Long - cn.wpa Page 114 these facilities indicates the need to use a Specifications) pertain to the issue of VHP "qualified visual examination of 100% of the nozzle cracking. The general design criteria VHP nozzles. This qualified visual (GDC) for nuclear power plants (Appendix A examination should be able to reliably detect to 10 CFR Part 50), or, as appropriate, and accurately characterize leakage from similar requirements in the licensing basis cracking in VHP nozzles considering two for a reactor facility, the requirements of 10 characteristics. One characteristic is a CFR 50.55a, and the quality assurance plant-specific demonstration that any VHP criteria of Appendix B to 10 CFR Part 50 nozzle exhibiting through-wall cracking will provide the bases and requirements for provide sufficient leakage to the RPV head NRC staff assessment of the potential for surface (based on the as-built configuration and consequences of VHP nozzle cracking.

of the VHPs). Secondly, similar to the effective visual examination for moderate The applicable GDC include GDC 14, GDC susceptibility plants, the effectiveness of the 31, and GDC 32. GDC 14 specifies that the qualified visual examination should not be reactor coolant pressure boundary (RCPB) compromised by the presence of insulation, have an extremely low probability of existing deposits on the RPV head, or other abnormal leakage, of rapidly propagating factors that could interfere with the detection failure, and'of gross rupture; the presence of of leakage. Absent the use of a qualified cracked and leaking VHP nozzles is not visual examination, a qualified volumetric consistent with this GDC. GDC 31 specifies examination of 100% of the VHP nozzles that the probability of rapidly propagating (with a demonstrated capability to reliably fracture of the RCPB be minimized; the detect cracking on the OD of a VHP nozzle) presence of cracked and leaking VHP may be appropriate to provide evidence of nozzles is not consistent with this GDC.

the structural integrity of the VHP nozzles. GDC 32 specifies that components which are part of the RCPB have the capability of For the subpopulation of plants which have being periodically inspected to assess their already identified the existence of PWSCC in structural and leaktight integrity; inspection the CRDM nozzles (for example, through the practices that do not permit reliable detection of boric acid deposits), there is a detection of VHP nozzle cracking are not sufficient likelihood that the cracking of VHP consistent with this GDC.

nozzles will continue to occur as the facilities continue to operate. Therefore, a qualified NRC regulations at 10 CFR 50.55a state volumetric examination of 100% of the VHP that ASME Class 1 components (which nozzles (with a demonstrated capability to include VHP nozzles) must meet the reliably detect cracking on the OD of the VHP requirements of Section XI of the ASME nozzle) may be appropriate to provide Boiler and Pressure Vessel Code. Table evidence of the structural integrity of the VHP IWA-2500-1 of Section XI of the ASME nozzles. Code provides examination requirements for VHP nozzles and references IWB-3522 6.2 Summary of Regulatory Issues for acceptance standards. IWB-3522.1(c) and (d) specify that conditions requiring 6.2.1 Applicable Regulatory Requirements correction include the detection of leakage from insulated components and Several provisions of the NRC regulations discoloration or accumulated residues on and plant operating licenses (Technical the surfaces of components, insulation, or 11

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floor areas which may reveal evidence of of a qualified volumetric examination

-borated water leakage, with leakage defined method, for example, one that has a as "the through-wall leakage that penetrates demonstrated capability to reliably detect the pressure retaining membrane." cracking on the OD of the VHP nozzle Therefore, 10 CFR 50.55a, through its above the J-groove weld.

reference to the ASME Code, does not permit through-wall cracking of VHP nozzles. Criterion V of Appendix B to 10 CFR Part 50 states that activities affecting quality shall be For through-wall leakage identified by visual prescribed by documented instructions, examinations in accordance with the ASME procedures, or drawings, of a type Code, acceptance standards for the appropriate to the circumstances and shall identified degradation are provided in be accomplishedt'inaccordance with these IWB-3142. Specifically, supplemental instructions, procedures, or drawings.

examination (by surface or volumetric Criterion V further states that instructions, examination), corrective measures or repairs, procedures, or drawings shall include analytical evaluation, and replacement appropriate quantitative or qualitative provide methods for determining the acceptance criteria for determining that acceptability of degraded components. important activities have been satisfactorily Criterion IX of Appendix B to 10 CFR Part 50 accomplished. Visual and volumetric states that special processes, including examinations of VHP nozzles are activities nondestructive testing, shall be controlled that should be documented in accordance and accomplished by qualified personnel with these requirements.

using qualified procedures in accordance with applicable codes, standards, Criterion XVI of Appendix B to 10 CFR Part specifications, criteria, and other special 50 states that measures shall be requirements. Within the context of providing established to assure that conditions assurance of the structural integrity of VHP adverse to quality are promptly identified nozzles, special requirements for visual and corrected. For significant conditions examination would generally require the use adverse to quality, the measures taken shall of a qualified visual examination method. include root cause determination and Such a method is one that a plant-specific corrective action to preclude repetition of the analysis has demonstrated will result in adverse conditions. For cracking of VHP sufficient leakage to the RPV head surface nozzles, the root cause determination is for a through-wall crack in a VHP nozzle, and important to understanding the nature of the that the resultant leakage provides a degradation present and the required detectable deposit on the RPV head. The actions to mitigate future cracking. These analysis would have to consider, for actions could include proactive inspections example, the as-built configuration of the and repair of degraded VHP nozzles.

VHPs and the capability to reliably detect and accurately characterize the source of the Plant technical specifications pertain to the leakage, considering the presence of issue of VHP nozzle cracking insofar as insulation, preexisting deposits on the RPV they require no through-wall reactor coolant head, and other factors that could interfere system leakage.

with the detection of leakage. Similarly, special requirements for volumetric 6.2.2 Deficiencies in Current Regulations examination would generally require the use 12

L V C. L..JI - t-%s. iC.OC.

t-age 13:

The NRC regulation at 10 CFR 50.55a used (FigureIWA 3400-1).

• requires licensees to perform system

• When a flaw is detected, its projections in pressure testing, VT-2, of the reactor pressure boundary in accordance with the both the axial and circumferentialdirections shall be determined.

inservice inspection requirements of Section XI of the ASME Boiler and Pressure Vessel *Flawsthat are equal to or greaterthan Code. The examination and frequency 45-degrees from the verticalcentedine of requirements are contained in Table the CRDM nozzle, or those that are within IWB-2500-1, Category B-P and the plus or minus 10-degrees of the angle (if acceptance standards are contained in less than 45-degrees) thatthe plane of the IWB-3522. The requirements for the system partial-penetrationattachment weld pressure tests are contained in IWA-5000. (J-groove weldpmkes-with the vertical centerdine of the CRDM nozzle, are The provisions of IWA-5242 state that a VT-2 considered to be circumferentialflaws.

visual examination may be conducted *The location of the flaw relative to the top without the removal of insulation by and bottom of the J-groove weld shallbe examining the accessible and exposed determinedsince the potential exists for surfaces and joints of the insulation. development of a leak path if a flaw However, operating experience indicates the progressesup the nozzle past this weld.

need for bare metal examinations since small The flaw acceptance criteriaare as leakage can result from a large crack as specified below depending on whether the shown in the ONS3. This is an area where flaw is in the pressure boundary or in the the Code requirements are insufficient in portion of the nozzle below the J-groove identifying flaws in VHPs. weld.

The Code provisions for disposition of flaws FlawAcceptance Criteria is adequate. However, there is a lack of information about crack size and growth rate. CRDM Nozzle PressureBoundary In a letter to NEI dated September 24, 2001, the staff described methods for flaw The CRDM nozzle pressure boundary characterization, acceptance, and crack includes the J-groove weld and the portion growth rate which should provide reasonable of the nozzle projectingabove the weld.

assurance of structural and leak tight While the CRDM nozzle is an integralpart of integrity of VHPs in light of the new operating the reactorvessel, no flaw evaluation rules experience. As quoted from the letter, these exist for nonferriticvessels or parts thereof methods are described below. in Section X1. Therefore, the rules for austeniticpiping shallbe applied with the Flaw Characterization following exceptions:

• The allowable flaw standardsfor austenitic Flaws must be characterizedby both their length and depth. There is currently piping in Section Xl, I1B-3514.3 may be insufficient data available to assume an appliedfor inside diameter(ID) initiated aspect ratio if only the flaw length has been axial flaws only.

determined. *The rules of IWB-3640 shall apply and the

• The proximity rules of ASME Code Section margins maintainedafter crack growth is X1 for consideringflaws as separatemay be evaluatedfor the period of service until the next inspection. The maximum flaw depth 13

1, L Vf L-UHi - c%, IU Paoe 141 l,,,,i~~~Pac 14 ln ,

allowed by IWB-3640 is 75-percent of the Palo Alto, CA:1997. TR-109136 Snozzle thickness (referto crack growth rate (Proprietary).

below).

• All outside diameter(OD) initiatedflaws, *There is currentlyno accepted crack regardlessof orientation (axialor growth rate for the Alloy 182 J-groove weld circumferential), shall be repaired. material.

• All ID-initiated circumferentiallyoriented CRDM Nozzle Below the J-Groove Weld flaws shall be repaired.

• Any flaw detected in the J-groove weld, its *The crackgrowth rate to be used for the heat affected zone (or adjacentbase flaws in this region of the nozzle, shall be material)must be repaired. Alternatives to the same as thdto's*d for ID initiatedaxial Code requiredrepairswill be consideredfor flaws within the CRDM nozzle pressure approvalif justified. boundary.

CRDM Nozzle Below the J-Groove Weld

• Axially oriented flaws (eitherID- or OD-initiated)are acceptableregardlessof depth as long as theirupper extremity does not reach the bottom of the weld during the periodof service until the next inspection.

• Circumferentialflaws (eitherID- or OD-initiated)are acceptableprovided that crack growth is evaluated for the periodof service until the next inspection. In no case shall the projected end of cycle circumferentialflaw length exceed 75-percent of the nozzle circumference.

• Intersectingaxial and circumferentialflaws shall be removed or repairedbecause of the greaterpropensityto develop into loose parts. Note: while flaws below the J-groove weld have no structuralsignificance, loose parts must be avoided.

Crack Growth Rate CRDM Nozzle PressureBoundary

• Crackgrowth to be used for axial ID initiated flaws shall be determined from Crack Growth and MicrostructuralCharacterizationof Alloy 600 Vessel Head PenetrationMaterials,by Bamford, W H., and Foster,J. P., EPRI, 14

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,7 1 7.0 RESPONSES FROM HIGH SUSCEPTIBILITY PLANTS High susceptibility plants are those defined nozzles, with an OD of 26.2 mm (1.030 in).

as being within 5 EFPY of ONS3 or those and a wall thickness of 5.3 mm (0.208 in.).

which have previously experienced either leakage from or cracking in VHP nozzles. The Oconee units have Babcock and Wilcox Twelve plants are in this category. They (B&W) designed vessels with metal include ONS1, ONS2, ONS3, ANO1, reflective insulation that is located on a Donald C. Cook Unit 2, North Anna Units 1 horizontal plane above the head. The and 2, H. B. Robinson Unit 2, Davis Besse insulation is located such that the lowest Nuclear Power Station, Surry Units 1 and 2, clearance for inspection of the nozzles is at and Three Mile Island Unit 1. For plants the top of the head-which has an within 5 EFPY of ONS3, the bulletin approximate 51 mm (2 inch) between the requested that licensees provide information upper-most nozzles and the insulation. The on future inspections and the basis for reactor vessel head service structure was concluding that these inspections will assure modified to provide nine, 12-inch diameter that regulatory requirements are met. For access ports which permit access to the top plants which have previously experienced of the RPV head for inspection purposes.

leakage or cracking in VHP nozzles, the bulletin requested that in addition to Findings and Activities for Unit 1 information on future inspection plans, licensee describe the extent of VHP nozzle On November 25, 2000, evidence of reactor leakage and cracking and describe the coolant system (RCS) leakage was corrective actions taken in response to the identified at ONS1, as described in licensee identified cracking. The staff's evaluation of event report (LER) 269/2000-006, Revision the licensees' responses are as follows. 1, dated March 1, 2001. As summarized in the Duke response to the bulletin, CRDM 7.1 Plants That Have Identified Cracking nozzle 21 and five of the eight thermocouple nozzles were identified with leakage 7.1.1 Oconee Units 1, 2, And 3 deposits.

7.1.1.1 Summary of Licensee Response CRDM nozzle 21 had a single crack that originated in the J-groove weld and grew By letter dated August 28, 2001, Duke through the weld and nozzle base metal, Energy Corporation (the licensee) submitted penetrating into the annulus region to create the Bulletin 2001-01 response for ONS1, a leak path. The crack was completely ONS2, and ONS3. ground out of the J-groove weld and nozzle material, and the nozzle was restored to its Description of VHP Nozzles and Insulation original configuration with the shielded metal The Duke response referenced the arc welding process using Alloy 690 weld information provided in the MRP-48 report material (Alloy 152). A protective Alloy 690 regarding the VHP nozzles in the Oconee weld pad was applied to the repairs to units. All three units have 69 CRDM protect and isolate any remaining original nozzles, with an OD of 101.6 mm (4.001 in.) Alloy 600 from the reactor water and a wall thickness of 15.7 mm (0.618 in.). environment.

In addition, ONS1 has eight thermocouple 15

It C, 'ý-' V =_'i _ý'. ,,, - '"  ; Pýý WV Haoe 16 ,i Paae 16 9 For the thermocouple nozzles in ONS1, and below the J-groove weld. No ID eddy current (EC) examinations and initiated circumferential indications were ultrasonic tests (UT) showed that all eight found.

nozzles contained deep crack-like indications that were predominantly axial in UT examinations on the four leaking nozzles orientation and located adjacent to identified 36 axial OD indications, and one (extending both above and below) the circumferential OD crack above the weld on J-groove weld elevation. Repairs to the nozzle 18. The circumferential crack on thermocouple nozzles involved removing nozzle 18 had a reported length of 1.25 the nozzles from service by machining out inches and a depth of 0.07 inches.

the existing nozzles and installing Alloy 690 plugs into the remaining penetration. As Repairs of the fou'eaking nozzles were with the CRDM nozzle repair, a protective accomplished using a remote Alloy 690 weld pad was applied to the semi-automated repair method. For these repairs to protect and isolate any remaining repairs, the existing nozzle was severed at a original Alloy 600 from the reactor water location above the J-groove weld and then environment. removed from the RPV head after separation from the J-groove weld. A Metallurgical samples were taken from the semi-automated welding tool utilizing the CRDM nozzle 21 weld and from several gas tungsten arc welding (GTAW) process thermocouple nozzles to determine the was used to install a new Alloy 690 weld cause of the observed cracking. In material (Alloy 152) between the shortened additional, seven additional randomly nozzle and the inside bore of the RPV head selected nozzles were examined using eddy base material.

current (EC) testing, and a total of eighteen nozzles were also inspected using a 0° Findings and Activities for Unit 3 ultrasonic testing (UT) scan.

On February 18, 2001, a visual examination Findings and Activities for Unit 2 of the ONS3 RPV head identified boric acid deposits around nine CRDM nozzles On April 28, 2001, a visual examination of (numbers 3, 7, 11, 23, 28, 34, 50, 56, and the ONS2 RPV head identified boric acid 63), as described in LER 287/2001-001, deposits around four CRDM nozzles Revision 0, dated April 18, 2001.

(numbers 4, 6, 18, and 30), as described in LER 270/2001-002, Revision 0, dated June Penetrant test (PT) examinations of the nine 25, 2001. PT examinations of these four suspected leaking nozzles covered an area nozzle identified multiple rejectable 3 inches in diameter from the nozzle, indications on each of the four nozzles. The including the J-groove weld surface, the fillet LER concluded that the leak paths for these weld cap and part of the vessel head four nozzles was axial cracks that initiated cladding, and extended 1 inch down the near the toe of the fillet weld and outside diameter of the nozzle from the weld propagated axially along the OD interface of to nozzle interface. For all nine nozzles, the the nozzle and the weld. PT examination revealed multiple rejectable indications. Post-repair PT examinations of EC examinations of the four leaking nozzles nozzles 50 and 56 identified through-wall identified clusters of multiple axial circumferential cracks extending indications that were located both above approximately 1650 around the nozzles.

16

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---7 non-leaking nozzles:

EC examinations of the nine leaking CRDM Oconee Unit 1: EC of ID of seven nozzles and nine non-leaking CRDM nozzles (numbers 4, 8, 10,14,19, 22,47, nozzles limited UT of ID of 17 nozzles 64, and 65) indicated clusters of shall axial Oconee Unit 3: EC of ID of nine nozzles LUT type cracks located above and below the of ID of nine nozzles weld. Nozzles 50 and 56 exhibited "non-typical clusters" above the weld; these Planned Future Inspections clusters were later determined to be

'A I

4; associated with through-wall circumferential cracks extending approximately 1650 In its bulletin res.poo ethe licensee C around the nozzles. Six of the leaking indicated that it plans to replace the RPV heads of=a hr , nee units, beginning nozzles (numbers 11, 23, 28, 50, 56 and 63) with the ueling outage (RFO) had deep axial indications, and nozzles 50 for ON iFO for ONS1 and and 56 had circumferential indications below thROor ONS2. The latter the weld.

two head repl* ments will be concurrent UT examinations were performed on the with steam generator replacements at these nine leaking CRDM nozzles and the same units. As described at a public meeting on nine non-leaking CRDM nozzles examined September 7, 2001, the new head will use with EC. The nine non-leaking nozzles did Alloy 690 CRDM nozzles along with Alloy not have any crack-like axial or 152 weld metal. In addition, the design will minimize the volume of weld metal on the circumferential indications. The nine leaking nozzles and will include stress conditioning nozzles had a total of 36 axial indications, of the outer surface of the welds.

nine circumferential indication below the weld and three circumferential indications above the weld. CRDM nozzle 23 was For the RFOs prior to the head identified with two circumferential indications replacements (fall 2q1JL.0,NS3, spring 2002 for ONSI anor ONS2),

below the weld and one circumferential indication above the weld. The latter was qualified visual examinations, as described in the bulletin, will be performed for all three discovered through a third party review of the data. units. As described at a public meeting on September 7, 2001, analyses by the The leaking CRDM nozzles were repaired licensee conclude that a leakage pathway from the J-groove weld area to the outer using manual repair methods, using Alloy surface of the RPV head exists for all but 690 filler materials (Alloy 152). A protective Alloy 690 weld pad was applied to the one of the nozzles for these three units.

This single nozzle, in Unit 1, will be repairs to protect and isolate any remaining original Alloy 600 from the reactor water examined using a volumetric technique at environment. the next RFO for this unit.

If evidence of leakage is found, the licensee Additional Inspections in Response to Identified Leakage committed to perform additional examinations, including PT, EC and UT, on As described above, the following additional the leaking CRDM nozzles to characterize examinations were performed on the nature and extent of cracking. The 17

k*Steven Long - techass.wpdl Page 18 !

Itevenlll Ion- IIlas "p Il PageI lI' licensee indicated that additional of the nozzle and subsequent CRDM inspections of other nozzles will be based ejection, leading to core damage. The on the nature of the observed cracking, the licensee employed following assumptions extent and severity of the cracking, the and methods:

occupational exposure rates, the availability of NDE equipment and a trained and a. Based on the flaws identifiedd by qualified workforce. inspection at three Oconee units and ANO-1, the licensee assumed that the flaws were initiated over tha last Basis for Compliance with Regulatory two operating cycles ( 18 month Requirements cycle). WdtbA5-.Jeakers at 4 plants during past 12 reactor years (1.5 The licensee concludes that volumetric year per cycle and two cycles for 4 examinations by December 31, 2001, of its units), the leak rate of 1.25 per units are not necessary to provide reactor year was estimated for the assurance that the Oconee units will not crack initiation. Once, OD is wetted, experience significant leakage, rapidly 100% of the OD cracks are assumed propagating failure or gross rupture. This with zero-time-initiation.

conclusion is based on the extensive efforts undertaken by the licensee on all three units b. The probability of OD flaw-to-CRDM within the last 12 months, the technical failure in one cycle was considered evaluations and other activities conducted to with a probability of 1.3x1 0-2. Same characterize and understand the situation at probability number is also used for Oconee. The licensee includes an the second cycle.

Oconee-specific risk assessment, described above, to buttress its conclusion that c. The probability of 6% not detecting volumetric examination by December 31, an existing leak due to human error 2001, is not necessary. was included. Again, 6% failure rate is used for inspection efficiency and this was an area which NRC staff Risk Assessment was not prepared to give credits to previous refueling outage In response to Bulletin 2001-01 and to inspections.

supplement deterministic analysis of CRDM nozzle for three Oconee units, the risk d. The flaw-to-CRDM failure was analysis was performed to evaluate the calculated based on a Monte Carlo plant risk for continuous operation with simulation of the fracture mechanics potentially undetected CRDM nozzle cracks and one failure per 80,000 Monte during the period prior to vessel head Carlo simulation is used (1 .3x10-2).

replacement. The plant-specific risk In the crack propagation, initial flaw assessment was performed based on the size from 0 to 180 degrees in linear risk assessment completed by distribution was assumed, and crack Framatome-ANP for the B&W Owner's growth was simulated using Peter group. The analysis considered that the Scott model, which is a function of limiting event due to the CRDM cracking stress intensity and temperature.

would be a medium size LOCA upon failure 18

11,Steven Long - tecflass.wpd

e. The CCDP for MLOCA is 3.5x10-3, threshold CDF guideline in RG 1.174.

based on Oconee PRA, Revision 2, Furthermore, the RG 1.174 guidelines and December 1996. The initiating event threshold numbers were provided based on frequency of MLOCA due to CRDM the mean values, and the acceptance failure is 1.73xl 0-6 per reactor year. guidelines may be higher if 95% values were used. Staff concluded that the risk

f. The CDF contribution due to CRDM assessment result provided ample margin.

failure-induced MLOCA is 6.0x10-8 per reactor year, well below the 7.1.2 Arkansas Nuclear One Unit 1 threshold value of 1.0x10- per reactor year in RG 1.174. 7.1.2.1 Summary-.fjLicensee Response

g. The conditional population dose By letter dated September 4, 2001, Entergy (CPD) with a medium size LOCA Operations, Inc. (the licensee) submitted the would be relatively small since the Bulletin 2001-01 response for Arkansas MLOCA may not challenge the Nuclear One Unit 1 (ANO1).

containment performance. Thus, the CPD value of 1.1x1-04 Description of VHP Nozzles, Insulation, and person-rem is used with a resulting Configuration public health risk of 6.6x104 person-rem per year. AN01 has 69 reactor vessel head penetrations containing 68 CRDMs and one reactor vessel level instrument which is the 7.1.1.2 Staff Assessment center nozzle. ANOl is a Babcock and Wilcox (B&W) designed vessel with metal

[Additional input from Allen] reflective insulation that is located on a horizontal plane above the head. The The probability of CRDM crack-to-failure lowest clearance for inspection of the propagation appears to be too optimistic. nozzles is at the top of the head, which has However, the assumption employed for an approximate 2-inch space between the initial crack size distribution is conservative. upper-most nozzles and the insulation. The An independent analysis by a NRC reactor vessel head service structure contractor indicated that median value for support contains more than 20 opening the crack growth rate may not represent the which allow inspection in the base of the actual rate, considering number and sizes of skirt around the vessel head.

crack observed in many plants, and a use of 95% value would be more prudent and Detection and Repair of Leaking CRDM bounding approach.

In licensee event report (LER)

Based on the worst heat (heat 69) with the 50-313/2001-002-00 dated May 8, 2001, the 95 percentile crack growth rate curve, the licensee described their actions associated initiating event frequency of the MLOCA with discovery of pressure boundary would be almost two order of magnitude leakage. During the Spring 2001 refueling lager than the value reported by the outage, the licensee saw evidence of boric licensee. However, even if the 95% value is acid leakage around CRDM nozzle number used the CDF increase due to the CRDM 56 during a visual inspection. After this failure-induced-MLOCA would meet the initial inspection, and with the reactor vessel 19

. ,.5- ..... Pane 20

[r Lv= ,,"L-01,V -, . . . .. r,' I ....

- ,I head still on, the licensee expanded the unnecessary. The basis for this conclusion visual examination to all CRDM nozzles was bounding fracture mechanics and flaw using remote video equipment No other growth evaluations which showed that leakage was observed during this expanded adequate safety margin exists to ensure that inspection. Penetrant examinations (PT) no adverse structural concern would exist were performed on the Alloy 600 J-groove between refueling outages assuming significant initial flaws.

weld-to-nozzle number 56 from beneath the reactor vessel head. The PT examinations found a crack on the outer diameter of the Planned Future Inspections nozzle beneath the weld (below the reactor The licensee committed to perform a coolant pressure boundary) on the downhill qualified visual examination of essentially side. The crack contained a circumferential segment at a location 0.4 inches from the 100% of the outer Pg*,Wsurface of the CRDMs during th utage. The weld fusion line, then the crack curved into evelop the axial direction. The PT examinations did licensee also commi e to not detect any indications on the inside contingency plans for volumetric surface of the nozzle. examination ifnecessary. With regard to long term management of primary water An ultrasonic (UT) examination confirmed stress corrosion cracking (PWSCC), the that there was a leak path at CRDM number licensee has an effort in progress to develop 56 that extended from an OD crack that a mitigation technique that would apply a propagated partially through-wall past the weld overlay of corrosion resistant material to the wetted surface of the CRDM nozzle weld to the nozzle annulus. The licensee performed an embedded flaw weld repair and J-groove weld using remote automated where the circumferential portion of the flaw tooling. The licensee noted that the was removed by severing the nozzle just technique, once developed, could be above its circumferential extent The axial applied as a repair or preventative action for portion was removed in the J-groove weld cracking of CRDM penetrations. Although not a commitment, t io begin using and on the OD of the nozzle by grinding. in th utage.

the technique The excavated cavity was built back up using an Alloy 690 compatible weld material. Ifevidence of leakage is found, the licensee committed to perform additional Additional Inspections in Response to examinations on the leaking CRDM nozzles Identified Leakage to characterize the nature and extent of cracking. The licensee did not identify what Framatome ANP performed an automated the scope of expansion would be for UT and ET examination oTM'CRDM inspection of additional CRDM nozzles.

nozzle after completing repair of the Risk-Assessment J-groove weld. The results confirmed that the remaining embedded flaw was The licensee stated that a probabilistic unaffected by further welding activities. The fracture mechanics evaluation is in Rrogress licensee evaluated the need to perform additional inspections on other CRDM by the EPRI MRP that will provide an nozzles during the Spring 2001 outage, and estimate of the likelihood of a pipe rupture in concluded that additional examinations were the CRDM penetrations.

20

tecnass.wpo tong - tecnass.wpa rage i II

. Esteven teven Long - Page 211n no structurally significant flaws were left in Basis for Compliance with Regulatory service, and the qualified visual inspection Requirements may be performed at the next scheduled refueling outage (Spring 2002).

The licensee concluded that the integrated industry approach to inspection, monitoring, 7.1.3 Donald C. Cook Unit 2 cause determination, and resolution of the identified CRDM nozzle cracking are clearly 7.1.3.1 Summary of Licensee Response in compliance with regulatory requirements.

By letter dated September 4, 2001, Indiana 7.1.2.2 Staff Assessment Michigan Power Company (the licensee) submitted the Bulletin 2001-01 response for The staff reviewed the AN01 Bulletin Donald C. Cook Units 1 and 2 (D.C. Cook 2001-01 response, and had the following Units I and 2).

specific comments. With regard to identification of further leakage, it should be Description of VHP Nozzles, Insulation, and noted that new flaw acceptance criteria Configuration have been developed by the NRC which will be forwarded to the industry to facilitate D.C. Cook Unit 2 has 79 reactor vessel dissemination of the information. In head penetrations containing 73 CRDM addition, the NRC concludes that all CRDMs nozzles, 5 thermocouple nozzle, and one should be volumetrically examined upon head vent nozzle. D.C. Cook Unit 2 is a discovery of additional leakage. Since Westinghouse designed vessel with metal leakage has been previously identified at reflective insulation. The seismic support ANOI, the licensee may be subject to structure provides lateral stability for the enforcement action if further leakage is CRDM housings as well as access for the identified. The basis for this approach is interconnecting cables, and is anchored to that further leakage may suggest the refueling cavity wall.

inadequate corrective action.

The licensee included a discussion on risk Detection and Repair of CRDM assessment, and stated that the NRC's assumption of an initiating event frequency D.C. Cook Unit 2 was in an extended of I for a rupture of a CRDM penetration is outage from September 1997 to June 2000 extremely conservative. The initiating event which limited the amount of EFPY of frequency of 1.0. may have been used by operation. The licensee has not detected the staff as part of sensitivity calculations to leakage from the vessel head penetrations.

evaluate the CCDP given a CRDM However, during the Fall 1994 refueling penetration rupture, but is nor6 nsidered a outage, an EC examination performed on 71 staff assumption. The staff acknowledges of the 78 vessel head penetrations showed that the risk assessment is not complete, indications in CRDM nozzle number 75.

but is in progress by the EPRI MRP. Three, closely spaced axial indications were The staff concluded that the proposed found. The upper extent of one indication method and timing of inspection are was near the acceptable. The staff is satisfied that the J-groove weld, but the flaw was primarily licensee's inspections during the Spring below the weld. A UT examination 2001 outage were sufficient to ensure that confirmed the largest indication, however 21

R IRM wage '

'(Steven Lona - tecnass.wDa aeLj the two smaller indications did not show up no surface indications open to the primary separately because they were too shallow water environment. All detected flaws will

(< 1mm) or because of their proximity to the be evaluated for acceptability using the larger indication. The licensee completed a criteria contained in the vendor's flaw data flaw evaluation which provided the handbook which the licensee stated was justification for continued operation. The under development. The handbook will CRDM nozzle was repaired by embedding contain predetermined evaluations for flaws the flaw using an alternate repair method dependent on size, location, and orientation which the NRC approved by letter dated that will permit determination of the way the April 9, 1996. The technique partially flaw may be dispositioned. The licensee removed the flaw and a weld overlay was also stated that the scope of enhanced applied. examinations beyond the next (Fall 2001) inspection has not been determined.

Additional Inspections in Response to Identified Flaw Basis for Compliance with Regulatory Requirements During the 1996 refueling outage, the five outer vessel head penetrations, including The licensee concluded that the provisions CRDM nozzle number 75, were described in the response to the Bulletin re-inspected using the same EC provide reasonable assurance that the examination technique used in 1994. vessel head penetration reactor coolant re-inspection of CRDM nozzle number 75 pressure boundary is not breached, and will showed no significant flaw growth, and no assure that the applicable regulatory additional indications were identified in the requirements are met.

other four outer penetrations. As mentioned above, CRDM nozzle number 75 was Risk Assessment subsequently repaired after the re-inspection. D.C.Cook has developed an initiation scenario of the CRDM crack-induced LOCA Planned Future Inspections event based on industry experience, coupled with the engineering judgement.

The licensee committed to perform a remote The correlation between industry visual examination of all accessible vessel experience, engineering judgement, and head penetrations under the reactor vessel risk quantification was not clearly explained head insulation during the next refueling in the response. The results are as outage in Fall 2001. In addition, the following:

licensee committed to perfom EC examination of the vessel head penetration a. The cumulative probability of first base material near the susceptible weld leak was estimated as a function of area and the J-groove welds. Any relevant the operating time, EFPY, based on indications will be investigated using a UT statistical analysis of industry data.

technique to size and characterize their The cumulative probability was depth, length, and orientation. The licensee converted into yearly leak frequency will re-examine the embedded flaw in by taking the slope of the CRDM nozzle number 75 using a liquid probability-versus-time relationship penetrant technique to verify that there are (the equation presented in the 22

recnass.wpa rage p*,steven tong - tecnass.wpa teven *Long - P'age 223 1 attachment 1 of the Bulletin would clearly met 1.0x10-6 ICDP, the resopnse for the frequency increase of CDP for the operating calculation has an error in the duration until January 19, 2002, as denominator by omitting time recommended in the RG 1.182 increments). The initial under the maintenance rule for through-the-wall leak rate frequency temporary risk increase.

of 1.07 xl 0-5 per reactor year is reported.

7.1.3.2 Staff Assessment

b. After the first leak as defined as axial through-the-wall crack, the crack The staff reviewed the D.C. Cook Unit 2 would propagate circumferentially Bulletin 2001-01 response, and had the and to the opening sizes which following specific comments. With regard to would lead to leak, SLOCA, and identification of further leakage, it should be MLOCA, and may lead to core noted that new flaw acceptance criteria damage. Licensee employed scott have been developed by the NRC which will crack growth model to evaluate the be forwarded to the industry to facilitate crack propagation, and median dissemination of the information. The distribution was presented as vendor's flaw data handbook that is opposed to NRC's 95/50 percentile currently under development should have values. However, in its risk criteria that are at least as conservative as assessmen the licensee presented the NRC staff's newly developed flaw risk model based on engineering acceptance criteria. In addition, the NRC judgement, which assumed that concludes that all CRDMs should be each paths leading to leak, SLOCA volumetrically examined upon discovery of and MLOCA would occur 90%, 8% additional leakage or degraded vessel head and 2% respectively. That would penetrations. Since a flaw was previously give the initiating event frequency of identified at D.C. Cook Unit 2, the licensee leak, SLOCA and MLOCA as may be subject to enforcement action if 9.63x10-3, 8.56xl 0-4 and 2.14x10" further cracking of vessel head penetrations per reactor year with corresponding and/or leakage is identified. The basis for CCDP values of 3.31x10 -,5 3.31x1O0 this approach is that further cracking and and 4.52x1 0- respectively. The leakage may suggest inadequate corrective corresponding CDF contribution by action.

the leak, SLOCA and MLOCA will be 3.19xl 0 7 , 2.83xl 0-, and 3.87xl 01 The staff concluded that the proposed per reactor year. This value would method and timing of inspection are be well within the a5;etable CDF acceptable. The staff is satisfied that the increase under the RG 1.174, licensee's proposed EC and UT techniques although no clear explanation of the will be effective in identifying and assigned split fractions for each characterizing any flaws in the vessel head event sequence was identified. penetrations, and the qualified visual inspection may be performed at the next

c. To extend the plant operation for 19 scheduled refueling outage (Fall 2001).

days from December 31, 2001 to January 19, 2002, the incremental Staff also believe that the methodology CDP was given as 2.16xl 0-7, which employed for the risk assessment was not 23

Long - tecIIass.wpI SSteven P'age 2241 raI e III" conservative. The initial leak frequency for 7.2 Plants That Have Not Identified "i"th point given in the equation of the Cracking but Are Within 5 EFPYs of attachment I is not only wrong for omitting ONS3 time interval in the denominator but also is not conservative for using points "i"and 7.2.1 North Anna Unit I and Surry Unit 1 "i-I", instead of points "i" and "i+1". This would amount to 4% smaller result. 7.2.1.1 Summary of Licensee Response Second concern was an engineering By letter dated August 31, 2001, Virginia judgement of assigning probability of 90%, Electric and Power Company (the licensee) 8% and 2% for the Leak, SLOCA and submitted the Bulletin 2001-01 response for MLOCA respectively as the initial crack North Anna Units I and 2 and Surry Units 1 would propagate further. No basis or and 2. Prior to the Bulletin response, the rationale of assigning the probability of each licensee met with the NRC staff on August path from initial leak to core damage was 2, 2001 to discuss contingency plans for the explained. It appears that the probability repair of circumferential cracking of reactor numbers were arbitrarily assigned. For vessel head penetration nozzles if such example, for a small LOCA, the vessel head cracking is found during inspections at North opening created by the failure of the CRDM Anna and Surry. A meeting summary nozzle has to be either partially blocked by dated August 7, 2001 was issued with a debris or the CRDM is partially ejected and non-proprietary version of the meeting somehow stuck-tilted in the vessel presentation materials. The NRC staff penetration leaving a hole equivalent to 2" informed the licensee that two requests for diameter or smaller. It would be more likely relief from American Society of Mechanical that once the CRDM fails and the CRDM Engineers (ASME) Code requirements nozzle is separated from the vessel head, would be necessary to implement these the vessel opening would be equivalent to repair techniques. The first relief would the ID of the nozzle (2.75" ID) as minimum, allow the use of technical criteria from a or even the OD (4") assuming a clean later version of the ASME Code to support ejection of the CRDM. In fact, it would be an embedded flaw repair process, and the prudent to assume that once the CRDM second relief would allow the use of Code nozzle failed it would be ejected out of the Case N-638 for an ambient temper bead vessel penetration. In addition, staff did not weld repair technique. The relief requests see any clear connection between the were submitted to the NRC staff, and are facture mechanics of Scott crack growth currently under expedited review. The staff rate and the engineering judgement conducted two conference calls with the employed for the risk assessment. licensee on September 14 and 21, 2001 to discuss their inspection plans and results for However, considering all of the ambiguity North Anna Unit 1.

and uncertainty in the methodology, the initiating event frequency for LOCA is same Description of VHP Nozzles, Insulation, and order of magnitude compared with the NRC Configuration crack growth estimates, and the risk numbers appear to be within the bound of North Anna Unit I and Surry Unit I each the acceptable guidelines in RG 1.174. have 66 reactor vessel head penetrations containing 65 CRDM nozzles and one head 24

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Page 25 1 vent nozzle. North Anna Unit I and Surry licensee stated that they will use EC on the Unit I are Westinghouse designed vessels inside diameter of the CRDM nozzles as with stepped reflective stainless steel well as the corresponding full J-groove insulation. The service structure (also welds from under the reactor vessel head called the reactor vessel lifting rig) bolts for North Anna Unit I (contingent on timing directly to the upper head of the reactor of qualification). If the technique could not vessel. A work platform on top of the be qualified in time for the North Anna Unit I service structure provides access to the inspection in Fall 2001, the licensee planned upper CRDM housings. to use the EC technique at Surry Unit 1.

The licensee also stated that UT will be performed if any EC indications are found.

Previous Vessel Head Penetration In the Bulletin response, the licensee Inspections committed to perform an effective visual inspection of each of the CRD housings and The Bulletin requested a description of the the reactor head vent where they penetrate VHP nozzle and reactor pressure vessel the top of the reactor vessel head for North (RPV) inspections that have been Anna Unit I and Surry Unit 1 during the Fall performed in the past four years, and the 2001 outages. During a conference call on findings. During the Spring 2000 outage, September 14, 2001, the staff reiterated the the licensee completed visual inspections of Bulletin's recommendation for a qualified North Anna Unit 1 and Surry Unit 1 in visual inspection for high-susceptibility accordance with Generic Letter 88-05, plants. During a conference call on "Boric Acid Corrosion of Carbon Steel September 21, 2001, the licensee informed Reactor Pressure Boundary Components in the staff of their intention to qualify the visual PWR Plants." The inspections were inspections for North Anna Units I and 2 performed with the insulation on the head. and Surry Units 1 and 2. The licensee also No evidence of leakage was detected. stated that they do not plan to do EC Westinghouse performed what the licensee examinations on 100% of the CRDM characterized as a "best effort" under the nozzles in North Anna Unit I or Surry Unit I head non-destructive examination since they plan to qualify the visual inspection at North Anna Unit I in February inspection with a plant specific analysis. In 1996 examining the two outermost rows of their Bulletin response, the licensee the CRDMs. The inner diameter (ID) of 20 committed to develop contingency plans for of 65 CRDM nozzles was characterized by volumetric examination if necessary.

eddy current (EC). No reportable indications were found, however, the Planned Additional Inspections if Leakage is thermal sleeves in some penetrations Detected interfered with the EC blade l~robe limiting the extent of the examination in those If leakage is detected, the licensee stated cases. The EC technique was only qualified that it is their intention to perform to characterize axial ID cracks. supplemental inspections from under the head using EC and UT procedures to locate Planned Future Inspections the source of leakage and to characterize any flaws that are found. The licensee also During the August 2, 2001 meeting on the stated that expansion of the EC and UT proposed weld repair technique, the inspections would be based on statistical 25

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,Steven Lono - tecflass wnd I determination of a relevant sample size, and Visual inspections were conducted during any additional unacceptable indications previous refueling outages in October 1997 would likely result in inspection of all of the and October 1999. In each case, a VT-3 housings on the reactor vessel head. inspection was performed of the reactor vessel head under the insulation. No Basis for Compliance with Regulatory evidence of leakage from the CRD and Requirements thermocouple nozzles was found. In addition, a VT-2 inspection was also The licensee concluded that the integrated conducted during each outage. Again, no industry approach to inspection, monitoring, evidence of leakage was detected.

cause determination, and resolution of the identified CRDM nozzle cracking are clearly Planned Future Inspections in compliance with regulatory requirements.

Each refueling outage TMI Unit 1 will perform a qualified bare metal visual VT-3 7.2.1.2 Staff Assessment inspection of all VHP nozzles. These inspections will be performed by certified

[Additional information will be provided ASME Level III inspectors trained in by Andrea] accordance with the EPRI Visual Training Package and specifically trained on VHP 7.2.2 Three Mile Island Unit 1 nozzle leakage experience from Oconee and ANO.

7.2.2.1 Summary of Licensee Response The TMI Unit 1 reactor head will be cleaned Exelon/AmerGen submitted it's response to to remove existing deposits and videotaped Bulletin 2001-01 for the Three Mile Island, prior to unit restart.

Unit I (TMI Unit 1) in a letter dated August 31, 2000. TMI Unit I is considered to be a For any VHP nozzle that is identified and high susceptibility plant, which is 4.1 EFPY suspected of leaking, a volumetric from that of ONS3. examination (using best available technology) will be performed for flaw Description of VHP Nozzles, Insulation, and confirmation and characterization. If the Configuration characterizations indicate circumferential cracking above the J-groove weld, TMI Unit The TMI Unit I reactor vessel head has 69 1 will perform additional volumetric CRDM nozzles and 8 thermocouple examinations of other readily available nozzles. It is a B&W designed head with CRDMs (the CRDMs that are removed from reflective horizontal insLatii- The the reactor vessel head to facilitate affected minimum clearance between the bottom of nozzle repair).

the insulation and the dome of the reactor vessel head surface is approximately 2 Basis for Compliance with Regulatory inches. TMI Unit I has eight 12 inch Requirements diameter access ports in the service structure. The licensee concluded that the integrated industry approach to inspection, monitoring, Previous Inspections cause determination, and resolution of the identified CRDM nozzle cracking are clearly 26

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" i .......... . . * . . Pag SfvnIohassA&pd................ Pag&27 in compliance with regulatory requirements. 7.2.3.1 Summary of Licensee Response 7.2.2.2 Staff Assessment The Carolina Power and Light company responded to Bulletin 2001 -01 for the H.B.

The staff reviewed the TMI Unit 1 Bulletin Robinson Steam Electric Plant, Unit No. 2 in 2001-01 response, and had the following a letter dated 4 September 2001. This plant specific comments. TMI Unit I does not is within 5 EFPY of ONS3.

have an interference fit for the CRDM nozzles, so the visual inspections will Description of VHP Nozzles, Insulation, and automatically be qualified (i.e. the as built Configuration clearances between the CRDM nozzles and the reactor head penetrations would allow a The HBRSEP Unit 2 RPV head has 69 leakage path). With regard to evaluation of CRDM penetrations. It is a Westinghouse identified flaws, it should be noted that new design that was fabricated by Combustion flaw acceptance criteria have been Engineering. The insulation on the head is developed by the NRC which will be "blanket Contoured." This insulation was forwarded to the industry to facilitate installed during the May 2001 outage, dissemination of the information. In replacing the older metallic thermal addition, the NRC concludes that all CRDMs insulation. The new insulation lies on the should be volumetrically examined upon reactor head and is installed in two layers, discovery of any leakage. with the blankets traversing the head between the VHPs.

The licensee refers to the "EPRI Visual Training Package," the staff is not familiar Previous Inspections with this package and is not sure if it is specifically designed for CRDMs. VT-2 visual inspection was conducted during the last three outages which took During the licensee's response it is stated place in 1998, 1999 and 2001. For the that "MRP 2001-050 indicates that the April, 2001 visual inspection, the inspectors Oconee nozzles would have taken more were briefed and viewed videotapes of the than 4-5 EFPY to reach the structural previous experiences at Oconee with margin. TMI Unit I is approximately 4 regards to VHP leakage. After the bare EFPY from reaching the Oconee Unit 3 metal examination, it was concluded that no time-at-temperature when the cracks were upward boron leakage pattern existed as detected. Therefore, TMI Unit I is not seen within the ONS3 videotape.

expected to have any structurally significant flaws." The licensee mis-interpreted the Planned Future Inspections meaning of the EPRI susceptibility ranking.

The ranking is not meant to be predictive of The next rea .orvessel he inspection is the extent of flaws. It is a simplistic model scheduled f1A qualified meant to rank a unit's time-at-temperature bare metal visu7 Bn will be relative to the time Oconee Unit 3 found performed. The previous inspection in 2001 cracks. will be used as a baseline for the future inspection. Should modeling and analysis 7.2.3 H. B. Robinson Unit 2 not be able to qualify the visual exam, a supplemental response will be provided to 27

L Q4,n I rnn - tErbQQ Aiflf1 Pag6e 281 I' - '*-

the NRC. Plans for future reactor vessel staff) it impossible for the licensee to head inspections may be modified to demonstrate qualification of the plant's last incorporate "lessons learned" from other visual examination and any future visual utilities and to assure that proposed examinations. In addition the licensee was inspection techniques will produce accurate not able to provide sufficient clarification of and reliable results. their previous inspection to demonstrate that the visual examination performed would Should future visual examinations identify have been effective in detecting boric acid deposits at the CRDM nozzles.

VHP nozzle leakage, appropriate actions will be taken in accordance with plant procedures ans ASME Code requirements The response is also vague with regard to to characterize the associated cracks or the scope of future examinations in the case of leakage being detected during the flaws. Inspection of additional VHPs using qualified visual examination.

appropriate NDE techniques would be performed in order to establish the extent of condition. 7.2.4 Davis-Besse Nuclear Power Station Basis for Compliance with Regulatory Requirements 7.2.4.1 Summary of Licensee Response Carolina Power and Light concluded that the By letter dated September 4, 2001, the integrated industry approach to inspection, FirstEnergy Nuclear Operating Company monitoring, cause determination, and (the licensee) submitted the Bulletin resolution of the identified CRDM nozzle 2001-01 response for the Davis-Besse cracking are clearly in compliance with Nuclear Power Station (DBNPS).

regulatory requirements.

7.2.3.2 Staff Assessment Description of VHP Nozzles and Insulation DBNPS has 69 CRDM nozzles, of which 61 Bulletin 2001-01 states that a qualified are used for CRDMs, 7 are spares, and one visual examination of 100% of the VHP is used for the RPV head vent piping. Each nozzles needs to be performed for plants within 5 EFPY of ONS3. This qualification CRDM nozzle has an outside diameter (OD) of 101.6 mm (4.001 in.) and a wall thickness needs to be plant specific, based upon the of 15.7 mm (0.618 in.).

as built configuration of the VHPs. If a qualified visual examination can not be DBNPS has a B&W-designed RPV with performed, a qualified volumetric metal reflective insulation that is located on examination of 100% of the VHP nozzles a horizontal plane above the head. The may be appropriate. During 2 conference insulation is located such that the lowest calls in September, 2001, the licensee clearance for inspection of the nozzles is at stated that they do not have as-built the top of the head, which has an dimensions of their vessel head approximate 51 mm (2 inch) between the penetrations, rendering (in the opinion of the 28

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7 upper-most nozzles and the insulation. The reactor vessel head service structure has 18 "mouse holes" or 'Weep holes" located around its circumference that permit access to the top of the RPV head for inspection purposes.

Past Examinations of the VHP Nozzles DBNPS RPV head. The CRDM nozzles were designed wi-thadiametral interference DBNPS has performed two inspections of the of 0.025 mm + 0.013 mm (0.001 in. t 0.0005 VHP nozzles within the last four years. The in.), with individual CRDM nozzle shafts last inspection was in April 2000 at RFO 12. custom ground to a diameter 0.025 mm Visual examination of the RPV heads near (0.001 in.) greater than the final CRDM bore the CRDM nozzles indicated some diameter. From measurements of the nozzle accumulation of boric acid deposits. These and penetration diameters, the interference deposits were positively attributed to five fits for DBNPS range from a maximum of leaking CRDM flanges. No visible evidence 0.053 mm (0.0021 in.) to a gap of 0.025 mm (0.001 in.).

of nozzle leakage was detected. For future reference, video documentation of the head condition was made after the head was From analyses performed by B&WOG and cleaned with demineralized water. cited by the licensee, a nominal interference fit of 0.025 mm (0.001 in.) opens to a gap of 0.084 mm (0.0033 in.) when considering temperature and pressure dilation of the RPV Future Plans for VHP Nozzle Examinations head at operating conditions. Therefore, the licensee concludes that a leakage path of The licensee indicated plans to perform a gap of less than 0.084 mm (0.0033 in.) will qualified visual examination of the RPV head occur at operating conditions for DBNPS, during the next RFO, scheduled for April effectively qualifying the DBNPS RPV head 2002. This examination will use the basic for a qualified visual examination.

requirements of ASME Vr-2 inspection.

Because of significant efforts being Basis for Compliance with Regulatory Requirements undertaken by the MRP and the nuclear industry to better understand VHP nozzle cracking and to develop optimized inspection The licensee's bulletin response includes a methods, mitigation and repair techniques, variety of bases for concluding that the the licensee proposed to provide a final applicable regulatory requirements will response to Bulletin Request 3.a by January continue to be met until the licensee 29, 2001, 60 days before the start of the next performs inspections at DBNPS in April RFO for DBNPS. 2002. The bases for the various regulatory requirements include:

The bulletin response provided a rationale for

• The operating time before DBNPS the qualification of visual examination for the 29

, Steven Long - tecnass.wpo Page 30 ji I1eenLil9- ecas~wa a- 30 would reach an equivalent recommended degradation time as ONS-3 is at least in the RGs 3.1 EFPY. 1.174 and Flaw growth calculations by 1.182, which Framatome-ANP in April 2001 were based on indicate that a through-wall flaw 1800 mean values. If around the nozzle would take a bounding approximately 4 years to grow analysis another 25% (e.g., 900) around the employed 95%

circumference. growth rate as Failure of a single CRDM nozzle is recommended bounded by both the LOCA and by NRC non-LOCA plant analyses, and contractor and simultaneous multiple CRDM nozzles the above three will not fail [sic). inspections DBNPS Emergency Operating were not Procedures provide adequate accepted, the directions to mitigate any transient risk numbers that would occur should there be a would fall above failure of a CRDM nozzle. the threshold acceptable range of the Risk Assessment RGs. In fairness, the In its response to Bulletin 2001-01, Davis threshold values Besse evaluated the risk contribution of the in the Rgs CRDM failure and subsequent MLOCA. The should be also onset of the cracks was evaluated based on adjusted to 95%

Weibull distribution of leak initiation model, percentile, in and further propagation of the cracks with order to use the modified Peter Scott metod and Heat 69 risk numbers crack growth rate. The median values were other than mean used for numerical values of the risk values.

contribution. However, the licensee claimed in its original response partial credits on With partial inspections conducted in 1996(RFO 10), credits to RFO 1998 (RFO 11) and 2000 (RFO 12). An 10 inspection independent sensitivity study by NRC staff and using the indicated that each inspection credit taken by bounding the licensee resulted in almost 80% analysis on reduction in the CDF. crack growth, the CDF However, without giving any credits to increase due to previous three inspections, the CDF the CRDM contribution with median crack growth rate failure may lie would be close to the threshold values somewhere 30

Pagii'_3ýi'i St~~nLon -tecriass~wod Pe between the above two values, median and technique. The relief requests were 95%. Again, if the uncertainty and ambiguity submitted to the NRC staff, and are currently of using mean values in the RGs are under expedited review. The staff conducted incorporated into the threshold values of the two conference calls with the licensee on RG guidelines, the CDF increase would be a September 14 and 21, 2001 to discuss their borderline value to be acceptable for inspection plans and results for North Anna continuous operation. Other hand, extension Unit 1.

of the operation for additional one and a half month (approximately one tenth of a reactor Description of VHP Nozzles, Insulation, and year) may not be critical nor unacceptable. Configuration Furthermore, the incremental CDP in this case would be one tenth of the CDF increase North Anna Unit 2 and Surry Unit 2 each during this period, and again, some partial have 66 reactor vessel head penetrations credits to previous partial inspections ought containing 65 CRDM nozzles and one head to be considered, particularly the RFO 10 vent nozzle. North Anna Unit 2 and Surry inspection. Unit 2 are Westinghouse designed vessels with stepped reflective stainless steel insulation. The service structure (also called 7.2.5 North Anna Unit 2 and Surry Unit 2 the reactor vessel lifting rig) bolts directly to the upper head of the reactor vessel. A work 7.2.5.1 Summary of Licensee Response platform on top of the service structure provides access to the upper CRDM housings.

By letter dated August 31, 2001, Virginia Electric and Power Company (the licensee) submitted the Bulletin 2001-01 response for Previous Vessel Head Penetration North Anna Units 1 and 2 and Surry Units I Inspections and 2. Prior to the Bulletin response, the licensee met with the NRC staff on August 2, The Bulletin requested a description of the 2001 to discuss contingency plans for the VHP nozzle and reactor pressure vessel repair of circumferential cracking of reactor (RPV) inspections that have been performed vessel head penetration nozzles ifsuch in the past four years, and the findings.

cracking is found during inspections at North During the Spring 2001, and the Fall 2000 Anna and Surry. A meeting summary dated outages, the licensee completed visual August 7, 2001 was issued with a inspections of North Anna Unit 2 and Surry non-proprietary version of the meeting Unit 2, respectively in accordance with presentation materials. The NRC staff Generic Letter 88-05, "Boric Acid Corrosion informed the licensee that two requests for of Carbon Steel Reactor Pressure Boundary relief from American Society of Mechanical Components in PWR Plants." The Engineers (ASME) Code requirements would inspections were performed with the be necessary to implement these repair insulation on the head. No evidence of techniques. The first relief would allow the leakage was detected.

use of technical criteria from a later version of the ASME Code to support an embedded Planned Future Inspections flaw repair process, and the second relief would allow the use of Code Case N-638 for In the Bulletin response, the licensee an ambient temper bead weld repair committed to perform an effective visual 31

OA.

Steven Long - ,LLI,.wpu Pane tp S ize. Then, given the inspection results from inspection of each of the CRD housings and ttie upcoming outage, the number of flaws to the reactor head vent where they penetrate b e expected in the head of each of the the top of the reactor v for North uninspected units could be calculated with a Anna Unit 2 during the ,utage and 9 5% confidence level. The licensee expects Surry Unit 2 during the-Sprn'g 2002 outage. t(o submit this evaluation to the NRC by During a conference call on September 14, n,id-November 2001. The licensee 2001, the staff reiterated the Bulletin's a3cknowledged that the Fall 2001 inspection recommendation for a qualified visual esults from North Anna Units I and 2 may inspection for high-susceptibility plants. r ecessitate an accelerated schedule for During a conference call on September 21, nspection of North Anna Unit 2 and Surry 2001, the licensee informed the staff of their Jnit 2.

intention to qualify the visual inspections for North Anna Units I and 2 and Surry Units I and 2. In their Bulletin response, the ii3asis for Compliance with Regulatory Requirements

(.

licensee committed to develop contingency plans for volumetric examination if rhe licensee concluded that the integrated necessary. ndustry approach to inspection, monitoring, cause determination, and resolution of the Planned Additional Inspections ifLeakage is dentified CRDM nozzle cracking are clearly Detected n compliance with regulatory requirements.

if leakage is detected, the licensee stated 7.2.5.2 Staff Assessment that it is their intention to perform supplemental inspections from under the [Additional Information to be provided by head using EC and UT procedures to locate Andrea.]

the source of leakage and to characterize any flaws that are found. The licensee also stated that expansion of the EC and UT inspections would be based on statistical determination of a relevant sample size, and any additional unacceptable indications would likely result in inspection of all of the housings on the reactor vessel head. In conjunction with Westinghouse, the licensee intends to develop a statistical basis for determining appropriate scope and schedule for future inspection activities for North Anna Unit 2 and Surry Unit 2.. "Theevaluationwill be based on the inspection experience to date for Alloy 600 penetrations ill include the results obtained M& or North Anna Unit 1 and Surry Unit M. "Teiciensee stated that the first goal of the work will be to v.lculate the number of flaws of a specified limiting size which could be left in the head without repair for a specific time period with a 95% confidence level of acceptable crack 32 I

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• U 35 Table 4.1 Plant and LOCA Sequence CDF and CCDP (IPE) - B&W DESIGN PLANT LOCA Sequence CDF CCDP of LOCA Sequence (without CRDM Ejection Sequences) (given Initiation of LOCA)

Commercial TOTAL Operation CDF (PRA Code) (IRY)

SLOCA MLOCA LLOCA SLOCA MLOCA LLOCA 7.52E-7 2.98E-3 7.52E-3 ANO-1 /74 4.67E-5 1.49E-5 (CAFTA)

CRYSTAL 1.53E-5 7.20E-6 i.67E-6 1.18E-7 3.60E-3 3.34E-3 2.36E-3 RIVER 3 /77 (CAFTA)

DAVIS-BESS 6.60E-5 2.10E-6 2.06E-6 1.08E-6 5.83E-4 (6.87E-3) 1.08E-2 2.7E-3*

E178 (CAFTA) 2.71 E-3 OCONEE 2.30E-5 3.70E-7 7.30E-6 1.90E-6 9.25E-5 (1.04E-2) 3.50E-3*

1,2,&3 I 73/74/74 (CAFTA)

TMI-1 174 4.49E-5 7.85E-6 2.07E-6 1.43E-6 3.38E-3 7.48E-3 1.97E-2 (RISKMAN)

Table 4.2 Plant and LOCA Sequence CDF and CCDP (IPE) - CE DESIGN

. SteNv n ,Lonn - techass wncd r'ag: 0n I1 5tAvAn 'Lona - techass.wod .

36 PLANT LOCA Sequence CDF CCDP of LOCA Sequence (given Initiation of LOCA)

Commercial TOTAL (wfthout CRDM Ejection Sequences)

Operation CDF (PRA Code) (IRY)

SLOCA MLOCA LLOCA SLOCA MLOCA LLOCA 1.74E-6 1.39E-6 1.39E-2 1.74E-3 3.43E-4 ANO-2180 3.40E-5 1.71E-6 (CAFTA) 2.40E-4 2.08E-5 3.59E-6 5.61E-6 4.12E-3 7.77E-3 2.78E-2 Calvert Cliffs I &2 175177 (CAFTA)*

1.36E-5 8.15E-7 1.22E-7 1.35E-7 8.15E-4 1.22E-3 1.35E-2 Fort Calhoun 1173 (CAFTA) 2.58E-3 1.63E-6 1.27E-6 1.65E-6 7.24E-4 (1.79E-3)

Millstone 2 (3.42E-5) 5.88E-5* 4.02E-3*

175 (CAFTA) 5.07E-5 1.50E-5 4.40E-7 1.80E-7 2.50E-3 (1.10E-3) 9.OOE-4 Palisades 1.83E-3*

171 CAFTA) 4.38E-3 9.00E-5 3.43E-6 2.26E-6 9.20E-7 4.29E-4 5.02E-3 Palo Verde 1, 2 ,&3 186186188 (CRYSTAL) 6.60E-3 3.OOE-5 2.90E-6 4.00E-6 3.30E-6 2.90E-3 4.OOE-3 SONG 2&3 183184 (NUPRA) 1.31E-2 St. Lucie 1 2.30E-5 1.60E-6 3.49E-6 3.94E-3 176 (CAFTA) 1.24E-2 2.62E-5 2.11 E-6 3.30E-6 5.20E-3 St. Lucie 2 183 (CAFTA) 1.80E-5 5.30E-6 1.14E-6 1.82E-7 1.19E-3 1.14E-3 3.64E-3 Waterford 3 185 (CAFTA)

Table 4.3 Plant and LOCA Sequence CDF and CCDP (IPE) - W DESIGN PLANT LOCA Sequence CDF CCDP of LOCA Sequence (without CRDM Ejection (given Iniation of LOCA)

Commercial TOTAL Sequences)

Operation CDF (PRA Code) (IRY)

SLOCA MLOCA LLOCA SLOCA MLOCA LLOCA Beaver 2.14E-4 1.80E-5 1.87E-6 9.70E-4 4.05E-3 Valley 1 176 (3-LOOP)

(RISKMAN)

I,Steven Long - techass.wpd r'age 37 1 r tev n on - i i iiiii ii ii r, g iswp (

37 Beaver 1.92E-5 4.21 E-5 <1.OOE-7 1.77E-3 <1.OE-4 Valley 2 /87 (3-LOOP)

(RISKMAN)

Braidwood 2.74E-5 6.66E-7 1.24E-7 3.66E-7 9.51 E-5 1.55E-4 1.22E-3 1&2 / 88/88 (4-LOOP)

(RISKMAN) 3.09E-5 7.64E-7 1.49E-7 4.11E-7 1.25E-4 1.86E-4 1.37E-3 Byron 1&2 185187 (4-LOOP)

(GRAFTER) 4.34E-3 Callaway 5.85E-5 4.29E-6 4.32E-6 2.17E-6 4.29E-3 4.32E-3

/84 (4-LOOP)

(NUPRA) I1AOE-3 Catawba 1&2 5.80E-6 5.40E-6 7.10E-7 4.20E-7 1.35E-3 2.37E-3

/ 85186 (4-LOOP)

(CAFTA) 1 .4E-2 Comnache 5.72E-5 1.65E-6 1.02E-6 2.85E-6 2.83E-4 2.19E-3 Peak 1&2 (4-LOOP) 90/93(CAFTA

)

2.96E-5 4.31 E-6 9.52E-7 (4.35E-3) (4.70E-3) 3.17E-3 D.C. Cook 6.26E-5 (4-LOOP) 3.31E-3* 4.35E-3*

1&2 175/78 (CAFTA)* i.20E-2 Diablo 8.80E-5 9.00E-7 4.70E-6 2.40E-6 4.66E-4 1.02E-2 Canyon 1&2 (4-LOOP) 185186 (RISKMAN) 1.25E-2 Farley 1&2 1.30E-4 1.74E-5 2.67E-6 3.76E-6 3.70E-3 3.47E-3

/77/81 (3-LOOP)

(CAFTA)* 1 .72E-2 8.74E-6 4.96E-6 5.75E-6 3.09E-6 1.34E-2 (1.44E-2)

Ginna /70 2.25E-3*

(CAFTER)* (2-LOOP)

(Table 4.3 W design continued)

PLANT LOCA Sequence CDF CCDP of LOCA Sequence (without CRDM Ejection Sequences) (given Initiation of LOCA)

Commercial TOTAL Operation CDF (PRA Code) (IRYY' SLOCA MLOCA LLOCA SLOCA MLOCA LLOCA H.B. 3.20E-4 7.OOE-6 5.23E-5 1.59E-5 4.67E-4 2.01E-2 3.18E-2 (3-LOOP)

Robinson 2 171 (CAFTA) 1.90E-4 5.66E-6 1.90E-6 2.56E-6 3.36E-4 4.13E-3 1 .27E-2 Indian Point 2 174 (4-LOOP)

(RISKMAN)

Indian Point 3 4.40E-5 3.92E-5 4.29E-2 176 (4-LOOP)

(CAFTA)

r5.. ,o pH I10Stvn Lono - tecflass.wod r~cf!A 1ýoI Stve ...........woc.

38 Kewaunee 6.65E-5 1.26E-5 7.59E-6 1.84E-6 2.44E-3 3.22E-3 3.68E-3

'74 (2-LOOP)

(GRAFTER)

McGuire 1&2 4.00E-5 1.10E-5 1.60E-6 1.90E-6 2.75E-3 5.33E-3 6.33E-3 181184 (4-LOOP)

(CAFTA)

Millstone 3 5.61 E-5 3.63E-6 1.03E-5 8.03E-6 4.OOE-4 1.69E-2 2.07E-2 (4-LOOP) 186 (CAFTA)

North Anna 7.16E-5 1.01E-5 6.64E-6 4.09E-6 4.81E-4 6.64E-3 8.18E-3 1&2178180 (3-LOOP)

(NUPRA)

Point Beach 1.15E-4 1.96E-6 1.07E-5 2.58E-5 6.53E-4 1.07E-2 5.I6E-2 1&2170/72 (2-LOOP)

(NUPRA)

Prairie Island 5.00E-5 4.10E-6 4.60E-6 4.60E-6 5.75E-3 1&2173/74 (2-LOOP)

(CAFTA)

Salem 1&2 6.25E-5 2.50E-6 3.10E-6 1.20E-6 2.50E-3 3.10E-3 2.40E-3 177181 (NUPRA) 6.35E-5 2.30E-6 4.10E-6 1.00E-6 2.30E-3 4.10E-3 2.OOE-3 (Table 4.3 W design continued)

PLANT LOCA Sequence CDF CCDP of LOCA Sequence Commercial TOTAL (without CRDM Ejection Sequences) (given Initiation of LOCA)

Operation CDF (PRA Code) (IRY)

SLOCA MLOCA LLOCA SLOCA MLOCA LLOCA 6.70E-5 3055E-6 1.00E-6 1.35E-6 1.98E-4 2.15E-3 6.65E-3 Seabrook 190 (4-LOOP)

(RISKMAN)

Sequoyah 1.70E-4:. 1.67E-6 3.63E-3 1&2 181182 (4-LOOP)

(RISKMAN) 7.OOE-5 2.30E-5 3.50E-6 3.10E-6 1.15E-2 5.83E-3 6.20E-3 Shearson Harris 1187 (3-LOOP)

(CAFTA)

South Texas 4.27E-5 2.42E-6 1.26E-6 1.15E-4 2.66E-3 Project 1&2 (4-LOOP) 1 88189 (RISKMAN)

Q I

K V.,,. I finn - lAIflfl Q+

% / e%ii iiiW 39 2.OOE-4 2.72E-5 7.62E-6 3.14E-6 3.40E-3 9.52E-3 1.06E&2 Summer (3-LOOP) 184 (GRAFTER) 1.17E-3 1.14E-5 5.30E-6 4.67E-6 5.43E-4 5.30E-3 9.14E-3 Surry 1&2 7.40E-5 172173 (internal)

(NUPRA) (3-LOOP) 4.62E-4 2.58E-6 4.65E-6 1.66E-6 2.58E-2 4.65E-2

• Turkey Point (3-LOOP) 3&4172)73 (CAFTA)

Vogtle 1&2 4.90E-5 3.33E-6 4.37E-6 1.54E-6 5.05E-4 5.46E-3 (4-LOOP) 187189 (CAFTA)"

Watts Bar 1 3.30E-4 1.85E-5 1.79E-6 2.32E-6 6.42E-4 3.85E-3 i.14E-2 (4-LOOP) 196 (RISKMAN) 4.20E-5 6.67E-7 1.85E-6 1.37E-6 2.67E-4 1.68E-3 2.74E-3 Wolf Creek (4-LOOP) 185 (NUPRA) 4.OOE-6 1.54E-7 3.97E-7 1.32E-6 2.26E-5 3.61E-4 4.40E-3 Zion 173 (4-LOOP)

(GRAFTER)

NOTE: Core Damage Frequency (CDF) and Conditional Core Damage Probability (CCDP) are from the Individual Plant Examination (IPE) database, unless updated as noted in the tables.

• The Original PRA was Riskman with Large Event TreelSmall Fault tree model The Original PRA was Grafter model from Westinghouse

• Revised value in the licensee response

- CAFTA and NUPRA are Large Fault treelSmall Event tree models, and majority of licensee are using CAFTA, and many current GRAFTER and Riskman users are converting to CAFTA.

Table I PLANTS HAVING MODERATE SUSCEPTIBILITY TO PWSCC Plant Proposed Additional Future Inspections Arkansas Nuclear One, Unit 2 Surface or volumetric of 25% of nozzles in Spring 2002 Beaver Valley, Units I &2 Effective Visual in September 2001 (Unitl), February 2002 (Unit 2)

Dri S AA IA

., 1 ,.rsq I L* -- '.AIrINI N-- zi

%LVI C, L=VW 4ý-Mnaa W 40 Calvert Cliffs, Units 1 &2 Effective Visual, Qualified Volumetric, Wetted Surface in F.pebruary (Unit 1')nlit 3)

Crystal River 3 EffectiVe Visual in Falt 2001 Diablo Canyon, Units I &2 Effective Visual in 1 1 002 (Unit 1) ancI Visua ir l..

Fort Calhoun Ginna Not Specified (will notify NRC by January 2002)

Indian Point 2 Not Specified (new owner to respond)

Indian Point 3 GLs 88-05 & 97-01 + TBD enhancements J.M. Farley, Units I & 2 Unit 1-Effective Visu 0 Unit 2 - NDE TBDi Kewaunee Effective Visual in Fall 2001 Millstone, Unit 2 .- V .aual of 60% w Palo Verde, Units 1,2, & 3 Volumetric J2),

Point Beach, Units 1 &2 Spring 2 Effective Visual in"n it 1)

Praide Island Units I & 2 February2002 Salem, Units I & 2 Effective Visual in (Unit 1), Apdl 2 U San Onofre, Units 2 & 3 Effective Visual or Qualified Volumetric or Wetted i* IriS 02 SSurt (Unit . Unit 3)

St. Lucie, Units 1 & 2 Effective ViiUnit 1), Effective Visual in a partial visual in t Fall 2001 (Unit 2)

Tur key Point, Units 3 & 4 Effective Visual in October 2001 (Unit 3), Spring 2002 (Unit 4)

Wa terford 3 Effective Visual in Spring 2002 TABLE 2 PLANTS HAVING LOW SUSCEPTIBILITY TO PWSCC Plant Proposed Additional Future Inspections Braidwood, Units 1 & 2 Not Specified Byron, Units 1 &2 Not Specified Callaway Not Specified Catawba, Units I & 2 Not Specified Comanche Peak~i I &2 Not Specified D.C. Cook, Unit I Remote Visual in Spring 2002 McGuire, Units I &2 Not Specified Millstone, Unit 3 Not Specified Palisades Not Specified Seabrook Not Specified Sequoyah, Units 1 & 2 Not Specified Shearon Harris I Not Specified South Texas Project, Units I & 2 Not Specified V.C. Summer Not Specified Vogtle, Units I &2 VT-3 each refueling Watts Bar, Unit 1 Not Specified

. All

- techass.wm d r v- I Ssteven Lonn a

41 Wolf Creek I Not Specified

Steven Long-techass.wpd Page 42 42

O aA2ý I I Q+tfIgl 'I nnr - n =cc nt m 43 9.0

SUMMARY

AND CONCLUSIONS L- - ..

.I; 7 -

. Steven'Lona - tecnass.woa r uw I I - . . -

44

10.0 REFERENCES

5 A I3 I .- tu~nd I fnftl - t, ass wnf r am*

• I 45 APPENDIX I Results of Independent Evaluation of Recent Reactor Vessel Head Penetration Cracking

I I r*y*

• I I .t.v.n'L-nn - techass.w.. r-,

46 September 7, 2001 MEMORANDUM TO: Samuel J. Collins, Director Office of Nuclear Reactor Regulation Ashok C. Thadani, Director Office of Nuclear Regulatory Research FROM: Jack R. Strosnider, Director IRA/

Division of Engineering Office of Nuclear Reactor Regulation Michael E. Mayfield, Director IRA/

Division of Engineering Technology Office of Nuclear Regulatory Research

SUBJECT:

RESULTS OF INDEPENDENT EVALUATION OF RECENT REACTOR VESSEL HEAD PENETRATION CRACKING Per request from the Office of Nuclear Reactor Regulation (NRR), the Office of Nuclear Regulatory Research (RES) convened an independent group of experts to evaluate the recent reactor vessel head penetration (VHP) cracking observed at Oconee and Arkansas Nuclear One. The group was tasked to provide recommendations that would be relevant to: (a) issuance of a generic communication from the NRC on this issue and (b) guidance for inspection activities for Fall 2001 outages at affected plants. Given the potential safety significance of the recently observed cracking, NRR issued NRC Bulletin 2001-01, "Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles," on August 3, 2001. The Bulletin incorporated insights gained from the expert group review.

The members of the expert group and their respective affiliations and technical areas are:

Dr. William Shack - Argonne National Laboratory - Environmentally Assisted Cracking Dr. Gery Wilkowski - Engineerieg Mechanics Corporation - Leakage modeling Dr. Richard Bass - Oak Ridge National Laboratory - Structural Evaluation Dr. Steven Doctor - Pacific Northwest National Laboratory - Non-destructive Inspection

rE...., A7I I Steven Lona - tecnass.woa r--,vc -t I 47 S. Collins, A. Thadani - 2 Review of the groups' reports, discussions with the group members, industry and staff experts, and examination of the literature and industry submittals, supports the following perspectives on the issue. The attachment summarizes and augments these perspectives in tabular form and provides a comparison with industry perspectives and the NRC staff assessment on the issues.

1. Susceptibility Evaluation - Significant uncertainty exists in determining the susceptibility of plants to this cracking phenomenon. The current industry susceptibility model considers only time and temperature. There are other variables (material yield strength, crevice chemistry, residual stresses from fabrication processes, etc.) that can significantly influence the susceptibility to stress corrosion cracking. However, given the need for timely decisions, and the difficulty in obtaining details on the other variables, the model provides the best method for ranking plants at this time.

However, the possibility of cracking at a low-ranked plant cannot be precluded and should be considered judiciously in assessing industry actions. It is noteworthy that some experts believe relatively few instances of cracking are expected at this time, even for plants as susceptible as Oconee-3. However, that does not preclude that cracking could exist and will continue to occur at future times, hence "one time" inspections will be inadequate and a program of regular inspections or monitoring should be required.

2. Crack Growth Rates - Due to the possibility of the concentration of aggressive chemical species in the annulus between the VHPs and the reactor vessel head, it is probable that crack growth rates for outer diameter (OD) cracking are higher than those expected for stress corrosion cracking (SCC) in Alloy 600. This would indicate growth rates on the order of 1 inch per year or higher for the higher temperature plants. A complicating feature is the probability of multiple crack initiation sites in the annulus around the outer diameter of the VHPs which could lead to an even faster "effective" crack growth rate until the residual stresses are sufficiently relieved that initiation of new cracks is unlikely and growth is controlled by fracture mechanics.

3. Detection and Characterization of Boric Acid Deposits from VHP leakage - Significant uncertainty exists in the determination of whether leakage through the annulus region, resulting from cracking, will be detectable as boric acid deposits on the surface of the reactor vessel head.

In addition, the sensitivity and qualification of visual examination methods needs to be carefully considered in this regard. In this respect, qualified volumetric examinations are recommended as the preferred inspection method for plants which have had cracking. In addition, qualified volumetric examinations would also be the preferred method of examination for plants with a high susceptibility to the degr'adat-on. However, qualified visual examinations could be employed if the sensitivity to detection of leakage can be demonstrated on a plant-specific basis (e.g.,

demonstration of maintenance of a gap between the penetration and the RPV head under operating conditions coupled with an effective leak detection program).

4. Volumetric Examination - It is feasible to detect and characterize the subject degradation with ultrasonic testing (UT). Reliability and effectiveness of such inspections remain to be determined and should include use of mock-ups and performance demonstration. Automated systems for UT inspections (and repairs) are available from several domestic S. Collins, A. Thadani -3 and foreign industry vendors. The expert group has also considered that, given the

F Steven Lana tecflaSs.VJOa

- VOW-- .YJ

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48 nature of the cracking observed thus far, a limited volumetric inspection on a sampling basis would not be adequate to deal with the uncertainties. If cracking is known to exist at a plant, 100% volumetric inspection of all VHPs would be indicated in order to minimize the potential for recurrence of reactor coolant pressure boundary leakage, which could constitute non compliance with the technical specifications and Appendix B. A likely limitation for Fall/2001 would be the number of qualified systems and teams that could be fielded to cover multiple outages. Additional issues would include acceptance criteria and ALARA/labor intensiveness of inspections/repairs.

5. Structural Margin - The expert group was able to provide independent verification of the structural margin calculations performed by the industry. These calculations (both from the industry and the expert group) show that the VHPs can accommodate very large through-wall circumferential cracks (e.g., approximately 270 degrees in extent for CRDMs) while still maintaining adequate structural integrity. The largest circumferential crack discovered at Oconee (approximately 165 degrees) was well within this margin. However, large uncertainties remain regarding the time estimates required for the crack to reach the latter configuration, and for it to potentially grow further to the point of failure. Estimates of the effective crack growth rate are strongly influenced by factors such as weld residual stresses, the environment in the nozzle-head annulus, and the number of initiation sites. Until such time as these issues can be further quantified, justification for structural margin can only be approximated through application of engineering judgement (see #8).

6. Potential for On-line Monitoring for Leakage or Cracking - On-line monitoring for leakage or cracking is technically feasible. In the case of leakage monitoring, EDF has employed on-line systems for French plants which are based on detection of N-1 3. Sensitivities of detection to 1 liter/hour have been demonstrated. However, the total leakage from the largest through-wall crack at Oconee as determined by the amount of boric acid present was probably less than 4 liters. In the case of on-line monitoring for cracking, acoustic emission has been demonstrated to work in crack detection/propagation in a nuclear plant application, but not specifically for cracking in VHPs. The expert group considered that implementation of such technologies would require development efforts for application to U.S. PWRs that would preclude their effective use in the near-term.

7. Probabilistic Risk Assessment - Existing PRAs do not explicitly address these types of initiating events, but combine them with other possible reactor coolant system breaks of similar size.

The estimation of event frequency, and the probability of recovery actions given the break location, were hampered by a lack of relevant information. Accordingly, the staff focused on the conditional core damage probability (CCDP), basically an estimate of the emergency core cooling system failu-§frf bability, given one or more CRDM failures. The major contribution to the CCDP would be from the resulting small to medium break LOCA. Additional considerations include the potential for damage of other rod assemblies, clogging the sump by dislodged insulation, and design, configuration, and alignment of engineered safety features (ESF). NRC is in need of additional plant-specific information from the industry to enable more accurate determinations in this regard.

S. Collins, A. Thadani -4

8. Summary - An estimate of the CCDP suggests the need for heightened attention as manifested by the issuance of NRC Bulletin 2001-01. Thus, further consideration must be given to the initiation frequency, which brings the focus to the cracking phenomenology and crack growth

bbi Steven Long - tecnass.wpu 49 rates. In that regard, the appropriate technical approach would be to use probabilistic fracture mechanics (PFM). RES has initiated an effort aimed at modifying the PFM code PC-PRAISE to try to address the issue in a more quantitative manner. However, it should be re-emphasized that there are significant uncertainties in the inputs which will likely limit the usefulness of the results in a strictly quantitative sense. In addition, this effort will likely require 3-6 months to produce meaningful results.

In the interim, a cracking hypothesis can be formed that involves the following assumptions: (1) the Oconee cracking is representative of the "worst-case," in the industry, (2) cracking initiates preferentially at multiple OD locations with high residual stresses (likely 1-2 quadrants - upper and lower hillside regions); (3) cracking progresses preferentially around the circumference instead of through-wall (expectation from fracture mechanics, consistent with Oconee experience); (4) crack growth rates are approximately 1-inch/year, and (5) the progression of the cracking relieves residual stresses.

Ifthe above assumptions hold, the crack driving force would tend to decrease as the cracking extends until itpenetrates through-wall to a significant extent. At this point, the crack driving force would increase again till failure. Inthis case, cracking on the order of that experienced at Oconee 3 would be predicted to take in the range of 6 months to over 1 year to grow to a point where the structural margin was compromised and on the order of 15 months to several years for the crack to grow to the point where failures would occur under normal operating loads. This evaluation requires application of engineering judgement and is highly uncertain. The most difficult assumption to justify, without additional inspections, is that the Oconee crack is the "worst case" crack that exists at this time. However, even a 250* through-wall crack would probably require 6 months or more to grow to failure under pressure loads. We plan to refine our assessment and the need for additional work after reviewing the industry responses to NRC Bulletin 2001-01.

Attachment:

As stated cc: R. Zimmerman B. Sheron Distribution: K.Wichman A. Hiser D.Jackson W. Norris J. Zimmerman W.Shack R. Bass S. Doctor G.Wilkowski S. Malik F. Coffman DOCUMENT NAME: G\crdpanelmemol.wpd ML012550307 - Att. ML012560084- Package OAR In ADAMS? (Y or N)_ ADAMS ACCESSION NO.: ML012550290 TEMPLATE NO. RES-_

DATE OF RELEASE TO PUBLIC 9119/01 SENSITIVE? N Publicly Available? (Y or N)_

See previous concurrence "E' = Copy with enclosures "N" =No copy To receive a copy of this document, Indicate In the box: 'C" = Copy without enclosures RES/DET/MEB RES/PRAB NRRtDSSA/APSB OFFICE RESIDETIMEB

• /RA M. Cunningham IRA/ M. Reinhart /RAI NAME E. Hackett * /RA! --"1 -*W.Chokshi 37132 37139 09/06/01 DATE 37132 OFFICE NRR/DETIEMCB RES/DET NRR/DE NAME B. Bateman /.AI M. Mayfield /RA/ J. Strosnider IRA/

DATE 37139 37140 37140 (RES File Code) RES TABULAR

SUMMARY

OF PERSPECTIVES AND COMPARISON WITH INDUSTRY POSITIONS Experts Opinion Staff Assessment Issue Industry Position

ridge RfavenI Ann - techass ndcv 50

1. CRDM Critical 273 degrees 271 to 277 Based on the around the degrees at 3 information Circumferential Through-Wall circumference at times operating presented by the 3 times the pressure. industry and the Crack Length operating 225 to 90 degrees independent pressure. for combined experts opinion through-wall and on issues 1- 5, surface flaw the staff geometries. believes that:

Further work is needed to Detectable evaluate time leakage can estimates for occur at single or linked crack flaws to reach a lengths critical length smaller in the than a environment of critical the annular gap. crack length.

The average time between plant outages is potentially less than the time required for a crack to reach a critical size.

The remaining lifetime of a 1650 through-wal 1 crack ranges between 1.5

- 6 years Additional confirmator y work will be needed.

I I Ann - TACflSSWflO ,

• vj 04--van g- n asc wn 51

2. Crack Growth Relief of Restrained Rate residual stress bending condition due to opening of limits crack the crack retards growth. Weld or terminate residual stresses further crack will be the growth. primary driving 6 years is force. Rates of required for residual stress crack to grow relaxation through wall. expected to A circumferential accompany crack crack is unlikely growth are to propagate unknown.

through the wall The CGR can be and grow along accelerated in the nozzle-weld acidic or basic contour. solution, and presence of sufficient stress. Above certain crack opening, the environment seen by the crack would be controlled by the primary coolant chemistry.

Simple fracture mechanics models may underestimate crack growth if multiple cracks initiate and link.

Primarily based The proposed 3.

on time and ranking in terms Susceptibility temperature. of susceptibility Ranking and based on Activation The activation operating Energies

_Pagy (Kcal/mole temperature is 0

C) reasonable.

crack initiation Activation energy 50 is appropriate.

crack growth 30 -35

4ý hmee vai A Page 52 i III kI - I IFIIII 52

4. CRDM Crack Annular average Leak rate interference gap analyses, which Leakage consider will contribute to leakage if the crack-opening crack length in displacement, the tube is surface greater than some roughness, number value. of turns, and actual flow path to thickness length indicate that a detectable leakage would occur from the crack.

Thermal expansion between the penetration and the RPV head creates an annular gap for leakage.

Ovalization of the nozzle head penetration will affect the dimensions of this gap.

An interference fit may occur at operating temperature, hence significantly blocking leakage; but could provide detachment restraint.

Boric acid For a 180-degree

5. Plugging of crack, and for Leakage Path plugging the crack is water quality <

un:iely. System 100%, boric acid pressure will stays in sweep out solution. No deposited boric concern of boric acid. acid plugging the crack.

Plugging from other corrosion products needs to be evaluated.

Qt+=inan* I n~nn - t*hl.. wnni '_Pa6& 531 Ir I I IIII I I 53

6. Adequacy of VT-2 can Boric acid NRC Bulletin deposits from 2001-01 indicates Visual Inspection distinguish the need for use between boron prior leaks from to Detect CRDM other sources of qualified Cracking deposits from inspection CRDM cracks and could challenge the ability to techniques for other certain non-relevant detect leaks from the VHP crevice categories of deposits. plants.

if the vessel head has not been cleaned.

Requires adequate access to inner rows of CRDMs and good illumination.

If only a small amount of leakage escapes the crevice there is less confidence in the visual examination.

ET is adequate

7. CRDM Crack for detecting and Detection (Eddy length sizing Current , through-wall Ultrasonic, and cracking Penetrant initiated from Testings) the ID of the nozzle. UT can be used to confirm length measurements and provide depth estimates.

Adaptive scanning is needed to accommodate the complex shape of J-groove.

UT using time-of-flight diffraction should work for OD PWSCC.

PnA S4 I J I ,nn - trh2C AIflt1 Pane 541 I IVI "t - . I 54

8. Can OD PWSCC System pressure Requires blockage Expert analyses of the crevice and opinions in CRDM Nozzle will prevent suggest that the blockage of the immediately after Grow Through-Wall sufficient concentration without Leaking? crevice concentration of mechanism for lithium hydroxide boric acid is not and boric acid is probable and formed and enough boric acid should steam or water is remain in also trapped to solution in the provide the crack plane.

environment in However, the which cracking possibility of can occur in the prohibiting outer surface of leakage still the CRDM nozzle. exists due to potential for interference fits at temperature and the possibility of plugging from other corrosion products (see Issue 5).

Page 551

[VUIn LFUIIy -

55 Considerations Recognizing the

9. CRDM Sampling Being evaluated risk perspective Inspection include:

(Issue 11), and Technical the required time and to inspect - 70 statistical CRDMs per plant, basis for a sampling the inspection would sampling be considered.

plan However, statistical Residual analysis and stresses operating and weld experience do not repair support sampling effects inspection.

(e.g highest residual stresses are associated with the outermost penetration S.)

Sporadic instances of cracking can be expected to occur.

Industry is Equipment capable Techniques are

10. Leak available, but Detection looking into of detecting Equipment availability and small leakage are not for near term available implementation.

efficacy of Potential several detection

• 0.5 gpm-acousti implementation technology.

c emission would be driven

• <0.2 gpm by the need for visual qualification and

• 0.026 gpm the associated humidity costs to the

• 0.0044 gpm industry.

N2-13

W L.2'i.^ll*l* I *r*fl _ t'*pfl*llZl* lgl/nt3 Page 56 1 f 'LVCI LAJ -  %'.' . '. ... .o 56

11. Risk Under development Existing PRAs do not Staff concurs with explicitly address expert group Implications evaluation.

these types of initiating events, but combine them with other NRC is in need of possible RCS breaks additional of similar size. The plant-specific estimation of event information from the frequency, and the industry to enable probability of recovery more accurate actions given the break determinations in this location, were regard.

hampered by a lack of relevant information.

Accordingly, the staff focused on the CCDP, basically an estimate of the emergency core cooling system failure probability, given one or more CRDM failures. The major contribution to the CCDP would be from the resulting small to medium break LOCA.

Additional considerations include the potential for damage of other rod assemblies, clogging the sump by dislodged insulation, and design, configuration, and alignment of

-engineered safety features (ESF). NRC is in need of additional plant-specific information from the industry to enable more accurate determinations in this regard.

B I Ann SS - Wt-.fl Wflfl Page 571

%11= - e, ass wn 57 APPENDIX II Summary of Foreign Experience With Reactor Vessel Head Penetration Cracking

nAI 4 SteverT Long- tecnass.w,,

p * .-

58

SUMMARY

OF FOREIGN INFORMATION In September 1991, cracks were found in an Alloy 600 vessel head penetration (VHP) in the reactor head at Bugey 3, a French pressurized water reactor (PWR). Examinations in PWRs in across the world were performed, and additional VHPs with axial cracks were detected in several European plants. About 5 percent of the international VHPs examined to date contained short, mainly axial indications of cracking.

In an ongoing effort to collect and review international experiences with control rod drive mechanisms (CRDM) nozzle cracking, NRC staff requested information from all foreign countries with western-designed PWRs. The request included questions based on past leaking or cracking indications and inspection programs currently in place for Alloy 600 materials.

International utilities have taken steps to detect and mitigate the primary water stress corrosion cracking (PWSCC) damage and to detect the leakage at an early stage. International utilities have inspected most of the CRDM nozzles and repaired the nozzles or replaced the vessel heads as appropriate. In one country, the three most susceptible vessel heads were replaced, even though no cracks were found in the nozzles of these heads.

Another country has replaced over 70% of its susceptible reactors, and is planning on replacing all vessel heads as a preventative measure. In service inspection of the upper head is now required in other countries.

Removable insulation on the vessel head and leakage monitoring systems are installed in many international plants for early leakage detection.

Additional inspection methods include eddy current tests for indications and ultrasonic tests for depth sizing of inside diameter initiated flaws.

Commonly these inspections are performed after leakage is detected, however some countries regularly schedule eddy current examinations of -their VHPs.

At the time of this report however, the international utility sector does not have a specific test or inspection procedure for outside diameter axial or circumferential cracking such as was found at the Oconee Nuclear Power Station.

Po 591 I

[/%1--i .-- *[ I ----

• I^^* L'*.L" ilJ*Ft SStievet oI - tec ass. Ipi I Pan 59 APPENDIX III Results of the Office of Research's Independent Assessment

/.

techass.wpd Page 601 Stevex"Long -

60 Appendix III RES Assessment of Proposed Regulatory Actions for Plants with Cracking/Leakage (Binl) and High Susceptibility Plants (Bin 2) under Bulletin 2001-01 Per request from the Office of Nuclear Reactor Regulation (NRR), the Office of Nuclear Regulatory Research (RES) was asked to evaluate proposed regulatory actions (see Section 6.0) for plants with cracking/leakage and high susceptibility plants under Bulletin 2001-01. This is in addition to the broader overall assessment of the key technical issues that was conducted by an independent group of experts convened by RES (Appendix I).

1. Susceptibility Evaluation - Although significant uncertainty exists in determining the susceptibility of plants to this cracking phenomenon, RES supports the NRR identification of the most susceptible plants (Bins 1 and 2). This includes the 4 units where this type of cracking has been previously identified (Oconee Units 1,2 and 3 and ANO-1) and eight additional units considered to be highly susceptible to the degradation based on operating time and RPV head temperature. However, RES considers that the susceptibility model is not accurate enough to draw a clear distinction between the high and moderately susceptible categories. Hence, as inspections are performed, additional units in the moderately susceptible category will likely discover some leakage/cracking.

In these cases, expansion of the inspection effort and potential repairs will have to be evaluated on a case-by-case basis.

2. Inspection Methods and Timing - RES considers that a "qualified visual" examination of the RPV head is the minimum acceptable inspection method for plants in Bins 1 and 2. A volumetric examination would be preferred and should be encouraged. However, it is recognized, at this time (1Q FY02), that such examinations have not been qualified. The "qualified visual" examination needs to be capable of discerning small amounts of boric acid deposits, and the leak path around the vessel head penetration (VHP) needs to have been demonstrated through consideration of fabrication measurements and details, and analysis. RES also considers that "one time" inspections will be inadequate and a program of regular inspections or monitoring should be required for plants that will not be replacing or repairing their RPV heads before the next schedule refueling outage.

With regard to timing of inspections, plants in Bin 2 which have not previously conducted inspections, need to accomplish, at a minimum, "qualified visual" examinations of the RPV head in the near term. At this time, near term is difficult to define clearly, since it depends on aspects of a probabilistic fracture mechanics assessment (PFM) that are not yet sufficiently defined.

However, preliminary estimates from PFM considerations would indicate the need to accomplish qualifiedm.inpections for Bin 2 plants prior to Spring, 2002.

3. Margins/Defense in Depth - Given the discussion above in (1.) And (2.) there are obvious concerns with meeting the current regulations and maintaining consistency with the defense-in-depth philosophy for plants in Bins I and 2. The current regulations (10 CFR of 50.55a) endorse ASME Code visual inspections for pressure boundary leakage in the region are not "qualified" per the VHPs. These inspections do not require the removal of insulation, the discussion in (2.), and hence do not meet the intent of the regulation. In addition, boundary.

defense-in-depth is not maintained because of the potential violation of the pressure safety margins is problematic because the inspections will Also, ensuring maintenance of Code not provide quantifiable information with regard to the extent of the cracking.

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4. Probabilistic Risk Assessment - RES considers that the major contribution (CCDP) from VHP failure would be from the resulting small to medium core damage probability other rod assemblies, break LOCA. Additional considerations include the potential for damage of and alignment of engineered clogging the sump by dislodged insulation, and design, configuration,

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'age 611 61 safety features (ESF). NRC is in need of additional plant-specific information from the industry to enable more accurate determinations in this regard. In the interim, RES concurs with NRR in the more general assessment that plants in Bins 1 and 2 have CCDPs in the range of 10-2 to 10-3 range (given the small to medium break LOCA) and are basically not differentiable given the information known at this time. With regard to the initiating event frequency, an estimate needs to be made based on a PFM assessment as discussed under (2.) above. However, the elements and inputs to such an assessment are not yet sufficiently defined to enable an accurate estimate at this time.

What is known, given the previous CCDP estimates, is that the initiating event frequency would need to be demonstrated to be lower than 10-2 to achieve an overall core damage frequency (CDF) estimate that would "result in only a small increase in core damage frequency or nsk" per RG 1.174.

5. Summary - Based on the preceding discussion, RES concurs with the proposed regulatory actions as outlined in Section 6. The plants in Bin 1, along with certain Bin 2 plants (Cook, Surry-1 and TMI-1), have conducted previous inspections, and are proposing additional inspections where the methodology and timing are adequate based on the previous discussion in (2.). For these units, there are no regulatory actions proposed beyond those which would result from the normal inspection oversight/enforcement process. From a susceptibility viewpoint, the remainder of the Bin 2 plants (Robinson, Davis-Besse, North Anna 2 and Surry 2) are effectively indistinguishable from the Bin 1 and other Bin 2 plants. These are units that should have a high likelihood of finding degradation such as that already observed for the Bin 1 plants. In each of these cases RES considers that either the inspection methodology or timing, or both are inadequate. Hence, RES concurs with the NRR recommendation for additional regulatory action for these units.