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Resolution of Generic Safety Issues: Issue 111: Stress Corrosion Cracking of Pressure Boundary Ferritic Steels in Selected Environments (Rev. 2) ( NUREG-0933, Main Report with Supplements 1–34 )

DESCRIPTION

Historical Background

Indications of possible stress corrosion cracking (SCC) in the Indian Point Unit 3 (IP-3) steam generator prompted MTEB to review foreign and domestic operating experiences related to possible indications of SCC in low-alloy ferritic steels. The incidents identified837 as possible precursors to generic concerns of SCC relate to BWR reactor vessels and PWR steam generators. These events and some additional information that are reviewed and discussed in this evaluation include:

(1) A through-wall crack in the transition cone of the steam generator shell at IP-3.
(2) A through-wall crack in the lower head closure weld region of the Italian Garigliano steam generator (an indirect cycle BWR similar to a BWR-1).
(3) A guillotine rupture of a transition cone (reducer) in the secondary piping of the German HDR test facility.
(4) Cracking of feedwater lines in W PWRs.
(5) Other events that may contribute to SCC in BWR reactor vessels and PWR steam generator vessels.
(6) Inferences from materials testing.

The materials of interest are those low-alloy ferritic materials (SA-533 Grade B, SA-508 Grade 2, and SA-302 Grade B) used in the fabrication of the subject pressure vessels.

Safety Significance

The reactor vessels and steam generators are constructed of low-alloy ferritic steels and designed to the ASME Codes. The ASME Codes are linked to fatigue crack initiation in chemically unreactive environments (ASME Section III) and fatigue crack growths of existing defects as part of the ASME Section XI inspection Code. Even though a corrosion allowance is specified in the ASME Codes as a design consideration, it is not linked to corrosion fatigue or SCC that may occur in active chemical environments such as those experienced in the nuclear pressure vessels (reactor pressure vessels, steam generator pressure vessels).

Should the materials used in the pressure vessels be susceptible to SCC and exceed the inherent allowances in the ASME design/inspection Codes, a vessel rupture could result in a core-melt and radiation doses to the public. This issue affects the design and operation of all LWRs except those designed by B&W.859

Possible Solution

Prior to developing a solution to this problem, MTEB proposed a research scoping effort to define the severity of the problem and the conditions under which the SCC phenomena are likely to be exacerbated. The research effort would also involve laboratory testing of the low-alloy materials in reactor-grade water with variable oxygen, chloride, and copper as possible water chemistry constituents.

No risk reduction can be attributed to the study (scoping) efforts. However, the proposed effort is expected to better define under what conditions SCC of the pressure boundary steels may occur and if such conditions arise or prevail during reactor operations. The proposed effort would also involve determinations of the effectiveness of post-weld heat treatments (PWHT) and water chemistry excursions that may affect the materials resistance to SCC. The results of these studies (research) could then possibly be used to determine when and where to conduct inspections to detect the cracks before they become a safety concern.

PRIORITY DETERMINATION

In order to develop background frequency information to establish the safety significance of this issue, a review and discussion of the incidents identified above was required.

IP-3 Steam Generator Event: During a refueling outage (with the reactor in a cold shutdown condition) on March 27, 1982, a small leak was detected on the shell side of steam generator #32 of IP-3. The leak originated in the circumferential weld joining the transition cone to the upper shell. The steam generator shell is constructed of SA-302 Grade B material approximately 4 in. thick. To characterize the cracking phenomenon, the utility had various samples removed for metallurgical evaluation and failure analyses. BNL performed an independent failure analysis on specimens from steam generator #32 and on three additional boat samples containing cracks cut from steam generator #31. Office of Inspection and Enforcement (OIE) issued Information Notice No. 82-37842 to inform the industry of the event. W informed843 the NRC staff that no indications similar to those observed at IP-3 were identified in the inspections performed on steam generators in 12 plants.

An investigation by BNL as reported in NUREG/CR-3281844 concluded that the cracking was caused by a low cycle corrosion fatigue phenomenon with cracks initiating at areas of localized corrosion (pits) and propagating by fatigue. The cause of the pitting/cracking was considered to be related to the unit's relatively high operating dissolved oxygen levels and copper species in solution. The report also concluded that SCC could not be entirely discounted as the possible failure mechanism. NUREG/CR-3281844 also identified that IP-3 had developed moderate to severe denting of the steam generator tubes. The sludge analysis in IP-3 showed concentrations as high as 45% copper and 40% iron. Significant amounts of chlorine (Cl), copper as cuprous oxide (Cu20), and alpha hematite (alpha-Fe203) were also present in the sludge pile. The presence of these constituents indicated that water chemistry control in the IP-3 steam generators had been poor for a considerable period of time. Additionally, in January 1981, IP-3 experienced a turbine blade failure which damaged approximately 50 condenser tubes and allowed chloride into the steam generators with recorded levels of up to 325 ppm. The chloride intrusion may have had some influence in initiating pits at the inside surface of the steam generator shell.

Results from constant extension rate tests (CERT) on SA-302 Grade B material in neutral and chloride solutions were reported in NUREG/CR-3614.845 The CERT were performed on weld and base metal samples in air, water, and chlorine solutions. The chlorine solutions as sodium chloride (NaCl) and cupric chloride (CuCl2) ranged from 1 ppm to 325 ppm chlorine. The results of the test indicated no significant effect in the NaCl CERT. However, the CuCl2 CERT indicated possible susceptibility of the SA-302 Grade B material with as little as 1 ppm chlorine (as CuCl2) in 268EC water. No attempt was made to control the dissolved oxygen content in the water. The combined results appear to indicate that copper as CuCl2 may significantly alter the electrochemical reaction. The IP-3 secondary water chemistry may, however, provide an even different corrosion mechanism than that of the CERT. In this regard, the electromotive force series of metals could also produce galvanic corrosion of the iron (Fe) in the presence of copper because carbon steel is anodic compared to copper (Cu) in the galvanic series. Thus, pitting/crevice corrosion of the carbon steel may have been acting as a combination of galvanic corrosion and low cycle fatigue. In the latter case, corrosion products in cracks (crevices) may act as wedges during cooldowns causing crack extensions. During heatups, newly-exposed crack surfaces develop more corrosion deposits. Repeated cycles, therefore, may result in through-wall cracks (corrosion-fatigue).

Because of the poor secondary water chemistry control at IP-3, the atypical massive chloride intrusion, and the results of the W inspections on other steam generators, the event at IP-3 may not represent a generic PWR condition but a plant-specific combination of atypical events. However, because of uncertainties in the CERT to represent conditions that may have prevailed at IP-3, and the indications from the CERT of the potential for copper in solution to effect some form of corrosion-related attack on the low-alloy materials, these effects cannot be ruled out as a potential generic concern, especially when considering the PWR secondary water chemistry controls that have existed in the industry (see "Other Conditions" contributing to SCC).

Garigliano Steam Generator Event: The Garigliano steam generator crack developed at the inner surface of the water box circumferential weld between the tube sheet and the nozzles on the primary side (August 1978). The through-wall crack propagated through the Monel clad and the SA-302 Grade B shell (approximately 2 inches thick). GE conducted an extensive investigation and reported846 its results to the NRC. The most pertinent information revealed that the crack propagation resulted from environmentally-assisted corrosion under sustained loads (SCC). Manganese sulfide as segregates were evident in the monel and base metal with the presence of sulfur in the region of crack tips. Therefore, aggressive acidic crack-tip chemistry caused by dissolution of the sulfide inclusions were concluded by GE to be contributors to the SCC. Local PWHT of the weld with unknown control was also reported by GE to have resulted in high residual stresses in the region of the weld. The high oxygen content (~200 ppb) in the coolant medium was not considered atypical, but it may have enhanced the electrochemical reaction involved in the crack initiation and propagation.

GE concluded that the conditions that prevailed in the Garigliano steam generator (high residual stress, material sulfur content and inclusions) were atypical of current domestic BWR design and PWHT. The NRC staff did not challenge the GE position. Therefore, the Garigliano event was not considered a generic event typical to domestic operating BWRs. However, the effects of sulfur content in the material and the potential contribution to SCC have since been subject to further tests and evaluations (see discussion on material testing). One might argue in hindsight that the Garigliano event could have been a precursor to the SCC susceptibility of high/low sulfur content low-alloy steels in reactor grade water.

HDR Rupture Event: NUREG-1061,611 Volume 3, describes the double-end guillotine break that occurred in the HDR test facility on November 3, 1983. The reducer (conic section) that failed was fabricated from a single billet of 15 Mo 3 steel. The wall thickness of the conic section was approximately one-fourth the design thickness. Therefore, the combined primary, secondary, bending, and notch stress concentrations could have resulted in a stress intensity of nearly two orders of magnitude above the design stress. This fabrication error could well have resulted in exceedance of some stress threshold that caused the failure. The thinness of the conic wall section and the high oxygen content (~8ppm) may also have contributed to the failure. The atypical design and fabrication errors related to the HDR failure are believed sufficient to preclude this event as representative support of this issue as a generic issue. It should be pointed out that, although the stresses were very high, there was no gross plastic deformation and no ductility exhibited on a microscale.857 It was a brittle fracture. The failure is atypical of fatigue in that there were numerous initiation sites. These facts point to stress corrosion cracking of low alloy/ carbon steels as the failure mechanism. This incident is cited to demonstrate the mechanism.

PWR Feedwater Line Cracking Events: These failures are being addressed in Issue 14. The primary failure mode has been identified as thermal fatigue (not CF or SCC) resulting from coolant stratification. The PWR Pipe Crack Study Group completed its investigation of this issue and published its findings in NUREG-0691.13 Based on the above findings, any SCC that may or may not have influenced the resulting failures were masked by the thermal fatigue constituent.

Other Events Contributing to Potential SSC: Intrusion of chloride, sulfide, copper, and other contaminants into the BWR reactor water and PWR secondary water may contribute to SCC of the vessels materials. EPRI NP-1136847 stated that 20 BWR plants over a 33-month time period (1974-1977) indicated 12 forced outages as a result of high conductivity in the reactor water or heavy condenser tube leakages. On an average, this amounts to 307.22 significant contaminant intrusions per BWR reactor-year. EPRI NP-2230307 reported 6 condenser leakages over 172 RY of PWR operation. This amounts to a frequency of 0.03 contaminant intrusions from condenser leaks into the PWR secondary cooling water of the steam generators.

As a further example of other apparent poor PWR secondary water chemistry operations (in addition to the IP-3 sludge analyses discussed earlier), the sludge deposits in the removed Surry 2A steam generator undergoing tests at Hanford were reported in NUREG/CR-3842.849 Analyses of the Surry sludge deposits revealed 35 to 60 percent metallic copper, 20 to 30 percent Hematite (Fe203), and 10 percent Cuprite (Cu20). All the analytical data on the sludge samples indicated that they originated from the secondary side. The high copper content probably originating from the condenser tubing (see "Other Considerations").

Tighter requirements for reactor water may account for the reported higher frequency of contaminant intrusion in BWRs from condenser tube leaks. However, Regulatory Guide 1.56848 provides methods determined acceptable by the NRC staff to maintain high purity water in the BWR reactor water cycles and to minimize failure of the reactor vessel from mechanisms of general corrosion and SCC induced by impurities in the reactor coolant.

For the secondary side of the PWRs, resolution850 of Issues A-3, A-4, and A-5 contained staff recommendations that the PWR plants incorporate Revision 3 to SRP11 Section 5.4.2.1 as plant-specific programs for secondary water chemistry control.

From the above limited data, condenser tube leaks in BWRs and PWRs have been frequent. However, the water purity requirements for BWR plants should alleviate potential corrosion effects to the BWR reactor vessels. For the PWR steam generators, adoption of the secondary water chemistry guidelines may reduce future corrosion potentials, but not necessarily resolve the effects of existing corrosion damage.

Based on the IP-3 experience, the above-described Surry sludge analyses, the recent Surry Unit 2 inspections discussed in "Other Considerations," and the fact that steam generator tube degradations have been linked to variable PWR secondary water chemistry controls,840 it appears reasonable to equate the adequacy of the steam generator secondary water chemistry environment to conditions that may also enhance SCC in the steam generator vessel shells.

Inferences from Materials Testing: A considerable amount of materials research and testing has been performed on the SA-508 and SA-533 reactor vessel materials and has resulted in the publication of several documents: NUREG/CP-0058,851 Vol. 4; NUREG/CP-0044,852 Vol. 1 (pp. 7, 91, 141, 179); NUREG/CP-0044,852 Vol. 2 (pp. 27, 91); Reference 853; and NUREG/CR-4121.854

The research and testing were performed in typical PWR and BWR reactor water chemistries. The research results also included comparisons with the ASME Section XI air and water fault lines. Based on the existing research results, the following generalizations appear appropriate for these materials:

(1) There is a trend toward increased crack growth rate with higher material sulfur content.
(2) A higher dissolved oxygen content results in higher initial crack growth rate, but the crack growth rate is stifled with crack depth such that after an initial period of crack growth rate the effects of the bulk solution dissolved oxygen content diminishes. Therefore, there is little difference in the effective crack growth rates of these materials in BWR and PWR reactor water chemistries.
(3) The crack growth rates for reactor pressure vessel materials are within, or consistent with, the ASME Section XI surface (wet) fault lines.

The most significant effect observed was the high/low sulfur content (material variability), and not the oxygen content (environmental variability). The aqueous solutions used in the referenced research did not contain copper in solution, but some tests did contain small amounts of chlorine in solution.

The only research test results obtained for the SA-302 Grade B base material and associated weld material are reported in NUREG/CR-3281844 and NUREG/CR-3614.845 These results were discussed in the earlier IP-3 comparisons.

Based on the above discussions, the differences in the dissolved oxygen contents for the BWR and PWR reactor water chemistries are estimated to have little or no effect on the probability of increased crack growth rates for the reactor pressure vessels. Only limited information was available for the (SA-302 Grade B) pressure vessel material. In the presence of the simulated and degraded PWR secondary water chemistry, the SA-302 material may be susceptible to some form of accelerated corrosion attack.

Frequency/Consequence Estimate

BWR Reactor Pressure Vessel Rupture Frequency Estimate: A nominal base case pressure vessel rupture frequency of 10-7/RY is assumed reasonable for the BWR reactor vessels.16 In consideration of (1) research results of the reactor vessels materials in their respective reactor water chemistry environments, the vessel materials crack growth rates are within the ASME code limits, (2) the protective corrosion shield provided by the cladding on the inside surface of the reactor vessels, and (3) the BWR reactor water chemistry requirements described earlier, no significant increase in the BWR reactor vessel rupture frequency from SCC is anticipated. However, to provide a coarse estimate, it is assumed that a 25% increase in the BWR reactor vessel rupture frequency can be attributed to SCC. This potential increase in BWR reactor vessel rupture frequency is based on the percentage of stainless steel pipe ruptures attributed to SCC reported in NUREG-1061,611 Volume 1. Because of the observed prominence of SSC in stainless steel pipes, it seems unlikely that the percentage of reactor pressure vessel ruptures due to SCC would exceed 25% of the total vessel rupture frequency without prior history of this condition. The change in BWR reactor pressure vessel rupture frequency that may be attributed to SCC is therefore estimated to be 2.5 x 10-8/RY.

BWR Consequence Estimate: Assuming that SCC provides a potential change in the BWR reactor vessel rupture frequency (2.5 x 10-8/RY), the probabilities of radioactive releases in BWR categories 2 and 3, as described in WASH-1400,16 are 0.1 and 0.9, respectively. Assuming a 1120 MWe BWR, meteorology typical of the Braidwood site, and a surrounding uniform population density of 340 persons per square mile, the public radioactive risk within a 50-mile radius is 0.113 man-rem/RY. Considering a remaining reactor life of approximately 30 years, the public risk is 3.5 man-rem/reactor.

PWR Frequency and Consequence Analyses: A leak or rupture of a single steam generator would likely produce a rapid cooldown of the reactor similar to an inadvertent full-opening of the turbine bypass valves or a main steam line break.16 The containments are capable of sustaining a complete blowdown of a steam generator. Therefore, rupture of a single steam generator with no additional failures has no significant risk to the public from core-melt or radioactive releases through containment failures. The plant operations and operation responses to such an event are assumed similar to those described in Issue A-22 for a steamline break inside containment. In addition, subsequent and detailed staff evaluations on PWR responses to MSLB with concurrent SGTRs and SBLOCAs were reported in NUREG-0937860 which concluded that a MSLB inside containment (similar to a steam generator rupture) would likely be bounded by the FSAR analyses and not result in a core-melt.

For a steam generator rupture to lead to a significant release (core-melt), the rupture must be accompanied by damage to the RCS and failure of the ECCS, or failure of the AFWS and the ECCS. The following sections will address these PWR systemic events.

PWR Steam Generator Rupture (SGR) Frequency Estimate: WASH-140016estimated that the SGR frequency was similar to the RPV rupture frequency (10-7/year). Considering approximately 3 steam generators per reactor, the base case SGR frequency is 3 x 10-7/RY.

To assess the potential increase in SRG frequency as a result of accelerated SCC or CF from PWR secondary water chemistry variability between plants, we reason the following: (1) plants with clean secondary water chemistry will have an SGR frequency equal to the above base case rupture frequency (3 x 10-7/RY), (2) plants that have experienced medium degradations of the steam generator tubes will have an SGR frequency one order of magnitude greater (3 x 10-7/RY) than the base case, (3) plants that have experienced severe degradations of the steam generator tubes will have an SGR frequency two orders of magnitude (3 x 10-7/RY) greater than the base case rupture frequency of 3 x 10-7/RY.

The above SGR frequency (3 x 10-5/RY) is back-calculated to estimate the number of steam generator leaks that have occurred by using the piping leak-before-break ratio of 20.16 The predicted number of leaks based on the above reasoning is (3 x 10-5/RY)(500 RY)(20) ~ 0.3. Likewise, if we estimate that steam generator ISI has a 10% chance of not detecting cracks in the steam generators before they develop into leaks, 3 steam generators with cracks could be expected. Compared to the 7 steam generators where cracking has been detected, the above crude estimates are fairly good, but a better correlation with leaks and cracks would be obtained from an SGR frequency of 10-4/RY. For comparative purposes, the probability of a MSLB is also 10-4/RY.

Alternately noting that no rupture has occurred in 1500 steam generator years (500 RY) and ignoring the current steam generator ISI experiences for leak-to-crack detection (1/7) and leak-before-break experiences in U.S. and foreign plants (2 leaks with no ruptures), we would estimate an SGR frequency of 10-3/RY. The SGR frequency of 10-3/RY therefore represents a bounding but prudent estimate. Ignoring the ISI crack detection capability and leak-before-break experiences appears prudent because of the uncertainties in estimating these early warning indicators. As an example of the conservatism of ignoring the crack detection capability, a very conservative staff fracture mechanics analysis839 estimated that a catastrophic rupture of the steam generator would only be predicted to occur from a complete circumferential crack (360°), with a crack depth approaching one-half the vessel wall thickness. A crack of this magnitude seems very likely to be detectable. Therefore, the SGR frequency may range from a best estimate value of 10-4/RY to an upper bound estimate of 10-3/RY.

PWR Steam Generator Support (SGS) Failure and LOCA Frequencies: If cracks develop in the steam generator vessel shells, it was independently judged16, 859 that the steam generator would likely leak before rupture. The SGR event would therefore most likely be bounded by the MSLB event previously discussed. However, should a catastrophic SGR occur, the steam generator reaction loading to the SGS structure is highly uncertain. In recognition of this, we will assume the conditional failure probability of 0.5 for the SGS (SGS/SGR). The SGS/SGR = 0.5 infers that the SGS is as likely to fail as not to fail. Given failure of the SGS, we assume the conditional probability of a large break LOCA (LBLOCA), given a SGS failure, is 1.

PWR Core-Melt Frequencies: The systemic events that are assumed to lead to core-melt conditions as a result of a catastrophic SGR are: (1) damage to the RCS (LBLOCA), and (2) failure of the ECCS in the unaffected loops, or failure of the AFWS and the ECCS in the unaffected loops. The estimated upper bound core-melt frequencies for these sequences are as follows:

Failure Event Frequency/RY
SGR 10-3
SGS/SGR 5 x 10-1
LBLOCA/SGS 1
ECCS Failure 10-2
  Σ = 5 x 10-6
Failure Event Frequency/RY
SGR 10-3
AFWS Failure 4 x 10-5
ECCS Failure 10-2
  Σ = 4 x 10-10 (negligible)

PWR Containment Failure Matrix: Containment response to a core-melt accident from the above LBLOCA/SGR can be grouped into separate plant damage states (PDS). The PDS depends on: (1) the availability of equipment or systems to reduce containment temperature and pressure; and/or (2) containment bypass or failure to isolate containment. The PDS descriptions and probabilities resulting from the LBLOCA/SGR are as follows:

Plant Damage State (PDS)
PDS Description Probability
A No containment heat removal or containment sprays 10-3 (Reference 16)
B Containment heat removal and containment sprays available 0.998 10-3
V/B Given B, but containment bypass through failed MSIVs in ruptured steam generator steam line (Reference 681)

The containment failure modes are similar to those used in WASH-1400.16 The conditional probability of the containment failure mode for each PDS is shown in the table below:

Conditional Containment Failure Modea
PDS α δ β 4 β 5 V
A 10-2 0.96 10-2 - -
B 10-2 - - 10-2 -
V/B - - - - 10-3

a - α, δ, β, V are the containment failure mode conditional probabilities for missile damage, overpressurization, failure to isolate, and bypass, respectively.

The probability of an α failure mode (α = 10-2) from an SGR refers to direct containment failure by missile penetration. For a LBLOCA-induced core-melt, the in-reactor-vessel steam explosion has a probability of 10-4 to produce a missile that breaches containment. For purposes of this analysis, the α failure mode probability from missiles generated by the SGR is assumed to be 100 times greater than that from an in-reactor-vessel steam explosion. Therefore, even through an in-reactor-vessel steam explosion is likely to occur from a core-melt, its contribution to containment failure is negligible. The corresponding WASH-140016 α release category is a Category 1 release due to the containment failure from a missile generated by the SGR.

Steam produced from the SGR by reactor molten fuel (core-melt) and water in the reactor cavity can fail the containment by overpressurization (δ). This would occur only when containment cooling is lost.16,860 The probability of overpressurization due to hydrogen burn is assumed negligible because the steam concentration in containment will tend to suppress hydrogen burn propagation. The probabilities of the δ mode failures for PDS A and B are assumed to be 0.96 and zero, respectively. The corresponding WASH-140016 release for PDS A and B are Category 2 and Category 3, respectively.

Failure to isolate containment (β failure mode) is assumed to have a probability of 0.01. The β4 mode is with containment sprays unavailable and the β5 mode is with containment sprays available. The corresponding WASH-140016 release categories for β4 and β5 are Category 4 and Category 5, respectively. The "V" failure mode probability681 of 0.001 represent containment bypass through the ruptured steam lines in the affected loop with the MSIVs failed open. The conditional PDS = V/B assumes containment sprays are available and the corresponding WASH-140016 release category is a Category 3 release.

The basemat melt-through failure mode is a relatively benign failure mode and, with the most likely case of the containment sprays being available, we assume basemat melt-through is precluded.

The LBLOCA assumed to be induced by the SGR may also be accompanied by SGTRs in the affected loop. However, the conditional SGTRs would be dominated by the probability and consequences of the LBLOCA sequences.

PWR Risk Consequences: The PWR risk consequences for a core-melt frequency (5 x 10-6/RY) resulting from a SGR-induced LBLOCA is 0.4 man-rem/RY. Over a remaining plant life of 30 years, the public risk is 12 man-rem/reactor. The tabulations of the calculated public risk parameters are:

Public Risk Parameters
WASH-140016 Release Category Containment Failure Mode Release Frequency (RY)-1 Conditional Dose/Release (man-rem) Public Risk (man-rem/RY)
1 α 5 x 10-8 5.4 x 106 0.3
2 δ 5 x 10-9 4.8 x 106 0.02
3 V 5 x 10-9 5.4 x 106 0.03
4 β4 5 x 10-11 2.7 x 106 -
5 β5 5 x 10-8 1.0 x 106 0.05
Total - 1 x 10-7 - 0.4

The release categories and corresponding containment failure modes are described in the Containment Matrix Section above. The release frequencies (Column 3) are the products of the core-melt frequency (5 x 10-6/RY) and the summed products of the PDS and the conditional containment failure mode probabilities for each PDS provided in the Containment Matrix Section above. The conditional dose (Column 4) is the man-rem per release for each release category. These release doses are based on the fission product inventory of a 1120 MWe PWR, meteorology typical of the Byron site, and a surrounding uniform population density of 340 persons per square mile over a 50-mile radius from the plant site, with an exclusion radius of one-half mile from the plant.

Cost Estimate

Based on discussions with RES, this issue could be incorporated at no additional cost into the long-term research plan which has not been finalized. A near-term effort would involve an initial expenditure of NRC research funds ($265,000). Depending on the outcome of the research results, additional NRC and industry funds may be needed to develop a solution(s). Because of the small risk, no other costs were estimated.

The industry has a significant economic incentive to repair surface cracks in their steam generators, before they develop into through-wall cracks. As an example, repair of steam generator surface cracks at the Surry plant involved removal by grinding (repair welding was not necessary) estimated by MTEB to cost approximately $1M. At IP-3 where a small through-wall crack developed in one steam generator, the repairs involved grinding and weld repairs. MTEB estimated the costs to IP-3 was approximately $8M. In neither of these cases were the plants required to go into forced outage situations. However, should a plant be placed into a forced outage situation as a result of through-wall cracks in the steam generators, the average replacement power costs of approximately $500,000/day, in addition to the repair costs, would likely result in costs well in excess of $8M.

Other Considerations

A comparison843 was made of the plants reported by W as having been inspected for indications similar to the IP-3 flaw with plants that have experienced severe steam generator tube degradation histories.840 The comparison indicated that, in general, the plants inspected were not plants with histories of severe steam generator tube degradations. Subsequent inspections of the replaced Surry Unit 2 steam generators have revealed intermittent cracks up to 1/4 in. deep.856 The cracks were in the transition region that was part of the original steam generator. The transition cone wall thickness in this area is 3.4 inches and is required by design to be at least 2 inches. Because these indications were in the original part of the transition cone, the affected material was exposed to the same poor secondary water chemistry discussed earlier. The cracking of three Surry 2 steam generator shells occurred at the same joint as the four Indian Point 3 steam generator shells. The inspections of the joints have predominantly been by UT methods from the outside of the shell. As experienced in some of the BWR stainless steel piping inspections for SCC, the UT indications were incorrectly ascribed to geometric configuration. In this regard, IE Information Notice No. 85-65858 has informed the industry of the events at IP-3 and Surry and the experience with UT versus magnetic particle examinations related to crack detection in the steam generators. Therefore, subsequent ISI testing of the SGS should be more reliable and thereby further reduce the chance of an SGR.

CONCLUSION

Based on limited operating experience (one steam generator leak in U.S. domestic plants and one steam generator leak in foreign plants) and expert opinion,859 steam generator outer shells are more likely to leak than to catastrophically rupture. A significant leak in a steam generator outer shell would be expected to result in plant responses comparable to a transient induced by the inadvertent full-opening of the turbine bypass valves. A larger steam generator leak (small rupture) is expected to be bounded by the MSLB with concurrent SGTRs and SBLOCA as evaluated in NUREG-0937.860 The detailed analyses860 determined that such an event would not result in a core-melt accident.

To further bound the probability and consequences of this issue, we have ignored the steam generator crack detection experiences and steam generator leak experiences (that essentially have provided defense-in-depth mitigations to severe steam generator ruptures) and assumed a catastrophic SGR probability of 10-3/RY that leads to a LBLOCA (failure of primary piping loop). Based on this scenario as a bounding analysis, the public risk from an SGR was estimated to be 12 man-rem/PWR. Therefore, the risk reduction potential (3.5 man-rem/BWR plant, 12 man-rem/PWR plant) indicates that this issue is of low safety significance to the public.

The quantified values used in this evaluation contain a number of unquantified uncertainties. However, to the extent judged reasonable, the bounding values are believed to be biased in conservative directions. Thus, these estimates are more sensitivity studies than absolute quantifications and, therefore, only represent the potential safety significance of this issue relative to other issues.

We have also considered other concerns raised by MTEB.857 "The experience at two plants (IP-3 and Surry 2) of the material failure mechanism that was not addressed in the original design (and raised doubt whether GDC 4 is being met) requires a response by the staff. The research effort promised in the future would be too late to address licensing concerns now, especially for operating plants. Active consideration should be given to placing a higher priority on research efforts to enhance our understanding in order to provide a meaningful, timely response." However, MTEB also concluded857 that this issue only provides a minimal risk to the public health and safety in terms of the contribution to core-melt probability.

Based on (1) the low public risk for this issue, (2) the MTEB expert opinion that steam generator leaks are more likely than SGRs859 (currently supported by the IP-3 and Garigliano experiences), (3) existing staff recommendations to the industry to implement improved secondary water chemistry programs,850 (4) the OIE Information Notice858 that should promote more reliable steam generator inspections, and (5) the industry economic incentive for resolution, this issue has minimal public risk that will be even further reduced by implementation of the above actions.

However, the MTEB concerns related to the need for a better understanding of the materials cracking phenomenon, potential licensing position(s) related to meeting the original licensing design bases, and whether or not the GDC are met, are considered licensing concerns. Therefore, based on the above evaluations, staff actions already taken, and the above discussions, this issue was classified as a Licensing Issue.

As a part of the improvements to NUREG-0933, the NRC staff clarified in SECY-11-0101, “Summary of Activities Related to Generic Issues Program,” dated July 26, 2011,1967 that the Generic Issues Program will not pursue any further actions toward resolution of licensing and regulatory impact issues. Because licensing and regulatory impact issues are not safety issues by the classification guidance in the legacy Generic Issues Program, these issues do not meet at least one of the Generic Issues Program screening criteria and do not warrant further processing in accordance with Management Directive 6.4, “Generic Issues Program,” dated November 17, 2009.1858 Therefore, this issue will not be pursued any further in the Generic Issues Program.

REFERENCES

  1. NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants,” U.S. Nuclear Regulatory Commission, (1st Ed.) November 1975, (2nd Ed.) March 1980, (3rd Ed.) July 1981.
  1. NUREG-0691, “Investigation and Evaluation of Cracking Incidents in Piping in Pressurized Water Reactors,” U.S. Nuclear Regulatory Commission, September 1980.
  1. WASH-1400 (NUREG-75/014), “Reactor Safety Study: An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants,” U.S. Atomic Energy Commission, October 1975.
  1. EPRI NP-2230, “ATWS: A Reappraisal, Part 3,” Electric Power Research Institute, 1982.

  1. NUREG-1061, “Report of the U.S. Nuclear Regulatory Commission Piping Review Committee,” U.S. Nuclear Regulatory Commission, (Vol. 1) August 1984, (Vol. 2) April 1985, (Vol. 3) November 1984, (Vol. 4) December 1984, (Vol. 5) April 1985.
  1. NUREG-0844, “NRC Integrated Program for the Resolution of Unresolved Safety Issues A-3, A-4, A-5 Regarding Steam Generator Tube Integrity,” U.S. Nuclear Regulatory Commission, September 1988.
  1. Note to R. Vollmer from T. Speis, “Proposed Request to Perform Research on the Stress-Corrosion Cracking of Pressure Boundary Ferritic Steels in Selected Environments,” January 7, 1985. [9909290082]
  1. Letter to J. Bayne (Power Authority of the State if New York) from S. Varga (U.S. Nuclear Regulatory Commission), “Steam Generator Tube and Girth Weld Repairs at the Indian Point Nuclear Generating Plant, Unit No. 3 (IP-3),” May 27, 1983. [8306150627]
  1. “Value-Impact Analysis of Recommendations Concerning Steam Generator Tube Degradations and Rupture Events,” Science Applications, Inc., February 2, 1983.
  1. Regulatory Guide 1.99, “Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials,” U.S. Nuclear Regulatory Commission, July 1975, (Rev. 1) April 1977 [7907100362], (Rev. 2) May 1988. [8907270187]
  1. IE Information Notice 82-37, “Cracking in the Upper Shell to Transition Cone Girth Weld of a Steam Generator at an Operating Pressurized Water Reactor,” U.S. Nuclear Regulatory Commission, September 16, 1982. [8208190220]
  1. Letter to D. Smith (U.S. Nuclear Regulatory Commission) from E. Rahe (Westinghouse), January 17, 1982. [9909290085]
  1. NUREG/CR-3281, “Investigation of Shell Cracking on the Steam Generators at Indian Point Unit No. 3,” U.S. Nuclear Regulatory Commission, June 1983.
  1. NUREG/CR-3614, “Constant Extension Rate Testing of SA302 Grade B Material in Neutral and Chloride Solutions,” U.S. Nuclear Regulatory Commission, February 1984.
  1. Letter to W. Hazelton (U.S. Nuclear Regulatory Commission) from H. Watanabe (GE), “‘Laboratory Examination of Garigliano Secondary Steam Generator-B Core Samples,’ NEDE-25162, July 1979,” December 13, 1979. [7912130566]
  1. EPRI NP-1136, “Limiting Factor Analysis of High Availability Nuclear Plants (Boiling Water Reactors),” Electric Power Research Institute, (Vol. 1) August 1979.
  1. Regulatory Guide 1.56, “Maintenance of Water Purity in Boiling Water Reactors,” U.S. Nuclear Regulatory Commission, (Rev. 1) July 1978.
  1. NUREG/CR-3842, “Steam Generator Group Project Task 8—Selective Tube Unplugging,” U.S. Nuclear Regulatory Commission, July 1984.
  1. Letter to All PWR Licensees of Operating Reactors, Applicants for Operating Licenses, and Holders of Construction Permits, and Ft. St. Vrain from U.S. Nuclear Regulatory Commission, “Staff Recommended Actions Stemming from NRC Integrated Program for the Resolution of Unresolved Safety Issues Regarding Steam Generator Tube Integrity (Generic Letter 85-02),” April 17, 1985. [8504120031]
  1. NUREG/CP-0058, “Twelfth Water Reactor Safety Research Information Meeting,” U.S. Nuclear Regulatory Commission, (Vol. 4) January 1985.
  1. NUREG/CP-0044, “Proceedings of the International Atomic Energy Agency Specialists' Meeting on Subcritical Crack Growth,” U.S. Nuclear Regulatory Commission, (Vol. 1) May 1983, (Vol. 2) May 1983.
  1. “Corrosion Fatigue Crack Growth in Reactor Pressure Vessel Steels—Structural Integrity of Light Water Reactor Components,” P. Scott et al., Elsevier Science Publishing Co., Inc., 1982.
  1. NUREG/CR-4121, “The Effects of Sulfur Chemistry and Flow Rate on Fatigue Crack Growth Rates in LWR Environments,” U.S. Nuclear Regulatory Commission, February 1985.
  1. NUREG-0975, “Compilation of Contract Research for the Materials Engineering Branch, Division of Engineering Technology,” U.S. Nuclear Regulatory Commission, (Vol. 2) March 1984.
  1. PNO-II-85-41, “Small Steam Generator Surface Cracks,” U.S. Nuclear Regulatory Commission, April 23, 1985. [8504290412]
  1. Memorandum for W. Minners from B. Liaw, “Prioritization of Generic Issue No. (111) Stress Corrosion Cracking of RCPB Ferritic Steels and Steam Generator Vessels,” June 7, 1985. [8506170320]
  1. IE Information Notice 85-65, “Crack Growth in Steam Generator Girth Welds,” U.S. Nuclear Regulatory Commission, July 31, 1985. [8507290456]
  1. Memorandum for H. Thompson from J. Knight, “Steam Generator Shell Transition Joint Cracking,” July 10, 1985. [8507190409]
  1. NUREG-0937, “Evaluation of PWR Response to Main Steamline Break with Concurrent Steam Generator Tube Rupture and Small-Break LOCA,” U.S. Nuclear Regulatory Commission, December 1982. [8412190335]
  1. Management Directive 6.4, “Generic Issues Program,” U.S. Nuclear Regulatory Commission, November 17, 2009.
  1. SECY-11-0101, “Summary of Activities Related to Generic Issues Program,” July 26, 2011. [ML111590814]
Page Last Reviewed/Updated Thursday, March 29, 2012