Resolution of Generic Safety Issues: Issue 67: Steam Generator Staff Actions (Rev. 5) ( NUREG-0933, Main Report with Supplements 1–35 )
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DESCRIPTION
Following the SGTR event at Ginna on January 25, 1982, increased staff effort was placed on developing means to mitigate and reduce steam generator tube degradations and ruptures. To meet these objectives, two steps were taken. The first step was to develop staff requirements to be implemented by licensees; these were evaluated in Issue 66. The second step was to develop recommendations for staff action; these were evaluated below.
The status of these actions as determined in this evaluation is listed in Table 3.67-1. For reference proposes, the sub-item numbers are consistent with the staff action numbers provided by DL/NRR.752 These items are also included in the CRGR review package753 and EDO recommendations to the Commission.753,757,758 The following is a summary of the evaluation of the 16 parts of this issue.
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The basis for each of the 16 recommended staff actions is provided in separate evaluations below.
| Sub-Item | Staff Action | Priority | MPA No. |
|---|---|---|---|
| TABLE 3.67-1 | |||
| 67.2.1 | Integrity of Steam Generator Tube Sleeves | 135 | NA |
| 67.3.1 | Steam Generator Overfill | A-47, I.C.1 | NA |
| 67.3.2 | Pressurized Thermal Shock | A-49 | NA |
| 67.3.3 | Improved Accident Monitoring | NOTE 3(a) | A-17 |
| 67.3.4 | Reactor Vessel Inventory Measurement | II.F.2 | F-26 |
| 67.4.1 | RCP Trip | II.K.3(5) | G-01 |
| 67.4.2 | Control Room Design Review | I.D.1 | F-08 |
| 67.4.3 | Emergency Operating Procedures | I.C.1 | F-05 |
| 67.5.1 | Reassessment of Radiological Consequences | LI(NOTE 3) | NA |
| 67.5.2 | Reevaluation of SGTR Design Basis | LI(67.5.1) | NA |
| 67.5.3 | Secondary System Isolation | DROP | NA |
| 67.6.0 | Organizational Responses | III.A.3 | NA |
| 67.7.0 | Improved Eddy Current Tests | 135 | NA |
| 67.8.0 | Denting Criteria | 135 | NA |
| 67.9.0 | Reactor Coolant System Pressure Control | A-45, I.C.1(2,3) | F-04, F-05 |
| 67.10.0 | Supplemental Tube Inspections | LI(NOTE 5) | NA |
ITEM 67.2.1: INTEGRITY OF STEAM GENERATOR TUBE SLEEVES
DESCRIPTION
Historical Background
This item was Recommendation 2.1 of the DL/NRR memorandum752 and called for the staff to develop an SRP11 Section to clarify staff positions on the materials design, fabrication, installation, examination, and inspection of steam generator tube sleeves.
Safety Significance
At the time this issue was raised, there was no specific SRP11 Section to guide the staff/industry in reviews related to the design, installation, and inspection of tube sleeves. Development of an SRP11 would provide an acceptable means to meet GDC 14 and GDC 32 of 10 CFR 50, Appendix A.
PRIORITY DETERMINATION
Consequence Estimate
The public risk reduction attributable to this recommendation was not quantifiable. It was believed that some small improvement in the effectiveness of sleeves to perform their intended function (i.e., assure retention of structural integrity of degraded tubes) could result from improved guidance.
Cost Estimate
Three man-months of NRC staff time ($25,000) were estimated for the development of the SRP.11 It was estimated that 25% of the operating and planned PWRs (22 plants) would require tube sleeve modifications. The SRP11 could reduce plant-specific reviews from 2 man-months to 1 man-month and was expected to also reduce industry manpower requirements by approximately the same amount. Therefore, the SRP11 would result in cost savings of $158,000 and $183,000 to the NRC and industry, respectively, for a combined saving of $341,000.
CONCLUSION
A small public risk reduction was achievable from development of an SRP11 on steam generator tube sleeves. However, the SRP would be cost-effective in that it would reduce NRC review cost and industry costs associated with the design, installation, and inspection requirements for tube sleeves. The earlier the SRP11 was developed, the greater the cost saving. This issue was addressed in the resolution of Issue 135.1075
ITEM 67.3.1: STEAM GENERATOR OVERFILL
DESCRIPTION
Historical Background
This item was Recommendation 3.1 of the DL/NRR memorandum752 and called for the NRC to select a small number of PWRs representing the PWR spectrum of designs and determine the potential for, and consequences of, steam generator overfill as a result of an SGTR. This recommendation was closely related to Items 67.5.1, 67.5.2, and 67.9. Based on the results of these studies, further NRC or licensee actions were to be determined. Potential steam generator overfill resulting from control system failures were not considered in this recommendation. Steam generator overfill via control systems failures were evaluated in the resolution of Issue A-47; Issues 37 and 56 were also related issues.
Safety Significance
Following an SGTR, the affected steam generator could fill up to the steam line safety valve due to primary-to-secondary leakage from continued operation of the safety injection pumps. The safety valve could lift at successively lower pressures and fail to fully reseat. The failure to completely reseat could contribute to steam generator overfill by lowering the damaged steam generator pressure, thus raising the differential pressure across the broken tube and sustaining the leakage despite reduced primary system pressure. Failure of the valve to reseat would also provide a direct pathway for release of radioactive primary water to the environment. This sequence of events is beyond the design basis for SGTR events in SRP11 Section 15.6.3 to establish that the radiological consequences meet 10 CFR 100.
For the B&W OTSG design in particular, it may not be possible to stop the primary-to-secondary leakage in an SGTR while maintaining the RCS in a subcooled state. The increased tendency for the OTSG leakage to continue throughout the event is a result of the tubes being directly exposed to the OTSG steam space. Generally, the emergency procedures instruct the operator to discharge steam to the atmosphere or, if available, to the condenser to control level in the damaged steam generator, as necessary. However, in at least one B&W plant, if the water supply for safety injection pumps is approaching a minimum level or if the offsite radiological consequences are becoming excessive, the OTSG is allowed to completely fill, thus terminating the leakage. The number of B&W plants that permit filling of the OTSG was not known. The staff did not believe that the potential for prolonged leakage and the associated offsite radiological consequences had been factored into OR or NTOL FSAR SGTR accident analyses. (See Item 67.5.2).
Possible Solutions
Solutions could involve improved RCS pressure control to reduce the differential pressure and leakage across the broken steam generator tube (primary to secondary), and/or improved EOPs to preclude overfill. The above measures were discussed in response to staff recommendations concerning RCS pressure control and EOPs. (See Items 67.9.1 and 67.4.3). With regard to the concern that the steam lines cannot support the dead-weight load if the lines are filled with water, additional supports or stronger steam lines could resolve this aspect of the concern.
PRIORITY DETERMINATION
Cost Estimate
The NRC cost would be dependent on the number of PWRs selected for this study and the design variations within this selected group.
Other Considerations
Following the Ginna event, concerns were raised relative to the potential for failing the steam lines under the additional dead-weight load if they are filled with water as a result of steam generator overfill. (The Point Beach SGTR, which was a relatively low leak rate, resulted in a near overfill condition.)755 Should the steam lines fail, the SGTR could become a LOCA outside containment. However, analyses753 conducted for 4 plants indicated that the steam lines were unlikely to fail under the additional dead-weight load. Accordingly, the staff's risk analyses753 assumed a conditional probability of steam line break, given a steam generator overfill, of 10-3 which was believed to be reasonably conservative. If the steam lines were re-designed to withstand an overfill condition, the analysis753 would indicate a reduction in core-melt frequency of 1.2 x 10-7/RY.
The consequence resulting from failure of the steam lines by overfilling the steam generators was assumed to involve releases typical of a PWR Category 4 release. Exposure was calculated assuming a typical mid-West meteorology and a population density of 340 persons/square-mile within a 50-mile radius of the plant. The potential public risk reduction was therefore [(1.2 x 10-7)(2.7 x 106)] man-rem/RY or 0.32 man-rem/RY. Considering an average remaining plant life of 24 years, the public risk reduction was about 8 man-rem/reactor.
CONCLUSION
This item encompassed several considerations related to steam generator overfills and was closely related to staff studies identified in Items 67.5.1, 67.5.2, and 67.9. The primary concern (mitigation of a steam generator overfill) was part of the following existing staff programs: (1) Issue A-47; and (2) NUREG-0737,98 Item I.C.1 (See Item 67.4.3). Therefore, the steam generator overfill issue was covered by the above programs. Rupture of steam lines as a result of a steam generator overfill is a secondary concern predicated on the condition that an overfill occurs. The public risk associated with rupture of steam lines is low and strengthening of the steam lines was considered a LOW priority.
ITEM 67.3.2: PRESSURIZED THERMAL SHOCK
DESCRIPTION
Historical Background
This item was Recommendation 3.2 of the DL/NRR memorandum752 and called for the staff to address the effects of RCS flow stagnation associated with isolation of a steam generator in the Pressurized Thermal Shock program (Issue A-49).
Safety Significance
During the Ginna SGTR event, the affected steam generator was isolated and the RCPs were tripped. As a result, the flow in the `B' Reactor Coolant Loop was reduced to a few hundred gpm while cold high pressure injection water was being injected into the loop. The cold leg piping apparently experienced a cool-down of approximately 260°F in 30 minutes. The reactor vessel apparently did not experience this rapid cool-down since the flow in the cold leg was in the reverse direction, i.e., from the reactor vessel towards the steam generator. Other events, as discussed in NUREG-0916,754 resulting in a steam generator isolation and continued safety injection could result in adding cold water to the reactor vessel.
CONCLUSION
The probability, consequences, and resolution of the above events were addressed in Issue A-49.
ITEM 67.3.3: IMPROVED ACCIDENT MONITORING
DESCRIPTION
Historical Background
This item was Recommendation 3.3 of the DL/NRR memorandum752 and called for the staff to address the accident monitoring weaknesses of the type observed at Ginna by implementation of Regulatory Guide 1.9755 and the SPDS.
Safety Significance
During the event at Ginna, several weaknesses in accident monitoring were apparent. These included: (1) non-redundant monitoring of RCS pressure; (2) failure of the position indication for the steam generator relief and safety valves; and (3) the limited range of the charging pump flow indicator for monitoring charging flow during accidents. These conditions make it more difficult for correct operator action in response to such events.
Possible Solution
Had Regulatory Guide 1.9755 been implemented at Ginna before the January 1982 event, the monitoring of the event would have been substantially improved and there would have been more assurance of correct operator actions. Improved accident monitoring would also have improved the NRC's ability to assess the plant status and the appropriateness of the licensee's actions and recommendations.
CONCLUSION
This issue was covered in Supplement 1 to NUREG-073798 (Generic letter No. 82-33)376 and was RESOLVED and implemented as MPA A-17.
ITEM 67.3.4: REACTOR VESSEL INVENTORY MEASUREMENT
DESCRIPTION
Historical Background
This item was Recommendation 3.4 of the DL/NRR memorandum752 and called for implementation of TMI Action Plan Item II.F.2 because it would have substantially improved the Ginna situation by ensuring that steam bubble formation in the reactor vessel upper head could be more accurately monitored.
Safety Significance
During the Ginna SGTR event, the formation of a steam bubble in the reactor vessel upper head significantly complicated the course of the event. The uncertainty about the bubble size was a significant factor in the operator's decisions to continue safety injection beyond the point when termination was called for in the emergency procedures.
Possible Solution
Implementation of NUREG-0737,98 Item II.F.2.
CONCLUSION
Following Commission approval for implementation of Item II.F.2, letters to individual licensees and orders to B&W licensees and ANO-2 were issued on December 10, 1982.491 Thus, this issue was covered in Item II.F.2 which was resolved and implemented as MPA F-26.
ITEM 67.4.1: REACTOR COOLANT PUMP TRIP
DESCRIPTION
Historical Background
This item was Recommendation 4.1 of the DL/NRR memorandum752 and called for the NRC to develop requirements for licensees to provide RCP trip criteria that would ensure continued forced RCS flow during steam generator tube breaks, up to and including the design basis tube rupture.
Safety Significance
Analyses indicated that continued operation of the RCPs following a range of small LOCAs could lead to excessive inventory loss for which the high pressure injection system would be unable to compensate. Generally, the range of break size of concern was from 0.02 to 0.2 ft2 (2 to 5 inches equivalent diameter). The interim position (documented in NUREG-0623)97 required manual-tripping of the RCPs on the symptoms of a small LOCA (i.e., a safety injection signal and low RCS pressure).
CONCLUSION
This issue was covered in NUREG-0737,98 Item II.K.3(5), which was resolved and implemented as MPA G-01.
ITEM 67.4.2: CONTROL ROOM DESIGN REVIEW
DESCRIPTION
This item was Recommendation 4.2 of the DL/NRR memorandum.752 As a result of a review of the Ginna control room following the tube rupture, several items related to the event were identified that were contrary to good human factors engineering principles. It was recommended that these items be reviewed by HFEB/NRR as part of the detailed control room design review required by NUREG-073798 and the information used as the basis for a study to determine what changes could be made to improve control room designs.
CONCLUSION
This issue was covered in NUREG-0737,98 Item I.D.1, which was resolved and implemented as MPA F-08.
ITEM 67.4.3: EMERGENCY OPERATING PROCEDURES
DESCRIPTION
Historical Background
This item was Recommendation 4.3 of the DL/NRR memorandum,752 the purpose of which was to ensure that newly-developed EOPs consider the experiences from the Ginna SGTR event. PSRB/NRR was expected to review the items listed below prior to emergency procedure implementation for inclusion in its review plan. This staff effort was to be considered in conjunction with existing work on NUREG-0737,98 Item I.C.1.
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Safety Significance
The above list included transients and plant conditions that form the basis of many of the emergency procedures, reliability analyses, human factors engineering, crisis management, and operator training. Plant conditions may exist, in addition to those pertinent to design bases, which could prevent proper operator actions during such events/conditions and possibly pose a serious threat to reactor safety.
Possible Solution
The solution to this recommendation was to consider the Ginna event in the development of EOPs.
PRIORITY DETERMINATION
Guidance for the evaluation and development of procedures for transients and accidents was covered by Item I.C.1 of NUREG-0737.98 Some of the items in the above list were explicitly included in the review requirements of Item I.C.1. Other items in the list are believed to be implicitly within the intent of Item I.C.1 in that the availability of systems under expected conditions (like Ginna) should be used in developing diagnostic guidance for operator and procedural development.
CONCLUSION
This issue was covered in NUREG-0737,98 Item I.C.1, which was resolved and implemented as MPA F-05.
ITEM 67.5.1: REASSESSMENT OF RADIOLOGICAL CONSEQUENCES
DESCRIPTION
Historical Background
This item was Recommendation 5.1 of the DL/NRR memorandum752 and called for the staff to reassess SGTR events at W and CE plants only to determine the effects of releases made for periods substantially longer and via other release points than those previously analyzed. These analyses should specifically address the applicability of the assumptions in SRP11 Section 15.6.3 and address the costs and benefits of requiring revised analyses by licensees. This issue was closely related to Items 67.5.2 and 67.3.1.
Safety Significance
Public risk from an SGTR, even considering steam generator overfill, was considered low for a typical PWR. This low risk was expected to remain valid even if new source term results were applied. However, the safety significance of this issue was derived from concern over the number of SGTR events and potential for exceeding the bounds of the analyses that are currently required in SRP11 Section 15.6.3 to demonstrate that doses from SGTR events will not exceed 10 CFR 100.
PRIORITY DETERMINATION
SRP11 Section 15.6.3 does not address a steam generator overfill in the SGTR scenario. In addition, termination of the leak from an SGTR within 30 minutes, as assumed in typical PWR FSARs, may be non-conservative and not consistent with operating experience. Therefore, implementation of this recommendation would allow the staff to upgrade SRP11 Section 15.6.3 and provide a better understanding and means to assess future SGTR events in operating plants relative to the consequence limits in 10 CFR 100.
Information generated from implementation of this recommendation would also assist licensees in their understanding of similar events and help determine the course of action needed to mitigate the consequences of SGTRs and overfilling of the steam generators.
CONCLUSION
Resolution of this issue was not expected to result in significant public risk reduction and, therefore, it was considered a low priority. However, AEB/NRR considered it a Licensing Issue and recommended the reassessment. DST/NRR agreed that a "best estimate" analysis modeled after plant experience like Ginna could be beneficial in more realistically determining the risk and conservatisms inherent in the existing SRP11 requirements. The issue was finally resolved1554 with recommended changes to SRP11 Section 15.6.3.
ITEM 67.5.2: REEVALUATION OF SGTR DESIGN BASIS
DESCRIPTION
Historical Background
This item was Recommendation 5.2 of the DL/NRR memorandum752 and called for the NRC to reevaluate and consider reclassifying or redefining the design basis SGTR event. This issue was closely related to Issues 67.3.1 and 67.5.1.
An SGTR accident is one of the events for which the NRC requires a safety analysis to show that a reactor will respond in an acceptable manner and that the health and safety of the public are adequately protected. The SGTR accident is the loss of integrity (development of a leak) in a steam generator tube (or tubes) so that reactor coolant water from the primary system flows into the secondary water in the steam generator. This provides a potential path for the release of radioactivity to the environment.
As analyzed in SARs, the event is a break of a single steam generator tube with flow out of the full-flow area of both ends of the steam generator tube at the break. The reactor is assumed to be at full power at the time of the accident.
The SGTR accident serves as the design basis for allowable reactor coolant activity since the amount of radioactivity released to the environment is directly proportional to the amount of activity in the coolant. The analysis of this event in SARs is intended to bound the potential release of radioactivity, should an SGTR occur. The behavior of reactor systems during this event has not traditionally received much emphasis, either in the analyses reported by the licensees or during review by the NRC.
Safety Significance
The safety significance of this recommendation was derived from the concern over the number of SGTR events and the potential for exceeding the bounds of the analyses that were required in SRP11 Section 15.6.3 to demonstrate that doses from SGTR events will not exceed 10 CFR 100.
PRIORITY DETERMINATION
The analysis of an SGTR is performed to bound potential offsite doses using many conservative assumptions (i.e., accident terminated within 30 minutes) to maximize the predicted doses (SRP11 Section 15.6.3). The probability of the simultaneous occurrence of the SRP11 conditions is extremely low. SGTR events have occurred at a frequency of approximately 2 x 10-2/RY. Therefore, this event could be classified as an incident that might occur during the lifetime of a particular plant.
SGTR events that have actually occurred were not as severe as the SRP11 design basis event. Had the frequencies of the conservative assumptions been included in a calculation of a design basis frequency, a much lower frequency would result. A change in classification would necessarily require changes to the conservative analysis assumptions (listed in the SRP11). Changes to the design basis assumptions may include more conservative limits on the reactor coolant activity for those plants that do not have STS limits on coolant iodine concentrations, SGTR overfill conditions, multiple ruptures of the steam generator tubes, and other conditional failure scenarios.
CONCLUSION
The basis for this issue was derived from the number of SGTR events that occurred and the existing potential for doses from these events that exceeded 10 CFR 100 guidelines. However, these doses would occur only if there were an unlikely (but not impossible) set of circumstances as discussed in detail in Section 8.1 of NUREG-0916.754
For the 4 SGTRs that occurred, there were no significant consequences to the public and the existing design basis SGTR was proven to be adequate. The staff believed that it was premature to establish a priority for reclassification of the design basis SGTR event, prior to obtaining the results from other Staff Actions (See Item 67.5.1). Therefore, this issue was considered a Licensing Issue and was integrated into the resolution of Item 67.5.1.
ITEM 67.5.3: SECONDARY SYSTEM ISOLATION
DESCRIPTION
Historical Background
This item was Recommendation 5.3 of the DL/NRR memorandum752 and called for the NRC to reevaluate the provisions for isolating the steam generators in conjunction with Items 67.3.1 and 67.5.1. The evaluation was expected to consider whether the existing provisions for isolating the main steam and feedwater lines were adequate, with particular emphasis on isolation of the steam generator with RCS loop isolation valves that utilized closed bonnet secondary safety valves or contained the discharge from the steam generator safety and relief (atmospheric dump) valves.
Safety Significance
The primary safety significance of SGTR events is the potential for a direct path for a loss of radioactive coolant from the RCS through the steam generator to outside the containment. This event could also increase the probability of a core-melt because the reactor coolant leaking from a steam generator tube cannot be recirculated. Other systems that penetrate the containment and interface either with the RCS or the containment have two containment isolation valves that close automatically or are locked closed. The steam generator safety and atmospheric valves open automatically and, as required by the ASME Code, cannot be isolated.
Possible Solution
Some of the older PWRs have block valves in the reactor coolant loops that could be used to isolate the steam generators and prevent the loss of coolant and radioactivity from the RCS. Alternatively, the discharge from the steam generator safety and relief valves could be routed to return to the containment or a quench tank. GDC 57 requires each line that penetrates containment (and is neither part of the RCS nor connected to the containment atmosphere) to have at least one isolation valve that is locked closed, automatic, or capable of remote operation. GDC 57 was not interpreted to apply to the valves on the steam generator. However, some improved means of isolating the steam generator, possibly either by requiring loop isolation valves in the RCS or containment of the safety valve discharge, could be considered.
PRIORITY DETERMINATION
Recommendation 8 of NUREG-0651755 stated "... For those plants provided with loop isolation valves, the use of these valves following an SGTR should be investigated. Isolating the affected loop would provide an almost immediate abatement of steam generator tube leakage, but would prohibit cool-down of the damaged steam generator. Licensees should, therefore, examine the advantages and disadvantages in their plant of loop isolation." As pointed out in NUREG-0651,755 the determination and isolation of the damaged steam generator appeared to take longer than the assumed 30 minutes in the FSAR analysis. In this regard, Item 67.5.1 could address this aspect of steam generator isolation.
The EOPs involved with isolation of the secondary system following an SGTR were identified in Item 67.4.3 as selected events for staff review. In isolating the steam generator, an operator's worst error could be isolating the wrong steam generator. If this were to occur, overfill of the broken steam generator could still result. In addition, the intact steam generator which is isolated could boil dry. Saturated conditions in this hot leg could result. When the operator recognizes the error, isolates the faulted steam generator, and opens the intact steam generator, he might have no steam generator cooling since natural circulation might have become inhibited through the intact steam generator due to void formation. The faulted steam generator would then be isolated, resulting in minimal transfer of heat. The operator could unisolate the faulted steam generator and steam either to the condenser (if available) or to the atmosphere, but this would result in increased offsite doses.
The W SGTR guidelines contain a note that advises operators not to use the loop isolation valves in the event of an SGTR. They further state that "... any use of LSIVs (Loop Stop Isolation Valves) must be justified on a plant-specific basis." The reasons given by W for not using these valves were: (1) their use has not been included in any accident analyses; (2) they are not meant to be safety components; (3) their use has not been recommended, since steam generator isolation has not been shown necessary to limit releases to an acceptable value; (4) the valves are very slow acting and take minutes to close; and (5) their subsequent re-opening required a rather careful procedure.
CONCLUSION
Many PWRs do not have LSIVs for use in an SGTR accident. For those plants that have them, modifications would likely be required. However, based on the above discussion, the valves did not appear to be necessary. In each of the SGTR events that occurred, the operator took correct action and in none of the events did incorrect action result in any significant adverse effect to the public. In each event, the SGTR was isolated to the faulted steam generator. Therefore, this issue was placed in the DROP category.
ITEM 67.6.0: ORGANIZATIONAL RESPONSES
DESCRIPTION
Historical Background
This item was Recommendation 6.0 of the DL/NRR memorandum752 and called for the staff to establish, as soon as possible, improved NRC emergency preparedness to handle nuclear accidents at licensed reactor facilities.
Safety Significance
In the event of a nuclear accident, improved NRC emergency preparedness procedures will enable NRC to monitor and evaluate the situation and its potential hazards, advise the licensee's operating staff as needed, and, in an extreme case, issue orders governing such operations.
Possible Solution
Resolution of this item centered around implementation of TMI Action Plan Item III.A.3.
CONCLUSION
This issue was covered in TMI Action Plan Item III.A.3.
ITEM 67.7.0: IMPROVED EDDY CURRENT TESTS
DESCRIPTION
Historical Background
Improved Eddy Current Tests (ECT) were originally proposed by the staff as requirements to be implemented by licensees. Improved ECT could enhance earlier detection of degradations and thereby minimize, or mitigate, steam generator tube degradations and ruptures. The evaluation of improved ECT as a requirement (Item 66.3) showed that use of current state-of-the-art improvements provided only small reductions in public risk. Likewise, since ECT was an evolving technology, imposition of any requirement was determined to be premature. However, it was also recognized that significant potential reductions in ORE could result from use of improved ECT. Therefore, this item was believed to warrant a medium priority ranking. The conclusion reached in Item 66.3 was consistent with the position that improved ECT should be handled as a Staff Action item and developed in accordance with the possible solution described below.
Safety Significance
The steam generator tube that ruptured at Ginna exhibited no ECT indication during earlier testing. Improved ECT techniques would most likely have given indications and the event could have been avoided.
Possible Solution
This effort, conducted in parallel with ongoing ASME Code Committee activities, would incorporate updated eddy current inspection procedures in the ASME Boiler and Pressure Vessel Code, Sections V and XI for NDE and ISI, respectively. The improved test procedures would be considered part of the in-service ECT of PWR steam generator tubing.
PRIORITY DETERMINATION
In a previous evaluation756 by the staff, it was determined that improved ECT techniques would provide small reductions in public risk and, therefore, was considered a low priority. It was also concluded that significant reductions in ORE could result from use of improved ECT techniques. The priority ranking based on the ORE reduction potential was medium. Improved ECT would also enhance the certainty that defective or degraded tubes would be identified and removed from service to assure meeting 10 CFR 100 release limits. The latter condition could be argued to classify improved ECT as a licensing issue. In either classification, an economic incentive for use of improved ECT of up to $5M/plant, based on avoided cost of forced outages, could be obtainable. Based on a combination of the above potential benefits, development of improved ECT procedures was recommended as a medium priority principally because of the potential reductions in ORE.
CONCLUSION
This issue was integrated into the resolution of Issue 135.1075
ITEM 67.8.0: DENTING CRITERIA
DESCRIPTION
Historical Background
This item concerned a staff recommendation to develop generic inspection criteria and methods to quantify steam generator tube denting. Operating experience showed that surveillance of steam generator tubes was necessary to identify denting and to take corrective action to mitigate the stress corrosion cracking induced by denting.
Safety Significance
Denting can enhance stress corrosion cracking leading to through-wall cracks and leaks in steam generator tubes. Denting, combined with flow slot `hourglassing,' caused the U-bend stress corrosion cracking that led to the SGTR at Surry Unit 2 in September 1976.
Possible Solution
Development of a generic inspection requirement and criteria for steam generator tube denting will provide assurance that minimum standards for denting are applied uniformly.
PRIORITY DETERMINATION
Frequency Estimate
At the time of this evaluation, only one SGTR event was attributed to the denting phenomena in approximately 300 RY of operation. This corresponded to an SGTR frequency of 3 x 10-3/RY. Therefore, the SGTR contribution to a core-melt frequency of 4.7 x 10-6/RY contained a contribution of approximately 15% or 7 x 10-7/RY due to denting.
Consequence Estimate
The PWR Category 4 release of 2.7 x 106 man-rem was used to estimate the consequences of a core-melt associated with an SGTR. Using the above frequencies, the public risk, annualized over a remaining plant life of 24 years, yielded a public risk of [(7 x 10-7)(2.7 x 106)(24)] man-rem/plant or 45 man-rem/plant. Based on the assumption that approximately 40 of the operational and planned PWRs (~90 plants) had or will experience denting problems, the total public risk was approximately 1,800 man-rem. Assuming a 30% reduction due to improved denting surveillance criteria resulted in a total public risk reduction of 13.5 man-rem/plant and 540 man-rem for 40 plants.
Cost Estimate
Industry Cost: It was estimated that, as a minimum, with the use of generic denting criteria from the STS, the industry cost benefit would parallel the NRC cost benefit.
NRC Cost: The estimated cost to develop the denting criteria was based on 3 man-months of effort; at $100,000/man-year, this cost was $25,000. The implementation mechanism was assumed to be an STS revision. It was assumed that the denting criteria in the STS would apply to NTOL and CP plants and those operating plants that experienced denting problems. Using the same ratio (40/90) as used in the above risk determination, 40 of the total of 90 plants will require implementation of the STS denting criteria. It was also estimated that development of generic denting criteria would reduce NRC plant-specific review time by 2 man-weeks/plant. The result was a cost saving of (40)(2)($1,920) or $153,600. The net cost benefit to the NRC was approximately $128,600.
Based on the above assumptions, development of generic denting criteria had a total net cost benefit of approximately $250,000.
Value/Impact Assessment
The public risk reduction associated with implementation of generic denting criteria was not significant. The major value in development of these criteria was that it could provide a net cost benefit to the NRC and industry. No negative impacts (adverse changes to existing plant-specific criteria) were assumed in this evaluation.
CONCLUSION
In consideration of the low potential public risk reduction, development of generic denting criteria was considered a low priority. However, the generic denting criteria provided a small public risk reduction potential and could result in a net cost reduction for the NRC and industry. The issue was addressed in the resolution of Issue 135.1075
ITEM 67.9.0: REACTOR COOLANT SYSTEM PRESSURE CONTROL
DESCRIPTION
Historical Background
This item addressed Recommendation 9 of the DL/NRR memorandum752 and called for a study to determine the need for controlling and reducing RCS pressure during and following an SGTR with emphasis on existing plant systems and equipment. The spectrum of possible initial conditions, RCS thermal-hydraulic conditions, and break sizes were to be considered. The use of the pressurizer auxiliary system was to be explicitly examined since its use could eliminate the necessity to use the pressurizer PORV in cases where forced RCS flow is lost. The study was to address the following objectives: (1) minimizing the primary to secondary leakage through the broken steam generator tube; (2) maximizing control over system pressure; and (3) minimizing the chances of producing voids in the RCS and other complicating effects.
Safety Significance
RCS depressurization following an SGTR is more difficult because of the loss of normal pressurizer spray. RCS fluid contraction, caused by the cool-down from the dumping of secondary-side steam to either the main condenser or to the atmosphere, will result in some reduction in RCS pressure, but other measures must be taken to expeditiously reduce the RCS pressure to the point where primary coolant flow into the damaged steam generator stops.
The pressurizer PORV was used during the Ginna and Prairie Island SGTR events to reduce RCS pressure. However, control of RCS pressure is difficult with the PORV since its use creates an additional loss of coolant. The decrease in RCS pressure can be so rapid that steam voids may be formed in the reactor vessel upper head and at the top of the steam generator U-tubes and may further complicate the RCS depressurization. Void formation can lead to concerns regarding core cooling. The Ginna operators were sufficiently concerned that they left the safety injection pumps operating, thereby overfilling the steam generator via primary-to-secondary leakage through the ruptured tube. The resulting secondary-side pressure transient caused the main steam safety valves to lift, releasing radioactive material directly to the atmosphere. It was not apparent that the auxiliary spray from the charging system could have successfully lowered RCS pressure to the point where primary coolant flow into the steam generators could have been stopped. It may have been that, by spraying cold charging fluid into the pressurizer, the decrease in pressure would have resulted in void formation thus expanding the RCS fluid volume, filling the pressurizer, and rendering further spray flow ineffective. This phenomenon was to be examined as well as the thermal stresses on the spray nozzle.
Possible Solution
With optimized RCS pressure control, the risk associated with an SGTR could be reduced by reducing the potential radiological consequences.
PRIORITY DETERMINATION
Frequency Estimate
Independent analyses by the staff considered three categories of SGTR events: (1) SGTR and loss of DHR; (2) SGTR resulting from LOCA; and (3) SGTR with loss of secondary system integrity. For Categories 1 and 2 above, the core-melt probabilities were not dominated by SGTRs and were calculated to be 5.5 x 10-7/RY and 3 x 10-8/RY, respectively. Category 3 included single and multiple tube ruptures followed by stuck-open steam generator safety valves, MSLB, failure of the MSIVs, steam generator overfill, and failure to depressurize the RCS before the RWST was exhausted. The latter was considered since recirculation water from the sump might not be available following an SGTR event should a loss of secondary system integrity (e.g., stuck-open safety valve, MSLB) occur outside containment.
It was assumed that RCS pressure control would enhance depressurization of the RCS by a factor of 10 for the Category 3 sequences involving less than 10 SGTRs. For greater than 10 SGTRs, the depressurization was assumed to be too rapid for the RCS pressure control to be effective. The result would be a reduction in core-melt frequency of 1.8 x 10-6/RY for enhanced RCS pressure control.
Consequence Estimate
The consequences resulting from an SGTR would involve releases typical of a PWR Category 4 release as used in WASH-140016 and modified to a typical meteorology with a population density of 340 persons/square-mile within a 50-mile radius of the affected plant. The public risk reduction was (1.8 x 10-6)(2.7 x 106) man-rem/RY or 4.9 man rem/RY. Considering an average remaining plant life of 24 years, the public risk reduction was estimated to be 117 man-rem/reactor.
Cost Estimate
NRC Cost: The cost of the recommended separate staff study depended on the existing capability for RCS pressure control following an SGTR and the incremental improvement required. As a minimum, the study could require a review and documentation of how existing systems and procedures already provided the requisite capability. In some plants, the study could require thermal-hydraulic modeling of the primary and secondary coolant systems as well as detailed stress analysis of selected components such as the pressurizer auxiliary spray nozzle. A study of this depth and the development of an optimized approach for RCS pressure control could cost one man-year ($100,000) or more.
TMI Action Plan Item I.C.1, clarified in NUREG-0737,98 included in its scope the development of EOPs for accidents and transients including multiple SGTRs. Likewise, the adequacy of existing and alternate means of satisfying LWR shutdown decay heat removal requirements were addressed in Issue A-45. Shutdown requirements in effect during SGTRs in PWRs were also considered in Issue A-45. Therefore, existing NRC studies negated the need for a separate study on RCS pressure control.
Industry Cost: The major cost of the study, as recommended, would be borne by the NRC and its contractors; however, input by and consultation with specific plants, plant types, or perhaps separate PWR Owners' Groups would be involved. In the latter case, NSSS Owners' Groups evaluated means of controlling reactor coolant pressure during an SGTR. The depth and scope of the Steam Generator Owners' Group (SGOG) study was expected to at least parallel the above NRC study.
The cost of implementing an optimized approach for RCS pressure control was likely to be highly variable, depending on the adequacy of the existing RCS pressure control capability and the differences between the existing and the optimized approach. The cost associated with implementing an optimized approach for RCS pressure control was not quantifiable, but could include some or all of the following items of cost: (1) developing, validating, and implementing new emergency procedures; (2) training plant operators; or (3) replacing equipment or upgrading equipment qualification if existing equipment must be operated outside of the conditions for which it was originally designed and qualified. In the scope of the recommended study, the implementation cost was moot. However, in an overall value/impact, the implementation cost could be significant.
Value/Impact Assessment
The value of the recommended NRC study on RCS pressure control was that it could uncover, or result in development of, optimized means (procedures, equipment, instrumentation) to control reactor coolant pressure to minimize primary to secondary leakage following an SGTR. Thus, the potential for overfilling a steam generator and the quantity of radioactive material released directly to the atmosphere following an SGTR should be reduced.
Based on the above frequency and consequence estimates, the value was a potential public risk reduction of 117 man-rem/reactor over an average remaining plant life of 24 years. The major initial impact was the cost of performing the study. Subsequent impacts depended on the results of the study and could not be quantified.
CONCLUSION
Based on the above, the potential public risk reduction of 117 man-rem/reactor that could be derived by a separate (new) NRC study on RCS pressure control was not highly significant. The potential value that could result from such a study would most likely be improved RCS pressure control for both accidents and transients. In this regard, staff actions developed under TMI Action Plan Items I.C.1(2,3) and Issue A-45 also resolved the objective of this issue. In addition, the work by the SGOG on RCS pressure control could have been factored into the review of Items I.C.1(2,3) and Issue A-45.
In summary, RCS pressure control was considered part of studies conducted for NUREG-0737,98 Items I.C.1(2,3), (which were resolved and implemented under MPAs F-04 and F-05) and Issue A-45.
ITEM 67.10.0: SUPPLEMENTAL TUBE INSPECTIONS
DESCRIPTION
Supplemental Tube Inspection (STI) was originally proposed by the staff as a recommended licensee action.752 The value/impact analysis756 ranked the proposed staff recommendation as a licensing issue. This ranking inferred that the staff-proposed STI would provide only small potential public risk reduction and a low value/impact ratio. However, as a minimum, the statistical sample size of the proposed STI would ensure that no more than the limiting number of defective tubes would go undetected. The limiting number of sample tubes to be inspected would be based on meeting 10 CFR 100 release limits from, and concurrent with, an MSLB. Thus, STI would provide additional assurance that existing regulatory requirements on radiological releases would be maintained and further reduce SGTRs. Subsequent information753 from industry indicated that the staff-proposed STI would result in higher costs and greater ORE than that previously estimated by the staff. The staff reevaluated753 their proposed STI and agreed in part with the industry assessment. However, it was the staff's position that some form of STI could be formulated to provide added assurance of tube integrity with less ORE and an improved value/impact relationship.
In view of the above, STI did not require licensee implementation but was identified for further staff action and evaluation.
CONCLUSION
This issue was classified as a Licensing Issue that called for the staff to investigate more practical alternatives for STI. 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
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