Resolution of Generic Safety Issues: Issue 100: Once-Through Steam Generator Level (Rev. 1) ( NUREG-0933, Main Report with Supplements 1–34 )
Once-through steam generators (OTSGs) are a feature unique to B&W reactor designs. Main feedwater is injected from a header, located at approximately mid-elevation of the OTSG, into an annular downcomer region. As the feedwater is sprayed into the downcomer, the condensing action of the relatively cold (455ºF) feedwater draws steam from the tube bundle through the aspirator ports in the inner shroud. This steam then heats the feedwater rapidly to saturation temperature (about 535ºF) preventing thermal shocking of the shell.
In 1984, Crystal River 3 submitted a TS change request to raise the operating water level limit of the OTSGs to 100% of the operating range (which is six inches above the aspirator ports). Since most operating B&W plants did not have an upper OTSG level limit in their TS, the TS change was requested to give Crystal River 3 the same operational flexibility. This change request raised a concern regarding operating OTSGs with the water level above the aspirator ports.1380
Permitting operation with a higher water level limit would allow less time for corrective operator action, if there were a transient that involved an increase in feedwater flow to one or more steam generators. If the increased feedwater flow continues (e.g., if the steam generator high-level detection system has failed, feedwater control valves have failed, or the main feedwater pump fails to trip), the steam generator water level may exceed the aspirator port level, thus preventing the preheating of the feedwater. If the increased thermal stresses on the tubes or shell wall are excessive, an SGTR or steam generator shell failure accident could occur creating a LOCA or an initial steam-side break in the case of a shell failure. This issue affected all B&W PWRs.
A possible solution entailed a detailed generic analysis to determine whether operating OTSGs at levels near or above the aspirator ports would introduce a significant safety problem at B&W plants. New plant-specific TS limits would have to be developed to preclude plant operations if OTSG water levels exceed a pre-set maximum level.
All ten of the operating or proposed B&W PWRs were considered in this analysis and Oconee 3 was selected as the reference plant; TMI-2 was not included because it was shut down indefinitely. The average remaining operating life of the 10 B&W plants considered was 28.2 years, based on the original 40-year license. However, it was assumed that 75% of these plants will have their licenses extended for an additional 20 years and, therefore, the total remaining operating life of these plants was assumed to be 432 RY.
The initiating transient of concern involved an increase in feedwater flow to one or more loops. If the increased feedwater flow continues, e.g., if the steam generator high-level detection system fails, feedwater control valves fail, or the main feedwater pump fails to trip, the steam generator water level may exceed the aspirator port level. The resultant backflow of feedwater through the aspirator ports may then result in a SGTR or steam generator shell failure accident. The accident sequence developed64 by PNL to model the effect of the proposed solution produced the following results:
(1) The average frequency of increased feedwater flow for B&W plants was developed in Section 1.0 of NUREG/CR-38621186 to be 0.13 transient/RY;
(2) The probability of failure on demand to reduce main feedwater flow (product of undetected failure of steam generator high-level trip and operator failure to terminate the overfeed event) was (0.047)(0.7) = 0.033;
(3) The probability of an SGTR, given an overfill event, was 0.027;
(4) The probability of steam generator shell failure (SGSF), given an overfill event, was 0.027;
(5) The sum of the conditional probabilities of SGTR and SGSF was 0.054;
(6) The probability of a failure on demand to mitigate the SGTR or SGSF (estimated from core-melt frequency from SGTR sequences divided by the SGTR initiating event frequency) was (2.7 x 10-6)/(8.6 x 10-3) = 3.14 x 10-4;
(7) The resulting base case accident sequence frequency was estimated to be (0.13/RY)(0.033)(0.054)(3.14 x 10-4) = 7.27 x 10-8/RY.
The effects of an enhanced testing and inspection program for steam generator level instrumentation and feedwater controls was assumed to reduce the conditional probablity of failure to reduce main feedwater flow, given a feedwater overfeed event, to 0.011/demand. Therefore, the adjusted case accident frequency was (0.011/0.033)(7.27 x 10-8)/RY = 2.43 x 10-8/RY. Thus, the reduction in core-melt frequency was estimated to be [(7.27 x 10-8)/RY - (2.43 x 10-8)/RY] = 4.8 x 10-8/RY.
Containment failure probabilities and corresponding dose consequences were then combined with the accident frequencies to calculate public risk. The base case and adjusted case risk was calculated64 by PNL to be 0.2 and 0.066 man-rem/RY, respectively. Based on a total operating life of 432 RY, the potential risk reduction for all affected plants was determined to be 56 man-rem.
Industry Cost: Licensees would have to prepare safety analyses to support revising plant-specific TS. The total cost for these safety analyses and TS preparation was estimated to be $4.1M; operation and maintenance costs associated with increased inspection and testing were estimated to be $4.3M. Thus, the total industry cost associated with the possible solution was estimated to be $8.4M.
NRC Cost: The total cost for development of a solution, support of implementation, and review of operation and maintenance was estimated to be $320,000, $91,000, and $490,000, respectively. Thus, the total NRC cost for the possible solution was estimated to be $0.9M.
Total Cost: The total industry and NRC cost associated with the possible solution was estimated to be $9.3M.
Based on a potential risk reduction of 56 man-rem and a total cost of $9.3M for a possible solution, the value/impact score was given by:
The central concern in this issue was that operating OTSGs at a high water level could allow feedwater back through the aspirator ports onto steam generator tubes potentially affecting tube integrity. The effects on steam generator tube integrity from this particular event, however, were within the steam generator design bases. A partial list of these design bases is summarized below:
- 15,000 cycles of adding 40ºF feedwater at 875 gpm when at hot standby conditions (normal condition)
- 500 cycles of adding 40ºF feedwater at 875 gpm during loading conditions (normal condition)
- 500 cycles of adding 100ºF feedwater at 875 gpm during loading conditions (normal condition)
- 7 cycles of adding 40ºF feedwater at 1750 gpm during a steam line break (faulted condition)
- 280 cycles of adding 40ºF feedwater at 1750 gpm with the flow initiated 30 seconds after a loss of main feedwater (faulted condition).
Given that main feedwater is normally about 455ºF during loading conditions, the thermal effects of adding 40ºF emergency feedwater would be substantially greater than those of spilling main feedwater through the aspirator ports onto the tubes. In addition, the aspirator ports are located near the middle of the tube sheet, which is a less stressed position than the location of the emergency feedwater nozzle, which is higher in the OTSG. This further indicated that the steam generator tubes were likely to withstand 455ºF main feedwater introduced through the aspirator ports onto the tubes.
OTSGs are designed to withstand over 15,000 cycles of injection of 40ºF emergency feedwater. The consequences of operating with a water level above the aspirator ports (which would introduce 455ºF water) are less severe than that assumed in this analysis and are within the OTSG design limits. The possible solution did not produce a significant reduction in public risk and the value/impact score was small. Therefore, this issue was DROPPED from further pursuit (See Appendix C). Consideration of a 20-year license renewal period did not change the priority of the issue.1564