NRC Generic Letter 1986-05
| ML031150274 | |
| Person / Time | |
|---|---|
| Issue date: | 05/29/1986 |
| From: | Miraglia F Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| GL-86-005, NUDOCS 8606020062 | |
| Download: ML031150274 (23) | |
UNITED STATES
NUCLEAR REGULATORY COMMISSON
'WASHINGTON, D. C. 20655
29 MAY 86 TO ALL APPLICANTS AND LICENSEES WITH BABCOCK AND WILCOX (B&W) DESIGNED
NUCLEAR STEAM SUPPLY SYSTEMS (NSSSs)
SUBJECT: IMPLEMENTATION OF TMI ACTION ITEM II.K.3.5, "AUTOMATIC TRIP OF
REACTOR COOLANT PUMPS" (GENERIC LETTER NO. 86-05)
Gentlemen:
The purpose of this letter is to inform you of (1) the staff's conclusions regarding the B&W Owners Group (BWOG) submittals on reactor coolant pump trip in response to Generic Letters 83-lOe and f, and (2)provide guidance concerning implementation of the reactor coolant pump trip criterion. Our Safety Evaluation (SE) on this subject is enclosed for your use.
With regard to the BWOG submittals referenced in Section V of the enclosed SE, we conclude that the methods employed by the BWOG to justify manual reactor coolant pump (RCP) trip are consistent with the guidelines and criteria provided in Generic Letters 83-lOe and f. The approved B&W Small Break LOCA Evaluation Model was used to demonstrate compliance with
10 CFR 50.46 and Appendix K to 10 CFR Part 50.
We have determined that the information provided by the BWOG in support of the loss-of-subcooling RCP trip criterion is acceptable. The generic information presented by the BWOG, however, does not address plant specific concerns about instrumentation uncertainties, potential reactor coolant pump problems and operator training and procedures as requested in Generic Letter 83-10. This information, contained in Section IV of the SE, is now being requested to assess implementation of the RCP trip criterion.
Accordingly, for those applicants and licensees who choose to endorse the BWOG
methodology, we request that operating reactor licensees implement the RCP
trip criterion based upon the BWOG methodology. Schedules for submittal of information requested in Section IV of the SE (refer to Appendix A for considerations associated with Generic Letters 83-lOe and f) should be developed with your individual project managers within 45 days from receipt of this letter. The requested information does not constitute a new requirement but only identifies information specified in Generic Letters
83-lOe and f which has not been provided under the BWOG generic program. In the event that licensees decide not to trip the RCP (an option provided for in Generic Letters 83-lOe and f), they should respond to the questions in Section IV of the SE and refer to Appendix B of the SE. Applicants should provide the appropriate response to the extent that this information is known at this time.
Those applicants and licensees who choose not to endorse the BWOG methodology should submit a schedule for submittal of plant specific RCP trip criteria or justification for non-trip of RCPs within 45 days of receipt of this letter.
C8606020062 ;^
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This request for information was approved by the Office of Management and Budget under clearance number 3150-0011 which expires September 30, 1986.
Comments on burden and duplication may be directed to the Office of Management and Budget, Reports Management, Room 3208, New Executive Office Building, Washington, D.C. 20503.
Our review of your submittal of information in response to this letter is not subject to fees under the provisions of 10 CFR 170. However, should you, as part of your response or in a subsequent submittal, include an application for license amendment or other action requiring NRC approval, it is subject to the fee requirements of 10 CFR 170 with remittal of an application fee of
$150 per application (Sections 170.12(c) and 170.21) and subsequent semiannual payments until the review is completed or the ceiling in Section
170.21 is reached.
If you believe further clarification regarding this issue is necessary or desirable, please contact Mr. R. Lobel (301 492-9475).
Sincerely, rragli Director Division of PWR Licensing-B
Enclosure:
Safety Evaluation cc w/enclosure:
Service Lists
UNITED STATES
NUCLEAR REGULATORY COMMISSION
WASHINGTON, D. C. 20555 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
BABCOCK & WILCOX OWNERS GROUP SUBMITTALS
REACTOR COOLANT PUMP TRIP
I. INTRODUCTION
TMI Action Plan Item II.K.3.5 of NUREG-0737 required all licensees to consider other solutions to the small-break loss-of-coolant-accident (LOCA) problems because tripping the reactor coolant pumps (RCPs) was not considered the ideal solution. Automatic trip of the RCPs in the case of a small-break LOCA was recommended until a better solution was found. A summary of both the industry programs and the NRC programs concerning RCP trip is provided in Generic Let- ters 83-10(a) through (f), which are included in the NRC report, SECY-82-475, from W. J. Dircks to the NRC Commissioners, "Staff Resolution of the Reactor Coolant Trip Issue" (November 30, 1982). SECY-82-475 also provided the NRC
guidelines and criteria for the resolution of TMI Action Item II.K.3.5, "Auto- matic Trip of Reactor Coolant Pumps."
In SECY-82-475 the NRC concluded: "that appropriate pump trip setpoints can be developed by the industry that would not require RCP trip for those transients and accidents where forced convection circulation and pressurizer pressure con- trol is a major aid to the operators, yet would alert the operators to trip the RCPs for those small LOCAs where continued operation or delayed trip might re- sult in core damage."
SECY-82-475 also stated: "The resolution provided in the enclosures [Generic Letter 83-10] is intended to ensure that for whatever mode of pump operation a licensee elects, a) a sound technical basis for that decision exists, b) the plant continues to meet the Commission's rules and regulations, and c) as a minimum, the pumps will remain running for those non-LOCA transients and accidents where forced convection cooling and pressurizer pressure control would enhance plant control. This would include steam generator tube ruptures (SGTRs)
up to approximately the design basis event (one tube)."
The Babcock & Wilcox Owners Group (BWOG) submitted a report to the NRC in response to the Babcock and Wilcox specific Generic Letters, 83-10(e) and (f).
The title of the report is "Analytical Justification for the Treatment of Reactor Coolant Pumps During Accident Conditions" (Reference 1). In addition the Duke Power Company submitted a modified version of this report with a revised steam generator tube rupture analysis (Reference 2) for the Oconee plants. Finally, Toledo Edison provided a raised-loop steam generator tube rupture analysis (Reference 3) for the Davis-Besse plant. The BWOG also provided additional information (Reference 4) in response to our request for this information based on our review of the generic submittal. We have also performed analyses of selected events to support our review (Reference 5).
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Appendix A to this report summarizesSection I of the enclosure to Generic Letter 83-10 for "Pump-Operation Criteria that Can Result in RCP Trip During Transients and Accidents," and Appendix B summarizesSection II, "Pump-Operation Criteria That Will Not Result in RCP Trip During Transients and Accidents."
II. SUMMARY
The BWOG maintains that it is highly desirable to maintain RC pump operation during non-LOCA events as an aid in the mitigation of the transient.- Consistent with this philosophy, the concept of subcooling margin was chosen as an indication for the need to trip all four RCPs. The BWOG philosophy for handling RCPs during transient conditions complies with the intent of the criteria stated in Generic Letter 83-10. The symptom approach of subcooling margin, developed as part of the Abnormal Transient Operating Guidelines (ATOG) Program, is intended to replace the present guidelines of tripping solely on the presence of a low RC pressure engineered safety features actuation system (ESFAS) signal.
Although the BWOG states that the subcooling margin is the basis for RCP trip, the BWOG also assumes for SGTR that the secondary-side radiation monitors are used to indicate almost immediately that a SGTR rather than a SBLOCA has occurred. Operator actions, other than RCP trip, are based on the operator distinguishing between a SGTR and a small-break LOCA based on secondary-side radiation alarms. ATOG procedures, when followed, will prevent loss of subcooling for an SGTR event.
A loss of subcooling will always occur for small breaks that have the potential to uncover the core and violate 10 CFR 50.46 criteria if the RCPs are tripped under certain two-phase conditions. Analyses of certain small break LOCAs, combined with the assumption of only one HPI train available, have demonstrated the potential for exceeding 10 CFR 50.46 limits if RCPs are tripped while the RCS is in a highly voided (070%) condition. Consistent with these results, the BWOG has adopted the position of tripping all four RCPs on indication of a loss-of-coolant accident.
The BWOG conclusion regarding partial or staggered RCP trip is that a run-all/
trip-all philosophy in conjunction with the selection of loss of subcooled margin as the trip signal best meets the BWOG objectives. The approach taken is straight forward and consistent with present ATOG operator guidelines which minimize the likelihood of operator error. The operator is not required to diagnose the event in order to decide if the pumps should be tripped. It ensures that the pumps will not be operated in a highly voided condition where pump integrity may be questionable. This provides assurance that all pumps will be available for pump bump or restart if reactor coolant conditions warrant such steps (Reference 6).
The BWOG trip-all RCP trip philosophy acceptability is based on the B&W NSSS
design and transient characteristics. The approach taken does differ from other Owners Group schemes. The reactor coolant primary loop configuration would allow for a partial or staggered pump trip while assuring adequate heat removal by at least one of the two once-through steam generators. However, this interim step is not required in B&W NSSSs because an adequate subcooling margin is maintained in all cases with the exception of the small-break LOCA.
It is therefore not necessary for the operator to distinguish between LOCA and non-LOCA (i.e., SGTR) events for RCP trip.
-3- In developing the response to Generic Letter 83-10, the BWOG concluded that the trip signal and philosophy selected were as adequate as partial trip schemes for assuring fuel temperature limits were maintained and were superior for ensuring pump Integrity, pump availability, and minimizing the chances of operator error.
No partial or staggered RCP trip schemes are considered except for the extreme case where mechanical damage to the pump is likely as this adds to increased decision making on the part of the operator during transient conditions.
Operators are instructed to trip the RCPs to prevent mechanical damage if RCP
shaft vibration reaches a specified peak-to-peak displacement. The displacement setpolnt depends on the pump manufacturer and is on the order of 20 mils. The operator has available for use in determining pump integrity the net-positive suction head (NPSH) and the pump motor current indications. A maximum allowable amplitude of vibration of the pump frame is also specified and is on the order of 2 mils peak-to-peak.
The BWOG followed the guidelines provided in Generic Letter 83-10 (e) and (f)
to justify manual RCP trip for small-break LOCAs. (See Appendix A, Section D.)
The BWOG studies concluded that:
1. Every Babcock & Wilcox plant's FSAR ECCS analysis demonstrates compliance with 10 CFR 50.46 if operator action to trip the RCPs is taken within 2 minutes after the RCP trip criterion is reached.
2. Most probable best estimate analyses indicate that in all Babcock & Wilcox plants, if the RCPs are tripped within 10 minutes during a small break LOCA
event, then the peak cladding temperatures will not exceed the 10 CFR 50.46 limit of 22001F.
The BWOG concluded that automatic reactor coolant pump trip is not required since adequate time for manually tripping the RCPs is demonstrated using 10 CFR 50, Appendix K, assumptions as well as most probable best estimate analysis results. It was also concluded that the most probable best estimate analysis results demonstrate that if the RCPs can be tripped within 10 minutes during the LOCA (if the operator should fall to trip the pumps when the trip criterion is reached), then acceptable cladding temperature will result.
Three best estimate analyses of the SGTR event have been performed to demonstrate that steam generator tube leaks up to a single double-ended rupture will not result in sufficient loss of subcooling, if ATOG procedures are followed, to produce an indication for the need to trip the RCPs.
These analyses are the generic 177-FA lowered loop plant SGTR, the Davis-Besse
177-FA raised loop plant SGTR, and a plant specific analysis for the Oconee plants. Duke Power submitted an independent analysis because of the differences between Oconee and the generic lowered loop plant (lower power and greater high pressure injection capacity).
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Since an SGTR can exhibit the same general characteristics as a small break LOCA, the general procedures for LOCA mitigation are followed. A continuous cooldown and depressurization of the RCS is essential to avoid opening of the steam generator safety valves thereby minimizing the risk of releasing radiation. Forced circulation by the RCPs will provide a continuous uninterrupted cooldown and depressurization of the RCS.
The best estimate analyses of a single double-ended SGTR demonstrated that operator actions as per ATOG to control RCS inventory, perform plant runback, and initiate low power reactor trip, preclude loss of subcooling margin and RCP trip during a single double-ended SGTR event.
The first stage for mitigation of a SGTR is the prompt recognition of the event and the determination of the affected steam generator. The occurrence of secondary radiation alarms (steamline monitor or condenser air ejector), almost simultaneous with the SGTR, coupled with the RCS pressure and pressurizer level drops, are unique indicators that a SGTR has occurred. The analyses assumed the operator diagnoses the SGTR following the radiation alarm and pressurizer low level alarm and begins to take prescribed action.
The minimum subcooling calculated for the SGTR analyses are 380 F for the generic
0 F for the
0
177-FA lowered loop plant, 37 F for the raised loop plant, and 26 Oconee plants. Therefore, with the early diagnosis of a SGTR based on radiation alarms and pressurizer level, and by following the ATOG procedures, the RCPs will not be tripped on a loss-of-subcooling margin for either the 177-FA lowered loop or raised loop plants.
No analysis results were presented by the BWOG for non-LOCA transients, but mild overcooling events and severe overcooling events were discussed. Reducing the need to trip the RCPs for more likely non-LOCA events such as mild overcooling events can be ensured by the judicious determination of the subcooling margin setpoint. Procedures based on ATOG provide guidance for pump restart for those events where an unnecessary pump trip might occur.
Consequently, reliance on the PORV for depressurization is unlikely.
The overcooling events considered included a spectrum of small steam leaks, ranging from single valve failures (2.5-3% total steam flow) up to and including a turbine bypass failure (25-30% total steam flow), as well as steam generator overfeed and accidental decrease in main feedwater temperature.
Of the overcooling events considered, no event results in a minimum reactor coolant system (RCS) subcooling margin less than 30F except for the turbine bypass failure. The analysis of turbine bypass failure shows that the pressurizer empties just after reactor trip and the system saturates. However, automatic high-pressure injection (HPI) initiation (at a reactor coolant pressure of 1600 psig) causes the system to rapidly repressurize so that the RCS is subcooled less than one minute after reactor trip.
The BWOG position on severe overcooling events is that while optimum selection of the loss of subcooling setpoint is expected to discriminate against the more likely overcooling events, severe overcooling events such as a large steam line break can result in a loss of subcooling and an indication for manual tripping of the RCPs. The FSAR safety analyses are performed assuming the most limiting case of pumps on or pumps off, therefore tripping of the pumps will not result in consequences more severe than previously analyzed.
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The BWOG has demonstrated that the use of a loss-of-subcooling margin trip strategy does cause RCP trip for small-break LOCAs in both raised- and lowered-loop plants. They show that for a SGTR the use of secondary radiation alarms plus operator actions to avoid loss of subcooling permit the RCPs to keep running for both raised- and lowered-loop plants. They conclude that using the loss-of-subcooling margin RCP-trip signal will prevent tripping for a large number of mild overcooling events.
The BWOG recommended procedure for calculating subcooling margin is to measure the RC hot leg temperature and pressure and calculate the saturation temperature (T. ) at the measured RC pressure. The difference between the calculated Tsat an athe measured RC temperature is the number of degrees of subcooling. The instrument uncertainty is determined using the square root of the sum of squares (SRSS) for the randomly occurring component errors, plus the sum of correlated errors associated with each component in the instrument string. The uncertainty induced due to the specific location of each component is accounted for in determinations of the individual component error.
Typically, three redundant temperature and pressure measurements are obtained from the hot legs and three subcooling margins are computed accordingly. A
pump trip Is initiated based upon the subcooling margin setpoint (minimum subcooling) and a two-out-of-three logic.
The first stage for mitigation of SGTR is prompt recognition of the event and determination of the affected steam generator. The occurrence of secondary radiation alarms (steamline monitor or condenser air ejector), almost simultaneous with the SGTR, and the RCS pressure and pressurizer level drops are unique indicators that a SGTR has occurred. The analyses assumed the operator diagnoses the SGTR following the radiation alarm and pressurizer low level alarm and begins to take prescribed action.
All operating B&W plants have condenser air ejector radiation monitors in addition to N-16 gamma main steam line (MSL) radiation monitors. Main steam line radiation monitor alarms (N-16) are anticipated to occur within 15 seconds after a steam generator tube rupture.
The mixing and transport assumption used by the BWOG is that the reactor coolant with an equilibrium concentration of N-16 (and other radioactive isotopes)
is assumed to flash to saturated steam in the once-through steam generator (OTSG) secondary side and is swept out of the OTSG by the MSLs (i.e., complete mixing with secondary steam) at the local secondary steam velocity (18 ft/s).
Each utility will need to show the basis for the loss-of-subcooling margin setpoint it is using including the instrumentation uncertainties for normal and adverse containment conditions and the effect of instrumentation location.
In addition to the establishment and justification of a RCP trip criterion, Generic Letter 83-10 also requested the licensees to estabish guidelines and procedures for cases where RCP trip can lead to hot, stagnant fluid regions at primary-system high points and to describe symptoms of primary system voiding caused by flashing of hot, stagnant fluid regions including the effects on the pressurizer and to specify guidance for detecting, managing and removing the voids.
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The BWOG response on guidelines and procedures for cases where RCP trip can lead to hot, stagnant fluid regions at primary system high points is that hot stagnant fluid regions may result from a lack of heat removal capability, but are not a direct result of tripping the reactor coolant pumps. The guidance for reestablishing heat removal capabilities is provided in the "Lack of Heat Transfer" section of the Abnormal Transient Operating Guidelines (Document No. 74-1123297-00).
Guidelines include the use of hot leg high point vents, 'bumping' reactor coolant pumps, and depressurization of the OTSG secondary side as a means of reestablishing natural circulation.
The symptom of primary system voiding caused by flashing of hot, stagnant fluid regions is a rise in pressurizer level during times of steady or decreasing RCS
pressure, and is an indication of primary system voiding.
The BWOG detailed response to specify guidance for detecting, managing and removing the voids is that the ATOG are being expanded to include guidance on the detection, management, and removal of voids as a result of NRC comments in the ATOG Safety Evaluation (Reference 7).
Current thoughts on the detection and management of reactor vessel head voids are described below.
Head Void Prevention Reactor vessel head void formation can be precluded by controlling the cooldown and depressurization such that the reactor vessel head fluid temperature is less than the primary system saturation temperature. Reactor vessel head fluid temperature may be obtained directly from a temperature measurement (if available) or inferred from predicted plant specific vessel head fluid cooldown rates. For plants without reactor vessel head vents, cooldown rates are about 40 F/hr to 5*F/hr to avoid void formation. Periodic restarting (bumping) of the reactor coolant pumps will help keep the temperature in the reactor vessel head low.
Higher cooldown rates can be achieved with passive vent systems (flow path between the reactor vessel head and the hot leg or steam generator). Flow through these lines occurs due to density differences between the vessel head fluid and the discharge (hot leg or SG) fluid. There are two parallel paths between the reactor vessel and the upper portion of the hot leg. The normal path through the hot leg will have most but not all of the flow. Therefore, faster cooldowns can be performed without void formation. In situations where flow through the passive vent system cannot occur (e.g., voids or stagnant conditions in discharge hot leg), the loop vent must be opened to initiate flow through the passive head vent line.
Some plants are equipped with active vent systems in which operator action Is required to provide a flow path from the vessel head to a suitable discharge (e.g.,
quench tank). Head fluid temperature response during venting is dependent on primary pressure, temperature, vessel head temperature, and venting configuration (minimum vent flow area).
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Head Void Recognition Head void formation can be detected using vessel head level measurements.
In addition, formation of head voids can usually be associated with:
(a) Opposite trending between primary pressure and pressurizer level (pressurizer level increase with primary pressure decrease). Note: this is also an indication of loop void formation. Therefore, hot leg level measurements may be useful in indicating vessel head void formation.
(b) Difficulty in reducing pressure after void formation.
(c) Head fluid temperature (if available from previous estimates) equal to primary saturation temperature.
If natural circulation flow can be verified in both loops, it may be assumed that any void forming is a vessel head void. Note that, unless vented, the head will be the hottest region in the primary loop and thus more likely to void first.
Head Void Elimination To facilitate the depressurization during cooldown after vessel head void formation occurs, the vessel head void should be eliminated. As previously mentioned, vessel head voids tend to slow the depressurization and thus the cooldown since it acts as a second pressurizer. Vessel head voids can be eliminated by:
(a) Venting.
(b) Ambient heat loss induced condensation.
(c) RCP bump.
Flashing due to depressurization should be prevented after the vent is opened.
To accomplish this, makeup or HPI flow should be increased to compensate for venting as well as normal letdown. The RC pressure is thus to be maintained or slightly increased through regulation of the size of the pressurizer steam bubble. Successful venting has occurred when primary pressure and pressurizer level increase suddenly. This level increase will occur even if a void exists in the hot leg.
Head level measurements are to be used to indicate trends only and may not suffice to determine if the void has been completely eliminated. The head level measurements (if available) are not to be used while venting is in progress.
Head void elimination due to ambient heat loss induced condensation is a slow process and may require extremely long cooldown times. The reactor coolant system can be cooled and depressurized with a vessel head bubble. The depressurization rates achievable using the power-operated relief valve(s)
(PORV) will depend on the total amount of steam in the system. The operator will only be able to depressurize with the PORV while a steam bubble exists
-8- in the pressurizer. The exact reduction of the depressurization rate will depend on the sizes of the vessel head bubble and the pressurizer bubble. As the cooldown progresses the vessel head bubble will slowly expand. When the PORV is opened the bubble will expand rapidly and if large enough will move into the hot leg. For natural circulation flowrates as low as 3 percent, and temperatures in the hot leg within 10 F of saturation, a steam void escaping
0
into the hot leg will be condensed long before it reaches the highest portion of the RCS candy cane. This expansion of the vessel head void into the hot leg can continue during the depressurization until the pressurizer bubble becomes too small (i.e., the high level limit in the pressurizer is reached).
A 50'F per hour cooldown with a 600 F steam void in the upper head is accept-
0
able from an operations as well as a stress analysis standpoint. The flow regime expected at the reactor vessel outlet is one of bubbly flow as opposed to slug flow. This indicates that the condensation will not be a violent one.
The proposed guidelines and procedures for the recognition and management of primary steam voids are acceptable and the ATOG procedures are being revised to incorporate these changes, in response to Generic Letter 83-31.
A primary objective of the parameter and setpoint selection is the avoidance of reactor coolant pump trip for the more probable of the non-LOCA events. Loss of subcooling margin has been shown to occur for all small break LOCAs of con- cern and may also occur for design basis overcooling type transients which may exhibit a RCS response similar to a LOCA.
Item I.1.e of the enclosure to Generic Letter (GL) No. 83-10 expresses the concern that "Transients and accidents which produce the same initial symptoms as a LOCA (i.e. depressurization of the reactor and actuation of engineered safety featuresS... result in the termination of systems essential for continued operation of the reactor coolant pumps (i.e., component cooling water and/or seal injection water)." The enclosure to GL 83-10 further states that "...In particular, if a facility design terminates water services essential for RCP operation, then it should be assured that these water services can be restored in a timely manner once a non-LOCA situation is confirmed, and prevent seal damage or failure."
The following contains some of the generic guidance provided in the ATOG to assure water services when RCP operation is desired. The potential for con- tainment isolation signals resulting from various transient types is discussed as well as guidance for the restart of RCPs under degraded service conditions.
1. ATOG emphasizes protection of the RCP seals and motor to prevent damage.
It is desirable to trip the RCPs to prevent mechanical damage in case they must be restarted at a later time. Preserving the RCPs for long-term cooling or cooldown is desirable, and it is recommended that they be shutdown if high vibration or loss of auxiliary cooling water services occurs. Limits on continued RCP operation are given in "Plant Limits and Precautions." The rules for RCP trip to prevent mechanical damage are applicable in all cases except (1) when the pumps were not tripped immediately (i.e., within 2 iminutes after the subcooling margin was lost) or (2) when severe Inadequate core cooling (ICC) exists. In these cases the operator should try to restore the RCP service which is lost.
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2. Operators are instructed to perform the remedial action of verifying or reestablishing RCP seal injection and service water flow if potential isolation signals have been verified (i.e., ESF signals). Those sections of ATOG which permit continued RCP operation or anticipate RCP restart give the instructions for the verification or reestablishment of seal injection and cooling water.
3. ATOG provides specific instructions for RCP restart. The Equipment Operation chapter of ATOG shows the conditions under which the RCPs can be restarted. For situations where Inadequate core cooling Is not a concern, confirmation that no RCP damage will occur is among the requirements for RCP restart. (If inadequate core cooling is a concern, RCP restart is required even if damage can occur). Some specific actions which must be taken to verify pump integrity before restart include:
(a) If component cooling water (CCW) is isolated and RCPs are allowed to run, bearings and stator temperature will rise. If RCPs are then tripped, they should not be restarted until component cooling water is restored and bearings have cooled down to normal operating temperature.
(b) If RCPs are tripped before bearing temperatures are excessive (exceed alarm setpoint), RCPs can be restarted and run once component cooling water is restored.
(c) Unless bypassed, interlocks will prevent pump restart until component cooling water and seal injection are available to the pump.
(d) Controlled bleed-off flow should be reestablished prior to pump restart.
4. Other considerations for RCP restart are verified on a plant specific basis. The Plant Limits and Precautions Documents, Plant Setpoints Documents, and RCP vendor instruction manuals provide further instructions.
In considering all BWOG plants generically, it is recognized that some differences exist. For example, (1) the plants utilize three different RCP vendors (Byron-Jackson, Bingham, and Westinghouse); (2) the plants utilize various motor suppliers (Siemans-Allis, GE, Westinghouse, and AEG); (3) the
205-FA plants operate with a lower subcooling margin than the 177-FA plants;
(4) system configuration and design differ slightly; and (5) as a result of recommendations for increased RCP reliability and response to NUREG-0737, Item II.E.4.2, each utility has opted for various isolation signals which affect RCP cooling water services availability.
The containment isolation signals presently being used, depending on plant and function, are:
Low RCS pressure (1500-1700 psig).
Low RCS pressure or high containment pressure (3-4 psig).
Low-low RCS pressure (400 psig).
ESF interlocked with RCPs not running.
High-high containment pressure (25-38 psig).
ESF with seal bleedoff redirected to quench tank.
High radiation (inside containment)
Low CCW surge tank level.
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Non-LOCA transients such as a severe overcooling resulting from a steam line break inside containment have the potential to produce the same initial symptoms as a LOCA. If it were desired to continue with RCP operation for these transients, low RCS pressure (1500-1700 psig) and high containment pressure
(3-4 psig) actuation have the greatest potential to cause unwanted isolation of RCP services and require timely reestablishment of these services. Using high-high containment pressure as an isolation signal would prevent isolation of the service functions for the majority of such transients and accidents and yet maintain isolation capability for a design basis accident (large LOCA
and steam line break). The other isolation signals mentioned above are used to preclude RCP or equipment damage.
The cooling water services supporting the RCP with the potential of being isolated are:
Seal injection.
Seal bleedoff (resulting from seal injection provided to pump).
Component cooling water to seal area coolers.
Component cooling water to RCP motors and oil coolers.
For a running RCP, seal integrity can be maintained with either seal injection or component cooling, within operating parameters, to the seal area coolers.
More than 10 years ago, B&W removed the seal injection isolation signal from the makeup and purification system design and recommended that the signal be removed from the operating plants. Presently there is only one plant with seal injection isolation which is signaled to close on 400 psig RC pressure. Four hundred psig RC pressure is an indication of a large break LOCA during which time RCP operation is not anticipated.
The seal bleedoff is important to seal integrity in that it provides pressure staging across the seals and removal of the heat generated by the rotating seals. Closure of the seal bleedoff line with the RCPs running can cause significant seal damage. In this situation with a low seal face leakage rate, the heat generation rate at the upper seal will triple due to tripling of the seal delta-p and there is not enough flow to remove this heat. ATOG instructions call for quickly reestablishing seal bleedoff flow or tripping the RCPs.
Some plants have initiated "hardware" changes to redirect the seal bleedoff flow to the quench tank upon receipt of a containment Isolation signal. Another alternative to minimize the occurrence of engineered safety feature (ESF)
isolation of seal bleedoff is to isolate seal bleedoff only on hi-hi containment pressure (the same signal that actuates containment spray flow). For plants utilizing ESF signals (1500-1700 psig RC pressure, 3-4 psig containment pressure) for isolation, timely reestablishment of seal bleedoff flow per the ATOG instructions is required for continued RCP operation.
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With proper seal injection and seal return, integrity of the seals can be maintained indefinitely on loss of component cooling water to a running RCP.
However, the RCP motors cannot be run indefinitely on a loss of cooling water. If it is desired to continue RCP operation, cooling water must be reestablished within a given time frame as indicated in ATOG to preclude damage. The time frame varies depending on the type of motor.
The generic nature of the BWOG submittal, concerning the RCP trip set point selection and the RCP essential service water systems, by nature does not include any actual plant specific information. We have therefore included a section (Implementation), herein, which describes those plant specific items we require each licensee to address when incorporating the RCP trip criterion into the plant procedures.
III. CONCLUSIONS
We have determined that the information provided by the BWOG for the justification of manual reactor coolant pump trip is acceptable. The methods employed by the BWOG to justify manual reactor coolant pump trip are consistent with the guidelines and criteria provided in Generic Letter 83-10 (e) and (f).
The approved Babcock & Wilcox Small Break LOCA Evaluation Model was used to demonstrate compliance with 10 CFR 50.46 and Appendix K to 10 CFR Part 50.
We have determined that the Information provided by the BWOG in support of the loss-of-subcooling reactor coolant pump trip criterion is acceptable.
We believe the analyses tools employed by the BWOG, and by the licensees for Oconee and Davis-Besse, are capable of qualitatively providing the appropriate information to evaluate the loss-of-subcooling RCP trip criterion.
We have concluded that the BWOG has developed an acceptable criterion for tripping the reactor coolant pumps during small-break LOCAs which minimizes reactor coolant pump trip for SGTR and non-LOCA events. The ATOG procedures for the identification of an SGTR and for the mitigation of the SGTR event are considered to be an integral part of the RCP trip criterion. When the operator follows the ATOG procedures for a SGTR event, subcooling is maintained and RCP trip will not be required.
IV. IMPLEMENTATION
The generic information presented by the BWOG does not address plant specific concerns about instrumentation uncertainties, potential reactor coolant pump problems and operator training and procedures as requested in Generic Letter 83-10. Appendix A contains a summary related to these issues, and may be used as a guideline to assure that these issues are adequately addressed.
In order to complete the response to Generic Letter 83-10 (e) and (f), each B&W
licensee is required to submit the following information to the NRC for plant specific reviews:
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A. Determination of RCP Trip Criteria
1. Identify the instrumentation to be used to determine the RCP trip setpoint, including the degree of redundancy of each parameter signal needed for the criterion chosen.
2. Identify the instrumentation uncertainties for both normal and adverse containment conditions. Describe the basis for the selection of the adverse containment parameters. Address, as appropriate, local conditions such as fluid Jets or pipe whip which might influence the instrumentation reliability.
3. In addressing the selection of the criterion, consideration of uncertainties associated with the BWOG or plant specific supplied analyses values must be provided. These uncertainties include both uncertainties in the computer program results and uncertainties resulting from plant specific features not representative of the BWOG generic data group.
B. Potential Reactor Coolant Pump Problems Section 5.4 of the BWOG generic report discusses the various aspects of the essential service water systems for the B&W plants In a generic fashion. Each licensee needs to identify and describe the plant specific features to:
1. Assure that containment isolation, including inadvertent isolation, will not cause problems if it occurs for non-LOCA transients and accidents.
a. Demonstrate that if water services needed for RCP operations are terminated, then they can be restored fast enough to prevent seal damage or failure once a non-LOCA situation is confirmed.
b. Confirm that containment isolation with continued pump operation will not lead to seal or pump damage or failure.
2. Identify the components required to trip the RCPs, including relays, power supplies and breakers. Assure that RCP trip, when determined to be necessary, will occur. If necessary, as a result of the location of any critical component, include the effects of adverse containment conditions on RCP trip reliability. Describe the basis for the adverse containment parameters selected.
C. Operator Training and Procedures (RCP Trip)
In response to NRC questions concerning the identification and management of primary system voids, the BWOG response identified potential changes to the ATOG procedures to incorporate proposed detection and management schemes.
Each licensee should endorse this program as described, and provide an implementation schedule for the revised ATOG.
If a licensee does not endorse the provided proposal, then a suitable alternate proposal must be provided including an implementation schedule.
V. REFERENCES
1. B&W Owners Group, "Analytical Justification for the Treatment of Reactor, Coolant Pumps During Accident Conditions," Babcock & Wilcox report
77-1149091-00 (February 1984).
2. H. B. Tucker, "Oconee Nuclear Station, Reactor Coolant Pump Trip Criteria, Docket Nos. 50-269, -270, -287," Letter from H. B. Tucker to H. R. Denton, March 30, 1984.
3. B&W Owners Group, "Best Estimate Steam Generator Single Double Ended Tube Rupture Analysis," Babcock & Wilcox report 77-1152840-00 (September 1984).
4. J. H. Taylor, "Transmittal of Responses to a Round of Questions from the NRC on the Report, Analytical Justification for the Treatment of RC Pumps During Transient Conditions," B&W Document Number 77-1149091-00, Letter to NRC, November 19, 1984.
5. "TRAC Analysis of the Babcock & Wilcox Reactor Coolant Pump Trip Criteria,"
LANL, (to be published).
6. R. H. Bryan, "Reactor Coolant Pump Trip Philosophy," Letter from R. H. Bryan, Chairman, B&W Owners Group Analysis Committee to J. R. Miller, Chief, Operating Reactors Branch No. 3, U.S. NRC, June 18,
1984.
7. Generic Letter 83-31, "Safety Evaluation Report for Abnormal Transient Operating Guidelines," September 14, 1983.
APPENDIX A
PUMP-OPERATION CRITERIA THAT CAN RESULT IN RCP TRIP
DURING TRANSIENTS AND ACCIDENTS
A. The NRC staff has concluded that if sufficient time exists, then manual action is acceptable for tripping the RCPs following a LOCA provided certain conditions are satisfied.
B. Potential problem areas should be considered in developing RCP-trip setpoints and methods.
1. Tripping RCPs causes loss of pressurizer sprays.
a. This produces a need to use PORVs in some plants to control primary pressure.
b. PORVs have frequently failed to close.
c. Despite testing, PORV operational reliability has not improved significantly.
2. Tripping RCPs tends to produce a stagnant region of hot coolant in the reactor-vessel upper elevations.
a. Hot stagnant coolant has flashed and partially voided the upper vessel region during depressurization or cooldown operational events.
b. Operators are not completely familiar with the significance of an upper-head steam bubble.
c. Operators have difficulty controlling coolant conditions to avoid or control flashing.
d. Operators may take precipitous actions when a steam bubble exists.
3. After tripping the RCPs, decay-heat removal by natural circulation is required. This procedure is used less frequently than controlling with the RCPs and it places more demand on the operators to control the primary-system conditions.
C. Consider the following guidelines in developing RCP-trip setpoints.
1. Demonstrate and justify that proposed RCP-trip setpoints are adequate for small-break LOCAs but will not cause RCP trip for other non-LOCA
transients and accidents such as SGTRs.
a. Assure that RCP trip will occur for all primary-coolant losses in which RCP trip is considered necessary.
b. Assure that RCP trip will not occur for SGTRs up to and including the design-basis SGTR.
c. Assure that RCP trip will not occur for other non-LOCA transients where it is not considered necessary.
-2- d. Perform safety analyses to prove that a, b, and c above are achieved.
e. Consider using partial or staggered RCP-trip schemes.
f. Assure that training and procedures provide direction for use of individual steam generators with and without operating RCPs.
g. Assure that symptoms and signals differentiate between LOCAs and other transients.
2. Exclude extended RCP operation in a voided system where pump head is more than 10% degraded unless analyses or tests can justify pump and pump-seal integrity when operating in voided systems.
3. Avoid challenges to the PORVs where possible.
a. If setpoints lead to RCP trip even though it is neither required nor desirable for transients or accidents with offsite power available, assure that challenges to the PORVs are avoided that would normally be handled by using pressurizer sprays.
b. Challenges to PORVs could be eliminated by using heated auxili- ary pressurizer sprays from a source other than the RCP
discharge.
c. If submittal recommends use of PORVs to depressurize, then licensees need to develop a program for upgrading the PORVs'
operational reliability.
4. Establish guidelines and procedures for cases where RCP trip can lead to hot, stagnant fluid regions at primary-system high points.
a. Describe symptoms of primary-system voiding caused by flashing of hot, stagnant fluid regions including effects on the pressurizer.
b. Specify guidance for detecting, managing and removing the voids.
c. Train operators concerning the significance of primary-system voids for both non-LOCA and LOCA conditions.
5. Assure that containment isolation will not cause problems if it occurs for non-LOCA transients and accidents.
a. Demonstrate that if water services needed for RCP operation are terminated, they can be restored fast enough once a non-LOCA situ- ation is confirmed to prevent seal damage or failure.
b. Confirm that containment isolation with continued pump operation will not lead to seal or pump damage or failure.
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6. RCP trip decision parameters should provide unambiguous indicators that a LOCA has occurred and the NRC-required inadequate-core-cooling instrumentation should be used where useful in indicating the need for a RCP trip.
7. NRC recommends that the licensee use event trees to systematically evaluate their setpoints to minimize the potential for undesirable consequences because of a misdiagnosed event.
a. Evaluate setpoints for events with RCP trip when it is preferable the RCPs remain operational.
b. Evaluate setpoints for events where early RCP trip does not occur and a delayed trip may lead to undesirable consequences.
D. NRC's guidance for justification of manual RCP trip in the licensee submittals is summarized in this section. This guidance had two purposes.
It was intended to assist plants that can and should rely on manual trip to justify it, and it was also intended to help identify those few plants that may not be able to rely on manual trip.
1. Analyses should demonstrate that the limits set forth in 10 CFR 50.46 are not exceeded for the limiting small-break size and location using the RCP-trip setpoints developed with the guidance of part C above.
a. Assume manual RCP trip does not occur earlier than 2 minutes after the RCP-trip setpoint is reached.
b. Include allowances for instrument error.
c. Generic analyses are acceptable if they are shown to bound the plant-specific evaluations.
2. Determine the time available to the operator to trip the RCPs for the limiting cases if manual RCP trip is proposed.
a. Perform the analysis for the limiting small-break size and location identified in D.1 above.
b. Use the most probable best-estimate analysis to determine the time available to trip the RCPs following the time when the RCP-trip signal occurs.
c. Most probable plant conditions should be identified and justified by each licensee.
d. NRC will accept conservative estimates in the absence of justifiable most probable plant conditions.
e. Justify that the time available to trip the RCPs Is acceptable if it is less than the Draft ANSI Standard N660.
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(1) Include an evaluation of operating experience data.
(2) Address the consequences if RCP trip is delayed beyond this time.
(3) Develop contingency procedures and make them available for the operator to use in case the RCPs are not tripped in the preferred time frame.
(4) No justification is required if the time available to trip the RCPs exceeds the Draft ANSI Standard N660.
E. Assure that good engineering practices has been used for the following areas.
1. Establish the quality level for the instrumentation that will signal the need for RCP trip.
a. Identify the basis for the sensing-instruments design features chosen.
b. Identify the basis for the sensing-instruments degree of redundancy.
c. Licensees can take credit for all equipment available to the operators for which they have sufficient confidence of its operability during the expected conditions.
2. Ensure that emergency operating procedures exist for the timely restart of the RCPs when conditions warrant.
3. Instruct operators in their responsibility for tripping RCPs for small-break LOCAs including priorities for actions after the engineered safety features actuation occurs.
APPENDIX B
PUMP-OPERATION CRITERIA THAT WILL NOT RESULT IN RCP TRIP
DURING TRANSIENTS AND ACCIDENTS
Consider the following guidelines if the submittal concludes that keeping the RCPs running is both the preferred and safest method of pump operation for
,small-break LOCAs and other transients and accidents.
A. Evaluate inventory loss.
1. Complete evaluation of LOFT Test L3-6 through the ECCS recovery phase.
2. Evaluate all modeling differences expected between LOFT and a PWR analysis.
B. Evaluate pump integrity.
1. Justify how the pump-seal and pump structural integrity will be assured during extended two-phase flow performance.
2. Include the consequences of pump and/or pump-seal failure in the analyses if their integrity cannot be assured.
3. Include one of the following if continuous RCP operation is expected even with a containment isolation signal.
a. Evaluate the capability to continue RCP operation without essential water services.
b. Evaluate the capability to rapidly restore essential water services.
4. Evaluate the RCPs' capability to operate in the accident environment.
5. Evaluate the consequences of RCP failure at any time during the accident if continuous operation in the accident environment cannot be assured.
C. Ensure acceptability of results.
1. Analyses should demonstrate that the 10 CFR 50.46 ECCS acceptance criteria are met with a model in compliance with Appendix K to
2. Assume continuous pump operation and also RCP trip at various times if continuous pump operation cannot be assured.
3. NRC will consider a request for an exemption to 10 CFR 50.46 requirements if analyses indicate compliance cannot be achieved.
-2- a. Submittal concludes that compliance with 10 CFR 50.46 would require operating the plant in a less safe condition. This needs to be supported with a risk/benefit analysis that can take credit for all equipment expected to remain operational during the accident.
b. Submittal concludes that design modifications would not be cost-effective to implement from a safety standpoint.
List of Recently Issued Generic Letters Generic Date of Letter No. Subject Issuance Issued To
86-10 Implementation of Fire 04/24/86 All Power Reactor Protection Requirements Licensees and
-Applicants f/Power Reactor Licenses
86-09 Technical Resolution of 03/31/86 All Licensees of Generic Issue No. B-59-(N-1) Operating BWRs and Loop Operation in BWRs and PWRs and License PWRs Applicants
86-08 Availability of Supplement 4 03/25/86 All Licensees of to NUREG-0933 Operating Reactors
'MA Prioritization of Generic Applicants for OLs Safety Issues" and Holders of CPs
86-07 Transmittal of NUREG-1190 03/20/86 All Reactor Regarding the San Onofre Licensees and Unit 1 Loss of Power and Applicants Water Hammer Event
86-06 Implementation of TMI Action 05/29/86 All Applicant and Item II.K.3.5 "Automatic Licensees with CE
Trip of Reactor Coolant designed Nuclear Pumps" Steam Supply Systems
86-05 Implementation of TMI Action , 05/29/86 All Applicants and Item II.K.3.5, "Automatic Licensees with B&W
Trip of Reactor Coolant Designed Nuclear Pumps Steam Supply Systems
86-04 Policy Statement 02/13/86 All Power Reactor on Engineering Licensees and Expertise on Shift Applicants for Power Reactor Licenses
86-03 Applications for 02/10/86 All Power Reactor License Amendments Licensees and OL Applicants
86-02 Technical Resolution of 01/23/86 All Licensees of Generic Issue B-19 Operating BWRs Thermal Hydraulic Stability
86-01 Safety Concerns Associated 01/03/86 All BWR Applicants with Pipe Breaks in the and Licensees BWR Scram System
1
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This request for information was approved by the Office of Management and Budget under clearance number 3150-0011 which expires September 30, 1986.
Comments on burden and duplication may be directed to the Office of Management and Budget, Reports Management, Room 3208, New Executive Office Building, Washington, D.C. 20503.
Our review of your submittal of information in response to this letter is not subject to fees under the provisions of 10 CFR 170. However, should you, as part of your response or in a subsequent submittal, include an application for license amendment or other action requiring NRC approval, it is subject to the fee requirements of 10 CFR 170 with remittal of an application fee of
$150 per application (Sections 170.12(c) and 170.21) and subsequent semiannual payments until the review is completed or the ceiling in Section
170.21 is reached.
If you believe further clarification regarding this issue is necessary of desirable, please contact Mr. R. Lobel (301 492-9475).
Sincerely, Frank J. Miraglia, Director Division of PWR Licensing-B
Enclosure:
Safety Evaluation cc w/enclosure:
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