ML19262B572
| ML19262B572 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 12/19/1979 |
| From: | Anderson T WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP. |
| To: | Eisenhut D Office of Nuclear Reactor Regulation |
| References | |
| NS-TMA-2181, NUDOCS 7912280568 | |
| Download: ML19262B572 (17) | |
Text
{{#Wiki_filter:e .J f. 4- .;; Westinghouse Electric Corporation Power Systems sex:55 Pittsuurg1 Pennsylvania 15230 December 19, 1979 NS-TMA-2181 Darrell G. Eisenhut, Director Division of Operating Reactors U.S. Nuclear Regulatory Commission 7920 Norfolk Avenue Bethesda, Maryland 20014
Subject:
Westinghouse Evalt cion of the Prairie Island Tube Rupture Ref: My letter to you of November 13,1979, NS-TMA-2156
Dear Mr. Eisenhut:
The Westinghouse evaluation of the tube rupture event at Prairie Island, as mentioned in the referenced letter, has been completed and is enclosed for your information. Your comments and recommendations regarding the content and usefulness of these reports would be appreciated. Very ruly yours,
. Meu T. M. Anderson, Manager Nuclear Safety Department 1
Enclosure
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ll ' 1649 238 7912280
SG 79-11-030 WESTINGHOUSE EVALUATION OF LICENSEE EVENT Operating Plant - Prairie Island Unit 1 Operating Utility - Northen1 States Power Date of Incident - October 2,1979 INTRODUCTION The Prairie Island Unit 1 plant is located in Minnesota and began com-mercial operation in 1973. It is a two-loop 1650 MWt PWR of Westinghouse design. The event of interest is a steam generator tube rupture which resulted in an automatic reactor trip and safety injection initiation. The terms " tube rupture" and " faulted" steam generator as used in this report are to be interpreted consistent with the Westinghouse-supplied E-3, Emergency Instruction, " Steam Generator Tube Rupture". I. DESCRIPTION OF INCIDENT The description of the incident is taken from interviews with
' Prairie Island operating personnel and management, from review of plar.t records, and from the Northern States Power Company Licensee Event Report, No. LER DPR-42, a copy of which is included as Appendix A of this report.
A. Plant Operating Conditions The plant was operating at 100% power. Reactor coolant system boron concentration was approximately 766 ppm, and one charging pump was operating under normal level control. Automatic pressure control was operating. The reactor coolant average temperature was approximately 5600F. Pressurizer and steam generator levels were normal, and both pressurizer power operated relief valves were operational. 1 1649 239
- 8. Sequence of Events Short Term Events The NSP LER included as Attachment A provides the basic short term sequence of events, parameter behavior and discussion of some of the important considerations. In addition to that provided in Attachment A, the following summary is provided to further clarify and amplify some of the important features of the short term transient of the event.
At 1417 on 10/2/79, a condenser air ejector high radiation alarm was received in the control room. Examination of the instrument reading showed off-scale indication. Coincident with the air ejector radiation alarm, pressurizer pressure and pressurizer level instruments showed rapidly decreasing indications. The highest rate of reactor coolant pressure decrease during the transient was approximately 100 psi / minute, while pressurizer level indicated a rapid decrease at a rate of approximately 10%/ minute. These symptoms provided indication of a loss of reactor coolant, most likely as a steam generator tube rupture, and resulted in auto- matic letdown isolation at 1423, when a second charging pump was manually started. Since RCS indications had not stabilized with the addition of the second charging pump, the third charging pump was manually started at approximately 1424. At 9 seconds past 1424, a reactor trip occurred as a result of low pressurizer pressure, and pressure continued to drop until safety injection initiation occurred automatically at 14 seconds past 1424 as a result of low-low pressurizer pressure. ' Subsequent calculations have been performed by Northern States Power and Westinghouse to estimate the size of the rupture. As noted in the NSP LER, the calculated break flowrate based on pressurizer level behavior was estimated at 391 gpm. In order 1649 240 2
to verify this estimate, Westinghouse utilized calculations based on the total injection flow to the RCS at the point where break flow equaled injection flow. This method resulted in an astimated break flow of 385 gpm. Finally, based on actual rupture geometry derived from visual inpsection of the break, Westinghouse calculated break flow by use of a modified Zaloudek critical flow correlation to be approximately 382 gpm. These diverse methods yielding the same result verify '.he break flow rate. The safety injection actuation logic had been mooified in May 1979 from the original design of initiation from coincident low pressurizer pressure and low pressurizer level to actuate on low pressurizer pressure only. Since pressurizer indicated level reached 0% span prior to the low pressure SI setpoint during this event, this logic change had no effect on the resulting signal for safety injection actuation. Following receipt of the automatic safety injection signal, all safeguards equipment required to actuate operated as designed including startup of the emergency diesels (although their use was not required since off-site power was always available to the emergency busses). In addition, the reactor coolant pumps were manually tripped at approximately 1426 according to a Prairie Island standing order to supplement procedures in compliance with I.E. Bulletin 79-06C. Within a minute of the initiation of safety injection, the mini-mum RCS pressure of approximately 1780 psia was reached, and refill of the RCS commenced by the action of safety injection. As pressure began to increase in the reactor coolant system, continued break flow to the f aulted steam generator resu'ted in a more rapid return of indicated steam generator narrow range level in the f aulted steam generator ("A" steam generator) than 1649'24I 3
the non-f aulted steam generator. This provided positive identi-fication of the."A" steam' generator as the location of the rup-tured tube, and at 1441, the "A" steam generator was isolated by terminating auxiliary feedwater to th t s%am generator and closing the Loop A Main Steamline Isoiecion Valve. When pressurizer level indication was returned due to the action of the safety injection pumps at 1456, one SI pump was stopped in anticipation of RCS depressurization to equilibrate the RCS and f aulted steam generator pressures and terminate the break flow. Since the reactor coolant punps had been stopped per procedures, normal pressurizer spray was unavailable as a means of RCS depressurization. Depressurization of the system was accom- plished by intermittant opening of one pressurizer PORV. Since the pressure and level of the pressurizer relief tank (PRT) were observed to increase wher, the pressurizer PORV was opened, the valve was cycled in an attempt to prevent the rupture of the PRT rupture disc. In addition, the operator initiated spray in the PRT in an attempt to limit the pressure i ncrease. These actions were insufficient to accomplish RCS cepressurization whi'. .naintaining PRT integrity, so at 1503 the other operating SI pump was stopped and the PRT rupture disc ruptured at 1507 when primary depressurization to approximately 950 psia was completed. At this point primary pressure equilibrium with the faulted "A" steam generator was achieved and break flow was reduced to near zero. A stable plant configuration was achieved, leading to the long term system recovery. Long Term Events The NSP LER gives the long term sequence of events, parameter behavior, and discussions regarding some of the considerations e.g. natural circulation cooldown. In addition to the points 4 1649 242
made by NS? the following v.iscussion is provided to further clarify and amplify some of the consideratons during the recovery phase following a steam generator tube rupture. (1) Natural circulation cooldown - During the recovery phase of the event, since the reactor coolant pumps had been stopped at 1426 and not restarted until 2129, the RCS continued to be cooled down on natural circulation. As pointed out in the LER the operators were familiar with this operation. There are several considerations with which Westinghouse plant operating staffs should be familiar when performing a natural circulation cooldown with a steam, generator tube leak or rupture. (1) Since there is conmunication between the primary and secondary side of the f aulted loop steam generator the cooldown of the non-faulted loop steam genera-tor (s) will reduce reactor coolant temperatures but
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will not significantly aid in RCS depressurization. The RCS pressure will remain at or above the faulted SG pressure due to the relation of charging and let-down flow so that a small amount of flow either from, or to, the faulted steam generator secondary will continue until actions are taken to depressurize the RCS below the faulted SG pressure. During the Prairie Island event the primary side pressure remained <40 psi above the faulted loop steam gen-erator pressure while on natural circulation cool-down. It would be most desirable to establish RCS pressure as close as possible to the faulted steam generator steam pressure to minimize the leak flow, as indicated in the Westinghouse reference Emergency Operating Instructions. 1649 243
(ii) Ar.other consideration regarding natural circulation cooldown is the potential for generating large tem-perature gradients within the reactor coolant system and vessel. On natural circulation cooldown the reactor vessel upper head region is essentially stag-nant with water initially at nearly full power hot leg temperature. The water in the upper head cools down slowly due to natural convection heat losses and control rod drive mechanism cooling system operation. (2) Cooldown/Depressurization/SG Drain - This phase of the recovery started at 2129 when the RCP in the non-faulted loop was started. With a RCP operating the primary side was depressurized below the faulted SG pressure by utilizing normal pressurizer spray. When RCS primary side pressure drops below the faulted SG pressure then the SG secondary side water drains into the primary. Baron concentrations in the RCS should be verified to assure adequate shut down margin while this draining operation is in progress. Since a RCP was operating there is no concern regarding an equal mixing of boron. If the depressurization operation was attempted without a RCP operating then boron samples should be taken more frequently since mixing of boron is not aided by forced circulation. At Prairie Is and the decfsion was made to allow the faulted loop steam generator secondary side water to drain back into the reactor coolant system during the depressurization. An alternate to this approach would have called for steam dump to the condenser from the faulted steam generator while depressurizing the reactor coolant system in order to mini-mize the secondary to primary drain. Since Prairie Island had adequate liquid holdup tank capacity, the decision was made to drain the secondary into the primary side in order to minimize radiological releases. 1649 244 6
i During the event the faulted loop steam generator water level returned to the narrow range span from being off-scale high at approximately 0130 on October 3,1979. Steam gen-erator water level was then kept above the top of the U-tubes in order to prevent the steam bubble in the faulted loop steam generator from contacting the relatively cold steam generator tubes. With the faulted steam generator secondary at relatively high pressure, uncovering the steam generator tubes and exposing them directly to the steam space could have resulted in an unplanned depressurization of the faulted generator. Therefore, level was maintained above the tubes until the f aulted steam generator pressure was reduced to near atmospheric pressure. (3) Reactor Coolant Pump Restart The reactor coolant punps were manually tripped following the receipt of an "S" signal. Af ter the system had been stabilized at an RCS pressure approximately equal to the f aulted loop steam generator, NSP recommended that at least one reactor coolant punp should be restarted. Westinghouse agreed with this recommendation which was consistent with the Westinghouse guidelines. The NRC expressed a concern regarding the transient response following reactor coolant pump restart. Specifically the concern was that pressurizer water level might decrease rapidly, due to enhanced RCS cooling, and possibly drop offscale low. Based on a con-servative hand calculation by Westinghouse, it was verified that a decrease in pressurizer water level, if any, would not exceed <l5% of instrument span. The pressurizer water level at this time was being maintained at 40% of span. At 2125 the non-faulted loop reactor coolant pump was bumped and 4 minutes later restarted for continuous operation. The 1649 245 7
RCS pressure and pressurizer water level did not change following the reactor cool &nt ptnp restart. The RCS temper-ature indications came together as expected with a ho; leg temperature increase of approxim,1tely 300F. The tempera-ture increase was due to the mixing of the hotter water in the stagnant faulted loop with the rest of the RCS water, and heat from the hot shell-side fluid in the tube bundle region of the faulted steam generator. The RCS was then depressurized utilizing normal pressurizer spray. 8 1649 246
II. ANALYSIS OF EVENT Analysis of this event shows that when a rapid RCS cooldown occurs with the plant on natural circulation and with one steam genarator isolated, primary flow in the isolated loop will become essentially stagnant. This effect is due to water in the isolated loop heating up as it flows through the steam generator tubes and developing a density head which offsets the driving head in the core. The flow stagnation may lead to temperature indications in this loop t aing non-representative of overall loop conditions, particu-larly if safety injection or high charging flow is being injected. The analysis shows a sharp decrease in cold leg temperature in the isolated loop downstream of the safety injection nozzle, due pre-dominantly to the cold SI water mixing with the low RCS flow; however this temperature is not representative of the bulk tem-peratures in the loop, particularly in the steam generator tube region. When SI is terminated, cold leg temperature rapidly be. ins to return to the secondary temperature in the isolated steam gen-erator. The RCS loop flows and corresponding RCS temperatures resulting from the analysis are shown in Figure 1. 9
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III. WESTINGHOUSE RECOMMENDATIONS A. Cooldown/Depressurization (1) The preferred plant cooldown mode is with at least one reactor coolant pump in operation. If natural cicrulation exists, Westinghouse recommends that, if at all practical, the plant should be maintained at or near hot shutdown until a reactor coolant pump can be started. Forced circulation (pump running) provides much better mixing of reactor cool-ant fluid, and a higher degree of assurance of uniform boron mixing and uniform cooling of structural steel in the reac-tor coolant system. (2) Following a tube rupture incident in which reactor coolant pumps have been tripped, a reactor coolant pump in a non-f aulted loop should be started first to assure slow mixing of fluid in the f aulted loop with the rest of the RCS. (Following a tube rupture, the faulted steam generator is isolated on the steam side. Without heat removal from that steam generator, the fluid may stagnate in that loop. Also, some less borated water may leak from the secondary back into the RCS if RCS pressure drops below sacondary pres-sure.) As a general rule, start first the pump in the loop with the most natural circulation, i.e., t.igh steaming rate and stable RCS temperatures. (3) It is reconmended that cooldown on natural circulation, if necessary, should be performed slowly so that thermal stresses of the reactor vessel can be minimized. (4) The Westinghouse Reference Emergency Operating Instructions currently provide provisions for depressurizing the faulted loop steam generator via steam dump to the condenser or the atmosphere. While Westinghouse believes that tnis approach does result in acceptable radiological doses, there is a 10 1649 249
strong desire to limit radiological releases to a minimum or zero whenever possible. Westinghouse will incorp3 rate in the guidelines an alternate means of depressurizing the faulted loop steam generator by allowing the draining of f aulted loop steam generator secondary fluid into the reac-tor coolant. Utilities should reviev each plants liquid holdup tank capacity to determine whether this is a viable alternate. In addition, an evaluation of the impact on radiological doses is currently being performed by West-inghouse to assess the relative release for each alternative. (5) While Prairie Island did not cooldown and depressurize the RCS on natural circulation it could be deemed necessary for some future event. Westinghouse will incorporate a caution in the guidelines emphasizing the step in the guidelines for sampling boron concentrations for this situation. (6) During RCS cooldown under natural circulation conditions, temperature indications in loops with isolated steam gen-erators should not be assumed as representative of bulk temperatures in the loop. Flow in the isolated loop may become stagnant, leaving the primary fluid in the steam generator at approximately the secondary side steam tem-perature. Indicated temperature in the isolated loop should be considered non-representative particularly during periods of safety injection or high charging flow. B. RCP Trip / Restart (1) It is reconmended that Westinghouse plants incorporate the Westinghouse guidelines provisions regarding RCP operation as provided in Westinghouse letter TMI-06-97, dated Nov. 7, 1979. These guidelines would keep the RCP's running during an event such as that described in this report so that cool-down on natural circulation and depressurizing the RCS with the Pressurizer PORV would have been precluded. For plants 1649 250 11
which may have tripped the RCP's with the RCP termination criteria given in the Westinghouse guidelines (plants with low shutoff head HPI), specific instructions are given at the appropriate time for RCP restart. (2) It is recomended that Westinghouse plants incorporate Westinghouse guideline provisions for RCP restart in plant recovery procedures for a steam generator tube rupture, as provided in Westinghouse letter TMI-06-88, dated Oct. 5, 1979 and letter TMI-06-97 as referenced above. C. PRT Considerations Current Westinghouse reference emergency operating instructions describe depressurizing the RCS by only one sustained opening of one pressurizer PORV if normal spray is not available for system depressurization. Subsequent calculations have shown that more mass is required to be discharged from the PORV to accomplish system depressurization when the valve is cycled, since some system repressurization occurs due to continued safety injection flow each time the valve is closed. (Note that the stable RCS pressure during safety injection is based on the pressure at which SI flow equals break flow). This larger release to the PRT when operating the PORV in a cyclic manner could contribute to loss af PRT integrity (i.e. burst of rupture disc). It is recommended that plant operating instructions consider this situation. A further observation of PRT behavior during the RCS depressur-ization operation using the PORV relates to the transient beha-vior in the PRT during the cyclic PORV operation. Two aspects of this behavior were observed, each of which could have contri-buted significantly to eventual rupture of the PRT rupture dis . First, it was noted that when the PORV was closed, a resulting drop in PRT water level and pressure was noted. This behavior 12
indicates that continued steam discharge to the PRT can estab-lish some volume of saturated liquid within the PRT such that instantaneous condensation of discharge steam cannot occur. Instead, the steam, on entering the PRT, must migrate some dis-tance to interact with subcooled liquid in order to condense. Thus, it is likely that during periods of steam discharge, some volume of liquid beneath the liquid level in the PRT is dis-placed by steam voids. This process would contribute to level swell in the PRT in excess of that provided by mass addition to the liquid inventory during periods of steam discharge to the tank. This level swell would cause a further pressure increase in the PRT due to gas compression, and would explain the observed drop in PRT level and pressure when the PORV was closed as the steam voids beneath the liquid level were condensed. It is recommended that plant operating personnel be made aware of this possible behavior. A second observation with respect to PRT behavior relates to potential effects of non-condensibles during discharge to the PRT. Since the pressurizer vapor space contains some quantity of non-condensible gases, addition of these can raise PRT pres-sure beyond that resulting from liquid mass addition and level swell noted above. Calculations of the liquid mass added to the PRT during the Prairie Island event have shown that insufficient liquid was added to the tank to raise pressure to the point of disc rupture. Therefore, non-condensible introduction to the tank could be a further contributor to loss of PRT integrity. It is recomended that plant operating personnel be made aware of this consideration. Increasing pressure in the PRT during RCS depressurization through a PORV is primarily a result of PRT level increase due to increasing mass inventory and level swell. Prior to rupture of the PRT rupture disc, little or no steam is added to the vapor space of the tank. Therefore, actuation of spray in the PRT will not be effective in controlling pressure. Instead, the 13 lb
liquid mass addition to the tank by the PRT spray will serve to increase PRT pressure. It is recomended that plant operating personnel be made aware of this consideration. D. Operator Information The alarm typewriter record provides additional data to the operators during a plant incident and shows the data in chrono-logical order. However, there are programs within the computer which normally monitor plant parameters and signal the operator when something is not correct. These monitoring programs are not interrupted by an incident and continue to print out data on the typewriter which interferes with rapid retrieval of the data pertinent to the incident. The record would be more useful to the operators during the course of the incident if the sequence of events record were not interrupted by the additional data coming from miscellaneous plant monitoring programs such as: Boron Follow, Redundant Measurement Status, Reactor Protection System Monitor and Large Motor Monitor. It is recomended that each utility review this record and minimize such interruptions to the maximum extent possible. E. RCP and SI Termination Procedures Westinghouse recomendations concerning instructions for termi-nating reactor coolant pump and safety injection operation following events which actuate safety injection have previously been discussed with the Westinghouse Owners Group. These recom-mendations have been reviewed to determine whether any changes should be made. These procedures have also been discussed and agreed to with the tRC. It is recomended that these instruc-tions, as transmitted by Westinghouse letter TMI-0G-97 be incorporated into plant procedures. 1649 253 14
F. Subcooled Press: e Control Operating procedures should recognize the differences in pres-surizer oper'tting characteristics when pressurizer water is subcooled. For rapid pressure reductions during normal opera-tion, flashing of saturated pressurizer liquid is the dominant mechanism 'sloving the rate of pressure decrease. For longer-term recovery (over tens of minutes), pressure is restored by boiling saturated liquid with pressurizer heaters. If the pressurizer liquid is subcooled, neither of these mechanisms exists, pressure drops rapidiy as pressurizer water level decreases, expanding the steam bubble. Therefore, under these conditions, maximum pressurizer heaters should be energized, and pressurizer liquid temperature monitored, until saturated conditions are restored. Similarly, pressurizer spray normally controls pressure increases. Without spray, an increase in pressurizer level compresses the steam bubble into the superheat range with a relatively large pressure increase. The pressure characteristic is similar to compressing a non-condensible gas. G. Letdown Initiation After SI Actuation Each utility should review its policy and procedures for reset-ting containment isolation, and restoring normal letdown follow-ing an automatic containment isolation signal. In particular, are existing radiation monitoring or sampling practices believed adequate to preclude significant contamination of auxiliary systems or atmospheric release in the event that reactor coolant activity increased significantly during whatever transient actu-ated containment isolation? (Note: According to fUREG-0600, the principal pathway for radioactive release to the environment from the TMI-2 accident was "through the makeup and purification system".) 1649 254 15
NSP Recomendations Westinghouse agrees with all the NSP recommendations indicated on pp 16, 17 of the attached LER with the following coments:
- 1. Westinghouse will add a stop or caution in the Westinghouse Refer-ence Emergency Operating Instructions for the operator to stop the turbine-dr1ven auxiliary feed pump as soon as possible and to shut the steam supply valve from the faulted steam generator.
- 2. Westinghouse believes that the current Westinghouse guidelines place sufficient emphasis on expeditious isolating of faulted steam generator and RCS depressurization/cooldown.
- 3. The Westinghouse guidelines consider both cases of with and without RCP operation. The guidelines are clear in that depressurization of the RCS with normal pressurizer spray is the preferred method.
Additional recommendations will be made by Westinghouse in this document regarding RCP operation.
- 4. Operators should be trained so that they understand the phenomena taking place during the transient. Specifically, when safety injection is operating the RCS pressure will equilibrate at the point where SI flow matches break flow.
4b. This recommendation relates to the correct mode for recommendation
- 4. Westinghouse has considered the increased flow out the break due to allowing the system to equilibrate but believes that this is the correct course of action because,1) pressurizer level might not be present and safety injection must be kept operating, 2) operator actions should be initiated from stable conditions rather than transient conditions whenever possible and, 3) termination of SI prior to system depressurization results in continued RCS inventory loss and depressurization in the absence of an indi-cated system level.
6 1649 255
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APPENDIX A 1649 256
NSP NORTHERN 5TATES POWER COMPANY wis u ranou s. wis u r sora es oi October 16, 1979 Mr J G Keppler Office of Inspection & Enforcement U S Nuclear Regulatory Commission 799 Roosevelt Road Glen Ellyn, IL 60137
Dear Mr Keppler:
PRAIRIE ISLAND NUCLEAR GENERATING PLANT Docket No. 50-282 License No. DPR-42 50-306 60 Tube Ruoture in No. 11 Steam Generator Enclosed are three copies of the Licensee Event Report and supple-mental information for this occurrence. This event is reported in coupliance with Technical Specification 6.7.B.1(c). Yours very truly, n G L 0 ,Mayer, PE no~ T' h - Mahiger of Nuclear Support Services LOM/ JAG /ak cc: Director, IE, USNRC (40) Director, MIPC, USNRC (3) Director, Di' . of Operating Reactors, NRC (Attn: M Crotenhuis) (5) G Charnoff MPCA Attn: J W Fernan 1649 257 Df,gaebntsas
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1649
TABLE OF CINIENTS Pace Table of Contents i List of Figures ii List of Tables iii A. Introduction 1 B. Regulatory and Offsite Agency Notification 1 C. Operational Sequence of Events 2 D. Operational Parameter Behavior - Short Term 4 E. Operational Parameter Behavior - Iong Term 4 F. Natural Circulation Cooldown/Praining 5 G. BCS Leak Rate and Minimum Water Inventory Calculation 5 H. Radioactive Releases 8 I. Offsite TLD Measurement 10 J. RCS Iodine Behavior 11 K. Steam Generator Inspection / Corrective Actions 11 L. Pecovery 14 M. Planned Actions 14 N. Ccmparison of FSAR and Actual Break Results 14 O. Reconuendations 16 P. Sumnary 17 1 1649 260
LIST OF FIGURES Figure Title Pace 1 Pressurizer Invel vs. Time 18 2 Pressurizer Pressure 19 3 Nuclear Power 20 4 Tave 21 5 Tc 22 6 bT B 7 Steam Pressure 24 8 Pressurizer Iavel and Level Setpoint 25 9 Pressurizer Pressure 25 10 FCS Icop Pressure 26 11 Cold Leg Terrptrature 26 12 Hot Ieg Temperature 27 13 Wide Range Steam Generator Level 28 14 Narrow Range Steam Generator Ievel 28 15 Steam Flow /Feedwater Flow - 11 SG 29 16 Steam Flow /Feedwater Flow - 12 SG 29 17 Turbine Steam Header Pressure 30 131 18 I Activity Behavior as a Function of Time 31 19 11 SG Outlet Eddy Current Inspection Program 32 20 11 SG Inlet Eddy Current Inspection Program 33 4 21 12 SG Inlet Eddy Current Inspection Program 34
- 22. Sketch of teaking and Adjacent Tubes 35 ii 1649 261
Ficure Title Pace
. 23 Overhead View - Failed Tube Area 36 24 Side View - Failed Tube Area 37 25 Frcnt View - Failed Tube Area 38 LIST OF TABLES
- 1. Pressurizer Level Time Behavior 7
- 2. Gasecus Releases via Air Ejector 8
- 3. Gaseous / Iodine Releases via 'ID Aux. Feed Pump 9
- 4. Gasecus/ Iodine Releases via Steam Dump 9
- 5. Liquid Releases 10
- 6. TID Ganrna Radiation Exposure 10
- 7. Unit 1 Steam Cenerator History 13
- 8. Ccaparison of FSAR and Prairie Island Break Results 14
- 9. Ccnparison of FSAR and Actual RCS Activities 15 1649 262 iii
A. I?TITODUCTION On October 2,1979, a tube break occurred in #11 steam generator of the Prairie Island Nuclear Generating Plant, Unit 1. B is event is being reported in accordance with Technical Specification Section 6.7.B.1 (c) in that an abnormal degradation of the reactor coolant pressure txx2ndary occurred. h is report describes the event and subsequent analysis in detail since the break, due to riechanical wear, is expected to be of interest to the nuclear industry. It should be noted that all engineered safety systems functioned as designed and the plant operating staff accomplished safe reactor shutdown, steam generator isolation, and RCS
. cooldown in an expeditious manner following existing operatirg procedures.
E is report addresses the following topics:
- 1. Regulatory and Offsite Agency ?btification
- 2. Operational Sequence of Events
- 3. RCS Parameter Behavior - Short Term
- 4. RCS Parameter Behavior - Iong Term
- 5. Naturt.1 Circulation Cooldown
- 6. RC3 I2ak Rate Determination
- 7. Radioactive Releases
- 8. Offsite TLD Measurements
- 9. PCS Iodine-131 Activity Behavior
- 10. Steam Generator Inspection and Cause Identification
- 11. Corrective Actions
- 12. Ccrparison of FSAR analysis and actual break results
- 13. Becanmendations Additicnal reports on this event, 79-27, may be issued if appropriate.
~
B. REGUIAIORY AND OFFSITE AGENCY FMIFICATION
?btifications associated with this event were prcmot. S e Emergency Director declared a site emergency at 1430. Offsite notifications are not required for a site emergency; however, the Emergency Director, being cognizant of the FSAR analysis, deemed the event significant enough to alert the offsite agencies of the potential for possible offsite consequences. All offsite contacts required for a general emergency were alerted. Se following are several of the offsite agencies contacted:
(a) Minnesota Department of Emergency Services (1432) (b) NRC Drergency Response Center, Bethesda, and the Region III I & E Director (1433) (c) NSP General Manager of Power Prcduction (1445) Be Govemor of the State of Minnesota was notified of the event at 1432. Se NRC I & E Site Inspector heard the announcement of the reactor trip at 1424 and was in the control rocm within one minute of the event. A Minnesota Dephrtment of Health Emergency Response Team was dispatched and arrived at the site environs at approximately 1700. m Se Region III I & E Emergency Response Team arrived on the site at approximately 1830. The site emergency was terminated at 2200 on October 2. C. OPEPATICtE SEQUENCE OF EVENIS Ihe following is a chrcnological sequence of events that occurred frcm the first indication of the steam generator tube break until the leakirs tube was identified. Date Time Event Oct 2 1414 High Radiation alarm on 1R15 (air ejector discharce gaseous radiation nonitor) 1420 Overtemperature AT Turbine Runback due to decreasing pressure 1421 Iow Pressurizer pressure (< 2139.9 psig) 1421 (approx) Ccmnenced load reduction 1422 Iow pressurizer level (< 18.3%) 1423 Started second charging pump (#11) 1424 (approx) Started third charging pump (#13) 1424:09 Beactor trip for "Iow Pressurizer Pressure" (< 1900 psig) 1424:14 Safety injection occurred due to "Iow Pressurizer Pressure (< 1815 psig) 1424:33 Minimum RCS water inventory; RCS pressure begins increasing 1426 11 Reactor Coolant Pump stopped 1427 12 Reactor Coolant Pump stopped 1432:29 11 Steam Generator level increased above the . "Io Lo Level" setpoint (13%) on the narrow range after having gone offscale low after the trip (It is normal for SG Iavel to go offscale low on a trip; ricovery in this case was much nore rapid than tsual)
Date Time Event Oct 2 1438 SI Reset 1441 Io:p A MSIV closed 1456 Pressurizer Level returned on scale 1456 Stcpped 12 SI punp 1456-57 Began depressurization of the RCS using the pressurizer PORV. (The valve was cycled 6 to 8 times to reduce pressure to required value) 1502 Pressurizer level reached the high level setpoint (> 55%) 1506 11 SI Punp stopped 1507 Pressurizer Relief Tank rupture disc relieved 1515 RCS pressure at 910 psig (sane as 11 SG pressure) leak apparently stopped 1550 Cmrmnced normal coalcbwn Orc 3 0640 RHR placed in service to continue cooldown to cold shutdown 1300 PCs at cold shutdown - Oct 6 1640 cmpleted draining of RCS Oct 7 0250 Identified leaking tube
'Ihere are several considerations that need to be made during a recovery frm an event as this. For the cooldown:
- 1. Since the leaking steam generator cannot be used for cooling, RG cooldown will tend to te slower. Also, there will be scme delay in ecoling the leaking steam generator to the point where entry is possible.
- 2. With a leak next to the tubesheet, there will be scrne draining of steam generator water into the RG. Adequate boron must be
. injected. In this case, a second boric acid tank was used to raise the boric acid concentration. In 11 steam generator, a sufficiently high boron concentration was measured to ensure no problems with RCS dilution during the cooldown.
- 3. Since large quantities of 12% boric acid were used for injection via the SI pumps to the cold legs, these lines must be flushed.
1649 265
D. OPERATIONAL PARAMETER BEHAVIOR - Short Erm te Prairie Island plant ctcputer has the " Post-trip review" option which accumulates plant key parameter data on a continuing basis and saves the data unmediately preceding and af ter a reactor trip. In addition, sof tware has been developed which plots this data. Figures 1 through 7 srow the behavior of the followirg parameters as a function of time: (1) Pressurizer I.evel (2) Pressurizer Pressure (3) Nuclear Power (4) Tave (5) Tc (6) Delta (A) T (7) Steam Pressure (secondary) It is worthwhile noting that pressurizer level went off scale before the safety injection occurred due to low pressurizer pressure at 1815 psig. Accident analyses in the past had assumed initiation of the SI signal due to the coincident low pressurizer level (5%) and low pressurizer pressure (1815 psig) signals. In May 1979, the SI actuation scheme had been nodified, as a result of tree Mile Island followup evaluations, to a 2-out-of-3 coincidence low pressurizer pressure actuation logic. With either scheme, SI signal initiation would have had to wait until pressure had dropped below 1815 psig. Bus, the safety analysis still bourus the plant response. Pressure during the nest severe portion of the transient was dropping at a rate of about 100 psi / minute. Pressure recovery was rapid once the SI pumps started injecting. Se plots of nuclear power and delta T show the power reduction prior to the trip. Se increase in Tave would be expected to acccupany the load drcp since the rods were at the withdrawal limit. Tc increased as expected after the load reduction and appeared to be levelling out at about 532F when the trip occurred. E. OPERATIONAL PAPAMETER BEHAVIOR - I.cng Term Figure 8 through 17 are recorder tracings showing the long term behavior of the following primary and secondary system parameters in order: (1) Pressurizer Level and Level Setpoint (0-100%) (2) Pressurizer Pressure (1700-2500 psig) (3) RCS Irop Pressure - Icops 11 and 12 (0-3000 psig) (4) Cold Leg Temperature - Irops 11 and 12 (50-650F) (5) Hot Leg Temperature - Icops 11 and 12 (50-650F) (6) Wide Range Steam Generator Level - 11 and 12 (0-100%) (7) Narrow Range Steam Generator Ievel - 11 and 12 (0-100%) 6 (8) Steam Flow /Feedwater Flow - 11 Steam Generator (0-4.5 x 10 lb/hr) (9) Steam Flow /Feedwater Flow - 12 Steam Generator (0-4.5 x 10 lb/hr) (10) Turbine Steam Header Pressure (0-1500 psig)
}bh9
H. RADIOACTIVE RELEASES 2e plant health physics staff nonitored the plant envirtnment for offsite release and determined activity levels of radioactive liquids and gases contained by plant systems or released to the environment. Airborne Activity Gas releases were made through the following paths: (1) Air ejector discharge (2) Turbine driven auxiliary feed pump exhaust (3) Atnespheric steam dumo (4) Gland steam exhaust te following is a summary of the releases made via those paths Periodic grab samples were taken on the air ejector exhaust in order to accurately assess the activity released via this path. S e air ejector was used during the period 1414, 2 October 1979 through 0730, 3 October, 1979. Even though the 11 steam generator was isolated at 1441, the health physicists deemed it prudent to nonitor the exhaust until the unit was secured. '1he following table summarizes the activity released during the period. TABLE 2 Gaseous Releases via the Air Ejector Nuclide Activity (CQ
. Xe l3 21.9 Xe l35 4.63 Ar 41 2.00 E-05 Kr 85m 0.034 Kr 0 0.446 3
H 1.94 E-05
'Ibtal Activity 27.01 C g The turbine driven auxiliary feed pump was operated for approximately
~ 24 minutes (until after SI was reset). Based on the 1715 steam generator activity data and assuming full flow with the auxiliary feed pump (a conservative assumption), the followirg is a suntnary of the radioactive releases via this path: 1649 267
TABLE 3 Gaseous and Icdine Releases via the TD Aux Feed Pt np Nuclide Activity (pc) 133 3.07 E+5 Xe 135 8.73 E+4 Xe Kr8 % 2.46 E+4 Kr 0 2.20 E+4 41 Ar 3.92 E+4 131 4.81 E-1 1 I l33 3.06 E-1 One of the 2 atmospheric steam dump valves off lcop A opened for 3 seconds after the reactor trip. This time is fairly typical based on previous operating experience. These valves normally take about 3 seconds to stroke full open. In order to determine the possible release via this path, it was assumed that full flow passed for 3 seconds and activities were backcalculated frcm the 1715 sample (as for the TD auxiliary feed pump evaluation). The releases were as follows: TABLE 4 Gaseous and Iodine Releases via the Steam Dumo Nuclide Activity (pc) 131 I 0.54 133 I 0.35 Xe l33 3.42 E+4 Xe l35 9.72 E+3 0 Kr 2.74 E+3 87 Kr 2.45 E+3 - Ar 41 4.37 E+3 tb estimate of the release via the gland steam exhaust is available at this time. Release by this path is expected to be less than that via the air ejector path. Further investigations will be made in this area. 1649 268 Liquid Activity , he air ejector condensor drains to the turbine building sump. Liquid sa:.ples were taken during the period that releases were made frca the turbine building sump. De table below sumarizes the releases trade during the period 2 October 1979 through 4 October 1979. TABLE 5 Date Nuclide Activity Released (pc) 2 Oct - Xe l33 1.23 E+3 Xe l35 7.56 E+3 3 Oct Xe l33 1.08 E+4 Xe l35 2.51 E+3 4 Oct Xe l33 1.13 E+3
'Ibtal Activity Released = 2.32 E+4 pc Steam generator blowdown was being directed to the condensor prior to the tube failure, thus this reduced one possible path for liquid release to the environment. Se circulating water system was operatino in the recycle r: ode where only 150 cfs may be returned to the Mississippi River. Bis tended to spread out the releases frcm the turbine building sump to the river over a longer period. Bere was no detectable iodine in the liquid samples during this period.
I. OFFSITE TLD MEASUREMENTS TLD's had been placed in four locations near the Prairie Island f acility cn 2 October 1979 (see table below for exact details) as the fourth quarterly TLD's. R ese were replaced on 3 October 1979 because of the incident. Rese TED's were shipped to and developed by Hazelton Environmental Sciences Corporation, of Northbrook, Illinois. Rese devices had a higher uncertainty because of higher in-transit exposure ccupared to those experienced in the field. Table 6 summarizes the TLD location, exposure period, duration and total exposure as reported by Hazelton Services. TABLE 6 . TLD Gamma Radiation Exposure Location Exposure Period Duration of Exposure 'Ibtal Exposure (Times) (Hours) (mrem) PI-l 10-2; 1100 to 28 0.18 + 0.42 Prescott 10-3; 1500 TW Gama Radiation Exposure Incation Exposure Period Duration of Exposure '1btal Exposure (Times) (Hours) (mrem) PI-2 10-2; 1030 to 29 0.33 + 0.40 G1sworth 10-3; 1535 - . PI-3 10-2; 1315 to 27 0.27 + 0.42 W Sector 10-3; 1615 - PI-4 10-2; 1330 to 27 0.28 + 0.39 Icck& Dam #3 10-3; 1620 -
'Ihese measurements show the low dose that could have teen received and these should have been low due to the low level release that occurred.
J. RCS IODINE BEHAVIOR Over 90 RCS I l31 sanples were measured in the 51/2 days af ter the event because of the interest in the spiking phencrenon and the transfer of coolant frem the RCS to the secondary with subsequent possig release of activity to the environment. Figure 18 shows the I activity behavior during the period 1515, 2 Octoter g 9 through 2200, 7 October 1979. Also indicated on the plot is th" I level neasured at 0730, 2 October, and shcun as the pre-trip les el. 'Ihe Indim -131 activity leveled out at approximately 8.5 x 10 # >c/ml because the purification system ion exchangers had been valved out after the trip to prevent reduction in the RCS boron concentration. K. STEAM GENERA'IOR INSPECI' ION / CORRECTIVE ACTIONS An inspection prcgram of the steam generator tubes was conducted with the following objectives: (1) to identify the ruptured tube (2) to obtain information on the possible cause of the tube rupture (3) to detect any further tube degradation in the steam gererator, ard (4) to determine the general condition of the steam generator tubirg.
'Ihe evaluation of the break and identification of the exact failed tube was acccrnplished by draining water frcrn the secondary side of the steam generator into the RCS through the opening of the leaking tube. Once the water on the seo:ndary side stopped draining, the break elevation was determined. 'Ihen by slowly adding water to the secondary side and visually inspecting the tube sheet frcm the primary side through the manways, the specific tube was identified.
Since the leaking tube (Row 4, Colunn 1, Inlet side) was located in the outer periphery of the tube bundle and the break was just above the tube sheet within the flow lane, foreign object damage was suspected. Therefore, the eddy current inspection (shown in Figures 19 and 20 for 11 steam 1649 2N
generator and Figure 21 for 12 steam generator) was concentrated in the outer periphery tubes. Be inspection program was conducted in accordance with Technical Specifications, Section 4.12. W e results of the eddy current examir.ations revealed that the Row 3, Colum 1 tube (adjacent to the failed tube) had irdication of a 65% reduction in wall thickness. Le Row 2, Column 1 tube (next tube) had a passible indication of <20% reduction in wall thickness. All of these indications were at approximately the sane elevation.
~
A complete visual examination of the outer peripheral area of the tube tur.dles and the flow lanes for both steam generators revealed no other signs of foreign objects. In addition, the eddy current examinations conducted for both steam generators revealed no other tubes with wear or degradation. With the aid of mirrors and fiber optics, a visual examination of the three dearaded tubes verified the eddy current results and revealed that the creak ressbled a classical overpressure turst (running approximately 1 1/2" in the longitudinal direction of the tube with an cpening width of approximately 1/2"). We other two tubes (Pcw 3, Column 1 and Row 2, Column 1) showed signs of wear. All wear marks were on the outer peripheral side of the tubes. Rese patterns were documented by photographs and are depicted in Figure 22. During this time, a coil spring, later measured to be 8.5" long,1.25" diareter, and 3/32 gauge was found to te lying on the tube sheet adjacent to the defective tubes. One end of the spring was lodged under the tube lane blocking device and the other end was free to neve. Figure 23 is an overhead view showing the location of the spring, tube lane blocking device, and the peripheral tubes. Figure 24 is a side view, and Figure 25 is a front view. A definite wear pattern on the tube sheet indicated that the spring had noved during operation. Later, a second spring, identical to the first, was found on the cold leg side. It was located just opposite the first sprirg in a similar condition with one end lodged under the tube lard blocking device and the other end extendig out cnto the tube sheet. In addition, part of an aviation hose clamp was found next to this spriry on the cold leg side. A close visual examination of the sprina on the cold leg side, the tubes and the tube sheet surface revealed no signs of spring novement, tube damage or wear. B is was confirmed by eddy current examination of all eight tubes in Column 1 in close proximity to the second spring. Once these objacts were renoved frcm the steam generator it was apparent that the spring and piece of hose clamp frcm the cold leg side were encrusted with oxides indicating no active novement while the coils of - the spring frcm the hot leg side had definite signs of wear. Rese springs have been shipped to Westinghouse for further examination. he springs and clamp appear to have been part of sludge lancing equipment used in one of the previous outages. Table 7 summarizes the work history on the Unit 1 steam generators. It appears that this spring was dropped into the steam generator prior to installation of the tube lane blocking device. Investigatiors in this area are continuing. 1649 2/I -
Three courses of corrective action were identified based on the following facts: (1) the pattern of tube wear (2) the location of tube wear relative to the spring location (3) the wear pattern of the spring on the tube sheet (4) the signs of war en the spring wire (S) no other tubes that were inspected other than the three previously
- discussed had any signs of wear or tube degradation (6) No other foreign objects were found.
It has teen concluded that the tube break was the result of reduction of wall thickness by the wearirg action of the spring against the tube. The three courses of corrective actions identified were - (a) plug the two defective tubes and several adjacent tubes, (b) re::ove a section of the defective Row 4 tube and plug the two defective tubes, or (c) stabilize the stabilize the defective Row 4 tube fran the primary side and plug the two defective tubes. Discussions a: Tong NSP, Westinghouse, and NRC staff re-vealed that option (a) should be selected for several reasons - (1) in accordance with AIARA, the occupational exposure would be least, (2) uncertainties in the desian concept of tube stabilization, and (3) minimize effects of possible instability of the defective Bow 4 tube. In addition to the failed tube, and the tube with 65% wall reduction, the remaining four adjacent tubes to the failed tube were plugged. This action was taken to eliminate the re: tote possibility of the failed tube breaking further and damaging the adjacent tubes. A secondary side pressure test is being conducted to assure leak tightness of the clugs. TABLE 7 UNIT #1 STEAM GENERATOR HISTORY OUTAGE DATE WORK PEREORMED EDDY CURREN'T SLUDGE IANCING 12/17/73 PERFORATED PIATES NONE NO 09/05/74 NCNE BO E S.G.s BOm S.G.s . 04/25/75 tmE BOTH S.G.s IK7IH S.G.s 03/04/76 FDDIFIED S.G.ORI- EDTH S.G.s BOIH S.G.s . FICE, DECKS, F.W. RItU & BIGDChN IRJES 04/17/77 ImE EK7IH S.G.s EK7IH S.G.s 03/26/78 taE S.G. #12 BOTH S.G.s 04/06/79 taE NONE EK7IH S.C.s 1649 272
L. RECOVERY 2e following schedule is planned for return to power depending u;en activity cleanup in the secondary systen: Date Event
~
Oct 17 Fill and vent RG Oct 19 Heatup the RCS Oct 21 Reactor critical Oct 22 Unit at 50% power M. PIANNED ACTIONS Durirg the next refueling outage, the plant staff will inspect the area of the failed tube for anar.alous behavior of the plugged tubes. N. COMPARISON OF FSAR RESULTS VS AC'HJAL BREAK RESULTS The Prairie Island FSAR Section 14.2.4 addresses a steam generater tube rupture. We table below st:nmarizes differences between the FSAR calculations and the October 2 break results: TABLE 8 Cancarison of FSAR and Actual Break Pesults Prairie Island Item FSAR Tube Break Iaak rate, gpn - 616 ~ 390 Percent defective fuel, % 1.0 0.01 Previous leak rate prior 5.0 0.0 to break, gpn Ibs., steam transfer 120,000 ~5,000* 30 minutes g activity released, Ci 21,700 Xg 1 equivalent ~ 30 (actual Xe133) I 209 ~1.0E-6 (actual)
- tore - Steam released fran operation of the turbine driven auxiliary feed-pump and steam dump to atnesphere actuation.
)h/)t 273
'Ihe FSAR assumed specific radionuclide mncentrations in the RCS coolant as shown in Table 9 which empares selected radio nuclides to the actual concentrations in the RCS coolant as measured at 0730 on 2 October 1979. It should be noted that all actual mncentrations were well below the postulated FSAR concentrations, thus assuring that the radioactivity levels released during the event were bounded by the PSAR analysis.
TABLE 9 Ccrr.parison of ESAR and Actual RCS Activities (pc/ml) 1 Measured Activity mble Gases FSAR 85 1,17 Kr
-2 Kr 0
1.46 1.19 x 10
-2 Kr 0
0.87 1.60 x 10 88 Kr 2.58 - 133 2 -1 Xe 1.74 x 10 3.35 x 10 133m -3 Xe 1.97 5.63 x 10 135 -2 Xe 4.95 8.32 x 10 1 5m 0.14 Xe Xe l38 0.36
-3 Ar 41 1.18 x 10 Corrosion Products / Activation Products 4.2 x 10-3 54 -3 Mn 1.19 x 10 58 -3 3.18 x 10
-4 cA 8.1 x 10 24 -3 Na 3.83 x 10 Non Volatile Fission Products l31 -2 I 1.55 2.15 x 10 133 -2 I 2.55 1.08 x 10 1649 274
-15
Ccrr;arison of FSAR and Actual RCS Activities (pc) m1 tbble Gases FSAR Mrasured Activity I I 1.4 7.0 x 10-3 l36
. Cs 0.33 6.7 x 10-4 137 Cs 0.43 1.73 x 10-3 l39 Cs -
2.45 x 10-4 99* Tc - 1.40 x 10-3 99 tb 2.11 8.47 x 10~4 S8 Y - 1.78 x 10 -3 FMES
- 1. FSAR Appendix D4
- 2. Sanple taken 2 October 1979, 0730
- 0. RECOMMENDATIONS A review of the event has resulted in the followirs recomnendations and comrrents -
(1) A note of caution should be added to the steam generator tube rupture procedure to have the operator stcp the turbine-driven auxiliary feed pump as soon as possible and to shut the steam supply valve frm the affected steam generator. Bis was done even though this caution had not been in the procedure. (2) Add a note of emphasis to the operator to isolate the leaking steam generator as soon as possible and to keep in mind that the MSIV bypass can be used to protect the steam generator fran overpressure. Also, reducing the RCS pressure quickly, while maintaining adequate RCS subcooling, (which was done during this event) will help prevent overpressure of the secondary side. (3) Consider operation of the reactor cx;olant pumps during a steam generator tube break. 'Ihis muld allow use of the spray valves in the depressurization process, which could minimize the citance of blowing the pressurizer relief tank rupture disc. It shc>>1d be pointed out that even though tne disc failed, there was little discharge to the containment. _16_ 1649 275
(4) he industry should consider the problems associated with a tube break recovery, in particular - (a) increasing pressure indicates level has prc6 ably reached its lowest point and that level is recovering (even if off-scale low), and (b) bringing pressure up in the pressurizer to greater than 2000 psig leads to increasing flow O(JT of the break (thus slower recovery) and decreasing makeup flow frca the SI pumps (due to pug-head curve efiaracteristics) (5) Evaluate the feasibility of not isolating instrument air to the containment, since the POR'/'s are used to reduce RG pressure in this event. Under current logic and procedures, contairnent isolation must be reset to repressurize the PORV accumulators. (6) Upgrade procedures for control of material into and out of the s*eam generator and other enclosed spaces. P.
SUMMARY
nis 14-day recort has atte:cted to c :coletely address all areas of interest to the NRC. Additional reports will be subnitted, as apprcpriate. 1649 276
LO480A 24 + I FIGURE 1 I I I I Pressurizer Level I I 21 + 1 g I I I
- I I
- I 18 + 1 I
- I I I I
- I IS + 1
% I
- I I
- I I I 12 + * **
- I I
- I I I e I
- I 5 9 + 1 8
I
- I I I I
- I 6 + [
I
- I I
- I I I 3 +
- I I I I
- I I I O + I I
- I I
- I
~
I
- I
?
~~
~3 +
I
- I c I I 12* ** * **
- N I I * * ** ** * ** ** * **
- si -6 + 1 sj I+_________+________+__________+________ #__ _ _ __, ___ ,___ _ _ , _ _ _ _ _ _ _ ,
-200 -100 0 100 200
-150 -50 Time (sec) 50 ISO liORIZ
PO480A 2380 + I FIGURE 2 I I I I
! Pressurizer Pressure I
2300 + I I I I I I I 2220 + I . I I I I I I 2140 + I I ** I PSIG I ** I I ** **
- I 2060 + **
I I
- I I ** I I ** I 1980 + ** I I ** I
& I ** I
- I *
' I **
1900 + I * ** I I **
- I I * **
- I I * *
- 1820 + 12 **
- I I * **
- I I I I 1740 + I I I I I I I
[ 1660 + I L-e I I I I N 1580 +
- I s3 1,-__------+-------+---------+--------+------ +--------+----- + =--
+
co -200 -lCO O I00 200
-150 -50 Time (sec) 50 150 HORIZ
t10052A FIGURE 3 100 + ** ** * ** I I
- I I
- Power Range I
I
- I 90 + ** ** * ** ** * ** **
I I I I I I I 80 + I I I
% I I I I 70 +
I I I I I I I 60 + I I I I I I I 50 + I e I I O I I i I I 40 + I I I I I I I 30 + I I I I I I , I 20 + I I I I I I I
& 10 + '" I I I C I I I 12*
- O +
I+--------+-------+---------+---------+I -----+---- -&-------+--------+
-200 -100 0 100
-150 200
-50 Time (sec) 50 150 110RI Z
T0401A FIGURE 4 . 564.0 + I I 11 RC Loop T I avg I I I I S61.5 + 1 I ** I I
- I I
- I 559.0 + *
- I I * ** * * * **
- I I * ** I I I SS6.S + I I I F I I I I S54.0 + I I I i I 12 o g H g 8
551.5 + I I I I I I I S49.0 + I I I I I I I S46.5 + 1
- I I i I I I S44.0 + I I I
- I I I I
- O 0-S41.6 + 1 * **
I I
- I I g I I * ** * ** ** * ** *
+ I CDS39.0 c I+-------+--------+--------+--------+-------+------ +-- -- --+---------+
-200 -100 0 100 200
-150 -50 Time (sec) 50 ISO Il0RIZ
T0406A S40.0 + I FIGURE 5 I I I I 11 RC Loop Cold Leg Temperature I I S38.5 + I i I I I *
- I I * * * * * **
S37.0 + I- **
- I I * *
- I I **
I I S35.5 + I I I ** P I I I I
- S34.0 + 1
- I I O I I *
' I
- 12 532.5 + I I
- I
- I * *
- I I *
- I S31.0 + *
- I I
- I I
- I I I S29.S + * **
- I I * * ** I I
- I I I
& S28.0 + I I I e I I N) I I CD S26.S + 1
- I I I I I I S2S.O + I
[+_______+_ _______e_________+_ _______+_________+_________+_________+_________+
-200 -100 0 100 200
-IS0 -SO SO I50 110RIZ Time (sec)
T0403A 103 + 1 I I FIGURE 6 I * ** *
- I 11 RC Loop Delta T I
- I 93 +
- I I
- I I * * ** * * ** ** I I I 83 + I I I I
I I I I 73 + 1 I I I I I 12 63 + I I I
, I I w I I T S3 + I I I I I I I 43 + I I I I I I I 33 + I I I I I I I ~ 23 + I * & I I e ! I O I I 13 + I hg I
I I I I I * ** *** 3 + I ** * **
- I+--------+ ------+--------+--------+--------+---------+----- +---- --+
-200 -100 0 100 200
-150 -50 50 150 IIORI Z Time (sec)
PO401A FIGURE 7 940 + . I I I I 11 Steam Generator I I I Outlet Pressure 915 + I I I ** * ** I I * **
- I I ** **
890 + 1 * ** I I ** I I * ** I I2
- 865 +
I I I PSIG I I I I 840 + 1 I I I I I I 815 + I i I I
" I a I i I I 790 +
I I I I I I I 766 + 1 I I I
- I I * **
- i I
740 + * * * ** ** I I I I I 9
~ I
- I o 715 +
I I I N I * * ** I ca I **
- I v1 690 +
I I+____ ___+________+ _____+_______+_________+-____ ___+____ __+_ _ ___+
-200 -100 0 100 200
-150 -50 Time (sec) 50 150 !!ORIZ
5 E'E E R M MMnnGD
- \ _._ . : \. _=. . .,. ,. -. .. . ..\ _
5 ;._._. .
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E s t-\ c 3-. :- :\.90. ==. FIGURE 8 5- .:: .. - =: ..
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Pressurizer level
.:1 59
^- - -
- . = :._ _=s= h.. - ::- i - -
. - .::_-". . 70 & level setpoint
_. . _ ,} _ [ l.5 ff::. 7 - '5E i E? 5 $98_b- J: . ' ~ 'd. _)(' '
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~=..CC... _'i.: =._._._. -
. 3=
- u. . . _._ . _.
_. ?? _= . 6T k _ = ~ , 3. - .-- -- 1 T. , - 40 . ~ J. _. T, ._ #.' _- + J .--l .- -
- f y. .:-l--
.:. , .:57:
.f -. -.., - k. ._ :. ]1 .:.:',
. 7*
.. .] .. : . ; , . .._ I ,1 .3 0 ' _: :s-p..
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- v!9 ?N_- - - - .E --+
o
=9:- :
C te _=__ _= :_ [E.u - *_i ) c: l.:( -%. . ~~I2 =l = p _ p___ :: _q=5:y_ ;_ :;g7--_ - r==.or h=.E --
. o
' eg ' m i n m m a a m a r $, - r i
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\ - . 3 ---
+
- \_- - = .--m t. e_ - u u - . _ ..
. ___...._.=___
_.W --t > __- =. =: ==- _: =..-s_ 2400-. : ,._ \, __ _. \ _ __.. . \. t= =_L=.. FIGURE 9
=T-si-t2300 :- p t :-) t '-
.',_.}.______.__~~-.,. Pressurizer
_q 3-- -- .-_ d... . ..2_ , __ _ . j=. . .
- b. .
- P ess ue
___ r L _=.-l -u.
- - - - -2200.--
. t _. .
.- -- .-._*1_._.- .
_ _ _=
== _.
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= _ . . _.
2100 __r -- __ _ % .. _..-t _ _ . _ t s- _ _ H..
- = .=_.;. m _._ _
c= J=__g-
- .= i
. _. . =k = . ,__.fb. -.= c.::l==
- l. _:
=-, 2000 in ___ , __;. ..
c . . __. _ _._ f _ _ - l : . - , - - =1 . :_- =
-- I =---= ___ I =- .= --_
. __ _. t=-_.
190 0 - .._,=- - I, ,_=__ r __.,__...
= . ; _.__
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n
-1= : i- i=
- d _ . _).= -- -
,_j -- =,.., I == : f._ ,.
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1 =_._~_.~.1 - _=_t3 ;- . =. _. l .i_~_,C
- _.. ..m I_=. .. .
.-..w '
L _ _ && .__l'.-~. I_ L. r ., r ,.- - - - - - , ,. 1649 284
*. F, Fr .n n r p n n n n r:
g - _ ,_ _ 1_, __4 wu - ; 1 -- i
. _ . - . .. _\_. . . ~ .
\ _ _> y.
u.
._..t_ . _\
i.. .. ._.2e00._ _. _ i _. . FIGURE 10
?'~.L...t
~~ i
- iksF_' ___.6,__
i
.._ _. p _..z . . l =..
. n I, .._.
] ,
RCS Loop Pressure
., _ ._~,, L,ynnn.4 $ p 1.j.. ..
7__ _ . ._
.. -9 M. .
u %_".". " " . _ _ . _1 <
~ . .- __.
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. ..e- l- . _ -._ ~~Q , &~2 u ps.n
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.=.
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.$ _.#..* . 1_ ,png .<
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t- , , I
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- ! t * !-
I 1 I 1 4nn I V %9 i 1, 1 %' = te u 1 l J. c , l In- ~ w I ~ w _ 1 3 m_ I X"'1" 4 rI 5 1.f l I
-- , - ,F ,
V r k, . ... n *J. rt. ? u " a e <s . a m m n n,I
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, _g - .+ ..
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\ _-_-i. ,
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.. g a
i 1 ve. . . 4 . . .h,? }
.._.__.i . . . . . g. .
_ _. g . .. I
~ ~ . . C. - -'
I. IdY. E.7 k ..
- ,< ; k . ..
FIGURE 11
. .~ . _ . . . . .
' / . p. . ._ .
ig._ __ .__ \
._. ... .. . ;,,p
- :I- .1 l
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i l Temoerature - r- ._ . % . : A,,y F-- ---
. r. . . qc." 1. ..c - ; ~
11 & 12 Cold Legs u '-
-~ --- !, h.--_.s. SmOl
;; A n-
~~ ~
_~ .__
'd. i.Li5bsk 5..'tLt.165,.
et g. e- - - - . _. . f y., 'p y f n ,p ,). g,p_
-h G hla n, ; ever&p +
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1
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1649 2n-
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. -_.-_. ._ .-.s .
n . .-
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- 4~= i -
j...._.._. n__.>-- - FIGURE 12 C9- '
% -. 6 ' '4% -
7 :'v ..2., i gWs _W' _ r
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.-l Temperature -
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, _ - .. . l _,.
, m . .__
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=
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1649 286 .
I CUERME500~l
* ?Q .--- \: r cf" 7 :=- 100 v :- (-c;_=
.\ ~ '" =
- \ .. --- :i 90 ~ \7..
FIGURE 13 [. y \ _ . .\ : - = y
-L- ..s \ . 80 .- --.: -
' i-V Steam Generator
\_...
-70
- f.-
_: Wide Range Level - 11 & 12 S/G's
.i --
( __ [ 15.=- -- f . l y
,__ CIf_ WC .
.1
~
pt(0
. . - _ ._. ... j S/ . . . . . . . . -
-30 o
.l. /;I- ol :l
/~ o
= 20l- l -
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l- -'! 2. 2 /i=.&;_- -W
. ~= E==07
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.\.'*-R i=l\22:t 2 4 =-- t\=-T \ == .i\ .:.=tE=.\~--~
- i. ,!b\ik\T i ==BW=== \2.'. ~2
[ . _ FIGURE 14 E _t =BEEM- _= (i . 3 -:g=1=i:-3 === '__
-- =m=-F=LarEe
= -
t ~=" 7'= _ . =A:_
~ ---~~;- -
Steam Generator
- 7 0 '"1-- =_:52g= _=:+ = Z-=d- _
Narrow Range Level -
--~ - ~~
~_] ? -E m- - .
11 & 12 5/G's _ _-- =.- ---
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-- ~~~~'
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n . . . . .L.- _ _- j649 287 EnnnF FFnnnnnR i._ _ 4.5 .. ... .
\ . ._. . . .. _ ._ ~1
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_ k. } I I FIGURE 15
-<'- , + t\ _...d
_ ., ...._.\ g , w_._..w___
=_4 - - - - - - --
11 Steam Generator ~ _ b ' t:5 # Fat _3.0 Steam Flow &
-.. _- _ - ~ _ ~ __~ " _ . . .- Feedwater Flow
__ _.u. 2.5 2.0
.._ l ..t. . . a '
__'._l..-_ ( __ l.5 _ _. 4
. --- l 10 H
-4 i
ley
. . l. . __.;
es- - - - e1
- u. > o_ .
n .. .cs_ ~1' l
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f._ ._.] l o_l _. - . n.. __..j cs > e - m - - - ,. m -- - PInF F p l' P T'" I~~! g i _ w 4.5 . ss.or ___ .y _. _.-. . _._. \ 4.0 FIGURE 16
- .__ .h' _ _ . _ .
~~~ ~~
~
l . _ .
, e 1..
12 Steam Generator _._..{ ._t _ ._ 4
. e. '
1 Steam Flow & pyn_- _ \ _. f3 ,,. F
'eedwater Flow
_~ T' %v
- 1. .
.. .. ~ " . _.~ . . ' . ' .
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_ . . __. L; .. _. .. _ 4 .. _. ._. 4 . 20 .
-- l.5
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l __
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- - - - - -, r
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=
=
.=&
-- _=== :.=: ..
- =.--- = . . = FIGURE 17 r
J. _..._._..n.
.:. . :: .>- - ~ ~
Turbine Steam
- ._, ,.--- Header Pressure
-/' "~;__*,*
._ ._ i
- ;_ =~ g .
.I~
_.4_._.... p _ .~ _ =
, _It ,
- - ._ C .;; = 2.-.;-- .7 . . _ . l.
._ = :=- -= :.1
.., ._.,..,;_._.._...._.4._..
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. --- 4 p _. , _
g, g ._ .. . __ E- 2._ttlC - d O
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i, e v- l ..m .. e . e e r e . n .' >- 1649 289
* , e e g' m .a . ,, ., ,,..., , . - , . .... i,,, ,,,, . ... - . , . . .
FtGWts IB
,L
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I i i i afl l t ! "I OIl8 1 i t I $ i l l 8 1 l l } I 1 I$[Q y g (Q' .] i k h O han) t 3 .. . p *. .n y My j , {,_1, . . } j.g 4,1. .. .Lp _. { _ 4 . I !
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-ry:i==E ..;;;---- ;; Cgr .~ . i i M-ii'-Hii_ '-
~- Z pii 4211 .I ei r.;I Ef - = hii.'i=:i3.2fi.ui.}s - -j - .n i n_;= , _
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