ML19323F173

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Operating Guidelines for Once-Through Steam Generator Rupture. Steam Generator Overfill Guidelines & Assessment of Licensed Operator Errors Encl
ML19323F173
Person / Time
Site: Crystal River Duke Energy icon.png
Issue date: 05/06/1980
From: Home M, Walters J
BABCOCK & WILCOX CO.
To:
Shared Package
ML19323F164 List:
References
RTR-NUREG-0667, RTR-NUREG-667 64-1119280, 64-1119280-00, BWNP-20004(6-76, BWNP-2004, NUDOCS 8005280615
Download: ML19323F173 (50)
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{{#Wiki_filter:O t 9 ENCLOSURE A HPI USAGE GUIDELINE CHANGES 8 0052 80 (p lE

ENCLOSURE A HPI USAGE GUIDELINE CHANGES Item 9 of our May 2,1980, submittal requested: Review procedures covering when HPI flow can be cut back and secured during a small break or overcooling transient. Our response was: Modifications to the small break and non-LOCA overcooling transient procedures will be completed to only require 20*F subcooling. (A Tsat meter exists, with digital display for ease of verification.) The guidelines will be submitted to the NRC for approval prior to implementation. i The following HPI Usage Guidelines fulfill that commitment and are sub-initted for your review. l l L' .r ....,-,_.,-_.......,r..,,___ _..m..

~ HPI Usage Guideline Changes Florida Power Corporation requested that B&W make available to them, on an earlier basis than formally scheduled, certain information gained through the Abnormal Transient Operating Guidelines (ATOC) Frogram. Principally, this information ' pertains.co the Small Break O'perating Cuidelines. The following guidelines represent the essentials of what we expect to pro-vide'to Florida on HPI usage during smal breaks, when the ATOG guidelines are, issued. These guidelines provide for safe, conservative HPI usage, but give added flexibility for HPI throttling to lessen the possibility for RC system overfill. Although minor details may change as the ATOC procedure evolves, the concept listed below is not expected to change. B&W will further document these changes by revising FPC's Small Break Operat-ing Duidelines within about a month. I. HPI Operation Instructions A. If the RPI system has been manually or automatically initiated be-cause of a low reactor coolant system pressure condition, it must remain in full operation until one of the following criteria is satisfied: 1. The LPI system is in operation and flowing at a rate in excess of 1000 spa in each line and the situation has been stable for 20 minutes. O-2. Fluid in all hot and cold legs is adequately subcooled. Ade-quately subcooled is defined as at least 20*F above the low ECS pressure ESFAS actuation pressure and 50*F below this actuation pressure. The instrument which measures subcooling must meet the criteria in Appendix A of this instruction. B. When adequate subcooling exists, HPI flow may be throttled but full HPI must be resumed if adequate subcooling is lost. C. HPI may be stopped and normal makeup restored when the adequate subcooling margin exists and the pressurizer level is on scale on the instrumentation. D. If the reactor coolant pumps have been stopped due to a low pres-sure ESFAS actuation, they may be restarted when adequate subcool-ing margin is restored and feedwater is available to at least one steam generator. If the subcooling margin subsequently decreases to below adequate margins, the RC pumps must be tripped again. If inadequate core cooling conditions exist, operate the RC pumps

  • in accordance with the ICC guidelines.

Y RC purp restart criteria as defined in the Small Ercak Operating Guideltecs remain in effect, execpt that the criteria given in the nLeve r.tra raph replace the criteria for r0 starting RC pumps. hen 50*F subcoolint, ia attained. l 2 , -.,,,,,.. + v -e e-* '~w' ' ' ' ~ * '

i II. Bases for these Instructions 1. B&W has concluded that an actual subcoo11ag margin of 5'F is all that is required for handling RCS small break concerns. Accordingly, if the operator is directed to read a neter that has total string inaccuracies within those definc'd in Appendix A of this ins:truction, the RCS will be at least 5'T subcooled then he reads an adequate margin of subcooling. 2. A break point at the ESFAS setpoint was chosen to give the operator a single setpoint (20'F) above ESFAS and a single setpoint (50*F) below ESFAS. The actual setpoint is a continuously varing margin from saturation based on existing instrument error at a given set of RCS pressure and temperature conditions and reactor building Pressure and temperature conditions. The values given (e.g., 20*F and 50*F) cover the maximum error within the given bands. 3. The incentive for throttling HPI is to avoid unnecessary challenges to the PORV and primary code safety valves due to overfilling the RCS. 4. Stopping HPI and resuming normal makeup is allowed when the trans-ient is well under control. Therefore, subcooling margin and a pressuriter level on scale on the available instrumentation is required. 5. The allowable restart of the reactor coolant pumps on adequate subcooling margin is intended to provide for an earlier restart and thus easier overall transient management. If adequate subcooling margin cannot be maintained, the reactor ~ coolant pumps must again be tripped. e e l . 0 .,,.._,.,,,.+.~,.,+-,2* b

r. s Appendix A Instrument Channel / Saturation Meter Requirements to support this Site Instruc-tion are: A. Accuracy - Saturation Tsat Margin Error RC Pressure Margin (Tsat) indicator (over pressure range) Range equipment for Conditions given in B, C, D, and E 15F 1500-2500 psis below. 30F 500-1500 psig 45F 150-500 psig B. RanP,e of External Environment The range of transient and steady state conditions for the environ =ent during nomal, abnomal and accident conditions for the temperature instrument channel and the pressure instrument channel shall be: Sensors Normal Abnormal Accident Temperature 80-122F 60-140F 286F (max) Pressure .5-2.5 psig .5--60 psig .5-60 psig Humidity 20-90% RH 10-100% RH 10-100% RH Radiation None None 2 x 104 R Seismic Former Contract Requirements Power Supply Compatible with Existing Class IE Equipment Spray Per Former Contract Requirements C. Jensor Signal Processing Equipment Mounted in a alass IE Enclosure Ambient External Conditions Normal Abnormal Accident Temperature 65-85F 40-110F 40-110F Prassure Atmosphere Atmosphere Atmosphere Humidity 40-60% 10-80%*RH 10-80% RH*(l) Seismic Former Contract Requirements Radiation Negligible Power Supply Compatible with Existing Equipment

  • Non-Condensing (1)90% RH for 24 hours e

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~ s D, The minimum periods of operability for the temperature instrument channel and the pressure instrument channel during normal, abnormal, accident and i' SSE conditions shall be: CONDITION Normal / Abnormal Accident Before SSE After SSE 2 times requirement Error (system) See 4.8.3C See 4.8.3C See 4.8.3C of A above. Period of Operability Continuous 10 days Continuous Continuous E. Halfunction or accident for which provision must be incorporated. The temperature instrument channel and the pressure instrument channel shall be qualified and isolated from the saturation meter such that the satura-tion meter will receive the temperature instrument channel and the pressure instrument channel for the following conditions: LOCA HSLB MFWLB RCS LEAK e e .h ( /.- - - - &

    • n - - - - ~ - - - - - - - -

_ g Additional HPI Usage Guideline Changes ~ B&W's cu'rrent operating instructions specify that HPI cooling be initiated immediately and the PORV opened if all feedwater is lost. This instruction could possibly result in unnecessary primary coolant discharge to the reactor building when emergency feedwater initiation is delayed. B&W analyses shows that the core will remain covered if HPI initiation is delayed by as much as 20 minutes after a loss of'feedwater. Therefore, this instruc-tion provides another parameter to control HPI initiation which potentially avoids some premature HPI starts. B&W now recommends that HPI cooling be initiated and the PORV be manually locked open when the following two criteria are satisfied: a. Neither main feedwater nor emergency feedwater is available b. The PORV has opened automatically because of rise in system pressure or the system pressure has reached or exceeded the i point at which the PORV should automatically open. ~ The above criteria are in addition to the instruction to start EPI whenever the system is less than 20' subcooled above the HPI initiation pressure or 50* subcooled below the RPI initiation pressure. Analyses indicate that the subcooling margin can re-main above 20' for as long as 20 minutes during loss of feed-water. B&W feels it is prudent to start HPI cooling earlier than reaching 20* subcooling if no feedwater is available. The two criteria above will assure that HPI cooling is initiated in a timely manner. A strong basis for choosing to initiate HPI cooling during a loss of feedwater coincident with flow through the PORV is the alarm for flow through the PORV at Crystal River.. Loss of feedwater can be verified by rising RCS pressure and temperature above normal operating limits plus zero flow indications on both the main and emergency feedwater flow measurement indications. SG steam pressure will also decay with time following a loss of feedwater. The time between loss of feedwater and RCS pressure reaching the PORV actuation setpoint should be used to regain feedwater. If feedwater cannot be regained by the time the PORV actuation pressure is reached, HPI cooling should then be activated. Once feedwater is regained and the steam generators are removing heat from the RCS, the PORV should be closed and HPI throttled consistent with the subcooling margin requirements previously issued to Florida. If HPI cooling has continued for more than t l a few minutes, it is likely.that the hot water in the pressurizer has been discharged through the PORV and code safety valves. The i l -.__n..,.----

4 pressurizer will then be solid with water. In this mode, RCS pressure should be controlled by balancing makeup and letdown; RCS temperature is controlled by the steam gencrators. Maintain this mode until a steam bubble can be established in the pres-surizer via the pressurizer heaters. O e 4 e e 4 O O 9 e e D 9

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O 4 4 ENCLOSURE B OPERATING GUIDELINES FOR OTSG TUBE RUPTURE m..

ENCLOSURE B OPERATING GUIDELINES FOR OTSG TUBE RUPTURE Item 10 of our May 2,1980, submittal requested: Review procedures covering 0TSG tube rupture in accordance with revised B&W Tube Rupture Guidelines and Small Break Guidelines. Our response was: Interim draft guidance on handling a steam generator tube rup-ture was prepared anci provided to Crystal River. A key item in the recommendat. ion section is early recognition and identi-fication of a steam generator tube rupture incident. i The final guidelines on handling a steam generator tube rup-ture will be submitted to the NRC for approval prior to implementation. The following Operating Guidelines for OTSG Tube

Rupture, Crystal River III, fulfill that commitment and are submitted for your review.

Part I is the Operating Guidelines. Part II is the Design Bases and this report is in the final publication stage. = _,

BWNP-20004 (6-76) ,i r BABCOCK & WILCOX NUCLEAt POWER GENERATION DivislON I TECHNICAi. DDCUMENT 1 i J I PART I OPERATING GUIDELINES 64 - 1119280 - 00 Doc. ID - Serial No., Revision No. for i OTSG TUBE RUPRlRE CRYSTAL RIVER III i J 1 W + PAGE 1 m__ _ _ =... - - ...--~ _ v

~ BWNP-20005 (6-76) . 8ABCOCK & WILCOX NUCLEAR Powit CENf tAtlON Divi $lON NUMBER RECORD'0F REVISION 64-1119280-00 l REV. NO. CHANGE SECT / PARA. DESCRIPTICN/ CHANGE AUTHORIZATION 00 Original Issue - M. M. Horne P.P.S.S. Prepared by_ _ _ _h_d_ b_ _ h ____ _________DATE_((4[#A Reviewed by_ _.fl_O -._b. _ _ _h_E_ _/l TE _ _ _ _7[_[O )_] fO __DATE_- Reviewed by __ _ \\ . _ _ _.}/r/ \\ ./7th; Approved by_ ___ /_ _ f_ _ _u w DATE__{_/f fa 5 DATE: 5-6-80 PAGE 2

~ BWNP-20006 (6-76) BABCOCK & WILCOX wumsta wuctime rowe,e cawenares omsow TABLE OF CONTENTS / EFFECTIVE PAGE LIST 64-1119280-00 SECTION TITLE PAGE 000. NO. 1.0 SYMPTOMS AND INDICATIONS (I)NEDIATE INDICATIONS) 4 64-1119280-00 2.0 IMIEDIATE ACTIONS 4 64-1119280-00 3.0 FOLLOW UP ACTIONS 4 64-1119280-00 5 64-1119280-00 1.0 SYMITOMS AND INDICATIONS (IFBfEDIATE INDICATIONS) 6 64-1119280-00 2.0 IhMEDIATE ACTIONS 6 64-1119280-00 3.0 FOLLOWUP ACTIONS 6 64-1119280-00 7 64-1119280-00 8 64-1119280-00 FIGURE 1 SUBC00 LING MARGIN REQUIREMEhTS 9 64-1119280-00 DATE: 5-6-80 PAGE 3

BWNP-20007 (6-76) .B ABCOCK & WILCOX uuctran rowie onnesanos oms!ow sumsee TECHNICA1 DOCUMENT "- 1219 2 M-@ A. REACTOR TRIP HAS NOT OCCURRED 1.0 SYPPTOPS AND INDICATIONS (IMtEDIATE INDICATIONS) 1.1 Main steam line high radiation alarm. 1.2 Condenser high rad, alarm. 1.3 Hi makeup (MU) rate. 1.4 Decreasing reactor coolant system (RCS) pressure. 1.5 Decreasing pressurizer (PRZR) and NU tank levels. NOTE: Only Items 1 and 2 are principal indications of an once-through steam generator (OTSG) tube rupture. The remaining symptoms also apply to a loss-of-coolant accident (LOCA). 2.0 IWEDI ATE ACTIONS 2.1 If PRZR level is being maintained by the NU system, go to Step 2.2. If not, manually control high pressure injection (liPI) with suction to the borated water storage tank (BWST) as necessary to maintain PRZR level greater than 100". If PR2R level cannot be Traintained, trip the reactor and go to Section B (reactor trip has occurred). 2.2 Isolate letdown. 2.3 Immediately begin runback of reactor at greater than 5'f, per minute. NOTE: If HPI with suction to the BWST is being required to maintain . PR2R level, the reactor will be shutdown on boron. 2.4 If reactor trip occurs during runback, go to Section B (Reactor Trip has occurred). 3.0 FOLLOWUP ACTIONS 3.1 Nake local survey of main steam line to confirm high radiation alarms and to verify the affected OTSG. 3.2 At less than 12', reactor power. A. Manually decrease the generator load to about 50d'. B. After the TB valves have steam pressure control, trip turbine. C. Place TBVs in manual and trip reactor. DATE: 5-6-80 PAGE 4 ._.._u_...,_.-.

BWNP-20007 (6-76) 8ABCOCK & NVILCOX 'NUCttat Powls GENteATION DIYl$ TON TECHNICAL DOCUMENT 64-1119280-00 3.3 Start PR2R spray and turn off all PRZR. heaters to depressurize the RCS. 3.4 As quickly as possible, depressurize and cooldown die RCS to less than 1000 psig and 500 F, initially using both steam generators (SGs). CALTION: Maintain a 20F subcooling margin above the ESAS low pres-sure ssetpoint, and 50F subcooling margin below the low pressure ESAS setpoint..See attached Figure 1. NOTE: If ranua11y controlling the depressurization and cooldown of the RCS and 50F subcooling is being maintained, bypass ESAS and do not trip RC pumps (RCPs) upon reaching the low pressure ESAS setpoint. NOTE: Go to one RCP in each loop before reaching 500F. CALTION: Ensure the TBVs are controlled as necessary to prevent the FSSVs from opening. NOTE: Block steam rupture matrix at SG pressure greater than 600 psig. Do not allow JSIVs to close before RCS is on decay heat removal (DHR) system. 3.5 When the leaking OTSG is identified and die RCS is below 540F, close the main and EFW supply and TB valves on the leaking OTSG and continue the cooldown at the maximum rate on one OTSG. NOTE: If steam driven FW pump is being used, switd1 supply steam to the unaffected OTSG to assure steam supply. 3.6 , Periodically monitor the affected OTSGs ' pressure and level. Initiate steaming to the condenser as necessary to maintain the OTSG pressure below 1000 psig and OTSG Ievel below 95% on the operate range. 3.7 Continue depressurization and cooldown below 500F at maximum allow-able cooldown rate (100F/IIR) per normal cooldown procedure until Dit system is removing heat while maintaining 50F subcooling. 3.8 As RCS pressure and leak rate decreases and RCS inventory and sub-cooling can be maintained by the 10 system dien secure llPI system and establish nonnal 12 control. 3.9 As cooldown proceeds, sample RCS for boron concentration. Borate as necessary to maintain required shutdown margin. DATE: j 5-6-80 PAGE 5

BWNP-20007 (6-76) SABC' CK G WILCOX O Numsta NVCLEAR Powie otNteAfloN Division TECHNICAL DOCUMENT 64-1i19280-00 B. REACTOR TRIP ltAS OCCURRED 1.0 SYMPTOMS AND INDICATIONS (D! MEDIATE INDICATIONS) 1.1 Main steam line high radiation alarm. 1.2 Condenser high rad, alarm. 1.3 Hi makeup (MU) rate. 1.4 Decreasing reactor coolant system (RCS) pressure. 1.5 Decreasing pressurizer (PRZR) and MU tank levels. 1.6 Reactor trip. 1.7 Low reactor coolant (RC) pressure engineered safety features actuation system (ESFAS) actuation (manual actuation of HPI if necessary for inventory control). NOTE: Only Items 1 and 2 are' principal indications of an once-through steam generator (OTSG) tube rupture. The remaining symptoms steam generator (OTSG) tube rupture. The remaining symptoms also apply to a loss-of-coolant accident (LOCA). 2.0 IMMEDIATE ACTIONS 2.1 If PRZR level is being maintained by the MU system, go to Step 2.2. If not, manually control llPI as necessary to maintain level between 50" and 100". Go to Step 2.2. 2.2 Isolate letdown. 2.3 'If ESAS is automatically initiated due to low RCS pressure, trip all RC pumps. NOTE: If manually controlling the depressurization and cooldown of the RCS and 50F subcooling margin is being maintained, bypass ESAS and do not trip RCPs upon reaching the low pressure ESAS setpoint. CAUTION: Ensure intermediate cooling water (ICW) and seal injection flow is maintained to RCP,,s and motors. 3.0 FOLLONUP ACTIONS 3.1 Make local survey of main steam line to confirm high radiation alarms and verify the affected OTSG. 3.2 If the RCPs are running, go to Step 3.3. l If the RCPs are not running, go to Step 3.4. DATE: A 6 5-6-80 ,_s.~.. J. --,-~ -, +

BWNP-20007 (6-76) BABCOCK 8 WILCOX uumsen

  • NUCtt At PoWit o(NEGAUoN olvilloN 64-i19280-00 TECHNICAL DOCUMENT 3.3 Reactor Coolant Pumps Running 3.3.1 Start PRZR spr'ay and turn off all PRZR heaters to depressurize '

the RCS. 3.3.2 As quickly as possible, depressurize and cooldown the RCS to less than 1000 psig and 500F using both SGs. CAUTION: Maintain a 20F subcooling margin above the low pressure ESAS setpoint, and 50F subcooling margin below the low pressure ESAS setpoint. 'See attached Figure 1. CAUTION: Ensure the TBVs are controlled as necessary to prevent the MSSVs from opening. NOTE: Block steam rupture matrix at SG pressure greater than 600 psig. Do not allow FEIV's to close before RCS is in DilR system. 3.3.3 Go to Step 3.5. 3.4 Reactor Coolant Pumps Not Running 3.4.1 Verify that OTSG IcVels are increasing to approximately 50'6 on the operate range. CAUTION: As soon as the affected OTSG is identified, do not feed the affected OTSG unless needed to maintain the low level . limit, verify natural circulation, or to maintain sub-cooling greater than 50F. 3.4.2 Restart 1 RCP in each loop as soon as appropriate subcooling margin is obtaining (See Figure 1). NOTE: Start RCP in loop with PRZR spray and ensure appropriate SG 1evel is obtained after restarting RCPs. Then depressurize to less than 1000 psig with PRZR spray. 3.4.3 Depressurize by opening the PORV if RCPs cannot be restarted. CAUTION: Do not reduce subcooling margin below appropriate limit. See Figure 1. 3.4.4 Cooldown RCS to less than 500F with the TB valves on both SGs. NOTE: Block steam rupture matrix at SG pressure greater than 600 psig. Do not allow >$1Vs to close before RCS is in DilR system. NOTE: Go to one RCP in each loop before reaching 500F. 3.5 When the Icaking OTSG is identified and the RCS is below 540F, close the main and EFW supply and TB valves on the Icaking OTSG and continue the cooldown at the maximum rate on one OTSG. 1 DATE: 5-6-80 PAGE 7

BWNP-20007 (6-76) BABCOCK & WILCOX Numsta NUtttAt POWER GENIGATION DIVISION TECHNICAL DOCUMENT 64-1119280-00 NOTE: If steam driven FW pump is being used, switch supply steam to unaf fected OTSG to assure steam supply. 3.6 Periodically monitor the affected OTSGs' pressure and level. Initiate steaming to the condenser as necessary to maintain the OTSG pressure below 1000 psig and OTSG 1evel below 95% on the operate range. 3.7 Continue depressurization and cooldown below 500F at maximum allowable cooldown rate (100F/flR) per normal cooldown procedure until Lil system is removing heat while maintaining 50F subcooling. 3.8 As RCS pressure and leak rate decreases and RCS inventory and subcocling can be maintained by the MU system then secure llPI system and establish tiormal MU control. 3.9 As cooldown proceeds, sample RCS for boron concentration. Borate as necessary to maintain required shutdown ma~rgin. DATE: 5-6-80 PAGE 8 l c_._..______,--._.-...__.,2..--_..._._..,.... m. .-.e

'e s. to Figure 1: Subcooling Margin Requirements l u, putuuuuuuuuuuuuuniuuinuuntuuutuuiniuniunininuinuutunuiony l l l i ,i i i II' ' (,, t i 5. 2400 i-NOTE: Adjustments for possible instrumenta-l .o j tion error and elevation pressure J. l .q.. [ / d-h [ 2200 P" differentials have been incorporated I / l il into this P-T Limit Curve Subcooling 20*F d^ 7 ~" i Margin Curve { j' l [ / l 2000 ' i' ~ I ,I I / b 1800 - -l,/ l~ { {.. i / p /l y

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4 0 4 9 ENCLOSURE C STEAM GENERATOR OVERFILL w- ~g-- + a ws.e mg_ e,* c ..nu,, n-

ENCLOSURE C STEAM GENERATOR OVERFILL Item 13 of our May 2,1980, submittal requested: Provide procedures and training for recovery from EFW actua-tion to avoid 0TSG overfill. Our response was: A section entitled " Recovery from Emergency Feedwater Actua-tion" is being incorporated into EP-108, " Loss of Steam Gener-ator Feed", and will be completed before startup. Emergency Procedure EP-113, " Plant Shutdown from Outside Con-trol Rcom", will be revised to include adequate operator veri-fication of proper feedwater water system status prior to leaving the Control Roem. Emergency Procedure EP-105, " Steam Supply Rupture", will be revised to state that Main Steam Isolation Valves will not automatically open. Also, new valve closing instructions will be developed for the operator. Emergency Procedure EP-101, " Unit Blackout", required changes are covered in Item 30. Abnormal Procedure AP-112, " Loss of Electrical Supplies", will be revised to recognize loss of the startup transformers as unit blackout. Emergency Procedure EP-108, " Loss of Steam Generator Feed", will be revised to verify feedwater valve status earlier in the response. The following changes to Operating Procedures and Emergency Procedures were suggested by Babcock & Wilcox. These changes address the steam generator overfill concern. L L l I

\\ j STEAM GENERATOR OVERFILL 1. All operators now receive training on steam generator overfill events, at the B&W Simulator, during Operator Training and Requalification. This training includes, but is not limited to, recognition of overfill and on understanding its consequences and concerns. You should reinforce this training in ycur own training programs. 2. Although B&W presently sees no need for the issuance of a separate guideline for this problem, changes that address steam generator overfill are needed to the Plant Operating and Emergency Procedures dealing with the following (if not already in existence in current revisions): Plant Startup/Heatup Plant Shutdown /Cooldown Reactor / Turbine Trip ICS Manual Operation Loss of Reactor Coolant / Reactor Coolant Pressure Steam System Rupture 3. When the reactor coolant system is below 305*F, steam generator overfill is not a safety problem. However, it could be an availability problem. 4. The general guidelines to be followed are: a. With the reactor coolant temperature above 305*F: I. If as the result of an unplanned event the OTSG water level reaches 82.5% on the operating range level indication (operator is alerted by steam generator high level alarm), close the main feedwater block valve and the startup and low load control valves to the affected OTSG. It is recommended an operator be assigned exclusively to control OTSG levels. If feedwater flow does not show an obvious decreasing trend within 20 seconds, immediately close and/or prevent the reopening of FWV-28, close the low load and startup feedwater block valves, and trip the main feedwater pump to the affected 0TSG. II. If the above actions do not terminate OTSG fill, the problem is in the emergency feedwater system. Attempt to gain control of the emergency feedwater system. If unsuccessful and the OTSG level reaches 360 inches (88% on the operating range level), trip the emergency / auxiliary feedwater pumps. ~="e r<===*e re? w%- + m ge v mes--wa mseeny m. a ww e re asar em f

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O O e b. During power operation, the ICS should be maintained in automatic. This will provide design equipment protection against overfill. However, if equipment or instrumentation failure causes an overfill event, the operator must carry out the guidelines of (a) above. When any portion of the ICS is placed in the manual mode during power operation, it is recommended an operator be assigned exclusively to the control of feedwater flow and 0TSG levels. His primary function is to anticipate and mitigate overfill problems prior to the 82.5% high level. However, if unsuccessful, the operator should carry out the guidelines of (a) above. These guidelines provide the operator action necessary to prevent a steam generator overfill event. Sections (a and b) apply during all operations, and Section (c) applies during reactor trip condition, except as noted below. Actions listed in (a.I and a.II), which specify steps to terminate OTSG level increase at 82.5% or 88%, do not apply when emergency procedures specify raising the water level above these levels. Specifically, these actions are not required where the Small Break Operating Guidelines specify raising 0TSG levels to 95% during some small break situations. D

~ ENCLOSURE D ASSESSMENT OF LICENSED OPERATOR ERRORS L__

ENCLOSURE D i ASSESSMENT OF LICENSED OPERATOR ERRORS Reconnendation 22 of the Advanced Copy of NUREG-0667, May 2,

1980,

" Transient Response of Babcock & Wilcox-Designed Reactors", urged the performance of an analysis of personnel-related LERs. An INP0 report was written for DRAFT NUREG-0667, April 2,1980, that addresses this subject. Therefore, we are submitting the INPO report for your review. i

CA-80-18 1NSTITUTE OF NUCLEAR POWER OPERATIONS ~ memoranc um INPO May 1, 1980 TO: P. Y. BAYNARD FROM: P. E. DIETZ

SUBJECT:

ASSESSMENT OF LICENSED OPERATOR ERRORS The following assessment of licensed operator errors was completed in support of the Crystal River Three Nuclear Safety Task Force. Recommendation 22 of the DRAFT NUREG-0667, April 2,

1980, transient response of Babcock and Wilcox - designed reactors urges the performance of an analysis of the number of licensee event reports attributed to licensed personnel error to determine the significance and cause of the higher number associated with the operation of B & F facilities.

As noted in the report, LERs have only been categorized by licensed personnel error since January 1978. The following table Js from the NRC report and covers LERs between January 1978 and January 1980. TABLE 1 LER OUTPUT ON LICENSED OPERATOR EVENTS FOR 1978 and 1979 YENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 58 6.44 CE 8 45 5.63 GE 25 142 5.68 W 25 131 5.24 m,-. ^-

J MEMO TO P. Y. BAYNARD PAGE TWO HAY 1, 1980 To address the expressed concern, I performed an independent analysis of the LER data. A search of the LER Data Base provided by NRC yielded the following information on licensed operator errors between January 1978 and March 1980. TABLE 2 LFR OUTPUT ON LICENSED OPERATOR EVENTS BETWEEN JANUARY 1978 AND MARCH 1980 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 CE 25 151 6.0 W 25 146 5.8 A cursory review of the data might indicate that licensed operators generate more LERs at B & W plants than at the other vendor-designed facilities. As noted in NUREG-0667, the reported LERs decreased significantly with age of the plant, those having already undergone the first several years break-in period generally submitting the fewest LERs. Accordingly, I attempted to analyze the data in such a way as to remove the bias caused by plant maturity. One simple approach was to eliminate from consideration plants more mature than any B & W plant. The starting date for each vendor's first plant is shown in table 3. TABLE 3 YEAR FIRST PLANT TAKEN CRITICAL VENDOR YEAR B&W 1973 CE 1971 GE 1959 W 1960 I a

MEMO TO P. Y. BAYNARD ~ PAGE THREE MAY 1, 1980 If only the plants that have been taken critical for the first time since 1973 are considered the B & W plants no longer generate the most licensed operator errors. TABLE 4 LICENSED OPERATOR ERRORS AT PLANTS CRITICAL FOR THE FIRST TIME SINCE JANUARY 1973 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 6 30 5.0 GE 12 100 8.3 W 16 119 7.4 The appendix looks at the accumulated experience for other starting years than 1973. It shows the effect on the data base of the older plants which are operating smoothly. Analyzing only LERs since 1978, is like taking a time exposure picture of operating history. By looking at a single time period, one can see all plant data affected by the same industry wide influences such as the THI-2 accident. Figures 1 through 8 show how the number of LERs varies with plant age. It can be seen that no one vendor-designed plant has a tendency to generate more licensed operator errors (LERs) than the others. In fact the data fluctuations for both GE and Westinghouse plants are larger than for B & W plants, and each bounds the B & W fluctuation. I conclude that the LER data does not support a concern that the error rate for licensed operators at B & W plants is greater than for other nuclear plants, once the bias due to plant maturity has been removed. PD/sd Attachments

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ATTACH 1!ENT APPENDIX LER OUTPUT ON LICENSED OPERATOR EVENTS FROM JANUARY 1978 TO MARCH 1980 O. PLANTS FIRST CRITICAL AFTER JANUARY 1978 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 1 10 10.0 CE 1 2 2.0 GE 1 22 22.0 W 2 45 22.5 1. FIRST CRITICAL AFTER JANUARY 1977 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 3 44 14.7 CE 1 2 2.0 GE 1 22 22.0 I. W 3 62 20.7 l i _1_

2. FIRST CRITICAL AFTER JANUARV 1976 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 3 44 14.7 CE 3 15 5.0 GE 3 31 10.3 W 6 73 12.2 3. FIRST CRITICAL AFTER JANUARY 1975 VENDOR TOTAL PLAN'IS LERs AVERAGE / PLANT B&W 3 44 14.7 CE 4 17 4.2 GE 4 44 11.0 W 8 93 11.6 9,

4. FIRST CRITICAL AFTER JANUARY 1974 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 7 62 8.9 CE 5 26 5.2 GE 10 94 9.4 W 10 98 9.8 5. FIRST CRITICAL AFTER JANUARY 1973 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 6 30 5.0 GE 12 100 8.3 W 16 119 7,4 . l i f ~

6. FIRST CRITICAL AFTER JANUARY 1972 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 7 41 5.9 GE 15 116 7.7 W 19 134 7.0 7. FIRST CRITICAL AFTER JANUARY 1971 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 17 121 7.1 W 19 134 7.0

8. FIRST CRITICAL AFTER JANUARY 1970 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT l B&W 9 70 7.8 CE 8 53 6.6 GE 20 135 6.7 W 21 139 6.6 i i i 9. FIRST CRITICAL AFTER JANUARY 1969 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 22 139 6.3 l 4 , L

+ ~ 10. FIRST CRITICAL AFTER JANUARY 1968 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 22 139 6.3 i 11. FIRST CRITICAL AFTER JANUARY 1967 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 24 144 6.0 J 4 p t l

12. FIRST CRITICAL AFTER JANUARY 1966 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 24 144 6.0 13. FIRST CRITICAL AFTER JANUARY 1965 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 24 144 6.0 4 - l t-

1: 4 14. FIRST CRITICAL AFTER JANUARY 1964 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT l B&W 9 70 7.8 CE 8 53 6.6 GE 22 144 6.5 W 24 144 6.0 l { 15. FIRST CRITICAL AFTER JANUARY 1963 ] VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 23 147 6.4 W 24 144 6.0 i e -, -., ~.,

16. FIRST CRITICAL AFTER JANUARY 1962 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 24 150 6.2 W 24 144 6.0 17. FIRST CRITICAL AFTER JANUARY 1961 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT j B&W 9 70 7.8 CE 8 53 6.6 GE 24 150 6.2 W 24 144 6.0 1 -g-t

18. FIRST CRITICAL AFTER JANUARY 1960 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 24 150 6.2 W 25 146 5.8 19. FIRST CRITICAL AFTER JANUARY 1959 VENDOR TOTAL PLANTS LERs AVERAGE / PLANT B&W 9 70 7.8 CE 8 53 6.6 GE 25 151 6.0 W 25 146 5.8

CA-80-27 INSTITUTE OF NUCLEAR POWER O P E R ATIO N S e memorandum INPO May 9, 1980 TO: P. E. Dietz FROM: W. C. Evans LICENSED-OPERATOR-ERROR DATA ANALYSIS I. DATA: BW 7, 1, 4, 3, 2, 9, 10, 24 CE 12, 11, 4, 9, 2, 4, 9, 2 GE 1, 3, 3, 5,4,7,5, 2, 4, 1, 3, 1, 12, 4, 2, 3, 5, 7, 3, 13, 19, 13, 0, 9, 22 W 2, 1, 4, 0, 1, 4, 3, 10, 2, 5, 0, 0, 12, 2, 2, 4, 1, 14, 6, 0, 5, 6, 17, 21, 24 II. MEANS, SUMS OF SQUARES: BW y= 7.50 Ey= 60 2 c= 7.43 Ey = 836 op = 2.63 N= 8 CE 9= 6.63 Iyg=52 c= 4.07 Ey 467 op 1.44 N= 8 GE 9= 6.04 Eyg=151 o= 5.68 Ey 1685 op= 1.13 N= 25 W 9= 5.84 Ey= 146 2 a= 6.74 Ey,3g44 op= 1.35 N= 25 OVERALL: y= 6.21 E=2=10 4 c= 8.01 Ey 4932 op= 0.99 N= 66 t

M:mo to P. E. Diotz Page Two

  1. May 9, 1980 III.

ANALYSIS OF VARIANCE: Assume a one-way ANOVA (ignore age effects in vendor data-variation in LER's is just a random sampling of error rate) to test for a difference in LER incidence between vendors. EFFECT SS DF MS F Vendors 18.84 3 6.28 .16 Error 2366.19 62 38.16 Total 2385.03 65 Since F3,62,0.95 = 3.1, we accept the hypothesis of no difference between vendors. Of course, there is an age effect in this data, so that the total variation is due to both that effect and any vendor differences. The additional variability introduced into the dath by this age effect tends to reduce our ability to find vendor differences (which, if they exist at all, are likely to be small). It was not practical to attempt more sophisticated analyses to account for the age effect, such as analysis of covariance or multifactor ANOVA. IV. CONFIDENCE INTERVALS ON MEANS:

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CA-80-27 INSTITUTE OF NUCLEAR POWER O P E R ATIO N S ..v memoranc um INPO May 9, 19 7 TO: P. E. Dietz FROM: W. C. Evans LICENSED-OPERATOR-ERROR DATA ANALYSIS I. DATA: BW 7, 1, 4, 3, 2, 9, 10, 24 CE 12, 11, 4, 9, 2, 4, 9, 2 GE 1, 3, 3, 5, 4, 7, 5, 2, 4, 1, 3, 1, 12, 4, 2, 3, 5, 7, 3, 13, 19, 13, 0, 9, 22 W 2, 1, 4, 0, 1, 4, 3, 10, 2, 5, 0, 0, 12, 2, 2, 4, 1, 14, 6. O, 5, 6, 17, 21, 24 II. MEANS, SUMS OF SQUARES: BW F= 7.50 Ey= 60 2 o= 7.43 Ey = 836 op = 2.63 N= 8 CE i= 6.63 Eyg=52 o= 4.07 Ey 467 op 1.44 N= 8 GE 9= 6.04 Ey= 151 2 o= 5.68 Ey = 1685 op= 1.13 N= 25 W y= 5.84 Eyg 146 o= 6.74 Ey = 1944 op= 1.35 N= 25 OVERALL: P= 6.21 E=2=10 4 o= 8.01 Ey 4932 op= 0.99 N= 66 [

b Memo to P. E. Diotz Page Two May 9, 1980 e III. ANALYSIS OF VARIANCE: Assume a one-way ANOVA (ignore age effects in vendor data-variation in LER's is just a random sampling of error rate) to test for a difference in LER incidence between vendors. EFFECT SS DF MS F Vendors 18.84 3 6.28 .16 Error 2366.19 62 38.16 Total 2385.03 65 Since F3,62,0.95 = 3.1, we accept the hypothesis of no difference between vendors. Of course, there is an age effect in this data, so tha-the total variation is due to both that effect and any vendor differences. The additional variability introduced into the data by this age effect tends to reduce our ability to find vendor differences (which, if they exist at all, are likely to be small). It was not prac;1,al to attempt mc e sophisticated analyses to account for ;' < age effect, such as analysis of covariance or multifac' ANOVA. IV. CONFIDENCE INTERVALS ON MEANS: Vendor { a-t62,.975 95% Interval L BW 7.50 2.63 2.00 (11.87, 3.13) CE 6.63 1.44 2.00 (11.0, 2.26) GE 6.04 1.13 2.00 (8.51, 3.57) W 5.84 1.35 2.00 (8.31, 3.37) Figure 1 is a sketch of these intervals, and shows that the vendor means and their 95% confidence intervals overlap - the data does not support the hypothesis of a difference in LER incidence across vendors. WCE/sd Attachment

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