NRC-87-0229, Suppl 6 to Fermi 2 Nuclear Power Plant Interim Startup Test Rept
| ML20237F125 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 12/07/1987 |
| From: | Orser W DETROIT EDISON CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| CON-NRC-87-0229, CON-NRC-87-229 NUDOCS 8712290377 | |
| Download: ML20237F125 (157) | |
Text
{{#Wiki_filter:-- -- - - - - - - - - , - - - - - - - - - , - - - - - - ----- 4 THE DETROIT EDISON COMPANY FERMI 2 NUCLEAR POWER PLANT INTERIM STARTUP TEST REPORT SUPPLDENT NO. 6 December 7, 1987 8712290377 871207 31E DR ADOCK O 5616 41,
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.l INTERIN STARTUP TEST REPORT I Supplement #6 Dated'12/7/87 i
Revision summary Forward Page General Update Page 1-3 Reference Addition Pages 2-2, 2-3 status Update Pages 3 1-1, 3 1-2, 3 1-3, Editorial and General 3 1-4, 3 1-5, 3 1-7 status Update j 1 Page 3 8-2 status Update i Pages 3 13-1, 3 13-2, 3 13-3 Major Update i 3 13-5, 3 13 6, 3 13-7 .l Page 3 30-3 status Update i I Page 3 34-2 status Update j
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Supp102:nt 6 i FOREWARD l This Supplementary Startup Test Report includes the testing performed . since the previous interim summary report dated September 10, 1987. { This report was transmitted to the NRC via NRC-87-0155 dated September 19, 1987 Since that report was issued, Fermi 2 has completed the Test Condition Three HPCI test sequence. Plant operation continued to be restricted to 50% power throughout aost of the three month report period. As of the writing of this report, operation of the plant to 75% power has been authorized and the balance of Test Condition Three testing will be performed as higher power levels are achieved. 3 I In this supplement we are transmitting an updated copy of the entire test report. Revision bars have been added to show where changes have been made, except for changes which are only cosmetic in nature or which only involve renumbering sections or pages. l The results sections of this report will be filled in as the tests are completed in the future. l l 1 __ - _ _- _J
N i-Supplearnt'6 FERMI 2 NUCLEAR PONER PLANT IN17.RIN STARTUP TEST REPORT INDEI 1.0 Introduction 4 1.1 Purpose 1.2 Test Report Format- $ i
'V 13 Plant Description ( \, 4} y 1.4 Startup Test Program Description ,,
1.5 References i\ 2.0 General Test Program Information -* 2.1 Chronology of Major Events Matrix of Test Completion Dates 2.2 t 30 Test Results Summary 4 31 Chemical and Radiochemical i , 32 Radiation Measurements l 33 Fuel Loading l 34 Full Core Shutdown Margin 35 Control Rod Drive System 3.6 SRM Performance and Control Rod Sequence 37 water Level Measurements 3.8 IRM Performarne
- 39 LPRM Calibration l 3 10 APRM Calibration 3 11 Process Computer l
3 12 RCIC 3 13 HPCI p 3 14 Selected Process Tr.r;peratures 4 m y 3 15 System Expansion 3 16 (Deleted) 3 17 Core Performance , i 3 18 (Deleted) 4 24 ~ 3 19 (Deleted) i 3 20 Pressere Regulator ' 3 21 Feedwater System 3 22 Turbine valve Surveillance 3 23 MsIV 3 24 Relief. Valves j 3 25 Turbine Stop valve and j Control Valve Fast Closure
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. FERMI-2 NUCLEAR POWER PLANT
?, 4 INTERIM STARYUP TEST REPORT 1.0 Introduction l
l 1.1 Purpc/4 i The pucpese of this Interim Startu;p Test Report and its j associate:1 supplements is to provide a summary of the test results obtained. in startup testing; completed from initial fuel load to the present. This report of. plant startup and. ,: t power ase.ension testing is submitted as required per Technicd ' Specification 6.9.1.1. This interim report plus-its supplereents cover all testing a;:plicable to the test conditions coupleted as described in UFSAR Subsection l 14.1.4.6. Supplements will.be issued as the remaining , testing is cospleted, at the intervals specified per Technicn!! Spedff cation G.9.1 3 Tncluded in this report are descriptions of the measured valutz of the operating conditions and characteristics obtained during the test program and any corrective actions tt.at are regtf. red to obtain satisfactory coeration. , 1.2 Test Report Forvet ! l l Sections 1.0 and 2.0 of this report provice Asneral information about the Fermi 2 plant and the testing program. Section 3 0 providu a basic description of the testing we have performed along with a summary of the results and analy. sis obtained fros' each test. Each test summary is di7ioW into three subsections covering the purpose, teJt er.teria, and results of each test. 13 Plant Description l l The Fermi 2 Nuclear Power Plant is located in Frenchtown Township, Monroe County, Michigan; The Nuclear Steam Supply
. System consists 'of a Genwal Electric BWR I! nuclear reactor rated at 3292 MWt, coupled to an English Electric Turbine / Generator rated at 1100 MWe, const.ructed in a Mark I containment.with a toroidal suppression pool.
l This plant is cwnM aM operatrid by the Detroit Ldison l Company and the inharine Power Cooperative, Incorporated. i l i l
" i
Supplin;nt 6 Peg 2 1-2 1.4 Startup Test Program Description The Startup Test Phase began with preparation for fuel loading and will extend to the completion.of the warranty demonstration. This phase is subdivided into four parts:
- 1. Fuel Loading and Open Vessel Tests
- 2. Initial heatup 3 Power tests
- 4. Warranty demonstration The Startup Test Phase and all associated testing activities adhere closely to NRC. Regulatory Guide 1.68, "Preoperational and Initial Startup Test Programs for Water-Cooled Power Reactors."
The overall objectives of the Startup Test Phase are as follows:
- 1. To achieve an orderly and safe intial core loading
- 2. To perform all testing and measurements necessary to determine that the approach to initial criticality and the subsequent power ascension are accomplished safely and orderly 3 To conduct low-power physics tests sufficient to ensure that physics design parameters have been met
- 4. To conduct initial heatup and hot functional testing so that hot integrated operation of specified systems are 1 shown to meet design specifications 5 To conduct an orderly and safe Power Ascension Program, I with requisite physics and system testing, to ensure that when operating at power, the plant meets design q intent
- 6. To conduct a successful warranty demonstration program .
1 Tests conducted during the Startup Test' Phase consist of Major Plant Transients and Stability Tests. The remainder ! of tests are directed toward demonstrating correct' ! performance of the nuclear boiler and numerous auxiliary j plant systems while at power. Certain tests may be j identified with more than one part of the Startup Test Phase. Figure 1-1 shows a general view of the Startup Test Phase Program and should be considered in conjunction with- . 1 1 1 i i w h_________._. _
Supplem:nt'6. ! Page 1 ! Figure 1-2 which shows, graphically, the various test areas as a function of core thermal power and flow. Note that-Figure 1-1 has been modified to reflect certain tests which we presently intend to delete.from the Startup Test Program, as discussed further in Reference 1.5 3 For a more comprehensive description of the testing program refer to Reference 1.5.2.- 1.5 References The following is a list of documents that provide supplementary information of the Fermi 2 Startup Test Phase-Program:
- 1. Fermi 2 Technical Specifications, Section 6.
l-
- 2. Updated Final Safety Analysis Report, Fermi.2 Nuclear.
Power Plant, Section 14. 3 Memorandum VP-86-0141, "Startup Test Program Changes", dated October 17, 1986, from Frank E. Agosti to James G. Keppler.
- 4. Memorandum NRC-87-0179, " Initial Test Program Changes" dated September 30, 1987, from B. R. Sylvia to U.:S.
Nuclear Regulatory Commission, Washington, D.C. W
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l Supplc22nt 6 ! Pzga 1-5 ! l FIGURE 1-2 I APPROIINATE POWER FLOW MAP SHOWING STARTUP TEST CONDITIONS 1 i I ' ' ' I I ' ' '- ) 110 - - 3 A. Netwrol circuleton O gg, _ S. Wanimum tweirewleton pump speed . C. Anolytieel tener limit of morter power view eenvoi NTC6 D. Ane#ytieel vocer timet of mester power i g,, flow sentrol g
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l 4 6 6 e i i 6 6 g g 0 10 20 30 40 50 60 70 00' 90 100 110 Percentage of Core Flow 3 Notes: l
- 1. See Figure 1-1 for startup test titles.
- 2. Power in percentage or rated Thermal Power 3292 MWT.
3 core riow gn perceratage or rated core recirculation riow. 100.0 x 10 lb/hr.
- 4. TC = test condition.
Supplemtnt 6 Page 2-1 2.0 General Test Program Information 2.1 Chronology of Major Events Date Received (5%) Facility Operating 03/20/85 License No. NPF-33 Started Fuel Loading 03/20/85 Completed Fuel Loading 04/04/85 Completed Open Vessel Testing 06/01/85 Initial Criticality 06/21/85 Received (Full Power) Facility 07/15/85 Operating License NPF-43 ) Completed Initial Turbine Roll 09/26/85 Bypass Line Replacement / 10/10/85 Environmental Qualification Equipment Upgrade Outage Begins i Neutron Source Changeout Complete 05/12/86 Outage Ends 07/24/86 Reactor Restarted 08/04/86 Completed Test Condition Heatup 09/03/86 Entered Test Condition One 09/16/86 . Initial Synchronization to Grid 09/21/86 i Condenser Repair Outage Begins 11/08/86 Reactor Restarted 12/18/86 Completed Test Condition One 01/07/87 Main Steam Line Instrument Tap 01/09/87 Repair Outage Begins Reactor Restarted 01/24/87 Entered Test Condition Two 02/24/87 Completed Test Condition Two 03/16/87 with Loss of Offsite Power Test ,
Supp15; nt 6 P;gs 2-2 Chronology of Major Events (Continued) Date MSR Refit Outage Begins 03/16/87 Reactor Restarted 04/03/87 Main Steam Line Tap Repair 04/12/87 Outage Begins.
. Reactor Resta'ted r 05/10/87 South RFPT Damaged 05/13/87 Reactor Restarted 05/14/87 Commenced Test Condition Three 06/10/87 Testing Completed Core Flow Calibration 06/14/87 at 50% Power Outage to Repair Reactor Recirc 06/25/87 MG Set "B" Reactor Restarted .06/28/87 South Reactor Feedpump Returned 07/02/87 to Service Outage to Repair Feedwater 07/31/87 Check Valve Begins Reactor Restarted 10/09/87-Commenced Test Condition Three 10/14/87-HPCI Test Sequence Completed Test Condition Three 10/24/87 HPCI Test Sequence NRC Authorization to Exceed 50% 12/05/87 Power Received l
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30 Test Results Sammaary-3 1 Chemical and Radiochemical 3 1.1 Purpose The principal purposes of this. test'are to collect . I information on the chemistry and radiochemistry of: the Reactor Coolant and Support Systems, and'to-determine that the sampling _ equipment, procedures and analytic techniques are adequate'to ensure
, specifications and process requirements are net.:
Specific purposes of_this test' include evaluation of' fuel performance, evaluations of filter: desineralizer operation by direct and' indirect-methods,~ confirmation of condenser integrity,, demonstration of proper steam separator-dryer operation, measurement and calibrati'on of the off-gas system and calibration of certain process
' instrumentation, if required. Data for these purposes are secured from a variety of sources:-
plant operating records, regular l routine coolant-analysis,' radiochemical measurements of specific nuclides and special chemical tests. 3 1.2 criteria-Level 1 Chemical. factors defined in the Technicalc Specifications and Fuel Warranty must be maintained within the limits specified. -Water quality.aust be known at alll times and remain within the' guidelines of the Water Quality Specifications. The actidty of-gaseous and liquid effluents aust conform to license limitations.' - Level 2 None ' j 3 1.3 mesults ! 1 Prior to loading fuel, appropriate chemistry data.. , was taken. All data remained within criteria levels except for feedwater conductivity and feedwater . copper concentration. These values could have been l elevated due to no condenser vacuum, minimum-: Feedwater System flow, low sample flow rates and q
- - - - - - - - - - _ _ _ _ _ _ _ _ _ _ _ __ "" --A.__. _
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the normally' expected higher corrosion product-levels during. initial-plant systems operationi . During heatup test condition,ithese values were within acceptable limits. See Figure 3 1 for. specific information'on pre-fuel load chemistry data. , During the heatup test condition, all' chemistry' data taken fell within applicable limits'except for-Control Rod Drive (CRD)' dissolved oxygen levels.
~ These levels'are expected to decrease.during further test conditions with. greater steam flow and the steaa jet air ejectors inLservice which will more effectively purge gases from the condenser. Refer '
to Figure 3 1 for heatup chemistry data. The Test Condition One data in general. remained within acceptance criteria limits. Reactor water? s chemistry'_and radiochemistry measurements,were made at a time.when plant conditions were fairly stable. Reactor pow 2r was at 175, the turbine was rolling . but with no electrical output load. Analysis of.the results showed the coolant to be well within the Technical Specification limits.on a11' parameters. Radiochemistry analyses of the coolant _showed activity levels and isotopes present to be normal' for this power level and core exposure. !The. Dose-Equivalent I-131 result was far below the' Technical. Specification limit' of 0.2 uCi/ga. In' Test) Condition One, the steam' jet air ejectors were in-service resulting.in low condensate, Condensates demineralized effluent, and CRD dissolved oxygen levels. The high CRD dissolved oxygen level ubich was'of concern during the.heatup test condition is no longer considered to be a problem. It should be noted'that Reactor Conductivity. varied considerably during the Test Condition One period. Conductivity has, on several occasions,'even exceeded the Technical Specification values of 1.0 unho/cm for several hours.- It was' determined that' the increase in conductivity was related to placing l the Generator on line and' increasing Generator load. One possible explanation was that operation- j' of the Generator was'. causing the paint that'was previously used to coat.the. internals of the' Moisture. Separator Reheater (MSR)~and the Main Turbine to be carried into the condenser'hotwell, thus causing the increase in Reactor: conductivity.-
~
Another contributing factor was felt to be the Krylon coating that was previously used as a i I l _ - - _ - _ _ - - - - - .__---.---..-----_.a-..a'.--.. b --
. Supplemnt 6 -
Pzgn 3 1 . i -] l preservative coating for the turbine blades,.which'
- was being worn off.the blades and into-the.
condenser. Further investigation discounted'the -
- 1rylon coating'(due to.it's chemical makeup)'as'a cause of the conductivity, increase. This situation seems to be improving'as the plant continues to '
operate for longer periods.at increasing power = levels. Efforts were made during the condenser. outage to remove paint from accessible areas in the. MSRs and LP. turbine exhausts. Mechanical-cleaning. by wire brushing and' vacuuming was performedfon the MSR's interior shell surface and hydro-lasing of the three.LP turbine exhaust' extensions to the condenser was performed.. Both Condensate Demineralized Effluent and Feedwater. dissolved oxygen levels at Test. Condition One were
- less than 10 ppb,.which are outside of the limits of 20 5 02 5 200 ppb. The.'20 ppb minimum oxygen concentration has been recommended to establish and:
maintain a~ protective magnetite film on the' inner surfaces of the carbon steel piping ~and equipment of-these systems. . The problem of low condensate /- feedwater dissolved oxygen has occurred during the
- startup of other operating plants. The resolution; at that time was:to simply. continue to monitor these l parameters at higher. power levels to see if the levels would increase with power. . If dissolved: l.
oxygen levels.do.not increase to greater than'20' ppb ' by 100% power, it may'be'come'necessary toLinject-oxygen into the feedwater system. An_ assessment ~ would first be made'as to the corrosivity.of the' water to the carbon steel piping to determine if' this is necessary.- All gaseous and liquid effluent samples o'tained;- b during performance of:this procedure were within'the license limitations. Various radioactive gaseous- q effluents were analyzed during Test Condition One. Grab sampics were taken in an attempt to correlate analysis results with actual monitor. readings. However, the activity. levels being seen at'the- .J off-gas and ventilation sample points were stil1 too j low to provide meaningful data. Only one noble gas was detected, at a level'which was-just above the minimum detection limit.' The off-gas monitor . readings were also still quite low and variable. Low off-gas activity' values are normal and expected' ; at this power level and core exposure. m --- _ _ . _ - . _ _ _ _ _ _ _ _ _ _ _ . - _ _ _ .
Supplement 6 Page 3 1-4' A measurement of radiolytic' gas in steam was. alsor made at Test Condition One. ' Analysis'results were below the 0.06 cra/MWt limit. Radiolytic gas is the hydrogen and oxygen formed in.the reactor..by-radiation induced breakdown of water molecules.- Values higher than 0.06~cra/NWtLcould exceed'the capacity of the' off-gas system recombiners.
.See. Figure 3 1 for more detail regarding the' chemistry data taken during Test Condition One~.
The Test Condition Three' data, in. general,' remained within acceptance criteria ~ limits and satisfied Technical Specification requirements. Reactor water chemistry and radiochemistry
~~
measurements were made at.a time when plant = conditions had been fairly stable for'48 hours. During'this time period, the' plant power level was held between 43 and 45 percent. Some of the-chemistry results, while.still acceptable,' indicated-problems with the primary system'and especially.with the reactor coolant chemistry. Approximately three hours prior to taking samples for this test, Condensate Filter Demineralized.(CFD);"B"'was removed from service and CFD "F" was placed~into service.- Reactor water conductivity spiked, from 0 58 uS/cm up to 0.82 uS/ca. 'At:the same time, sulfate levels increased in the coolant and the pH. dropped. Since all of'this occurred in the same-time period,.the conclusion was made that.there was j a resin intrusion and that the CFDs'were the source of the resin.. Numerous.other chemistry excursions have occurred which' support this conclusion. Following those occurrences, progress was made;in: l reducing and eliminating the source of:the resin intrusions.-_ The procedure for precoating the'CFDs was changed to allow for a fiber underlay on the
~
vessel septa. This inert underlay was used, on~an-
'interin basis, to reduce the amount of powdered-resin'which was escaping. Since that' time', elements (septa) of a new design have been installed for' each of the seven vessels. The new design septa utilizes.- '
a porous metal membrane which has a very small pore. size, when compared to the_old design wire screen- < 3esh elements and'the precoating procedure has been changed to eliminate.the use of the inert fiber underlay. No'further' evidence of resin intrusion has been noted since the new septa.have been- .. installed and as a result, reactor coolant chemistry has shown significant~ improvement.
Supplan nt 6' Pcg3 3 1-5
..The higherf than desired levels of sulfate in thel reactor vessel Are utilized to. complete 'a reactor water cleanur S WCU) test which could not be' accomplish-i i fC1. This test was to determine the.
chlorida reu .1 rate of the desineralizers. . A = test: . procedure rm W Tn was made to' allow other anions to be used as well .s chloride,.as theyLwould have' similar RWCU rssoval rates. 'The.RWCU successfully-demonstrated a removal' capability of greater than'. 90% for sulfates.-- ~ Condensate and feedwater chemistry were also'- - examined._z All values'obtained,.with the exception of dissolved oxygen,:were within-the water quality spectications limits.- Again, however, some of the results reflected the' problems which were occurring; in the primary system'. Condensate conductivity was-higher than would_be normal, and this may have been attributable to carry-over of volatile resin
. breakdown products in the steam. Feedwater conductivity values.were also'somewhat higher than !
normal, and again this'may have been. partially the result of resin breakdown. . Resin escaping from the condensate filter desineralizers would be exposed.to l high temperatures in the feedwater system, which can begin the process of degradation. The insoluble-iron and. total metals found in the condensate, condensate desineralizer~ effluent, feedwater and-reactor' water were within the specification limits and at levels expected for a plant startup. The two. exceptions noted during Test Condition Three , testing are identical to two from Test Condition-One. All are for 1ow dissolved oxygen (< 10 ppb) in
~
the condensate demineralized effluent-(CDE) and.in the final feedwater (FFW). .A minimum level of dissolved oxygen (20 > 02 5 200 ppb).is desired in the feedwater systen to' promote and. maintain a' passive corrosion layer on the pipe walls. Low-levels of dissolved oxygen can. lead to excessive corrosion and higher corrosion products in the feedwater samples. ' Current corrosion product levels cannot yet be conclusively attributed to the low dissolved oxygen, but-if the dissolved oxygen level does not increase with increases in power, it may be necessary to inject oxygen into, the, feedwater system. These parameters of dissolved-oxygen and corrosion products will continue'to be monitored closely in future test conditions.-
- -----------_m _ _ , _ . _ , _ _ _ _ _ _ _
i Supplc= nt 6 ; Pago 3 1-6 l 1 All gaseous and liquid effluent samples obtained during the performance of this procedure were within , the license limitations. Various radioactive gaseous effluents were analyzed ; during Tc3 crab samples were taken in an attempt i to correlate analysis results with actual nonitor- ,f readings. -However,.the activity levels seen at the off-gas and ventilation points are still too low to provide meaningful data. The sum of.six noble gasses is plotted against the off-gas monitor readings, but the plot has little meaning since i present off-gas activity is too low to affect the monitor. . However, the activity is sufficient to p.erform an analysis of the off-gas radionuclides and reactor water iodines.' By normalizing the nuclide activities with' respect to release rate, fission yield, and half-life, and then plotting the data, it was determined that the plant has a " recoil" pattern of release. Such a pattern indicates that there is no failed fuel. A measurement of radiolytic gas in steam was made. Analysis results were below the 0.06 cfm/MWt limit. Radiolytic gas is the hydrogen and oxygen produced in the reactor by radiation induced breakdown of water molecules. It is a normal expected process,
- but values higher than the limit could cause the capacity of the off-gas system recombiners to be exceeded.
See Figure 3 1 for more detail regarding the-chemistry data taken during Test Condition Three. Also note that identifying marks have been added to several data points in Test Conditions One and Three to note that sample dates are other than that of the. sain column heading. Reactor power conditions were, however,'approximately the same as during the balance of sampling, ] q 1 i
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) c t , e u n b / i e d q o p ) o mg e t p b h E r o t s ( p m a t r i i p u eh o d p s n ( ( mc d /
n o m e l y o r n y ) ms ai ed s n _ C T a f o t b G d p u a _ e - n r i _ t t P e d A e f vC o l o s n s a T W o l i0 ( p a t ) i e e D C M M b e t 5 l k T c2 n i r m s a l l l l l l lu lb u e c o / i t . o u d e g nit s s l n y i r c y t n o o u r p u o l I S C O P ( a n l l l l l I l l I n _ a e _ s s p l . n i k i m a n h a . m e r a T S 1 t D eT _ s t y r d s el : : S e l a 2 A t u m p - / a 0d m E N e 4 a a T _ H 1 R S O l l l l l l l N l l
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. Suppls=nt 6_
Page 3 2-1 32 nadiation senasurements 3 2.1 Purpose The purpose of this test is to determine the-background radiation levels in the plant environs for baseline data and activity build-up during power-ascension testing to ensure the protection of plant'
- personnel during plant operation. .
3 2.2- criteria Level 1 The radiation' doses of plant origin and the occupancy times of personnel in' radiation zones shall'be controlled consistent with the guidelines of the standards for protection against radiation outlined in 10CFR20, " Standards for Protection Against Radiation", and NRC General: Design Criteria. Leve1~2 None 323 nesults
~
Radiation measurements were taken in the' form of-process and. area radiation monitor data and site-surveys. To date, all data taken hac_been acceptable and personnel radiation protection has been provided in full' compliance with the criteria. See Figures 3 2-1 through 3 2-3 for applicable monitor and survey readings. These Figures reflect the results of this-test for all the test conditions: for which this data has been completed.
-O L -)
I Supplemnt 6 Page 3 2-2
]
l FIGURE 3 2-1 (Page 1'of 5) ' Area Radiation Monitor Sensor Iscations . Channel No. Imoation (Col.) Floor-Bldg;- 1 (F-10) 2nd Fir. Reac. Bldg.- (RB) Pers. Air Lock / 2 (B-9) 1st Fir. RB Equip. Air Lock 7 3 (J-13) 2nd Fir. Aux. Bldg. (AB) Access Control ( 4 (G-10) 2nd Fir. AB Change. Area Control
-5 (B-13) 3rd Fir RB CRD Storage and Maintenance Area i 6 (G-13)'3rd Fir. AB Main Control' Room (CR) l 7 (F-9) Sub Base. RB S.E. Corner l 8 (B-10) Sub Base. RB S.W. Corner- l 9 (B-15) Sub Base..RB N.W. Corner a 10 (G-17) Sub Base. RB N.E. Corner 11 (G-11) Sub Base. RB HPCI Rs.
12 (F-11) 1st Fir. RB Neut. Hon. Eq. Rs. 13 (F-10) 1st Fir. RB Neut. Hon. Control Panel. 14 (A-11) Sub Base. RB Supp. Podl 15 (F-15) 5th Fir. RB Fuel Stor.. Pool 16 (F-15) 4th Fir. RB New Fuel Vault-17 (F-12) 5th Fir. RB Refuel Area Near Reactor 'I 18 (F-13) 5th Fir. RB Refuel Area Near Reactor (High Range) 19 (L-12) 3rd Fir. Turbine Bldg. (TB) Turbine Inlet End 20 (R-10) Base. TB Sump 21 (N-7) 2nd Fir. TB Main Cond. Area 22 (J-4) ist Fir. TB Decon. Area 23 (M-17) ist Fir. Rad. Waste Bldg.l(RWB) Control Rs. 24 (N-17) Base. RWB. Equip. Drain S. Pump 25 (P-16) Base. RWB Floor Drain S. Pump 26 (R-17) 1st Fir. RWB Drus' Conveyor' Aisle Operating Area 27 Spare 28 -(G-11) 4th Fir. AB Vent. Equip. Ra. 29 (B-15) 4th Fir. RB Change Rs. 30 (H-12) RB Basement Air Lock 31 (B-12) ist Fir. RB Drywell Air. Lock Labyrinth 32 (G-13) 1st Fir. AB Near Blowout Pnl. 33 (C-9) 1st Fir. RB South Air Lock 34 (N-2) 2nd Fir. TB Near Off Gas Equip. 35 (R-2) 1st Fir. TB Near S.J.A.E. Area 36 (K-1) 1st Fir. TB 5.W. Corner 37 (M-2) 3rd Fir. TB South End 38 (R-14) Base. RWB Scrap Cement Recovery 39 (L-13) 1st Fir. RWB H.P. Lab 40 (P-16) 1st Fir. RWB Receiving Area 41 (S-17) ist Fir. RWB Bailing Room 42 (N-16) 1st Fir. RWB Filter Demin. Area 43 (S-17) Mezz'. RWB Washdown Area 44 (S-12) 1st Fir.' Service Bldg. (SB) Mach. Shop. ,
Supp1122nt 6 1 P ga 3 2-3 l FIGURE 3 2-1 (Page 2 of 5) Area Radiation Monitor Sensor Locations ~ i 1 Channel No. Location (Col.) Floor-Bldg.
#45 1st Fir. Inside Drywell !
#46 1st Fir. On Site Stg. Bldg. Control Room
'47 1st Fir. On Site Stg. Bldg. Compactor Room
#48 1st Fir. On Site Stg. Bldg. Truck Unloading Station i
#The remote indicator is located on Process Radiation Monitor Panel j H11-P884 (Relay Room). .(
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Supplament'6- ,f Paga 3 3-1 33 Fuel Loading. 3 3.1 Purpose The purpose of this test was to load fuel safely and; efficiently.to the full core size (764 assemblies). 332 Criteria
.i 1
Level 1. The partially loaded core must be subcritical by at. least 0 38 percent ~ delta k/k with the analytically.- determined strongest rod fully withdrawn. There must be a neutron. signal count-to-noise count-ratio of at least 2:1' on the required. operable SRMs or fuel loading chambers (FLC). The minisua count-rate, as defined by the Technical Specifications, ., must be' met on the required operable SRMs or fuel I loading chambers.- I Level 2 None 3.3 3 Results i Prior to fuel loading, all fuel assemblies were inspected and then stored in the: fuel pool in such a 1 way that no rotation of fuel assemblies would be-I required during their transfer to the. reactor vessel-and also that no assembly would pass over any other- ' assembly in the fuel pool during fuel loading; The only exception ~to this was bundle LJK 954 which was i oriented SW instead of.SE in the fuel pool, but was verified to be properly oriented in the core. Before the start of fuel load,'all' control rods were ! fully inserted, all blade guides were positioned as ;j shown on Figure 3 3-1. : Seven Sb-se neutron sources j
. were installed at locations shown on Figure 3 3-1.
All applicable initial conditions were verified prior to the start of fuel loading. Four times during the fuel loading process, fuel loading was suspended'for greater than eight hours, and all applicable initial conditions were reverified before- ) fuel loading was resumed. ')
.1 1
l
.)
~
Supplem:nt 6 P g; 3 3-2 The Bottom head drain temperature indication was used to obtain the Reactor Coolant Temperature at least once every eight hours (+ 15 minutes) during the fuel loading process. Detailed fuel loading sheets, approved by the Reactor Engineer, provided the instructions on each individual fuel assembly to be moved from a specific location in the fuel pool to a pre-assigned location in the core. It also provided the instructions on what control rods were to be exercised for functional and sub-criticality checks for pre-defined core configurations. FLC moves to be made during the fuel loading were also included. Most of the changes required to the fuel loading sheets during fuel loading were to move the FLCs earlier due to high count rates experienced when fuel assemblies and/or the neutron sources were too close to the FLCs. The only other change involved using Control Rod 10-27 (instead of 06-27) for a sub-criticality check due to an accumulator problem with Rod 06-27 Four FLCs (one per quadrant) were used to monitor the count rate from the start of fuel loading up to the point when 532 bundles were loaded in the core. i In order to keep the FLC count rate within a desirable range and to accommodate an increasing core size, it was necessary to move the FLCs outward by approximately one cell routinely as fuel loading progressed. The location of FLCs was selected to ensure that each quadrant of the core was adequately monitored. (See Figure 3 3-4) The upscale alarm setpoint was set at 1 x 10 5 e andtheupscaletripsetpointwassetat2x10gs cps for each FLC. The downscale rod block setpoint was 3 cps. The FLCs were checked for flux response either by control rod pulls during scheduled sub-criticality checks or by lifting the FLCs partially out of the core. These flux response checks were made at least once every eight hours during fuel loading and prior to the resumption of fuel loading when fuel loading was delayed for eight hours or more. In addition, che Signal-to-Noise ratio was calculated for each FLC prior to start of fuel load, during any required reverification of plant initial conditions and every time the FLCs were moved to a new location. (See Figure 3 3-2)
Suppliment 6 Paga 3 3-3 Four SMs (one per! quadrant) were used to monitor . the neutron count rate starting from the point when 532. bundles were loaded:in the core to the-completion of: fuel load-(764' bundles).. With the SRM" detectors connected to the SM instrument channels, therodblockand.gheupscalegripsetpointswere4 set ~down to 1 z'.10 and 2 x~10 respectively, ,, since no previous saturation test'was performed on: the SM detectors. The down scale rod block setpoint was 3. cps. 'The SRM flux response check was performed at least once every eight hours during'the fuel loading process by partially withdrawing each .a SRM.
-Fuel loading commenced on March 20,-1985 with the loading of four. fuel' assemblies around'the central, neutron source.: The loading continued in control-cell units that sequentially completed each face of.
an increasing square cor+, loading-in a clockwise
" direction until a:12 x 12 square was completed with symmetry about the center. source.- The. thirteen control cells (52 bundles) needed to form a 14 x 14 square array of bundles around the center Control Rod (30-31) were loaded next.- The remaining control-cells were' loaded, one on'each face at'a time,'in"a
-clockwise manner, such that.the core was' rotationally symmetric after every four control cells had been loaded.. '(See Figure 3 3-3).
Control = rod functional and sub-criticality checks were performed either after every cell (first 4 cells in the core),: or after every two or four. cells as dictated by the detailed fueliloading sheets. The purpose of the sob-criticality checks was to ensure that it was safe to load ~the next control cell (s). . For each bundle a visual' verification was performed to ensure that'the bundle was' properly grappled before the bundle was lifted from the fuel pool racks, that there was adequate clearance on all-sides while the bundle'was being moved to the-reactor cavity and that it was loaded in the core in the proper. location'with the proper orientation. Also, physical verification was made-of the. fact' 4 that the bundle was ungrappled before the hoist was raised. Similar verifications were made for the blade guides lifted out of the core and the FLC-aoves made during the fuel. loading process. c L4 b'- _'___.________.____._____.____._._____________._.____._.._
Suppl e:nt 6 Pzg2 3 3-4 A day-by-day account of the fuel load progress is given in Figure 3 3-5. Most of the probless'that caused delays were related to the rt.; fueling bridge (limit switch, power loss, grapple indication, air hose break, etc.). Fuel loading was halted on Sundays in order to perform required weekly surveillance on FLC/SRMs, IRMs, APRMs and the refueling bridge. During the fuel loading process, FLC/SRM count rates were monitored periodically and 1/M calculations were performed and plotted for each FLC/SRM and for the average of the four FLC/SRMs (See Figure 3 3-6). The average 1/M plot was used to project the estimated number of bundles for criticality. If criticality was projected during the next loading increment then the increment size was reduced between 1/M calculations. Strong geometric effects were seen, particularly during the first few bundles loaded in the core and also when the bundles were loaded near and FLC. These geometric effects resulted in erronious (but highly conservative) projections which often resulted in very small increment sizes (1 - 2 bundles) between 1/M calculations. After eighty bundles were loaded in the core, the maximum increment size between 1/M calculations was reduced to one cell (4 bundles except for the peripheral locations where a maximum of five bundles were loaded between 1/M calculations). Bundle LJK 677 was identified to have a rusted channel fastener that had to be replaced. Some debris was identified in the core on bundles LKJ 398, LJK 506 and~LJK 957 After fuel loading was completed, these bundles 3ere pulled out of the core to correct the respective problems and reinserted-back into the core. After the 12 x 12 square array of bundles was completed, a partial core shutdown margin (SDM) demonstration was performed by withdrawing the analytically determined strongest Rod (26 - 27) and a diagonally adjacent Rod (22- 23) out of the core. Sub-criticality with these two rods withdrawn demonstrated that there was at least a 0 385 delta K/K shutdown margin for the existing core configuration. Because the calculated Keff for the 12 x 12 array with the two rods withdrawn was 0.9758, and the calculated Keff for the full core .1
Supplem nt 6'
-P g2 3 3-5 with only the strongest _ rod withdrawn is 0 97, ,
sub-criticality for the partial core demonstrated-that the shutdown margin would be' met throughout the remaining fuel loading process. The fuel' loading was completed after fifteen days on-April 4, 1985 All criteria were satisfied.
l Supplez.ent 6 Page 3 3-6 ' FIGURE 3 3-1 1 NEUTRON SOURCE LOCATION AND BLADE GUIDE ORIENTATION l PRIOR TO FUEL IAADING N - . l
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- SOURCE (7) / BLADE GUIDE (185)
Supplct:nt 6 Pagn 3 3-7 FIOURE 3 3-2 Signal to Noise Measurement DATE A B. C D # OF BUNDLES (TIME) DETECTOR CPS S/N CPS S/N CPS S/N CPS S/N 14ADED 03-20-85 FLC 10 24 10 99 10 32 3 10 24 Prior to (2019) fuel load 03-21-85 FLC* 50 49 60 59 50 49 80 79 4 (0005) - 03-22-85 FLC# 50 249 50 99 60 149 70 174 48 (0340) 03-22-85 FLC# 6.8 16 38 9.8 6.5 64 6.0 5 96 (2005) 03-22-85 FLC# - - 7.0 34 - - - - 96 (2227) 03-23-85 FLC* 5 4 12 11 - - - - 144 (2110) 03-25-85 FLC 10 19.0 11 14.7 12 19 0 12 14.0 156 (1420) 03-26-85 FLC# 10 49.0 20 89 9 - - - - 196 (0020) 03-26-85 FLC# 33 189 32 159 40 159 4.8 15 260 (1915) 03-28.85 FLC# 30 99 4 39 35 116 2.5 73 388 (1116) 03-29-85 FLC 300 999 100 999 150 374 90 299 440 (0907) 04-01-85 SRM 16 159 12 119 40 399 '5 i 149 532 (1528)
#S/N Ratios obtained during FLC moves
-FLC not moved I
Supplement 5 ! Paga 3 3-8 , FIGURE 3 3-3' I CORE LOADING SEQUENCE 1
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Suppisc nt 6 Page 3 3-10 i FIGURE 3 3-5 1 Daily Fuel Loading Progress j BUELES IDADED DATE DA% TO DATE C0001ENTS 03-20-85 4 4 Fuel load started at 2130. 03-21-85 32 36 Rod Block limit switch malfunction. 03-22-85 62 98 03-23-85 58 156 03-24-85 0 156 Weekly surveillance on SRMs, IRMs, APRMs and Refueling Bridge. 03-25-85 38 196 Fuel load resumed at 1500. 03-26-85 82 278 03-27-85 84 362 03-28-85 76 438 03-29-85 66 504 Transformer #64 lost due to initiation of its deluge (fire protection) system. l 03-30-85 28 532 0400 refuel bridge power cable problem. Cable cut and re-termed to , restore the system. i 03-31-85 0 532 Weekly surveillance. FLC to SRM switchover. 04-01-85 14 546 Fuel load resumed at 2000. 04-02-85 74 620 04-03-85 48 668 Air hose damaged when stuck center section of the mast was released and dropped. 04-04-85 96 764 Fuel load completed at 2350. ! i
'l i
Suppica nt 6- l Pega 3 3 FIGURE 3 3-6 i NUMBER OF BUNDLES LOADED 1/N Plot _. -, -. , - m ,___m
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L______.__..______._ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ . _ _ . _ _ _ _ _ _ . _ _ _ ______ O
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Supplccent 6 Page 3 3-12 FIGURE 3 3-7' (Page 1 of 2) t TVEL 14 CATI 0tl VERIFICATION
*RM Mdii!
et M M M M E i. l RR M M M Rs! 4 R M MR RR d
-:*1 M MMM MR R ft M RMM MM A M R RM MMM R l-WR NE: M M M R; d MWM MRMR!
M t MMM R; "M M M R)MMMM R
-NiR R M MM MS '
2.itMMMMM* M MM MM& ..j MRR.'
Supplessnt 6 Page 3 3-13 FIGURE 3 3 . (Page 2 of 2)~ FUEL 14 CATION VERIFICATION
'l xugny-4M M M M W-mM M M M M W4 gM M M M M M b-
!MRM M MMMy" iM RB MMWMe- Mk" iM RM MMM lMRMM M!M M&'
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-----_---__--_A_-_.-._--a.- - _ _..--b....
( Supplsn nt'6' PIga 3 4-1 34 Full Core Shutdown Margin 3.4.1- Purpose-The purpose of this' test is to assure that,the reactor will be subcritical throughout the first cycle with any single control rod fully withdrawn and all other rods fully inserted with the core in its maximum. reactivity state. 3 4.2 Criteria
. Level 1 The shutdown margin oftthe. fully loaded core with-the analytically. determined strongest' rod withdrawn must be'at least 0 38 percent! delta k/k plus R (an=
additional margin for exposure) where.R =~0 5' percent ~ delta k/k. Level'2 Criticality should occur within + 1.0 percent delta k/k of the predicted critical. 343 Results The fully loaded core was made critical-by. withdrawing control rods following the B sequence, using the Reduced Notch Worth Procedure. This-sequence contained ~the analytically' strongest Rod 06-39, which was fully withdrawn-before reaching criticality.1 Prior.to performing the shutdown..~ aargin-demonstration,.as required by. Technical Specifications, the shorting links were removed to ,q put the Reactor Protection Systes:in the !j
.non-coincidence scram mode. 1 The point of criticality was demonstrated by l withdrawing control rods.following'the' order given -)
in the rod pull sheets until an'(approximate) 300 j second period was observed with Group.3 Rod'18-51 withdrawn to notch Position 08. Moderator temperature was recorded'at 960F. Later, with moderator temperature still at 960 F, the reactor was then made supercritical by withdrawing Control Rod 10-43 to Position 08. SRM A,B,C and D , measurements were.taken every 30 seconds for.three .l and one half minutes.. Period analysis was performed j by fitting the data linearly on a semi-log plot and 1 1
]
1; i-
Suppls: Int 6 Page 3 4-2 measuring time to increase one decade from which' period was calculated. The average period was determined to be 76.5 seconds. < The shutdown margin of the fully loaded core at 68 F with the analytically strongest rod withdrawn. was determined to be 2 72% delta k/k. Level.1 criteria were satisfied since the measured shutdown margin was larger than R + 0 385 - 0.88% delta k/k where R is defined here as the analytical difference in shutdown margin (cold) at the most limiting point in the cycle and Beginning of Life - of the core. The difference in keft between the theoretical critical configuration and the actual measured' critical configuration was found to be 0.28% delta k/k. This satisfies' Level 2 criteria since' criticality occured within 1% delta k/k of the theoretical critical eigenvalue. l
Supp12:snt 6 Page.3 5-1 35 Control Rod Drive System 3 5.1 Purpose l Each control rod drive (CRD) was tested to measure insert / withdraw and scram times and friction dP levels in the CRD hydraulic system. This was done i to demonstrate that the CRD system operates properly over the full range of primary coolant temperatures. and pressures. 3 5.2 Criteria Level 1 Each CRD aust have a normal withdrawal speed less l than or equal to 3 6 inches per second, indicated by a full 12 foot stroke in greater than or equal to 40 seconds. The mean scram time of all the operable CRD's with functioning accumulators must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are de-energized). Position Inserted From Fully Withdrawn Scras Time (Seconds) 46 0 358 36 1.096 l 26 1.860 6 3 419 l 1 \ The mean scram time of the three fastest CRD's in a two-by-two array must not exceed the following times (scram time is measured from the time the pilot scram valve solenoids are de-energized). Position Inserted From Fully Withdraien Scram Time (Seconds) , 46 0.379 l 36 1.161 I 26 1.971 6 3.642 l l l I
Supp1sm nt 6 P:ga 3 5 Level 2 , .Each CRD aust have a normal insertion or withdrawal! speed'of 3.0 (1 0.6) inches per second: indicated.by a full 12 foot stroke in 40 to 60 seconds.. If the differential pressure variation exceeds 15 paid for a; continuous drive-in, a settling test must be performed. In this case the differential settling pressure should not be less than 30 psid, nor should it vary by more than 10 paid over a full stroke.
-353 nesults Insert / withdraw timing, friction' testing, and' scram timing were performed on the CRDs at the conditions specified in Figure 3 5-1.
All of the indiv'idual control rods were scram time tested, friction tested and insert / withdraw timed during the Open Vessel test condition. Adjustments' to some CRDs had to be done in some~ cases to bring insert / withdraw times into acceptance limits. During the friction testing, no pressure differential measurements exceeded the criteria of 15 paid and no settling tests had to be performed.. The four slowest rods in each sequence were also scrammed at reduced accumulator pressure. All test criteria were satisfied. During Heatup, the four slowest rods in each sequence were scram timed at 600 psig and at 800 psig.. Upon reaching rated temperature and pressure. conditions, all CRDs.were scram timed. The eight' slowest rods determined during Open Vessel and Heatup testing were then-insert / withdraw timed, friction tested, and scrammed at' reduced accumulator pressure. Figure 3 5-2 shows the average scram time ! of the eight slowest rods, four in each sequence, at various reactor pressures compared to the maximum permissible.
)
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Supple:: Int 6 '
'P2ga 3 5 The specific results from our rated pressure testing are as follows:
l Mean Scras Times .l l Rod Position' l 46 1 36 l 26 l' 06 l l Mean Scram Time for all 1 0 302 l'O.852'l 1 398 l 2.501 I -l 88 Sea. B rods (sec) l l l' l l-l Mean Scram Time for all- l 0.288 1 0.802-l 1 340 l 2.436 l.- l 97 Seq. A rods-(sec) l l l l~ l' l Mean Scram Time for AIL IO.295 l'O.826 l 1 368 l 2.467-l l rods', Seq. A and Seq. B (sec) l l l 1: l l'(core average) I l l l l l Mean Scram Time of the 1 0.325 1 0.900 l 1.481 1 2.655 l 1 3 fastest CRDs in a two-by-twol l l l l' I array for AIL rods, Seq. A andl l l l- -l l Seq. B (core average) l l l l l In conjunction with the planned scram for the-Shutdown from outside the Control Room test performed in Test Condition One, the scram times for the four (4) slowest. Sequence "A" control rods were determined. All the scraa times were within the acceptance criteria.
')
i l i i I i _ __ _ __ - - _ A
Supplia nt 6 ! Paga 3 5-4 FIGURE 3 5-1 CONTROL-ROD-DRITE SYSTEM TESTS Reacter Pressure with Core Loaded Test Accumulator Preop psig Description Pressure Tests 0 600 800 rated Position All All Indication Normal Stroke Times All All 4(a) Insert / Withdraw Coupling All All Friction All 4(a) Scram Normal All All 4(a) 4(a) All Scram Minimum 4(a) 4(a) Scram Zero 4(a) Scram (scramdischarg{c) Normal volume high level) Scram Normal 4(b),
- a. Refers to four CRDs selected for continuous monitoring based on ;
slow normal accumulator pressure scram times, or unusual ' operating characteristics, at zero reactor presssure. The four selected CRDs must be compatible with rod worth minimizer, RSCS systems, and CRD sequence requirements.
- b. Scram times of the four slowest CRDs will be determined at Test Conditions 1 and 6 during planned reactor scrams. j
- c. The scram discharge volume fill time will be determined at Test '
Conditions 1 and 6 during planned reactor scrams. Note: Single CRD scrams should be performed with the charging valve , closed (do not ride the charging pump head). a
Suppk=nt 6 P2ge 3 5-5 FIGURE 3 5-2 Scram Testing Results , n 6- 4' a
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(' f Suppleme M 6 Pcgr 3.6 1 36 Source Range Monitor y,rformance and Control Rod Sequer.ca q Exchange D, h A. i w.
~ 3 6.1 Purpose 8
' } a
$J The purpose of this test was to.ddwonstrate that t.d,'
- operational sources, source ry.gti monitor (SRM) ~'\ _
! instrumentation, and rod n t6drawal sequences 'h p provideadequate'infoEmatpontoachievecriticality N. (
>) , e and increase poww fn a tyfe and efficient manner. , ( Theeffectoft.$olchlrofarrementsonreactorpower b i . was also determined.
- s' 4
) 3 16.2 Criterd a % , e m J, Level 1,. s (4 )n \ i l s
> There must be a neutron signal count-to-noise count ",'
t* / ratio of at least 2:1 on the required operable SRMs. s*q y , 4 There must be a minimum count rate as defined by i Technical Specification on the required operable 5 , 6 SRMs., i :f' ,3 Level 2 , [N
., None .y( i
,r ; i 3.6.3 .Mrmics t r ' {t k.hrtotheinitialcriticalityinsequenceB,thh, count-to-noise ratio for SRM (A, B, C and D) werel r 4 , 1119, 199 and 49 respectively. These ratios weree well above the Level I criteria of 2:1. ' TM pirfisus -
cetnth on the SRMs (A, B, C and D) were .20, 11, 40 i ,S a'no 15 eps respectively. These were well above tre " ,% sinlinus Level 1 criteria required of 0 7 cps.
- S v. 4 > Ng .
1 .VM readings Ukra ta ko taken' periodically during initial critica21tj in both sequences and IRM
, readings were obtained during the initial heatup in sequence B. All testi. criteria were satisfied.~
f Performance data was gathered during power Nscension to 20% in Control Rod Sequence A and Sequence B. At q
' the feedend flow, ofand each rod worth steam minialzer flow values were group, recuice P(d.RN,
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Supplement 6 r r Page 3 7-1 3 7 ' water Level Measurement 3 7.1 Purpose The purpose of thi:r dest is to measure the reference leg temperature and recalibrates the instruments if the measured temperature is different from the value assumed during the initial calibration. 3 7.2 criteria Level 1 '
, t.
None; 4^ Lavet 2 '
- The difference between the actual reference' leg i temperatt.re(s) and the value(s) assumed during initiaDcalibration shall be less than that amount that will result in a scale endpoint error of 1 percent of the instrument span for each range.
373 Results Testing of the level instrumentation accuracy showed that scale end point errors when actual drywell temperatures and assumed calibration temperatures l were compared were 0.708%, 0.554%, 1.0507% and 0 320% for wide range (Div. I), wide range (Div. II), narrow range (Div. I) and narrow range (Div. , II),respectively. The slight Level 2 criteria j violation for Div. I narrow range level instrumentation was found acceptable following an evaluation performed by General Electric. It was previously intended to repeat this test to l obtain another set of data with all the drywell l l coolers in operation. However, based on an evaluation performed by General Electric, the test results are acceptable and no further testing is required. l l l l l
. - _ -__ _ _ __ ___ _ -. _. ._ _ _ .- - _ _a
Supplsecnt 6 Pag 2 3 8-1 3.8 IM Performance 3 8.1 Purpose The purpose.of this test is to adjust the intermediate range sonitor system to obtain an: optinua overlap with the SRM and APRM systems. 3.8.2 criteria Level 1 Each IRM channel aust be on scale before the SMs exceed their rod block setpoint. Each APRM aust be on scale before the IRMs exceed their rod block setpoint. Level 2 None 3.8.3 Results During the initial criticality, all IRMs except IRM DghowedresponsepriortotheSRM'sreaching5x 10 cps. IRM D was repaired and tested satisfactorily at a later date. Range 6/7 overlap calibration was also completed for each IRM, except IRM G which was reading erratically. This IRM was replaced and retested successfully. IRMs G and H' underwent repairs during the outage that required retesting of the range 6/7 overlap. After some adjustments, overlap was again successfully demonstrated for both. All APRMs were shown to be onscale prior to any IRM exceeding its rod block setpoint during a plant shutdown in Test Condition One. It was noted that IRM channels C, E, F and H were not reading one-half decade below their range 9 rod block setpoints. Although Technical Specification
~
verification of overlap was satisfactorily performed in conjunction with Plant Surveillance procedures, the test will be reperformed after APRMs are adjusted at a higher power level. 1 L - .
Supplcosnt 6 Page 3 8-2 IRM G Range 6/7 Overlap Calibration was reperformed successfully during the plant restart-in October 1987. This calibration was necessary due to the replacement of the preamplifier for this IRM. l 1 C________________________ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . . _ _ _ ._ . _ _ _ _ _ _ _ _ _ _ _ _
Supplac;nt 6 P!g) 3 9-1 39 LPRM Calibration 3 9.1 Purpose The purpose of this test is to verify LPRM response to flux changes and proper LPRM connection to neutron monitoring electronics and to calibrate the LPRM's to their calculated valves. 3 9.2 Criteria Level 1 None Level 2 i Each LPRM reading will be within 10 percent of its calculated value. J 393 Results The initial LPRM verification test was performed while the Reactor was at rated pressure in the heatup test condition, in conjunction with scram time testing. Specific control rods were selected
)
to be used for flux response checks based on their ~ , proximity to the LPRM strings. The withdrawal of these rods from Position 00 (FULL IN) to Position 48 (FULL OUT) was observed in terms of the LPRM flux response as the rod was withdrawn past each of the four LPRMs for the associated LPRM string. All 172 LPRMs (43 LPRM strings with 4 LPRMs per string) were observed, using Brush Recorders and STARTREC System for flux response. Initially, no flux response was observed on 25 of the 172 LPRMs. For the LPRMs that showed flux response, the proper order of the LPRM response (D, C, B, A) was observed. 1 During supplemental testing, it was found that some ; LPRM detectors were connected in reverse order and i these were corrected. One detector was found j damaged and had to be repaired. During Test : Condition One all remaining LPRMs were observed to l show proper flux response following repair efforts.
]
An initial LPRM calibration utilizing the Traversing-In-Core Probe (TIP) System and the Backup Core Limits Evaluation (BUCLE) program was conducted in Test Condition One. Utilizing TIP traces, local LPRM readings, and heat balance information, a gain 1 _ _________________-_m__E
[ , q Supplsment 6-Page 3 9-2 adjustment factor (GAF) was determined for each LPM. These GAFs were then used to adjust the gains of.the LPRMs and a followup test was performed to' verify criteria. Due to non-steady state conditions, a total of four full sets of.TIP traces were made. Upon completion of the test,.a total.or'23 LPMs did not meet the above criteria.. The majority of the. failures were reasonably close to the criteria, oru .q were in the low power region of the core where- !
. criteria can-be ignored.
During Test Condition Three relevant portions of REP' 54.000.05, LPM Calibration '- Computer . Determination,'were performed. .This entailed performing an OD-1 with a complete set of TIP traces, running a P1 to update the LPRM.GAFs,. . obtaining an OD-10 Option 7 GAF edit, and obtaining ! the initial LPRM flux amplifier input currents. i All 172 GAFs were-reviewed, and it was determined that eight (8) GAF adjustments on the following LPRMs were necessary. 16-33A .48-17A i 48-33A 24-25A 16-57A 08-17D 16-09A 32-49D. These eight GAF values were outside of.the 0.95 to 1.05 range, and-were used'to calculate new LPRM flux amplifier input currents. Following these signt-(8) LPRM GAF adjustments,~an. OD-1 with TIP-traces was performed, a P1 was run and an OD-10, Option 7 GAF edit was obtained. Upon review of the GAF edit only one LPRM GAF was outside of the 1.00 1 0.10 required range. LPRM 32-49D was. reading 0.0, and was diagnosed as a. drifter on the latest'P1 edit. .IGAF.was manually set, a P1 was run, and the LPRM 32-49D had a GAF of. 1.0. Upon completion of REP 54.000.05, all.172 LPRM readings were verified to be within 10 percent of-their calculated readings, thus satisfying the Level-. 2 criteria. E _ __.___________ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ ___ ______ _ ____ ._____._____________.__________________1
.Supplcment 6:
Peg) 3 10-1 310 Average Power Range Monitor Calibration 3 10.1 Purpose The purpose of this test is to calibrate the APRM system. 3 10.2 criteria Level 1 In the startup mode, all APRM channels must produce a scram at less than or equal to 15 percent of rated thermal power. - The APRM channels must be calibrated to read equal to, or greater than the actual core thermal power. Recalibration of the APRM system.is not necessary from a safety standpoint if at least two APRl1 , channels per RPS trip circuit have readings greater than or equal to core power. Technical. Specification and fuel warranty limits on APRM scram and rod block shall not be exceeded. Level 2 If the above criteria are satisfied, then the APRM channels will be considered to be reading accurately if they agree with the heat balance to within (+7,
-0) percent of rated power.
3 10 3 Results During heatup, each APRM channel was calibrated to read greater than or equal to a manual calculation of Core Thermal Power based upon a constant heatup rnta analysis. The APRM scram trip setpoints were also adjusted to produce a scram at less than 15% of rated power. The Level 1 criteria was satisfied. An initial APRM calibration was performed during Test Condition One at a Reactor Power of 13 3%. All APRMs were adjusted to read within (+3, -0)% of calculated core thermal power, as determined by a manual heat balance calculation. A second APRM calibration was performed later in Test Condition. One when core thermal power (CTP) was determined to be 15.56% as determined from a manual heat balance calculation. APRM gain adjustments were then evaluated and the APRMs adjusted to read 16.0% which is +0.44% above CTP and satisfies the above Level 2 criteria. I I
- u. --.- - --,_- . . . .-_--_,_a__r__
'I ,, SupplacInt 6' PIga 3 10-2 During Test Condition.Two, following a. full core j LPRM calibration, each APRM channel was calibrated l to a reactor power of.48.4%. This reactor core-thermal power was calculated by. heat balance, and the six APRMs were calibrated to read within (+7,
-0)$ of the 48.4% power, thus satisfying Level-2 criteria.- This also ensured that the Level 1 criteria requiring that the APRM channels be . .
calibrated to read equal.to, or greater than the I actual core thermal' power was set. Finally,.the-Scale Factor was determined to be equal to 1.0 since; no APRM gain adjustments were imposed. This satisfied the Level 1 criteria requiring- that, Technical Specifications and fuel warranty = limits on' APRM scram and rod block shall not be exceeded. During Test' Condition Three, the. Process Computer was used to. determine.a core thermal power of 48 3%. No APRM gain adjustments were laposed which allowed the Scale ~ Factor to be set-equal to 1.0. Therefore, the-six'APRM desired. readings were-determined to be 48 35.. The six APRM' readings taken locally at Relay Room Panel H11-P608 revealed that the absolute differences between the desired and current APRM readings were within (+25. -05) except for APRM B' which initially read 48.2%. .Therefore, APRM B was adjusted by changing the setting of-the R16 gain potentiometer to read greater than 48 3% CTP. The final APRM readings at that power were as follows: APRM A 50.0 APRM D 49.2 APRM B 48.8 APRM E 48.6 APRM C 49.0 APRM F 49.2 The scale Factor was determined to be equal to 1.0 and all the APRMs are reading greater than core thermal power. This satisfied the Level 1 criteria. A's seen by the data above, the Level 2 criteria is also satisfied. 1 d i i
)
i i
.y Supplement'6-
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Paga 3 11-1 l
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3 11 Process Computer-3 11.1 Purpose. a The purpose of this test'is to verify'the. performance of the process computer under plant I operating conditions. , j 3 11.2- criteria Level 1 None' ;i Level 2 Programs OD-1, P1, and OD-6 are considered' operational when the MCPR, the maximus LHGR, the-maximus APLHGR, and thu LPRM gain adjustment factors calculated by BUCLE and the process computer agree' with the tolerances specified in the FSAR. Remaining programs will be considered operational on? the successful completion of.the static and dynamic. testing. 3 11 3 Results The TIP System consists of five identical probes used to measure and record-the axial. neutron flux-profile at 43 radial core locations. .The recorded information is used.by the Process Computer to calibrate the fixed in-core. Local Power Range-Monitors. Each probe is driven'into and withdrawn-from the core by its associated drive sechanism.- In order to operate automatically, the TIP drive. control units must be programmed with the probe position at top and bottom of the core. These top and bottom limits are programmed and verified in the TIP cold alignment. This portion of the; test was performed successfully by hand-cranking the TIPS.to the top of the core and setting the core limits: i based on the resulting position readings.- In order to follow and read data from the TIP-
' machines, the Process Computer must receive position information and flux signals from the TIP System.
This interface is tested in the Static Systen Test' , Case by_ running the TIP machines in various. configurations andLverifying the proper responses on the Process Computer. j l i s 4 -- . . . _a_._____1______ ___i_. _ _ _
- - __ -- . - _ _ = - - -
'l SuppltcInt,6' PIga 3 11-?
'The Static System Test' Case had two objectives:-
verification of'the program' logic and checkout of' the TIP interface. The first objective was successfully achieved, but the TIP interface i checkout was unsuccessful due to a. problem with the .) TIP System that resulted in the loss of TIP' position 1 indication. This original position indication ! problem was repaired. J I
.As part of,the Test Condition'One testing, the TIPJ.
top and bottom core limits were reverified under hot conditions, and the TIP interface with the'.X-Y plotter was'also verified-to function properly.-
-Following repairs to TIP "C" ball valve, a.' process q computer. interface problem, and TIP "B" Logic,-a.
successful OD-1 was obtained from the process
. computer. It was noted.that's three'(3).second-delay was occurring between X-Y plotter traces and the machine normalized, full power adjusted TIP array. This problem was corrected prior to the OD-1 portion of the Dynamic System Test Case.
The Dynamic Systen Test Case was performed during-steady state: conditions with reactor power at-approxinatley 20%. The. testing included:
- 1. Verification of the Computer. Outage Recovery Monitor (CORM) to initialize necessary variables-and exposure arrays as part of initial plant computer startup and to allow for controlled set-of data in further system testing.=
- 2. Verification that all required plant sensors for.
NSS programs are being properly scanned. 3 Verification.of the heat balance subroutine used . by OD-3 and P1 by comparing it with a manually calculated heat balance.
- 4. Performing an LPRM calibration to' verify the operation of 0D-1 prior to the verification of thermal limit calculations.
5 Verification of thermal limits calculations and- d core power distribution. I
- 6. Verification of the exposure updating programs P4 (10 Minute Core Energy Increment), P1 (Periodic Core Evaluation), P2 (Daily Core ]
Performance Summary) and P3 (Monthly Core Performance 3uasary). - _ _ _ - _ _ _ - _ _ _ - _ _ _ __ ~-
5 Supplenint'6 Page 3 11-3 7 Verifying key variable memory locations'and performing manual calculations to verify the remaining NSS software at steady state operation and syssetric rod pattern.
-Thermal limit and LPPM calibration factor-calculations were verified in conjunction with the.
-DSTC. The verification was performed.by taking the same data that is' input to the P1 program, for its calculation, and inputting'it into an approved offline computer program (Backup Core Limits Evaluation (BUCLE), which also performs the F1 calculations. .The resulting thermal limits and LPRM-calibration' factors were verified against the criter ia.- In all instances the results were in the same fuel assembly and the results are as follows:
Parameter Location P1 Results Bucle Results. 5 Error-Max LHGR '33-52-13 3 78 3 78 0% Max HAPLHGR 27-10-13 3 30 3.30 05' Min CPR 27-10 3 877: 3.876 .02%' P1 Result - Bucle Result.
% Error = L# 100%
P1 Result The Local Power Range Monitor'(LPRM) gain adjustment factors calculated by BUCLE and the process computer were verified to agree within 2%. Programs OD-1, P1, OD-6'and the remaining NSS programs were considered operational upon the satisfactory performance:of this procedure. During Test Condition-Three, a Process Computer - BUCLE Comparison was performed at steady-state conditions at 148.4% reactor power and 935 core flow. With P1 blocked, the following list of process computer edits were obtained and compared to the respective BUCLE edits: RCAL GAF W PBUN EBUN NSS Core Performance Log Thermal Data in Fuel Assembly II, JY The 12 Bundles Closest to CPR Limits The 12 Highest Ratios of a Bundle MAPLHGR to its LIMLHGR
-Target Exposure and Power Data l I
i 1
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9 1 C___________________-._____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ . _ . _ _ _ _ _ _ _ _ _ . _ _ _ . _ . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _
- j ..
~ Supplement' Page 3 11-4 Each process computer value was verified to agree with each BUCLE value to within +'2% (FSAR
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tolerances). An MCPR of 2.819. was calculated by P1,'and an~ MCPR of 2.821 was calculated by BUCLEs PINEWRP, each for. bundle 17-18. These values are.within 0.07% of each other,.therefore satisfying the' Level 2 criteria. An MLHGR of 5.76 was calculated by P1, .and an MLHGR of 5.75 was calculated by BUCLEs PINEWRP, each for-bundle 17-26-11.- These values are within 0.17%.of each other, therefore satisfying the Level 2 criteria.- An MAPLHGR of 5.05 was calculated for bundle 17-26-11 by both P1 and BUCLEs PINEWRP. Therefore, the Level 2 criteria was satisfied. The' process computer OD-10, Option 7 GAF edit was compared to the BUCLEs EDITMAP GAF array. The' values were verified to agree within + 2%, therefore satisfying the Level 2 criteria.. l l 1
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I Suppl'; ment 6 Page 3 12-1 3 12 RCIC system 4 i i 3 12.1 Purpose The purpose of this test is to verify the proper l' operation of the RCIC system over its expected operating pressure range. ] 3 12.2 Criteria Level 1 The average pump discharge flow must be equal to or greater than the 100-percent-rated value after 50 seconds have elapsed from initiation on all auto starts at any reactor pressure between 150 psig and rated. With pump discharge at any pressure between 250 psig and 100 psi above rated pressure, the required flow is 600 gps.. (The 100 psi is a conservatively high value for line losses. '"3 measured value may be used if available). The RCIC turbine shall not trip or isolate during auto or manual starts. Level 2 To provide a margin on the overspeed trip and isolation, the first and subsequert speed peaks on the transient start shall not exceed the rated speed of the RCIC turbine by more than 5 percent. For small speed or flow changes in either manual or automatic mode, the decay ratio of each recorded RCIC system variable must be less than 0.25. The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere. The delta P switch for the RCIC steam supply line high-flow isolation trip shall be adjusted to actuate at 300 percent of the maximum required steady state flow, with the Reactor assumed to be near the pressure for main relief valve actuation. I
Supplecint 6-Page.3 12 3 12 3 Results. During the Heatup Test Condition, the RCIC pump' suction and discharge was lined-up'in a1 closed loop with the condensate storage tank., The. system was subjected to negative and positive 10% step changes in flow at system flows of 600 gpa and 270 spa.using both r. step generator and the RCIC flow controller. Minimum flow data was also'taken at a' speed of 2000 rps and a.RCIC quickstart was performed. The RCIC system was able to' supply 600. gps.at a-
' discharge pressure of 1140 psig in 35 seconds when.
automatically started using 940_psig steam from the~ vessel. The K72 time delay relay.was set down from 10 see to 5 see to prevent the RCIC turbine from coasting'down~ excessively before the. opening of. thel Steam Adalssion Valve, thus reducing the experienced transient. The RCIC turbine did'not isolate or trip during the auto.and maunal starts. e In addition,' there were no RCIC. turbine speed peaks or oscillations in RCIC system variables in:the transient testing. The RCIC system was also subjected.to an extended run at rated flow conditions. .RCIC performed satisfactorily with all. system temperatures stabilized below alara levels and'a negative-pressure maintained on the gland seal. condenser system. All Level 1 and Level 2 criteria.were satisfied = except the RCIC steam supply high flow isolation trip setting. During the Outage for the replacement of the Main Steam Bypass Lines, engineering modifications to the instrument lines were completed that were expected'to solve the problems found with
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the instrument sensing lines. Upon recommencing Heatup in August of:1986, the RCIC EGN module was found malfunctioning and was replaced. Because of this and the instrument line modifications discussed above, the RCIC system was .i subjected to further testing including 10% positive .! and negative step changes _in both speed and flow,. .j and a quickstart. With the reactor pressure at 955 psig,.the RCIC system was able to supply 600 gpa at a discharge pressure of 1143 psig in 33 seconds. All Level 1- , and Level 2 criteria were satisfied except the ; turbine gland seal system verification and the RCIC ! steam supply high flow isolation trip setting.. (. . . .
' Supp10=nt 6
'Page 3 12-3 !
Due to.a failure of the RCIC Barometric Condenser. l Vacuus Pump, data 'did not show the existance of. a Vacuus on the vacuum tank as required by the test. criteria. Subsequent; work on the Barometric Condenser Pump corrected.the problems and it was retested successfully. . Data was also taken during this test to determine-the actual;3005 value for the RCIC steam supply line, high flow isolation trip setpoint.. Hovever, the' trip setpoints were'not, adjusted to these. settings,. but are being:left'at the current trip setpoints given in the Technical Specifications. -'The current settings as specified by the Technical Specification are set conservatively compared to the value calculated by the performance.of this.. testing, yet provide ample margin to prevent spurious RCIC-isolations on system automatic initiations. During Test Condition One, RCIC system testing consisted of a hot' manual' vessel injection, two (2): cold quick start vessel injections, a'150 psig CST: to CST run, a'150 psig vessel injection, and a CST to CST run at. rated pressure for- baseline data. ' The, only problem of any significance during any of these. runs was a turbine speed peak 29 rpa above the Level 2 limit of 4725 rpm,.which occurred during the initial hot manual vessel injection. . Minor adjustments were made to the.RCIC control circuitry and the probles did not' reoccur'in subsequent tests.. For the hot manual vessel injection, with the reactor supplying steam.at a pressure of 915 psig, the RCIC pump delivered a flowrate of'3 600 gpa at a discharge pressure ~of 965 psig in 28.4 secends.~ As discussed above, the turbine reached a marinua speed. peak of 4764 rps, which exceeded the Level 2 criteria. Based on data taken in conjunction with this test, it was determined that the actual line loss value for the RCIC system was 50 paid. For the first' cold vessel injection, with'the reactor supplying steam at a pressure of 918 psig,. the RCIC pump delivered a flowrate of 3 600.gpa at a.- discharge pressure of 970 psig in 28.5 seconds. The-saximum speed peak was 4686 rps for the RCIC. turbine. 1 i
1 Supplsecnt 6-P ga 3 12-4. For-the second cold vessel; injection, with.the reactor' supplying steam at a pressure of 910.'psig, the RCIC pump delivered a flowrate of 3600 gpa at a
. discharge pressure of.970 psig in 29 2 seconds, with a maximum speed peak of 4488 rps.
During the 150 psis CST to CST.run, with.the reactor.. supplying steam at a pressure at.165 psig,=the RCIC pump delivered a flowrate'of 3600 sps at a' discharge pressure of.271 psig in~22.0 seconds, with a maximum speed peak of 2818. During the rated reactor pressure CST to.. CST,run . with the reactor supplying steam at a' pressure of-920 psig, the.RCIC pump delivered a flowrate.of-3 006 gpa at a discharge ~ pressure of 1095 psig in 29 < seconds,-with no discernable speed peak as the
' turbine ramped up smoothly to'a: final speed of 4500 rps.
The.150 psig vessel injection was conducted with the reactor supplying steam at.160 psig. The systes' reached 3 600 gpa in an elapsed' time of'21.5_ seconds at a discharge pressure,of 215:psig, with a maximus: speed peak of 2641 rps. RCIC testing was successfully completed witha 150-psig cold CST to CST baseline data test. With the reactor supplying steam at a pressure of 165 psig, . the RCIC pump delivered a flowrate. of 3 600, gpa at' a discharge pressure of 360 psig in 19 5 seconds, with an initial speed peak of 1418 rps followed by.a smooth ramp to a final maximum speed of 2766 rps.
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Supplcc;nt 6 Pcgo 3 13-1 3 13 HPCI System NOTE: As discussed in memorandum NRC-87-0179, " Initial Test Program Changes",' dated September 30, 1987, from B. R. Sylvia to U.S. Nuclear Regulatory Commission, Washington, D.C., the Level 1 criteria for system response time to rated flow has been modified to agree with Plant Technical Specifications. The Level 2 criteria for margin to overspeed trip has been modified to reflect the control system hydraulic modifications which improved the stop and control valve response to a quick start. 3 13 1 Purpose The purpose of this test is to verify proper operation of the High Pressure Coolant Injection (HPCI) system over its expected operating pressure range. 3 13 2 Criteria Level 1 The average pump discharge flow must be equal to or greater than the 100-percent-rcted value with a system response time of less than or equal to 30 seconds as defined in Technical Specifications at any reactor pressure between 150 psig and rated. With pump discharge at any pressure between 250 psig I and 100 psi above rated pressure, the flow should be ) at least 5000 gpm. (The 100 psi is a conservatively ' high value for line losses. The measured value may be used if available). j The HPCI turbine shall not trip or isolate during auto or manual starts. Level 2 The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere. The delta P switch for the HPCI steam supply line high flow isolation trip shall be adjusted to actuate at 300 percent of the maximum required steady-state flow with the reactor assumed to be near main relief valve actuation pressure. ___. _ _ _ _ _ _ a
I i Suppls=nt 6 ] Page 3 13-2 For small speed or flow changes in either manual or automatic mode, the decay ratio of each recorded HPCI system variable must be less than 0.25 The margin to avoid the overspeed. trip shall be at least 10% of the nominal overspeed trip setpoint of 5000 rps, during all auto starts of the HPCI system. 3 13 3 nasults Following setup of the control system, initial coupled turbine performance runs were performed on the HPCI systes during initial heatup. . Dynamic
^ stability checks were conducted with the HPCI pudp suction and discharge lined-up in a closed loop to the CST. Flow step changes of 1 500 gpa were introduced by the flow controller in automatic, with HPCI system. flows at 5000 gpm.and 2700 gpa.
During automatic initiation testing of HPCI, a l discharge flow of 5000 gpm was reached in 23 4 seconds. Twenty-five seconds after the automatic initiation HPCI flow had reached 5310 sps at a discharge pressure of 1140 psig, 190 psig greater than reactor pressure. HPCI did not trip or isolate during any of the manual or automatic starts. Adequate margin was demonstrated on turbine speed peaks and oscillations of system variables. An extended run was performed in which system temperatures stabilized at acceptable levels and the gland seal system performed satisfactorily. All Level.1 and Level 2 criteria were satisfied except for the steam supply isolation' trip setpoint. During the extended Outage which started j in the Fall of 1985, engineering modifications were completed that were expected to correct the problems , experienced with the instrument sensing lines. Because of this modification, the EGR bypass line installation, and other modifications that were made to the HPCI Systes during the Outage, the Startup Tests were repeated for this system when the plant restarted in August of 1986. , i Dynamic Stability checks were again completed using 500 gpa step changes introduced in both manual and automatic flow control modes with the HPCI System operating in a closed loop to the CST. Level 2 criteria was exceeded when HPCI System flow had a measured decay ratio of 0.28 resulting from a I mid-flow speed decrease step change in the manual I
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Ptga'3 13-3 j mode. This is currently considered:to be acceptable-but will be examined closely in HPCI testing at. -) higher test conditions. j 1 During a HPCI automatic-initiation in the CST closed loop lineup, a HPCI System flow of 5000. gps was achieved in 21.2 seconds. Twenty-five seconds after-the automatic initiation occurred, HPCI flow was . 1 5003 sps at 1185 psig pump discharge pressure, 225 psig greater than the 960 psig reactor pressure. Data was also taken during this test to determine. the actual ~3005 value for the HPCI steam supply.line high flow isolation trip setpoint.--'However, the trip setpoints were not adjusted to these settings, but are being left at the current. trip setpoints : given in Technical Specifications.- The current. ~ isolation settings as specified in Technical- _ ) Specifications are considered acceptable as they are' . conservative yet provide ample margin to prevent- N
-spurious HPCI isolations.on system automatic !
initiations. All other Level 1 and 2 criteria were met. During retesting of HPCI in September ofL1986,-a. sluggish response was noted in the HPCI control valve. In an attempt to make the HPCI System more, responsive, it*was decided to replace.the EGR in the-hydraulic portion of the HPCI control.systemt As a result, the 1000 psig hot CST injection.was repeated to verify proper control system operation. HPCI was-successfully quick started and-HPCI discharge flow reached the 100-percent-rated value (5000 spa) in 21.0 seconds. Following the automatic. initiation,- HPCI flow leveled out at 5100 gpa with a discharge ~ 1 pressure of 1190 psig. The initial speed peak was. ) 2134 rps and the maximus peak was 4114.rps.? All 1 other Level 1 and Level 2 criteria were met. In June of 1987, following the February 1987 turbine rotor replacement (reference LER 87-006-00) and prior to-the scheduled Test Condition Three HPCI test sequence, tuning of the HPCI governor control system was performed. During this tuning, a RCIC turbine trip occurred on low suction pressure when the HPCI turbine was Quick Started. To prevent-recurrence, HPCI and RCIC suctions were aligned to different sources.
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Supplennt 6 .; Page 3 13-4 During the initial vessel injection attempt, the HPCI turbine underwent a total of five overspeed l trip / reset actions, violating Level 1 criteria, J prior to being secured. Two diagnostic CST to CST runs determined the overspeed conditions were minimum. flow related, and consequently, the second l vessel injection attempt was to provide an immediate j flowpath to the vessel by manually opening the l injection valve immediately following the Quick ! Start. The second vessel injection attempt was aborted when a logic problem caused the injection valve to cycle closed, creating a water hammer damaging the suction relief valve, suction pressure instrumentation and the flow transmitter. In addition, the RGSC was found to be defective. Following repairs to the suction relief valve and replacement /recalibration of the RGSC, suction and 1 flow instrumentation, retuning was performed. l Once the governor control system had been retuned, a third vessel injection attempt and dynamic stability checks were performed, this time successfully. Time to rated flow was 25.2 seconds, exceeding the Level 1 criteria of 25 seconds. The initial speed peak ' was 1096 rps and the maximum speed peak was at 3991 rpm. All speed and flow step changes exhibited acceptable decay ratios. At no time did the gland seal condenser system allow steam leakage to atmosphere. Following the required 72 hour cooldown period, a cold vessel injection attempt resulted in two . overspeed trip / reset actions, a Level 1 criteria ! violation. ; i Per GE recommendation, the control valve hydraulic l assist valve was fully closed and retuning was performed. After the retuning effort, another HPCI , vessel injection and dynamic stability checks were i performed, resulting in a time to rated flow of 22 3 seconds with initial and maximum speek peaks of 1222 and 4303 rps, respectively. This exceeded the Level 2 criteria for a maximum speed peak of 4200 rps. Several speed and flow steps at aid flow conditions failed to achieve Level 2 quarter damping criteria. 1 At no time did the gland seal condenser system allow l steam leakage to atmosphere. l I l
l Suppl;;;nt 6 , Pcge 3 13-5 1 l After the required 72 hour cooldown period, HPCI was Cold Quick Started to the vessel. Time to rated , flow was 27.5 seconds, exceeding the Level 1 criteria of 25 seconds. The initial and maximum speed peaks were 1095 and 4461 rpm, respectively. This exceeeded the Level 2 criteria of a maximum speed peak of 4200 rpm. At no time did the gland seal condenser system allow steam leakage to j atmosphere. The second Cold Quick Start to the vessel occurred 286 hours after the previous Cold Quick Start, far in excess of the required 72 hour cooldown period. Time to rated flow was 30.85 seconds, exceeding the , Technical Specification allowable value of 30 1 seconds and the Level 1 criteria of 25 seconds. The initial and maximum speed peaks were 2918 and 4328 rpm, respectively, exceeding Level 2 criteria for a maximum speed peak of- 4200 rpm. At no time did the gland seal condenser system allow steam leakage to atmosphere. . During a diagnostic test to investigate HPCI performance after a 24 hour cooldown period, the HPCI turbine tripped on overspeed. In order to further investigate HPCI performance, five dj- -**c HPCI CST to CST test runs were performed. At . .lt of this and other investigations, the HPCI tucuine control oil system was disassembled, cleaned, and inspected and the HPCI EGR was replaced. During the HPCI outage, the HPCI discharge check valve was changed from a lift check to a swing check in an attempt to improve closing times to mitigate suction piping overpressure { transients observed during HPCI turbine trips. ; Following HPCI operability checks, tuning was again , performed resulting in acceptable turbine ! performance. HPCI Quick Start performance was ! further improved by changing out the HPCI stop valve limit switches, reducing the delay to the RGSC ramp start. In October of 1987, the Test Condition Three HPCI Vessel Injection test sequence was reperformed in its entirety, beginning with the Hot Vessel Injection. Following a manual start to the vessel, dynamic stability checks were performed. Two of the average flow steps, 1 500 gpm at 2200-2700 gpm, did not meet
Supplca nt 6'
'Page 3 13-6 the Level 2 criteria for quarter damping. This condition was accepted because of the high degree of stability at higher. flow rates.
Following the manual start a Hot Quick Start to the vessel was performed, with rated flow occarring after 20.5 seconds. The maximum transient' speed : ', peak was 4117 rps. All other Level 1 and Level 2 criteria were met. Following a 91 hour cooldown, the first HPCI Cold Quick Start was performed, with rated flow occurring after 21.5 seconds. The maximum transient. speed
' peak was 4130 rps. .All other Level 1 and Level 2 criteria were met.
The final HPCI Cold Quick Start was performed following a 74 hour cooldown period. Thelmaximus-transient speed-peak was-4123 rps.and rated flow was obtained 21.4 secords after initiation. Approximately one ainute into the test, the HPCI turbine tripped on.High RPV Water Level (Level 8). Because'.of..the short duration of the test, Gland Seal System data could not be taken. -This Level 2-criteria violation was accepted based on acceptable Gland Seal System performance on all prior tests. The HPCI turbine trip on Level 8 was avoidable with! a more rapid feedwater turbine speed' adjustment and. was not the result of any HPCI System component malfunction and, therefore, was not considered to be a violation of the Level 1 criteria. All other-Level 1 and Level 2 criteria were satisfied. Following the completion of HPCI Vessel. Injection testing, the final Cold CST Quick Start test.was performed.to collect. baseline data for the-Operations Surveillance Testing Program. After a 72 hour cooldown period, HPCI was Quick Started to the CST, with rated flow occurring after 19 9 seconds. The maximum transient speed peak was 4148 rps and steady state flow stabilized at 5400 gpa with discharge pressure at 1260 psig. 4 As expected, the testing again proved that the HPCI l isolation at 300% steam flow is set low. The data indicates that the isolation should' occur at a-flow corresponding'to 800-820 inches of water. The trip units have a span of i 500 inches of water and are set for the Technical Specifications value of 395 inches of water. This condition is acceptable for-the interim, as adequate margin exists to both 1 W
Suppicesnt 6 Page 3 13-7 transient and steady state HPCI steam flows, but further engineering evaluations are in progress' concerning possible trip unit modifications and a Technical Specifications ' change, if increase of.the present setpoint is determined to be necessary. All other Level 1 and Level 2 criteria were satisfied. All HPCI testing at rated reactor pressure has been satisfactorily completed. The only HPCI testing remaining to be performed is the Hot and Cold CST Injections and stability checks to be performed at a reactor pressure of 150 psig. l I i i i l l l i i
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l Supp1 m nt 6 P:ga 3 14-1 3 14 Selected Process Temperatures i 3 14.1 Purpose i The purposes of this procedure are to establish the proper setting of the low speed limiter for the recirculation pumps to avoid coolant temperature stratification in the reactor pressure vessel bottom head region, to provide assurance that the measured ! bottom head drain temperature corresponds to bottom ) head coolant temperature during normal operations, { and to identify any reactor operating modes that cause temperature stratification. 3 14.2 criteria j l Level 1 The reactor recirculation pumps shall not be restarted nor flow increased unless the coolant j temperatures between the steam dome and bottom head drain are within 145 F. The recirculation pump in an idle loop must not be started, active loop flow must not be raised, and power must not be increased unless the idle loop suction temperature is within 50 F of the active loop suction temperature. If two pumps are idle, the loop suction temperature must be within 50 F of the steam dome temperature before pump startup. Level 2 During operation of two recirculation pumps at rated core flow, the bottom head temperature as measured by the bottom drain line thermocouple should be within 30 F of the recirculation loop temperatures. 3 14 3 Results For the initial testing conducted in 1985, the coolant temperatures measured at 30% Recirculation pump speed satisfied the Level 1 criteria. The instability of the recirc. speed controller that , occurred during this test precluded an effective , investigation of the stratification phenomenon at I low flows. The test also allowed setting of the low speed limiter based on flow controller variations j off % of rated speed. Flow controller variations 2 of ! 5% were experienced prior to stratification so the test was terminated.
SupplcIsnt 6 Paga 3 14-2 ! The minimum recirculation pump speed data collection was resumed in August, 1986 following completion of
.the preceding Outage. In subsequent heatup testing, the Recire MG Sets were hand cranked down to speeds of about 20%. The Level I criteria was satisfied at all times during this test.. The low speed limiter setting was chosen to be'285 speed based'on the ;
previously observed controller instability below I that level. l The remaining testing.in this section will be { completed at higher test conditions, including those l tests intended to verify the Level 2 criteria at rated core flow. . i l I 1
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l Suppls: Int 6 P ga 3 15-1 3 15 Systes Expansion 3 15.1 Purpose The purpose of this test is to verify that selected plant piping systems are free and unrestrained with regard to thermal expansion, and to verify that the thermal movement of the piping and associated support system components is consistent with the analytical prediction of the piping system stress analysis. 3 15.2 criteria Level 1 The measured displacements at the instrumented locations shall be within the greater of the specified allowable tolerance of the calculated values, or 2 0.25 inches for the specific points. There shall be no obstruction which will interfere with the expected thermal expansion of the piping system. Electrical cables shall be able to accommodate expected thermal expansion of the piping system. Instrumentation and branch piping can accommodate expected thermal expansion of the piping system. The constant hanger shall not be bottomed or topped out. The spring hanger shall not be bottomed or topped out. The snubber shall not be bottomed or topped out. a Level 2 l The measured displacements at the instrumented I locations should be within the greater of the specified expected tolerance of the calculated values, or 1 0.25 inches for the specific points. The installed cold position of the constant hanger. I must be within 1 5% of the design cold load. The installed cold position of the spring hanger , must be within i 5% of the design cold load. i l 1
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Suppls: nt 6- ; Pegn 3 15-2 ; The snubber may deviate'from its design cold position setting + 1/2", providing the position is not less than 1/28 from bottoming out. 3 15 3 nesults Piping' Inspection Results
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Selected piping systems were walked down at various' i plant conditions to identify possible restraints toL 1 projected thermal expansion. These walkdowns, , occured at ambient temperature,'2500F and rated -1 temperature. Hanger'and snubber settings were recorded and thermal expansion (PVDET) sensors were verified to be intact. No restraints to projected thermal expansion were identified. One-hundred and, forty-three (143) supports were identified as being out of tolerance. or topped or bottomed out. Following re-verification and engineering. evaluation, sixteen .
~(16) supports were adjusted or modified and the ;;
remainder accepted as is.
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q The East and West' Main Steam Bypass Lines were. 1 replaced during.the Outage which started'in'the Fall ,l of 1985, because of cracks which were discovered'in. " these lines. During subsequent testing following reactor restart in August,.1986 these lines'were visually inspected to verify that they were unrestrained with regards to projected thermal-expansion. These walkdowns occured at ambient temprature;andatrecirclooptemperaturesof. 350 and rated. No restraints to bypass line thermal expansion were identified. Five supports were found out of ! tolerance, and upon engineering evaluation were accepted as-is. Third thermal' cycle visual inspections and hanger readings were made on all system piping including the replaced Main Steam Bypass Lines.. There were no restraints to thermal expansion identified. Two-hundred-ninety-five (295) supports'were identified as not being within their proper working. range. Following engineering evaluation and reverification, eight (8): supports were reset and-the remaining supports accepted "as-is". W 4
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a l 1 Suppliment 6 1Prga 3 15-3 Systes' Expansion Results Selected points on the piping' systems were wired' with remote' sensors to monitor the thermally induced piping movements during system operation. The ,m monitored points were expected to' undergo large - novements,or. experience large thermal stresses. After establishing initial readings for the sensors at ambient conditions,Lthe sensors were monitored. during the~ initial ~heatup of the plant. -Data was .I 0 recorded at 50 F intervals until the reactor i reached operating temperature.: The evaluations ] found several criteria exceedances, but upon
' engineering evaluation of.the exceedances,.all were found acceptable.
In addition,. initial ambient sensor readings'taken before Heatup were compared to ambient sensor > readings after'a Heatup and-cooldown cycle was '\ \ completed. No appreciable difference in the before and after readings were noted, indicating' piping movement was not restrained. Thermal Expansion data was again taken at 50 F-- 0 intervals at moderator temperatures beginning at - - 1000 F during the subsequent heatup cycle following-initial heatup. The' data was evaluated at each- ' temperature plateau'before proceeding to the next level. Upon reaching rated temperature, four Level 2 criteria violations existed,'but these were very minor and accepted as-is. The East and West Main Steam Bypass Lines that.were replaced in the fall of 1985 were also monitored for expected thermal expansion during the subsequent l heatup after the Outage.- The heatup ar.d cooldown sensor' readings satisfied all Level 1~and Level 2 criteria except at the 350 F recirc loop temperature plateau. At that point there was one Level 2 failure which resulted.from inadequate heating of the bypass piping due to the bypass 1 valves being closed at the time the test was performed. .At higher temperatures data was.taken with the bypass valves open, and all criteria were satisfied. ( 1 I
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j , T' 9 .. % x I *- ./ Supplcment 6
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I-Pcg2 3 16 8
.a 3 16 Core Powq? Distribution NOTE: AA discussed in memorandus VP-86-0141, "Startup Test.
Program Changes", dated October 17, 1986, from Frank' E. Agosti to James G. Keppler, ittis our. intention to delete this test. \ ,,
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Supplement 6 Page 3 17-1 3 17 Core Performance 3 17.1 Purpose
- a. To evaluate the care thermal power.
- b. To evaluate the following core performance parameters:
- 1. Maximum linear heat generation rate (MLHGR)
- 2. Minimum critical power ratio (MCPR).
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3 Maximum average planar linear heat generation rate (MAPLHGR). 3 17.2 Criteria I Level 1 The maximum linear heat generation rate (MLHGR) during steady-state conditions shall not exceed the allowable heat flux as specified in the Technical Specifications. The steady-state minimum critical power ratio (MCPR) shall be maintained greater than, or equal to, the value specified in the Technical Specifications. The maximum average planar linear heat generacion rate (MAPLHGR) shall not exceed the limits given in the plant Technical Specifications. Steady-state reactor power shall be limited to full rated maximum values on or below the design flow I control line. ! Core flow should not exceed its rated value. Level 2 l None 3 17 3 Results BUCLE computer analysis of whole core TIP traces obtained at 15.6% reactor power showed that all criteria were met, during Test Conditien One. The Core Perforanance parameters during Test Condition Two were deter:i'ined using the Process Computer programs P1 (Periodic Core Evaluation) and
Supplc :nt 6 P ga 3 17-2 OD-3 (Core Thermal Power /APRM Calibration). All Level 1 criteria were satisfied upon the deter 51 nation and verification of the following parameters: Core Thermal Power (CHWT) Percent of Rated Core Thermal Power (PCT PWR) Core Flow (WT,' Maximum Linear Heat Generation Rate (MLHGR) Minimum Critical Power Ratio (MCPR) Maximum Average Planar Linear Heat Generation Rate (MAPLHGR) During Test Condition Three, the Process Computer ' programs (P1 and OD-3 Option 2) were again run to determine the above parameters: The Process Computer edits were utilized to determine that all requirements associated with the test were satisfied as follows: The Core Maximum Fraction of Limiting Power Density was 0.43 which satisfied the acceptance criteria that this value be less than or equal to 1.0. The Core Maximum Fraction of the Limiting Critical , Power Ratio was 0.44 which satisfies the acc3ptance ! criteria that this value be less than or equal to 1.0. The Core Maximum Average Planar Linear Heat i Generation Rate Ratio was 0.42 which satisfies the acceptance criteria that this value be less than or - equal to 1.0. l The rated maximum value for reactor power at 95 3% of rated core flow was determined to be is 96.5% of . rated Core Thermal Power based on the design flow I control line. The actual calculated CTP was 48.6% which was below the design flow control line. Measured core flow was 95 3% of rated core flow j which satisfies the criteria, that core flow does > not exceed its rated value. I _ _ _ _ _ _ _ A '
lSupplcO2nt'6 Pig 3 3 18-1 11
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- 3 18'stema Production This test was prevte,aaly deleted fros.the FSAR (Section 14.1.4.8.18).
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l . . Suppls= nt 6 Pzga 3 19-1 3 19 Core Power-Void Mode Response IKME: As discussed in memorandus'VP-86-0141, "Startup Test Program Changes", dated October 17, 1986, from Frank E. Agosti.to James G. Keppler, it is our intention to delete this test. l i 2 1 I i i c
l Suppitment 6 P:g3 3 20-1 3.20 Pressure. Regulator 3 20.1 Purpose. The purpose of this test is to: a.: Determine the optinua settings forlthe pressure control loop by analysis of the transients induced in the reactor pressure control system by means of the pressure regulators,
- b. To demonstrate the takeover capability of the-
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backup pressure regulator on failure of the' controlling pressure regulator and to set spacing between the setpoints at an appropriate' value,
- c. To demonstrate smooth pressure control transition between the control valves and bypass valves when the reactor generates more steam than is used by the turbine.
3 20.2 criteria Level 1 The decay ratio must be less than 1.0 for each-process variable that exhibits oscillatory response to pressure regulator changes. Level 2 In all tests the decay ratio must be less than or equal to 0.25 for each process variable.that exhibits oscillatory response to pressure regulator changes when the plant is operating above the lower limit setting of the master. flow controller. Pressure control deadband, delay, etc., shall be small enough for steady-state limit cycles, if any, to produce turbine steam flow variations no larger than 0.5 percent of rated flow. During the simulated failure of the controlling pressure regulator along the 100 percent rod line, the backup regulator shall control the transient so that the peak neutron flux or peak vessel pressure remainsbglowthescramsettingsby75percentand 10 lb/in. , respectively.
Supplcccnt 6 Page 3 20 ! After a pressure setpoint adjustment, the time between the setpoint change and the occurrence of j the pressure peak shall be 10 seconds or less. 1 (This applies to pressure setpoint changes made with j the recirculation system in the master or local i manual control mode.) l 3 20 3 Results , 1 Proper pressure regulator operation was demonstrated j in Test Condition One by analysis of system response j to step increases and decreases in pressure demand with the bypass valves open and generator not on the line. Additional steady-state measurements were i taken with the generator loaded and bypass valves I closed. All Level 1 and Level 2 criteria were met. f 1 The pressure setpoint changes on each regulator, I while significant in magnitude (11-13 psig), were 4 stable and well damped. As such no system tuning ! was performed in this test condition. l 4 The Regulator failure tests yielded significantly different responses (14 psig change for failure of
#1; 6 psig change for failure of #2). This discrepancy in response is likely attributable to differences in the time delay circuitry for each i channel in the High Value Gate and difference of 1 7 j psig in the sensed pressure being fed to each j regulator channel. The time delay component in the l regulator high value gates has since been removed. j The testing performed for the Pressure Regulator during Test Condition Two consisted of introducing 10 psig step change and simulated regulator failures in the Pressure Control System.
The Level 1 criteria for this test during Test Condition Two was satisfied when no process variables were found to be divergent and all decay I ratios were less than 1.0 during the 10 psig step l changes and simulated regulator failures. Steady-state steam flow variations were monitored by measuring generator electrical output limit cycling due to pressure controller operation. The Level 2 criteria requiring that these variations are no < 1arger than 1.0 percent peak-to-peak of rated flow was satisfied by analysis of the generator output which showed a maximum variation of 0.9 percent peak-to-peak of rated flow. _m__ m_____mm--_o
SuppleInt 6 Pzga 3 20-3' The'other Level 2 criteria associated with this_ test required that, after a pressure setpoint adjustment,- the time between the' change and the occurrence of the pressure peak shall be 10 seconds or less._ Analysis of this test's 10 psig steps showed peak pressures between 3.6 and 5.2 seconds, satisrying the criteria. Finally, the elimination of the time delay to backup regulator: takeover resulted in significant improvement over Test Condition One results'in response to both normal transfers and regulator failures. At no time did the bypass valves enter' their." FAST" mode and all transients were controlled and strongly damped. a
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l Supplcaent 6 i
~ Page 3 21-1 1 i
d 3 21 reedwater system- > 3 21.1 Purpose'
- a. To adjust'the feedwater control system for :j acceptable reactor water level control.
- b. To demonstrate stable reactor response to- a subcooling changes. l
.)
- c. 'To demonstrate the capability of the automatic'- l core flow runback feature to prevent low water- i level scram following.the trip of one feedwater -
pump.
- d. To demonstrate adequate response to feedwater heating loss.
- e. To determine the maximum feedwater runout capability.
3 21.2 criteria Level 1 The response of any level-related variable to any . test input change, or disturbance, must not diverge during the setpoint changes. For the feedwater temperature loss test, the marinus-feedwater temperature decrease due to a single failure case must be less than or_ equal to.100 0F. The resultant MCPR anst be greater than the fuel-thermal safety limit. For the feedwater temperature loss test, the increase in simulated heat flux cannot exceed the predicted Level 2 value by more than 2 percent. The-predicted value will be based on the actual test : values of feedwater temperature change and power' level. The feedwater flow runout. capability must not exceed the assumed value in the FSAR. Level 2 Level control systen-related variables may..contain oscillatory modes of response.- In these cases, the decay ratio for each controlled. node of response must be less than or equal ~to 0.25, as a result of
.the setpoint change testing. i 4 4 u_.__.______=_i_.______---i ______.__.-___=_-_L_.______-- _ . - _ . _ _ _ . . . . - - _.-__.____-.___.--.-_.-_--._--D~
I Supples;nt 6' pig 2 3 21-2 A scram must not occur from low water level following a trip of one of the operating feedwater pumps. There should be a greater than 3-in. water-level margin to scram for the.feedwater pump trip. i For the feedwater temperature loss test, the l increase in simulated heat flux cannot exceed the predicted value referenced to the actual feedwater temperature change and power level, which will be taken from the Transient Safety Analysis Design. Report. The average rate of response of the feedwater actuator to large (>20 percent of pump flow) step disturbances shall be between'10 to 25 percent of pump rated feetwater flow /sec.' This average response rate will be assessed by determining the time required to pass linearly through the 10 percent and 90 percent response points of the flow transient. l The dynamic flow response of each feedwater actuator (turbine or valve) to small (<10 percent) step disturbances shall'be the following: l a. Maximum time to 10 percent of a step disturbance l 11.1 sec.
- b. Maximum time from 10 to 90 percent of a step disturbance $1 9 sec.
- c. Peak overshoot (percentage of step disturbance) 115 percent.
3 21 3 Results During the initial heatup, the feedwater system performed satisfactorily in both the manual and automatic modes. All level-related variables did not diverge during testing and all system related variables did not exceed a 0.25 decay ratio for their oscillatory responses in the level setpoint changes. All applicable test criteria were satisfied. q i During Test Condition One, as previously done during i the heatup testing, the Startup 1.evel Controller- I setpoint was adjusted to simulate step changes of~ three inches for Reactor water level. During the setpoint increase water level increased in a smooth
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i i
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C__________ _ _
Suppl ment 6' P g3 3 21-3 manner with little overshoot and stabilized within 75 seconds. During the setpoint decrease water level decreased and overshot the three inch down-step by 2 to 3 additional inches. This overshoot dampened rapidly and water level stabilized within 110 seconds. The Test Condition One test was completed satisfactorily. The criteria that the decay ratio of level control system-related variables being less than .25 was met for all portions of this test. During Test Condition Two, feedwater system testing was limited to single element master level controller step changes due to equipment problems with the Dynanic Compensator Lead / Lag Network Computation Module. The dynamic flow response of the Reactor feed pump turbines was not able to be checked because the flow to the Reactor was insufficient to allow automatic level control with two pumps operating with both minimum flow bypass valves shut. Both minimum flow bypass valves are required to be closed to adequately measure the flow response of the feedwater actuators to step inpats. Feedwater system response to five inch Reactor level changes using setpoint tapef manipulations in single element automatic control were smooth and controlled. All applicable acceptance criteria were met for the conditions tested. In Test Condition Three, at a reactor power of 48%, testing was conducted in both One Element.and Three Element modes, with each feedpump feeding the vessel and the other in standby. This satisfied the above noted Test Condition Two testing that could not be completed earlier due to the inoperative Dynamic Computation module. Both SRFPT Control Systems (System #1 and System #2) ! were tuned and i 10% speed demand steps with the , pump in the recirculation mode were performed. 1 After the completion of SRFPT Speed Control System i testing, the NRFP was then placed in standby after ; the SRFP was placed into service feeding the l vessel. Level setpoint tape changes of up to i 5 ; inches were performed in both One Element and Three Element modes. Once proper Level Control System i response was verified, the t 5 inch level setpoint I adjustment ramps were performed in both One and Three Element modes.
Supplatint 6 Prge 3 21-4 Following completion of SRFP: testing, both'of.the
.NRFPT Speed Control Systems were tuned and tested, again with the pump'in the recirculation mode. Once.
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the NRFP was placed in service feeding the vessel, level'setpoint' change testing was performed in the same manner as the SRFP.
-The STARTREC traces for both One and Three Element Control mode _were' analyzed for quarter dampe<F .
respnnse. The following signals were_ deemed to be Level Control System-related: Feedwater Control Function Generator Output'- NRFP Feedwater Control Function Generator Output - SRFP Master Feedwater Controller Output North Reactor Feed Pump Flow South Reactor Feed Pump Flow North RFPT Speed-South RFPT Speed
'All of the above signals showed quarter damped (0.25) response to ! 5 inch level setpoint changes which satisfies the Level I criteria of non-divergence and the Level 2 criteria of decay ratio.
The balance of the planned Test' Condition Three Feedwater System testing sust.be performed at greater than 505 reactor power. 4
'A.
Supple a t 6 P;g3 3 22-1 s 3 22 Turbine valve Surveillance
.i 3 22.1 Purpose j
-l To demonstrate acceptable procedures and maximum power levels for surveillance testing of the main ;
turbine control and stop valves without producing a i reactor scram. 3 22.2 criteria Level 1 None Level 2 Peak neutron flux must be at least 7.5 percent below the scram trip setting. remainatleast10lb/in.geakvesselpressuremust below the high-pressure scram setting. Peak heat flux must remain at least 5.0 percent below its scram trip point. Peak steam flow in the high-flow lines must remain 10 percent below the high-flow isolation trip settings. 3 22 3 Results' The Turbine Valve Surveillance test has not been completed to date. - _ . _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - - _ _ _ _ m _ m.__ _ ___
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il Supplc= nt 6 Page 3 23-1 3 23 Main steam Isolation valves 3 23 1 Purpose
- a. To check functionally the r.ain steam line isolation valves (MSIVs) for proper operation at selected power levels.
- b. To determine reactor transient behavior during and after simultaneous full closure of all MSIVs.
- c. To determine isolation valve closure time.
3232 criteria Level 1 l The MSIV stroke time (ts) shall be no faster than 3 0 seconds (average of the fastest valve in each steamline) and for any individual valve 2.5 seconds 5t3 55 seconds. Total effective closure time for any individual MSIV shall be t ol 3 plus the maximum instrumentation delay time and shall be 15.5 seconds. The positive change in vessel done pressure-occurring within 30 seconds after the simultaneous full closure of all MSIVs must not exceed the Level 2 criteria by more than 25 psi. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2 percent of rated value. . Flooding of the main steam lines shall not occur following the full MSIV closure test. The reactor must scram during the full simultaneous MSIV closure test to limit the severity of the neutron flux and simulated fuel surface heat flux ) transient. ' Level 2 During full closure of individual valves, peak vessel pressure must be at least 10 psi below scram, peak neutron flux must be at least 7.5 percent below scram, and steam flow in indivic'ual lines must be at , least 10 percent below isolation trip setting. The peak heat flux aust be at least 5 percent less than its trip point. The reactor shall not scram or isolate as a result of individual valve testing. s l
Suppl:2:nt 6 P2g3 3 23-2 The relief valves must reclose properly (without leakage) following the pressure transient resulting from the simultaneous MSIV full closure. The positive change in vessel done pressure and simulated heat flux occurring within the first 30 seconds after the closure of all MSIV valves _must not exceed the predicted values in the Transient Safety Analysis Design Report. Predicted values will be referenced to actual test' conditions of initial power level and done pressure and will use beginning of life nuclear data. The predicted values will be corrected for the appropriate measured parameters. After the full MSIV closure, the initial action ~of the RCIC and HPCI shall be automatic if L2 is reached, with RCIC capable of establishing an average pump discharge flow equal to or greater than 600 gpm within the first 50 seconds after automatic initiation and HPCI capable of. establishing an average pump discharge flow equal to or greater than 5000 gpm within the first 25 seconds after automatic. initiation. If the low-low set pressure relief logic functions after,the simultaneous full MSIV closure-test, the open/close actions of the SRVs shall occur within
+20 psi of the low-low set design setpoints. The total number of_ opening cycles, for the safety / relief valves opening on low-low setpoint, after initial blowdown is not to exceed four times during the initial 5 minutes following isolation.
If any safety relief valves open as a result of this test, only one valve may reopen after the first blowdown.- Recirculation pump trip shall be initiated if L2 is reached after the MSIV full closure test. 3 23 3 Results During the Heatup Test Condition, with the RPV at rated temperature and pressure conditions, each of the inboard and outboard isolation valves were successfully closed slowly to the approximately 90% open position and then fully reopened, without_any noticeable change in reactor pressure, APRM readings or reactor water level. l
Supp11 ment 6' 1 Page 3 23 3 J In Test Condition One, with the Reactor at 7% power, . a fast full closure of each individual MSIV was performed. All applicable Level 1 and Level 2 criteria were met. The closure times are shown in the table below, using a calculated maximus instrument delay time of 0.299 seconds. j l Test Condition One# 1 I I l I l MSIV l ts I tsol l Total I. l l l l l l F022A l 4.298 l 4.611 1 4.910 l
, i F022B l 3 505 l 3 703 1 4.002 l l F022C I 4.798 l 4.904 1 5.203 l l-F022D I 3 205 l 3 301 l 3.600 l l F028A l 4.294 l 4.387 1 4.686 I l F028B i 3.809 1 3.839 I 4.138 l l F028C I 3.617 1 3.899 1 4.198 l l F028D l 4.057 I 4.226 1 4.525 l-
- All recorded times are measured in seconds.
The remaining Level 1 and Level 2 criteria are associated with the MSIV simultaneous full closure and will not be verified until that test is performed during a higher test condition. l
- c, i'
Supplcs;nt 6
. Page 3 24-1 3 24 Roller valves ,
3 24.1 Purpose The purposes of this test are to verify that the. Safety Relief Valves (SRV) function properly (can be-opened and closed manually), reset properly after operation, and that there are no major blockages in the relief valve discharge piping. 3 24.2 criteria Level 1 There should be a positive indication of steam discharge during the manual actuation of each valve. Level 2 Variables related to'the pressure control,systen may-contain oscillatory modes of response. In these cases, the decay ratio'for each controlled mode of response must be less than or equal to 0.25. The temperature seasured by thermocouple on the , discharge side of.the valves shall. return to within 10 F of the temperature recorded before the valve was opened. If pressure. sensors are available, they. shall' return to their initial state'upon valve closure. During the 250 psig functional test, the steam flow through each relief valve'as seasured by the initial and final bypass valve.(BPV) position shall'not differ by more than 10 percent from the average-relief valve steam flow as seasured by bypass _ valve pos'. bion. During the rated pressure test, the steam flow through each relief valve as seasured by change in 1 MW(e) is not to differ by aore than 0.5 percent of rated MW(e) from the average of all the valve responses. 3 24.3 Results During.the heatup testing, all 15 SRVs were manually ' actuated. There was positive indication of steaa I discharge upon actuation of each SRV. . As each SRV was operated there was a sudden temperature rise on the SRV discharge tailpipe, the appropriate pressure q l
Suphiccnt 6 Page.3 24-2; su'itsh responded, and.BPV position decreased to. ] control reactor pressure. The Level I criteria was ( satisfied. J All. pertinent. variables related to pressure control-did not exhibit any oscillatory responses with decay- ~' ratios greater than 0.25... - The SRV discharge line temperat'ures for,five SRVs- d
-did not return to within 100 F of.the temperature recorded prior to actuation'as'quickly as the other discharge lines; however, they did cool down-sufficiently to indicate that the SRVs were not-leaking. . Shortly after the performance of this test a reactor scram occurred and on'the subsequent startup, the SRV tailpipe-temperatures remained low, further verifying that the SRVs did properly reclose.
Three SRVs had steam flow values, as neasured by BPV; position change, that differed from the average relief valve steam flow by greater than 10%. .The bypass valve position was inadequate to get a proper value of steam flow from BPV position change. 'Upon-the actuation of each SRV the BPV closed completely. Had there been more bypass steam flow, the BPV would not have closed completely and there would be a more accurate velue of SRV steam flow. This steam flow variance was reevaluated-during the Test Condition Two SRV testing. All fifteen SRVs were manually. actuated with the plant at rated pressure during Test Condition Two.. Plant parameters related to pressure control were monitored on the GETARS computer,'as well as.other. plant parameter responses, including generator load decreases. The Level 1 criteria was met based on three positive indications of steam discharge during the. actuation of each valve. They were the sudden temperature rise in the discharge tailpipe, the positive ~ indication of a MWe decrease during the valve actuations, and the response from the tailpipe . pressure sensor of each valve being tested. 1 The Level 2 criteria requiring that Pressure Control. Systen variables did not exhibit any oscillatory i responses with decay ratios greater than 0.25, was
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_ _ _ --___----_-__ _ _ .__ _ _ _ _ _ . . _ - . . _ _- d
Supplt= nt 6 Page 3 24-3 verified by the analysis of the GETARS data of the I following variables: j Pressure Regulator Output Control Valve Demand ) Control Valve #1 Position j Narrow Range Pressure 3 Generator Output (Gross We) ] GETARS data was also used to verify that'the change in the plant's W e following each SRV lift did not differ by aore- than 0.5% of the rated We from the average of all valves responses. All SRVs exhibited. a less than 5 5 We variation from the 68.5 We average variation, thus satisfying the Level 2 criteria. SRVs B21-F013J 0 and B21-F013M did not return to within 10 F of their initial tailpipe temperature values during the test. However, the temperatures did return to within 100 F of their initial values when checked at a later time, thus satisfying a Level 2 criteria. Finally, part of the Licensing Commitment 2.c.5 of the full power operating license was satisfied by this Test Condition Two relief valve test. It was demonstrated that all adjacent temperature readings were within 45 F of each other following a 10 second SRV lift with a suppression pool aixing system in operation. This concludes the relief valve testing to be performed during the Startup Test Phase Prograa. 1 1 s i
. i Supplcc;nt 6 Page 3 25-1
- 3 25 Turbine stop valve and control valve Past closure Trips 3 25.1 Purpose The purpose of this test is to demonstrate the response of the reactor and its control systems to protective trips in the turbine and generator..
3 25.2 criteria Level 1 For turbine / generator trips, there should be a delay of no more than 0.1 seconds following the beginning of control or stop valve closure before the beginning of bypass valve opening. The bypass valves should be opened to a point corresponding to greater than or equal to 80 percent of their capacity within 0 3 seconds from the beginning of control or stop valve closure motion. ; Flooding of the main steam lines shall not occur following the turbine / generator trips. The positive change in vessel done pressure occurring within 30 seconds after either generator or turbine trip must not exceed the Level 2 criteria ! by more than 25 psi. The positive change in simulated heat flux shall not exceed the Level 2 criteria by more than 2 percent of rated value. Level 2 There shall be no MSIV closure in the first 3 minutes of the transient, and operator action shall 1 not be required in that period to avoid the MSIV trip. The positive change in vessel done pressure and in simulated heat flux that occur within the first 30 seconds after the initiation of either generator or l turbine trip must not exceed the predicted values in ( the Transient Safety Analysis Design Report. For the turbine / generator trip within the bypass valves capacity, the reactor shall not scram for initial thermal power values less than or equal to 25 percent of rated. ; t ww__w__~__ _ - _ - - _ - _ _ _ _ . _ _ - - - ___. - .
)
'I i Supplssent'6 l Page 3 25-2 >
If the low-low set pressure relier logic functions,- ., the open/close actions of the SRVs shall occur ! within i 20 psi of their design setpoints. If any. ]
.' safety relief valves open,.only,one valve.say reopen .i after the first blowdown.
3 25 3= nasults During the Test Condition Two testing with a reactor- l power of 21.8%, a turbine / generator trip was : 1 initiated with a generator output of 151 MWe, by ) opening both generator output breakers CN and CF. A reactor scran did not occur following the-tubine/ generator trip with the reactor at 21.8% D
. power. This.is required at_a reactor power.< 255, therefore, satisfying the Level 2 criteria.
The East and West bypass valves began opening within'. 0.04 seconds and 0.06 seconds, respectively, following;the beginning of the control and stop valve' closure. This satisfied the'< - 0.1 second opening time required for the Level 1 criteria. i The Level 1 criteria.(applicable to Test Condition-Six) requiring that the bypass valves.open to a-point corresponding to > 80% of their capacity , within 0 3 seconds from the beginning of the control and stop valves closure actions.was not satisfied during the Test Condition Two' testing.- Thel valves only opened to 56 3% of their. combined capacity at: 0 3 seconds with the West Bypass' Valve open 99.8%, and the East Bypass Valve open 12.75. ' Repairs and off-line response time' testing of the East' Bypass Valve Unitized Actuator'were performed successfully_ during the MSR outage, and the effects of stesit flow on bypass valve response time will beLfurther-evaluated during the generator load rejection test in Test Condition'Six. l
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Suppisc:nt 6 Pcg3 3 26-1 3 26 Shutdown from Outside the Control Room 3 26.1 Purpose To demonstrate that the reactor can be brought from a normal, initial, steady-state power level to the hot shutdown condition and to verify that the plant has the potential for being safely cooled from hot' shutdown to' cold shutdown conditions from outside the control room. 3 26.2 criteria Level 1 None Level 2 During the cold shutdown demonstration, the reactor must be brought to the point where cooldown is initiated and under control. During the simulated control room evacuation and hot shatdown demonstration, the reactor vessel pressure and water level are controlled using equipment and controls outside the control room. 3 26 3 Results During the simulated control room evacuation and hot shutdown test performed during Test Condition One,- the designated Shutdown Crew, consisting of the minimum shift complement, performed all activities associated with the reactor shutdown and control of the reactor vessel water level and pressure from. outside the Control Room. The reactor vessel pressure and water level were controlled for a period of over thirty minutes following successful reactor shutdown and isolation from outside the Control Room by the miniaua shift complement, which successfully meets all test criteria and performance objectives of the applicable governing documents.
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Supp11 Int 6 Psgs 3 26-2 The test sequence of events was as follows: Time Event 1223 Test Start Time (H1 Coma Announcement) 1224 " Shutdown Crew" Evacuation of Control Room
)
1224 APRMs A&B to Standby..(to initiate Reactor > Scram) i 1224 Relay TTR-2 manually tripped (to initiate ! Main Turbine Trip) 1225 -Main Steam Line. Radiation Monitors to Standby (to initiate MSIV Isolation) 1226 Restoration of APRMs A&B and the Main Steam Line Radiation Monitors to the Operate positions 1226 Exit Relay Room 1228 Transfer Switches operated at Remote Shutdown Panel (RSP) (RSP Control). 1230 RHRSW started at Remote Shutdown Panel (RHR Service Water Pumps A&C) . 1233 RHR Pump A started at Remote Shutdown Panel 1233 Div II Transfer Switch operated (Div II D.C. ESF Power) 1234 RCIC initiated from Remote Shutdown Panel 1235 RCIC at rated flow (600 gpm) 1237 "A" SRV cycled from Remote Shutdown Panel (Open for approximately seven seconds) 1238 "B" SRV cycled from Remote Shutdown Panel (Open for approximately nine seconds) 1239 Start or Stable Control Period in Hot Shutdown 1313 Completion of Stable Control Period in Hot Shutdown 1 ____-___________-_.__.____m_ ____________ -_ _.__ _ _ _ _ _ _ _ _ _ _ _ _ _ -_ - _ _ . . . _ _ _ _ . . _ _ _ _ _ _ ___m- _- __
.SupplccInt 6 Pcga 3 26-3 Time Event 1313 Transfer Switches operated (RSP Transfer'to Control Room Control) 1313 Test Termination The remaining testing within this section, involving a demonstration of the plant's capability to reach cold' shutdown conditions from outside the control room, is scheduled to be performed in Test Condition Six.
_______m_.__..__..._ -
l i l Suppl e:nt 6 P0g's 3 27-1 ] 1 1 3 27 Flow Control 3 27.1 Purpose i
- a. To determine the correct gain settings for the individual recirculation controllers. 4 i
- b. To demonstrate plant response to changes in j recirculation flow in both local manual and master manual mode,
- c. To set the limits of range of operation for the recirculation pumps.
3 27.2 Criteria i Level 1 The transient response of any variable related to the recirculation system to any test input must not diverge. Level 2 The decay ratio of the speed loop response shall be
<0.25 at any speed.
Flow control system limit cycles (if any) must produce a turbine steam flow variation no larger than 10 5 percent of the rated steam flow value. I The APRM neutron flux trip avoidance margin shall be 37 5 percent, and the heat flux trip avoidance f margin shall be 25.0 percent as a result of the ! recirculation flow control maneuvers. ] 3 27 3 Results In Test Condition Two, 1 4% step change testing was performed on both recirculation system speed control l loops in the local manual mode at 38.8% Reactor ! power and 47.5% core flow. A review of the data recorded indicates no variables related to the recirculation system were divergent. A qualitative review of the speed response of the ! A Reactor Recirculation MG Set verified that the decay ratio was < 0.25 for the i 4% speed steps performed. t j
Supplsment 6L
'Page 3 27-2 The B Reactor Recirculation MG Set exhibited a limit cycle of approximately 2 1/25 speed peak-to-peak.
when operating at 38% speed. Due to this limit cycle, the "B" speed loop response Decay. Ratio could not be verified and will be retested when controller optimization is performed in. Test Condition Three. Flow control systes limit cycles were verified and the peak-to-peak change in gross generator output during steady-state conditions was less than 1 0.5% of rated generator output or 11.5 MWe peak-to-peak. This criteria was satisfied with the largest observed generator output limit cycle of 10.55 MWe peak-to-peak (1.46% of rated output). The peak APRM neutron flux was 57.715 This APRM reading includes an APRM gain adjustment factor of 1.25 which was required due to a high core peaking factor.- The calculeted APRM neutron flux trip-avoidance margin was 60.29, satisfying the 3 7.5% criteria. The minimum heat flux trip avoidance margin lwas 22 39% for the increasing speed steps, satisfying the criteria of 2 5.05. During Test Condition Three, following a core flow calibration at approximately 50% power, the mechanical and electrical stops on the reactor recirculation pumps NG Set scoop tube positioners were set to limit the upper range of. operation of the recirculation pumps. These values are as follows: Equivalent rps / Core Flow MG Set A Mechanical Stop 850 / 102.5% MG Set B Hechanical Stop 868 / 102.5% MG Set A Electrical Stop 840 / 101% MG Set B Electrical Stop 855 / 100 7%-
Supples nt 6 Page 3 26-1 3 28 Recirculation System 3 28.1 Purpose
- a. To' verify that the feedwater control system can satisfactorily control the water level without a resulting turbine trip / scram and obtain actual pump speed / flow.
- b. To verify recirculation pump startup under pressurized reactor conditfens.
- c. To obtain recirculation system performance data.
- d. To verify that no recirculation system cavitation occurs in the operable region of the power-flow map.
3.28.2 criteria Level 1 The response of any level-related variables during pump trips must not diverge. Level 2 The simulated heat flux margin to avoid a scram shall be greater than or equal to 5.0 percent during the one pump trip recovery. The s'PRM margin to avoid a scram shall be greater than or equal to 7.5 percent during the one pump trip recovery. During the noncavitation verification, runback logic shall have settings adequate to prevent operation in areas of potential cavitation. During the one pump trip, the reactor water level aargin to avoid a high-level trip (L8) shall be greater than or equal to 3 0 inches. l 3 28 3 Results During Test Condition Two, recirculation system baseline performance data was recorded at 38.8% reactor power and 47.5% core flow and at 48% reactor power and 55.7% core flow.
Supplement 6 Page 3 28-2 Baseline Recirculation System Performance data at Test Condition Three power - flow conditions was tollected at 47% power and 100% core flow. Also during Test Condition Three, a test was run to verify that the recirculation pump runback limits are sufficient as to prevent operation where recirculation pump or jet pump cavitation is predicted to occur. The test was conducted by establishing total core flow at 905 (+ 35) of rated at a reactor power of 44.25 Both Recirculation MG Set Scoop Tubes were locked and while reducing reactor power by the insertion of control rods, jet pump dp, recirculation pump vibration, drive flow, pump delta pressure, and pump suction temperatures were continuously monitored for indications of pump cavitation. Throughout the power reduction to the actuation of Limiter #1 at 23 6% of rated feedwater flow and 27.4% of rated reactor power, no indications of pump cavitation were observed. Reactor power was further reduced to 21.7% rated } feedwater flow and 25 3% of reactor power at which point the power reduction was stopped due to indication of an increasing width of the recording of reactor core delta P which could be an early indication of cavitation. Therefore, it may be concluded that the runback logic settings are conservatively adjusted such that operation in areas of potential cavitation is prevented and that the Level 2 criteria has been satisfactorily met. l 1
Supplement 6 Page 3 29-1 3 29 Loss of Turbine-Generator and Offsite Power 3 29.1 Purpose
- a. To determine the reactor transient performance during the loss of the main generator and all offsite power.
- b. To demonstrate acceptable performance of the station electrical supply system.
3 29.2 Criteria Level 1 The reactor protection system, the diesel-generator, RCIC and HPCI must function properly without manual assistance. HPCI and/or RCIC system action, if necessary, shall keep the reactor water level above the initiation level of low-pressure core spray, LPCI, and automatic depressurization systems. Level 2 i If the low-low set pressure relier logic functions, the open/close actions of the SRVs shall occur within +20 psi of their design setpoints. If any safety relief valves open, only one may reopen after , the first blowdown. 3 29.3 Results The test was initiated during Test Condition Two by isolating the plant from off-site power by simultaneously opening both the 345 KV and 13 2 KV feeds to the in-plant busses. It was demonstrated that the following actions occurred once the test was initiated without any operator assistance:
- 1. The Reactor Protection System automatically scrammed the reactor.
- 2. The Turbine / Generator Protection System automatically initiated a trip and fast closure of the Main Turbine steam admission valses.
3 The Emergency Diesel Generators automatically ; started and properly loaded the ESF bussss, and ' l 6
Suppl;;:nt 6 Page 3 29-2
- 4. Control of reactor water level and pressure during transient conditions were maintained.
It was also demonstrated that the required equipment and support systems operated satisfactorily without dependence on off-site power sources for the extended test duration of 30 minutes. No automatic initiation signal /setpoint was received for either HPCI or RCIC. The lowest reactor water level reached during the test was 138.8 inches. The Level 1 setpoint of 31.8 inches,. at which Core Spray, LPCI and ADS are initiated, was therefore avoided by a significant margin. Based on the above, the Level 1 criteria for this test was successfully met. Following the first blowdown, only SRV B21-F013A reopened. This satisfies the Level 2 criteria requirement that specifies only one SRV may open at that time. The low-low set pressure relief function for two low-low set valves, SRV "A" and SRV "G" was actuated during the test. On increasing reactor pressure, six SRVs lifted at a pressure of 1100.1 psi. These actuations were in accordance with the Level 2 criteria required for this test. This concludes all Loss of Turbine / Generator and Off-Site Power testing during the Startup Test Phase program. 1 l i l l -___ _ _ _ _J
Suppl;::nt 6 Page 3 30-1 3 30 steady-State vibration 3 30.1 Purpose To determine the vibration characteristics of the primary pressure boundary piping (NSSS) and ESF (ECCS) piping systems for vibrations induced by recirculation flows, hot two-phase forces, and hot hydrodynamic tranutents; and to demonstrate that - flow-induced vibrations, similar in nature to those expected during normal and abnormal operation, will not cause damage and excessive pipe movement and vibration. 3 30.2 Criteria Level 1 The measured vibration levels of the piping shall-not exceed the acceptable specified values. Level 2 The measured vibration lev 91s of the piping must not exceed the expected speci?!ed values. 3 30 3 Results During Test Condition One, the RCIC Steam Supply Line inside the drywell and the RCIC Pump Discharge Line near its connection to the Feedwater Line were monitored for vibration using installed sensors during a vessel injection at rated conditions. Evaluation of the data showed that all vibration levels were within acceptable values. During Test Condition Two, steady state vibration was measured for selected piping systems at 25% (1
- 55) of rated steam flow and at 50% (+ 55) of rated core flow. Data was initially gathered for reven piping systems consisting of Feedwater, Main Steam, Reactor Recirculation, RHR, SRVs D&J, HPCI and RCIC. More data was collected at a later date for eight locations on the Main Steam piping and one location on the RCIC piping at 25% and 29% rated steam flow.
This extra testing was necessary because the Level 1 criterion for six of these locations were exceeded in the initial set of data. Also, more data was . needed to determine the impact of the removal of ! 1 i 1 I
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Supplrn nt 6 Page 3 30-2 snubbers from piping between the Turbine Control ] Valves and the High Pressure Turbine. J i A total of eight Level 1 criterions for instruments D-015, D-016, D-017, A-014, Ar015, and A-016, were exceeded in this second set of data. However, based on hand held vibration measurements and/or detailed ; pipe stress analysis by Sargent and Lundy, all i criteria violations were found acceptable. ) Revised criteria' levels for selected sensor l locations were incorporated into future test plans. j During Test Condition Three, vibration data was collected to determine the flow induced vibration responses of the Main Steam Lines, Reactor Recirculation Loops, Feedwater, HPCI, RCIC, RHR and j Safety Relief Valve piping during steady-state ' vibration hardwired testing. Steady-state vibration data was obtained and analyzed for 80 (! 5)% and 100 (+ 5)% of rated core flow. Post transient 4 steady-state data was also obtained following the l HPCI RPV injection for HPCI piping sensors. There was a total of two (2) exceedences to the Level 1 criteria as follows during the 80% core flow data collection: Level 1 Measurement Sensor mils p-p mils p-p , A-014 10 11 3 A-015 14 49.6 l For sensors A-014 and A-015, it was determined that j l their readings were unreliable, and that vibration for this area of piping is acceptable based on the readings of sensors D-009, D-010 and D-011. There was one exceedence to the Level 2 criteria during the 100$ Core Flow data collection. l 1 Level 2 Measurement l Sensor inch p-p inch pg j SA-RZ 0.024 0.027 The Level 2 criteria exceedence for sensor SA-RZ was evaluated and considered to be acceptable. Review of the same sensor data at 25% steam flow and 50% core flow showed satisfactory peak-to-peak amplitude.
Supplsatnt 6 i Page 3 30-3' Post' transient' steady-state data following the NPCI' RPV. injection was analyzed and found acceptable; i however, this data collection was repeated due to , the subsequent replacement of E41-F005, HPCI :) Discharge Check Valve.- Results from this additional-data collection during a HPCI RPV-Injection in October of 1987.were also acceptable. l - l q l l l i 4 I s,
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Supple nt 6 Paga 3 31-1 3 31 Recirculation System Flow Calibration 3 31.1 Purpose To perform a complete calibration of the installed recirculation system flow instrumentation. 3 31.2 criteria Level 1 None Level 2 Jet pump flow instrumentation is adjusted so that the jet pump total flow recorder provides a correct core flow indication at rated conditions. The APRM/RBM flow-bias instrumentation is adjusted to function properly at rated, conditions. The flow control system shall be adjusted to limit maximum core flow to 102.5 percent of rated flow by limiting MG set scoop tube position. 3 31 3 Results Daring Test Condition Three at a reactor power of 455, a total core flow calibration was performed using Reactor Engineering procedure 56.000.02. This was the first core flow calibration performed and therefore, approximately 5% margin was established between rated and indicated core flow. During the initial run, the jet pump milli-volt readings were found to be varying making it difficult to obtain accurate readings. Several readings were taken at each square rooter. The highest and lowest readings were averaged together and the average value was recorded. The Reactor Engineering procedure required that the jet pump square rooter output be within .25 aa of the l expected output based upon measured input. This requirement was not initially met. The Reactor Engineering in-house code calculated a total core flow of 97.7%. This value compared well against the General Electric code, JRPUMP, (which calculated core flow to be 97.6%). This is a very good agreement since the Reactor Engineering code used jet pump instrument span from I&C calibration sheets, while JRPUMP used the design instrument span
Supplt2:nt 6 P:g2 3 31-2 of 10-50 ma. An RC network was developed to filter the jet pump milli-volt' readings and the Reactor En61neering procedure was run a second time. Milli-volt readings were taken simultaneously from the input and output Jacks of the square root extractors. This method enabled us to meet the requirement that the output of the square root be within .25 na of the expected output. The filter helped, but did not prevent, the oscillations in the milli-volt readings. The Reactor Engineering procedure was run a third time using a different filter with a 4-5 second time constant. The milli-volt readings were still unstable but average values were recorded. Core flow was calculated to be 100.0% by the Reactor Engineering code, while JRPUMP calculated core flow to be 99.8%. The flow calibration was completed by adjusting B21-602 A, B and B31-607 A, B, C, D summers, which satisfies the Level 2 criteria for the adjustment of instrumentation providing core flow indication and APRM/RBM flow-bias. The recirculation system was placed in MASTER MANUAL. Speed and flow data was collected while flow was decreased from 100% to 80%. Flow vs speed data was plotted for this range. This data was extrapolated out to 102.5% core flow to obtain the corresponding speed. Flow was increased to 95%. The recirculation system was placed in the LOCAL MANUAL mode. MG Set "A" speed was increased to 850 rpm (equivalent to 102.5% flow). The mechanical stop was set at this speed. The electrical stop was set 6/64" before the mechanical stop based upon the scoop tube positioner. This position is at 840 rpm (equivalent to 101% flow). The mechanical and electrical stops were set in a similar manner on MG Set "B". MG Set "A" speed was reduced and MG Set "B" was increased. The mechanical stop was set at 868 rps (equivalent to 102.5% flow). The electrical stop was set at 855 rps (equivalent to 100.7% flow). This is 14/64" before the mechanical stop based upon the scoop tube positioner. This ! satisfies the Level 2 criteria of limiting the i maximum core flow to 102.5% of rated by limiting the MG Set Scoop Tube positions. Another core flow calibration will be performed at higher power conditions and the unstable jet pump . milli-volt readings will be further addressed. ) l l i j l 1
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l l Supplc::nt 6 { P:ge 3 32-1 l i 3 32 Reactor Water Cleanup System 3 32.1 Purpose The purpose of this test is to demonstrate specific aspects of the mechanical operability of the reactor water cleanup system. 3 32.2 criteria Level 1 None Level 2 The temperature at the tube side outlet of the non-regenerative heat exchangers (NRHX) shall not exceed 1300 F in the blowdown mode and shall not exceed 120 F in the normal mode. The cooling water supplied to the non-regenerative heat exchangers shall be less than 6 percent above the flow corresponding to the heat exchangers capacity (as determined from the process diagram) and the existing temperature differential across the heat exchangers. The outlet temperature shall not , exceed 1800F. The bottom head flow indicator will be recalibrates against the RWCU flow indicator if the deviation is greater than 25 gpm. The pump available NPSH is 13 feet or greater during ' the hot shutdown with loss of RPV recirculation pumps mode defined in the process diagrams. 3 32 3 Results l During the Heatup test condition, the RWCU system l was placed in a configuration so that flow was taken l from the bottom drain and directly fed back to the l vessel, bypassing the demineralizers. In this configuration G33-610, bottom drain flow, should read the same as G33-609, system inlet flow. Our data showed a maximum deviation of 62 gpm. Bottom drain flow was recalibrates such that the Level 2 criteria could be satisfied. Also during Heatup, the RWCU system was operated in both the normal and blowdown modes with the reactor ; at rated temperature and pressure. Process
'Suppls: Int 6 P2ge 3 32-2' variables were recorded in order to demonstrate'the proper performance of the RWCU system in each of these modes. The non-regenerative heat exchange tube side outlet temperatures for the normal and blowdown mode were 1120 F and 122 F respectively. These values were within the Level 2 criteria limits of 1.20 F and 130 F for each mode. Using temperature measurements from the RBCCW side of the non-regenerative heat exchangers (NRHX) the cooling water flow was calculated to be less than 6% above the NRHX capacity. The non-regenerative heat exchanger cooling water outlet temperatures were well within our Level 2 criteria of 1800F. All applicable Level 2 criteria were satisfied.
The remaining testing for the Reactor Water Cleanup System (Hot Standby Operation) will be completed in Test Condition Four. l L___ __ _ ___ .
Supple: Int 6 Pega 3 33-1 3 33 Residual Heat Removal System 3 33 1 Purpose The purpose of this test is to demonstrate the ability of the Residual Heat Removal (RHR) System to remove residual and decay heat from the nuclear system so that refueling and nuclear servicing can be performed. 3 33 2 criteria Level 1 None Level 2 The RHR System is capable of operating in the suppression pool cooling and shutdown cooling modes at the flow rates and temperature differentials indicated on the process diagrams. 3 33 3 Results During the Heatup test phase, each division of the RHR system was placed in the Suppression Pool Cooling Mode and process data was taken for a 30 minute time period. The extrapolated heat capacity for both heat exchangers indicated an excess capacity of 67.5%. This was expected since in early heat exchanger life the heat transfer coefficient is f larger and capacity was determined to accommodate some deterioration. , 1 l I
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y , Supplex;nt 6 P;ga 3 34-2 During the first successful HPCI cold vessel injection to the reactor the load on force pin j F-155, located at the HPCI discharge, exceeded its j Level 1 criteria. After a detailed walkdown of the I HPCI supports and upon completion of further j analysis of the HPCI System pipe supports by Sargent j and Lundy, three additional strain gauge networks on j three other HPCI supports were installed to monitor i strains during the next cold injection. During that cold injection, all Level 1 and 2 criteria were satisfied. The additional strain gauges were monitored and these values were provided to Nuclear Engineering for evaluation and were found acceptable. Subsequent to this test, a HPCI vessel injection was g[; 4 performed on 7-5-87 which resulted in a HPCI e' overspeed trip. During that event, a water hammer and suction line overpressurization transient occurred (reference LER-87-030-oo) which, after engineering analysis, has resulted in the replacement of E41-Foo5, HPCI Discharge Check Valve and several HPCI System hanger modifications. Due to these changes in HPCI piping configuration, this testing was reperformed to evaluate HPCI piping response during the next planned HPCI Quick Start testing sequence. That additional test was performed in conjunction with a Hot Quick Start Vessel Injection on October j 14, 1987 and resulted in all criteria being met. The results from the three tests are summarized below: Level 1 Sensor 6/22/87 7/4/87 10/14/87 Allowable F-155 13966 lbf 4929 lbf 2164 lbf 10000 lbf I _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ .n i
l Supplesent 6 Page 3 34-1 3 34 Piping Systen Dynamic Response Testing 3 34.1 Purpose Verify that piping system structural behavior under x probable transient loadings is acceptable and within / the limit predicted by analytical investigations. ? 3 34.2 criteria Level 1 The measured vibration levels of the piping shall not exceed the acceptable specified values. Level 2 I The measured vibration levels of the piping must r.ot exceed the expected specified values. 3 34.3 Results Piping dynamic transient vibrations were monitored during Heatup, in conjunction with Relief Valve testing, for two SRV lines and selected Main Steam Lines. All vibration data recorded was within the acceptable and expected limits as defined by the Level 1 and Level 2 criteria. Piping dynamic transient vibrations were monitored during Test Condition Two in conjunction with relief valve actuations during relief valve testing, and during the planned Turbine / Generator Load Reject (Within Bypass) test. Deta for the two SRV lines and the Main Steam Lines showed all vibration data was within Level 1 and Level 2 criteria except D-001, which was inoperable, and D-003, D-005 and D-008 which did not meet Level 2 criteria. All violations were reviewed and evaluated by Sargent and Lundy and were found to be acceptable. It is worth noting that the original criteria for these instruments were given as "information only" and were mistakenly incorporated into the procedure as Level 2 criteria. During Test Condition Three, data was collected to determine the flow induced vibrational response of
- the High Pressure Coolant Injection (RPCI) system piping during a planned KPCI System cold vessel injection to the reactor.
wuum s. or ., Plent Technienl- . Vice President 8peC1.fiCationa nuciear owanons 4 v., DetrOil r.r m ooo uartn ome a Dec ember 2 0, 1987 Edison mw"gnway -- N RC-8 7-0 2 2 9 wuciear or < - U. S. Nuclea r Regulatory Commis sion Attention: Document Control Desk Washington, D. C. 20555
Reference:
(1) Fermi 2 4 j NRC Docket No. 50-341 ' Facility Operating License No. NPF-43 (2) Detroit Edison Letter to NRC "Startup Report" VP-86-0014, dated March 12, 1986 l 1 (3) Detroit Edison Letter to NRC "Startup Report Supplement 1" VP-86-0070, dated June 13, 1986 (4) Detroit Edison Letter to NRC "Startup Report - Supplement 2" VP-86-0177, dated December 17, 1986 4 i (5) Detroit Edison Letter to NRC "Startup i i Report - Supplement 3"-VP-NO-87-0055, dated March 20, 1987 I (6) Detroit Edison Letter to NRC "Startup Report - Supplement 4" NRC-87-0084, dated 1, June 19, 1987 (7) Detroit Edison Letter to NRC "Startup Report - Supplement 5" NRC-87-0155, dated September 19, 1987
Subject:
Startuo Reoort - Supolement 6 This is Supplement 6 of the Startup Report for Fermi 2. As required by Fermi 2 Technical Specification 6.9.1.3, a supplement is being submitted every 3 months until completion of the Startup Test Program. A supplemental report will be submitted by March 20, 1988. If you have any questions reg a rd ing this report, p le a s,e contact 586-1617. Patricia Anthony, Compliance Engineer at (313) Sinc e W. S. Orser cc: A. B. Davis E. G. Greenman Vice President Nuclear Operations W. G. Rogers J. J. Stefano ?
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.U. S. Nuclear Regulatory Commission December 20,11987 NRC-87-0229 Page 2 bec: F. E. Agosti, P. M. A14thony C. Borr (WPSC,.Inc)
S. G. Catola R. C. Drouillard J. H. Flynn G. M. Fo rd R. S. Lenart W. S..Orser G. R. Overbeck E. M. Page E. Preston, Jr. T. Randazzo' S. Savage (NUS) G. E. Smith B. R. Sylvia G. 11 . Trahey j W. M. Tucker C. T. Weber D. Wehmeyer Approval Control NRC Chron Secretary's Office (2412 WCB) Licensing File S-1 l 1 i 1 l.' ~. .]}}