ML18022A539
| ML18022A539 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 07/30/1987 |
| From: | Duncan R, Watson R CAROLINA POWER & LIGHT CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| HO-870468-(O), NUDOCS 8708040428 | |
| Download: ML18022A539 (272) | |
Text
{{#Wiki_filter:RFT-ULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS) I
~ACCEEEZQN NBR:8708040488 FAC IL: 50-400 Sh DQC. DATE:
87/07/vv NQT*RIZED earon Harri s- Nuc 1 ear Power P lant'i Uni t"- 1 i NQ Car ol ina DOCKET 05000e00 I AUTH'. NAME AUTHOR AFFILIATION DUNCAN. R. J. Carolina Power h Light Co. WATSON'. A. Carolina Power h Light Co. RECIP. NAME RECIPIENT AFFILIATiON
SUBJECT:
"Carolina Power 'c Light Co Sh aron Harris Nuclear Power Plant Cycle i Star tup Rept. " tJ/870730 ltr.
DISTRIBUT10N 'ODE.: IE26D COPIES RECEIVED: LTR ENCL SIZE: TITLE: Startup Report/Refueling Repor t'per Tech Specs) NOTES:,Application'or permi t. renewal filed. 05000400 REC IP IENT COPIES REC IP IENT COP IES ID LTTR ENCL ID CODE/NAME LTTR ENCL i i CODE/NAME'D2-i LA 0 PD2-i PD BUCKLEY7 B 2 2 INTERNAL: ACRS A , TECH ADV i i NRR/PMAS/1LRB; REQ FILE 02 i RES DEPY QI R FILE Oi i i RQN2/DRSS/EPRPB EXTERNAL: LPDR'SIC NRC PDR" TOTAL NUMBER OF COPIES REQUIRED: LTTR iB ENCL i7
<<~S CPS'arolina Power 8 Light Company HARRIS NUCLEAR PROJECT P. O. Box 165 New Hill, North Carolina 27562 JUL 30 1987 File Number'. SHF/10-14030 Letter Number'HO-870468 (0) Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555 SHEARON HARRIS'NUCLEAR POWER PLANT DOCKET NO. 50-400 LICENCE NO. NPF-63 START-UP REPORT Gentlemen'. In accordance with Technical Specifications 6.9.1.1 for the Shearon Harris Nucle'ar Power Plant, Unit No. 1, Carolina Power 6 Light Company herewith submits the enclosed Start-up Report. containing a summary of initial plant start-up and power escalation testing. This report fulfills the requirement for the issuance of a Start-up Report within 90 days following commencement of commercial operation. Very truly yours, R. A. Watson Vice President Harris Nuclear Project RAW/lkd Enclosure cc'Messrs. Dr. J. Nelson Grace (NRC) G. F. Maxwell (NRC-SHNPP) MEM/HO-8704680/PAGE 1/OS1
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CAROLINA POMER AND LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT CYCLE 1 STARTUP REPORT MIS/StartupMan/1/OS3
ACKNOWLEDGMENTS PREPARED BY: R. J. DUNCAN Power Ascension Test Program Development Engineer R. Colthorpe Power Ascension Engineer Y. Lee Power Ascension Engineer S. Benda Power Ascension Engineer A. Phillips, Power Ascension Engineer G. Michie Power Ascension Engineer S. Alvis Technical Support Scaling Engineer C. Mittag Technical Support Reactor Engineer D. Henneke Power Ascension Engineer J. Arnold Work Processor G. Ward Work Processor R. Smith Clerk MIS/StartupMan/2/OS3
Table of Contents Section Title ~Pa e 1.0 Introduction 6 2.0 Discussion of Harris Power Ascension Test Program 9 3.0 Discussion of Harris Power Ascension Tests 30 3.1 Core Loading 33 3.2 Post Core Loading System Testing 49 3.3 Physics Testing 94 3.4 Transient Testing 116 3.5 Instrumentation and Calibration Testing. 144 4.0 References 174 MIS/StartupMan/3/OS3
' Table Title List of Tables
~Pa e 2.0-1 Harris Major Milestones 10 2.0-2 Harris Operational Modes 11 2.3-1 HZP Flux Map Results 16 2.4-1 . 30X Power Flux Map Results 18 2.5-1 50X Power Flux Map Results 21 2.6-1 75X Power Flux Map Results 24 2.7-1 90X Power Flux Map Results 26 2.8-1 100X Power Flux Map Results 29 3.0-1 List of Test Summaries 31 3'2.1-1 Bypass Regulating Valve Level Control Response (Level Deviation) 51 3.2.1-2 Bypass Regulating Valve Level Control Response (Nuclear Power. Deviation) 51 3.2.1-3 Transfer Response from Bypass to Main Feedwater Regulating Valve at 20X Power 52 3.2. 2-1 100X Steam Generator Automatic Control Gain Setpoints 55 3.2.8-1 RCS RTD Bypass Hot Legs Transport Time 66 3.2.9-1 RCS Flow Rate at Hot Standby 68 3.2.13"1 Rod Drop Time Results 73 3.2.13-2 Rod Drop Two"Sigma Results 73 3.2.14"1 RCS Flow Rates 76 3.2.22"1 Turbine Generator Statepoint Data 91 3.2.23-1 Moisture Carryover Results 93 3.3.1-1 Reactivity Computer Dynamic Test Results 96 3.3.5-1 Core Performance Characteristics and Limits 108 3.3.6-1 3.3.7-1 Rod Worth Data Summary ill Process Computer Incore/Excore Normalization Factors 114 3.5.1-1 GFFDS (Gross Failed Fuel Detection System) Resu its 145 3.5.3-1 Primary Plant Thermal Power Data Summary 150 3 ~5 ~3 2 Secondary Plant Thermal Power Data Summary 150 3.5.4-1 RCS Process Temperature Data for 100X Power 154 3.5.5-1 RVLIS (Reactor Vessel Level Indication System)
Hot Standby Data 158 3.5.5-2 RVLIS 100X Power Data 158 3.5.8-1 75X Feedwater Flow Instrument Data 168 3.5.8"2 75X Steam Flow Instrument Data 168 3.5.8"3 90X Feedwater Flow Instrument Data 169 3.5.8-4 90X Steam Flow Instrument Data 169 3.5.8-5 100X Feedwater Flow Instrument Data 170 3.5.8-6 100X Steam Flow Instrument Data 170 MIS/StartupMan/4/OS3
List of Fi ures ~Fi ure Title ~Pa e 2.0"1 Shearon Harris Nuclear Plant Reactor Power vs. Days of Operation 12 3.1.1-1 Core Loading Sequence 35 3.1.1-2 Core Loading Sequence 36 3.1.1-3 Core Loading Sequence 37 3.1.1"4 Core Loading Sequence 38 3.1.1-5 Core Loading Sequence 39 3.1.1-6 Core Loading Sequence 40 3.1.1-8 Control and Shutdown Rod Locations 41 3.1.1-7 Burnable Poison Rod and Source Locations 42 3.1.2-1 Temporary NI Voltage Plateaus 44 3.1.2-2 Temporary NI Discriminator Settings 45 3.2.3-1 Main Feed Pump lA 100X Data 57 3.2.3-2 Main Feed Pump 1B 100X Data 58 3.2.16-1 Nominal Pressure 'Response to Opening of Pressurizer Spray Valves 80 3.2.16-2 Nominal Pressure Response to Actuation of All Pressurizer Heaters 81 3.3.1-1 ICRR vs. Control Rod Bank Position During Approach to Criticality 97 3.3.1-2 ICRR vs. Total Dilution Time to Criticality During'pproach 98 ICRR vs'eactor Makeup Water Addition During Approach to Criticality 101 3.4.4-1 10X Load Decrease From 75X Power 125 3.4.4-2 10X Load Increase From 75X Power 127 3.4.5-1 50X Load Reduction From 75X Power 131 3.4.7-1 Turbine Trip From 100X Power 137 3.5.4-1 RCS Temperature Trends - Protection Channels 155 3 '.4-2, RCS Temperature Trends Control Channels 156 3.5.7-1 Nuclear Instrumentation Channel N41 Current 161 3.5.7-2 Nuclear Instrumentation Channel N42 Current 162 3.5.7-3 Nuclear Instrumentation Channel N43 Current 163 3.5.7-4 Nuclear Instrumentation Channel N44 Current 164 MIS/StartupMan/5/OS3
1.0 INTRODuCTION This repozt describes the required testing at Shearon Harris Nuclear Power Plant from the time the prerequisites for initial fuel loading were performed (including initial Reactor Coolant System fill for fuel load) through 100K power NSSS Acceptance Testing. The plant performed well during the Power Ascension Phase, allowing the plant to set a record from receipt of Low Power License to increasing power above 5X in 62 days. The entire Power Ascension Testing Program from receipt of license to completion of required, testing, was completed in 165 days. Shearon Harris Nuclear Plant is a pressurized water reactor located in the extreme southwest corner of Wake County, North Carolina, and the southeast corner of Chatham County, North Carolina. The city of Sanford, North Carolina, is- approximately 15 miles southwest. The Nuclear Steam Supply System (NSSS) is a three-loop,'estinghouse Reactor rated at 2785 megawatts thermal (Mwt) which includes 10 Mwt from the reactor coolant pumps. This output corresponds to approximately 950 megawatts electric (Mwe). The turbine generator is supplied by Westinghouse. Daniel Construction Company, Inc., as the constructor, performed the major part of the plant construction. Selected portions of the work were performed by other contractors under the dizect supervision of CP&L. Ebasco Services .Incorporated was the Architect/Engineer responsible for the design, engineering, and equipment and material procurement for the project. License No.- NPF-53 was issued by the Nuclear Regulatory Commission (NRC) on October 24, 1986, and allowed Carolina Power and Light Company to proceed with initial fuel load and low power testing, including criticality and low power physics testing, at power levels not.to exceed 5X of rated thermal power. The initi.al'uel assembly was loaded into the core on November 17, 1986 and loading and core mapping was completed on November 21, after installation of 'the upper, internals and vessel head the RCS was filled and vented. Mode 5 was entered on November 25, 1986. Cold Shutdown testing was started on November 25, .1986 and the plant was at Hot Standby conditions on December 25, 1986. Testing was completed at Hot Standby and initial criticality was achieved on January 3, 1987 at 1536 hours. Post core loading and low power physics testing was completed and the Full Power License was issued on January 12, 1987. Harris plant entered Mode 1 on January 18, 1987, and the turbine generator was synchronized on January 19, 1987 at 2147 hours. The unit reached 100K power on April 21, 1987 at 0115 hours. The lOOX Turbine Trip Test was performed on May 2, 1987, and the NSSS Acceptance Test completed on May 2, 1987. The unit was declared commercial on May 2, 1987 at 0001 hours. Tables 2.0"1 Harris Major Milestones and 2.0-2 Operational Modes summarized the above data. Carolina Power and Light has notified the NRC of technical aspects hindering the performance of the Generator Net Load Trip from lOOX power and the Large Load Reduction from lOOX power. MIS/StaztupMan/6/OS3
The Power Ascension Tests "Large Load Reduction at 100X" (9108-S-05), and "Generator Net Load Trip from 100X" (9108-S-13) have been deferred until the is fully modified to prove the design aspects of these tests. As the 'lant plant is currently configured, both tests are expected to safely trip the plant ~ Delay of these tests meets Regulatory Guide 1.68 intent to verify plant design of Full Load Rejection and Large Load Reduction since the plant design is not yet fully implemented for these transients. The safety intent of Regulatory Guide 1.68 is met in regard to Generator Trip since this test. will result in a Turbine Trip/Reactor Trip or Reactor Trip/Turbine Trip. Large Load Reduction is also expected to require a manual reactor trip. In both cases, the plant has shown by the performance of the Turbine Trip Test that the plant responds safely to a trip at 100X power without safety system actuation except for Auxiliary Feedwater Actuation, which will occur if feed flow is lost due to a secondary system transient. FSAR Section 14.2.12.2.18, "Large Load Reduction and Generator Trip from 100X requires that plant responses .during the transients be monitored and that generator/turbine maximum credible overspeed be shown as acceptable. The following is the FSAR abstract'cceptance criteria. ACCEPTANCE CRITERIA Lar e Load Reduction Generator Tri from 100X Power c Reactor and Turbine must not trip
- 1) Reactor trip 6 Turbine should not
- 2) Safety injection is not 2) Safety injection is not initiated initiated
- 3) Steam Generator safety 3) Steam Generator safety valves valves shall not lift should not lift
- 4) Pressurizer safety valve 4) Pressurizer safety valves shall not lift intervention should not lift
- 5) No manual should be required to bring the plant to steady state conditions The response of the primary plant has been tested during the Turbine Trip test from 100X and met objectives 2, 3, 6 4 above for both tests and challenged no safety systems with the exception of Auxiliary Feedwater starting on a Loss of Main Feedwater. Neither test is expected to pass objective 1, nor is the Large Load Reduction expected to pass objective 5 until the plant has been fully modified to meet design for these objectives. The intent of Regulatory Guide 1.68 in regards to Generator Trip has been met in that the Mechanical Overspeed Test was performed satisfactorily with no load on the Generator.
However, Harris is not currently designed to assure a generator trip which would be acceptable (i.e., without a reactor trip) in that all Westinghouse recommended modifications have not yet been installed to implement full load ' reject capability at Harris. MIS/StartupMan/7/OS3
0 Westinghouse (FCQL-467) has notified CPGL that in attempting to perform a Generator Trip (Net Load Reject), .it is expected that the opening of the: generator output breakers with the lack of a Load Drop Anticipator Circuit in DEH may cause the turbine to rapidly overspeed to the OPC trip setpoint and will subsequently cause a turbine-reactor trip and test failure. In addition, the low rod worth of control rod bank "D" and secondary plant performance during transients are predicted to cause a test failure. The. plant is not expected to accept a 50X load rejection from 100Z without a manual'eactor trip due to loss of feedwater instabilities which will be corrected during Cycle 1 refueling outage. It has however, sustained an acceptable 50X Load Rejection from 75X power and thereby shown primary and secondary dynamic plant response with no safety system actuation. Carolina Power and Light has also notified the NRC of intentions to delete the performance of the 10X Load Swing from 100X power from the Power Ascension Test Program. The intent of Regulatory Guide 1.68 is that the plant be proven to first show the ability to sustain a 10X load swing and second to make any adjustments to automatic control'ystems necessary to meet that end. Based on the Heater Drain Pump Transient at 100X power on May 27, 1987 and previous Load Swing'Tests at 30X, 50X, and 75X, the intent of Regulatory Guide 1.68 has been completed satisfactorily. The plant experienced and safely executed an unplanned 10X load swing on May 27, 1987 when a Heater Drain Pump tripped and operations executed a 80 MWe (901 MW gross - 821 MW gross) decrease in power in approximately two minutes. All automatic control systems operated properly during the transient. The increase in power was performed at a normal rate of 5 MW/minute. As a result of this transient and the previous load swing tests, no adjustments to any automatic control system has been necessary. The plant General Operating procedure (GP"005) has been modified to direct the operator to initiate a 10X runback in power to 90X upon any loss of heater drain pumps. Both the delay of the Large Load Reduction and Generator Trip, and the deletion of the 10X Load Swing have had 10CFR50.59 reviews, performed and based on those reviews it. was determined that no unreviewed safety questions i ex s't MIS/StartupMan/8/OS3
2.0 DISCUSSION OF HARRIS POWER ASCENSION TEST PROGRAM The Harris Power Ascension Testing Program consisted of single and multisystem tests that occurred commencing with initial fuel loading and continuing through full power. These tests demonstrated overall plant performance and included such activities as cold and hot shutdown testing, zero power tests, and power ascension tests. A program governing procedure entitled "Power Ascension Testing Program Power Escalation, 9100-S-01" was utilized to control which tests required completion prior to power escalation to the next testing plateau. 9100-S-01 also included proper signoffs by the Plant Nuclear Safety Committee Chairman and the Plant General Manager. The Power Ascension Test Sequence was utilized for each plateau to coordinate the sequence o'f testing activities at that plateau. In the subsections that follow, a description of the testing at each plateau is provided. The descriptions'~include additional details concerning special license conditions and commitments made to the Nuclear Regulatory Commission prior to the Power Ascension testing program, where applicable. Also included as part of Section 2.0 is a table showing major milestones for Harris which occurred during the startup program, and a list of operational modes as defined by the Technical Specifications. Figure 2.0-1 is a historical graph of Reactor Power versus Days of Operation. i MIS/StartupMan/9/OS3
TABLE 2.0-1 HARRIS MAJOR MILESTONES MAJOR MILESTONES DATE 5X Power License Issued October 24, 1986 Fuel Load November ll, 1986 Initial Criticality January 3, 1987 (1536 hrs.) Full Power License Issued January 12, 1987 5X Test Completed January 13, 1987 Entered Mode 1 January 18, 1987 Initial Synchronization to Grid January 19, 1987 (2147 hrs.) 30X Test Completed February 17, 1987 50X Test Completed March 29, 1987 75X Test Completed April 14, 1987 90X Test Completed April 20, 1987 100X Power Achieved. April 21, 1987 (0115 hrs.) 100X Test Completed May 1, 1987 Commercial Operation May 2, 1987 (0001 hrs.) MIS/StartupMan/10/OS3
TABLE 2.0-2 HARRIS OPERATIONAL MODES REACTIVITY X RATED AVE. COOL. MODE CONDITION Keff* THERMAL POWER TEMP ~ 1 ~ Power'peration > 0.99 > 5X' > 350 F 2 Start-up > 0-99 5X > 350 F 3~ Hot Standby < 0.99 0 > 350 F 4~ Hot Shutdown < 0.99 0 350 F > Tavg > 200 F 5 ~ Cold Shutdown < 0.99 0 < 200 F
- 6. Refueling~ < 0.95 0 < 140 F
- Excluding Decay Heat Fuel in the Reactor Vessel with the vessel head closure bolts less than .
fully tensioned or with the head removed. MIS/StartupMan/11/OS3
0 SHEARGN HARRIS NUCLEAR PLANT REACTOR POV/ER vs. DAYS OF OPERATION 110.000 100.000 90.000 80.000 70.000 60.000 C> 50.000 40.000 30.000 20.000 10.000 0.000 07-JAN 22-JAN 06-FEB 21-FEB 08-OAR 23-OAR 07-APR . 22-APR 07-t1AY DAYS OF CPERATIQ)
2~1 INITIALCORE LOAD AND COLD SHUTDOWN S UENCE The Power Ascension Test Sequence was utilized to coordinate the sequence of operations associated with initial core loading and cold shutdown testing. This sequence included scheduling of the individual Power Ascension Tests associated with core loading. The sequence specified as prerequisites what testing had to be completed prior to commencement of core loading, the required status of the plant necessary to support core loading, and the required rod measurements with full and no Reactor. Coolant System Flow. The fuel load prerequisites included the initial boration of the Refueling Water Storage Tank (> 2000 ppm), the Boric Acid Storage Tank (> 7000 ppm), and initial fill of the RCS with the necessary sampling to ensure uniform boron concentration in the RCS. The required nuclear instrumentation checks were either performed as a separate test (temporary instrumentation) or as a part of the Initial Fuel.. Load procedure (permanent instrumentation surveillance tests). 1 Results of individual tests c'ompleted during the core loading and Cold 'Shutdown sequence are discussed in Section 3.1 and 3.2 of this report. Upon completion of core loading, plant systems were aligned as dire'cted by the Plant Operating Procedures, the RCS was filled and vented, and Cold Shutdown testing was performed. The Initial Core Load and Cold Shutdown Testing Plateau included the following tests.'101-S-01 Initial Fuel Load 9101-S-02 Reactor Coolant and Associated Systems Fill and Vent for Initial Fuel Load 9101-S-03 Reactor Coolant System Boron Concentration Sampling 9101-S-,04 Core Loading Instrumentation Check 9101-S-06 Rod Drive Mechanism Timing Test, RCS Cold 9101-S-07 Rod Drop Time Measurement, RCS Cold-No Flow 9101-S-08 Rod Drop Time Measurement, RCS Cold-Full Flow MIS/StartupMan/13/OS3
2.2 HOT STANDBY TESTING The Power Ascension Test Sequence was utilized to define the sequence of tests and operations from Cold Shutdown to Hot Standby testing which constituted the Hot Standby Testing Plateau. This testing included the RCS RTD/Thermocouple cross calibration as was done during Hot Functional Testing, Reactor Vessel Level Indication System (RVLIS) data gathering for calibration curves, various RCS flow and leakage measurements, and control rod measurements with full and no Reactor Coolant System Flow at hot standby conditions including rod indication and rod control tests. Results of individual tests completed during the, Hot Standby testing plateau are discussed in Section 3.2 of this report. Upon completion of hot standby testing, initial criticality was performed and the Zero Power Testing Plateau was entered. The Hot Standby Testing Plateau included the following tests: 9102-S-01 Incore Thermocouple and RTD Cross Calibration 9102-S"02 Reactor Coolant System Leak Rate Test 9102-S-03 Reactor Coolant System Flow Measurement 9102-S-05 RTD Bypass Loop Flow Verification 9102-S-08 Rod. Drive Mechanism Timing, RCS Hot 9102-S"09 Rod Drop Time Measurement, RCS Hot - No Flow 9102-S"10'102-S-11
'od Drop Time Measurement, RCS Hot Full. Flow Rod Control Test 9102-S-12 Rod Position Indication MIS/StartupMan/14/OS3
2 3 INITIAL CRITICALITY AND ZERO POWER TESTING The Power Ascension Test Sequence was utxlxzed to define the sequence of tests and operations, beginning with initial criticality, which constituted the Zero Power Testing Plateau. The Power Ascension Test Program - Power Escalation Procedure ensured that post core loading precritical testing had been completed and results approved by the Plant Nuclear Safety Committee and Plant Management prior to continuation of the testing program. Prior to commencement of dilution to initial criticality, source range nuclear instrumentation channels were verified to have a signal to noise ratio greater than 2, and power range high level trip setpoints were conservatively set to 20 + 1X.- of full power. Plant operating procedures were utilized where appropriate to establish plant conditions'ero Power Testing Plateau tests obtained a full core flux map with all rods out'Refer to Table 2.3-1 for a .tabulation of the flux map results obtained)> to assure adequate margin to hot channel factor'imits prior to increasing power to 30X, performed boron eirdpoint measurements, isothermal temperature coefficient measurements, and reactivity worth of control and shutdown rod banks utilizing rod swap techniques. Natural Circulation Testing was performed at approximately 3X to 3.5X reactor power and various zero power statepoint data information was obtained for operational alignment of temperature instrumentation RVLIS, pressurizer heater and spray capability, radiation shield survey, and RCS flow coastdown. Results of individual tests completed during the Initial Criticality and Zero Power Test plateau are discussed primarily in Section 3.3 of this report. Upon completion of this testing phase, the 30K Power Testing Plateau was entered. The Initial Criticality and Zero Power Testing Plateau included the following tests. 9103"S-01 Initial Criticality. 9103-S-05 Boron Endpoint Measurement - ARO 9103"S-lo Isothermal Temperature Coefficient Measurement - ARO 9103-S-13 Flux Distribution Measurement Test 9103"S-23 Natural Circulation 9103-S-25 NIS Overlap Verification, Data Acquisition, Power Range Calibration and Setpoint Adjustment 9103-S-26 Reactivity Worth .of the Control and Shutdown Banks Utilizing the Rod Swap Technique 9103"S-33 Shield Survey Test 9102-S-04 Reactor Coolant System Flow Coastdown 9102-S-06 Pressurizer Spray and Heater Capability and Continuous Spray Flow Settings 9102-S-15 Operational Alignment of Process Temperature Instrumentation at Hot Zero Power 9102-S-18 Reactivity Computer-Initial Setup and Calibration 9102-S-19 Reactor Vessel Level Indicating System and Calibration 9102-S-20 Incore Moveable Detector System Preliminary Operational Test MIS/StartupMan/15/OS3
TABLE 2.3-1 HZP FLUX MAP RESULTS AC'TUAL MAXINJM LIMIT Reaction Rate Error, Percentage 7.41X 10K FN ,1.498 1.77 AH Fq(Z)/K(Z) '.313 4.56 Quadrant Power Tilt Ratios 1.013 1.02 HZP FLUX MAP .EXTRAPOLATED TO 304 POWER ACTUAL MAXINJM LIMIT FN AH 1.498 1 '98 Fq(Z)/Z(Z) 2.313 4.56 c MIS/StartupMan/16/OS3
2.4 TEST SE UENCE AT 30X POWER C The Power Ascension Test Sequence was utilized to define the activities which constituted the testing program from Hot Zero Power, after completion of low power testing, up to and including the 30X Power Testing Plateau. The Power Ascension Test Program Power Escalation procedure ensured that the Initial Criticality and Zero power test sequence had been completed and results approved by the Plant Nuclear Safety Committee and plant management prior to entry into mode 1. Prior to increasing, power for this test sequence, power range high level trip setpoints .wer'e conservatively set for 49 + 1X of full power. A full core flux map was also obtained at 30K, stable xenon (refer to Table 2.4-1 for tabulation of the flux map results obtained), to assure adequate margin to hot channel factor limits prior to increasing power to 50X. Until a precision calorimetric could be performed in the 20"30K power range, reactor power level was monitored by using reactor coolant system AT indication where 100X power was conservatively equated to a 54'F core temperature difference (Narrow Range Thhot Tcoj.d . <). Plant operating were utilized where app'ropriate to establish plant conditions and
'rocedures to change reactor power. During ascension to the 30X plateau, power was stabilized near the 5X, 10X, and 20K levels to accommodate testing at these plateaus. Testing, at this plateau included a statepoint data acquisition at 30X, automatic steam generator level control system adjustment, dynamic automatic steam dump control system adjustment, turbine generator statepoint data acquisition, a 48-hour endurance run on Auxiliary Feedwater Pumps, and a 10X load swing from, approximately 38'ower after failure at 28X power.
Results of individual tests completed during power ascension to and while at the 30K plateau- are discussed in Section 3.2 through 3.5 of this reports The 30X Power Testing Plateau included the following test: 9104-S-01 Calibration of Steam and Feedwater Flow Instruments at Power 30X 9104-S-04 Automatic Reactor Control 9104-S"05 Automatic Steam Generator Level Control Test 9104-S-06 Thermal Power Measurement and Statepoint Data Acquisition at. 9104-S-07 30'ross Failed Fuel Detection System Test 9104-S-08 NIS Overlap Verification, Data Acquisition, Power Range Calibration and Setpoint Adjustment 9104-S-10 Core Performance Test 30K 9104-S-15 Loss of Offsite Power 9104-S-16 Main Steam and Feedwater System Test 9104-S-18 Operational Alignment of Process Temperature Instrumentation 9104-S-19 Remote Shutdown Test 9104-S-20 Auxiliary Feedwater Turbine and Motor Driven Pump 48 Hour Endurance Run 9104-S-21 Turbine Generator Statepoint Data 30K 9103-S-27 Turbine Overspeed Trip Test ( 9103-S-28 9103-S-29 Dynamic Steam Dump Automatic Control Automatic Steam Generator Level Control MIS/StartupMan/17/OS3
TABLE 2.4-1 30X POWER FLUX MAP RESULTS ACTUAL MAXIMUM LIMIT Reaction Rate Error Percentage 7.0848X 10X FN 1.435 1.71 hH Fq(Z)/K(Z) 2.041 4.56 Quadrant Power Tilt Ratios 1.0074 1.02 30X FLUX MAP EXTRAPOLATED TO 50X POWER ACTUAL HAXIMUM LIMIT 1.435 1.64 AH Fq(Z)/K(Z) 2.041 4.56 i-MIS/StartupMan/18/OS3
2 ~ 5'EST SE UENCE AT 50X POWER The Power Ascension Test Sequence at 50X Power was utilized to define the activities which constituted the testing program during escalation from 30X to 50X power and at approximately SOX of rated thermal power. The Power Ascension Test Program - Power Escalation procedure ensured that the Test sequence at 30X power had been completed and the results approved by the Plant Nuclear Safety Committee and plant management prior to increasing power above 30X testing plateau. Prior to increasing, power for this test sequence, power range high level trip setpoints were conservatively set to 69 + 1X power. A full core flux map was also obtained at 50X, stable xenon (refer to Table 2.5" 1 for tabulation of the flux map results) to assure adequate margin to hot channel factor limits prior to increasing power to 75X. Plant operating procedures were utilized where appropriate to establish plant conditions and to change reactor. power. Testing at this plateau included a statepoint data acquisition at 50X, operational alignment of process temperature instrumentation, calibration of steam and feedwater flow instrumentation, shield surveys, steam cycle sampling, RCS flow measurement by calorimetric, turbine generator statepoint, and Main Steam and Feedwater System tests which calculated secondary plant performance. P In addition, reactor physics related procedures were performed to do preliminary calibration of incore determined power to the power range excore detectors and included f(q) function to relate incore axial offset to excore AI ~ A power coefficient determination was also performed to verify design reactivity values. A test was performed to verify no condensate induced water hammer occurred when feedwater was directed to the steam generator preheater section. The Main Feedwater Pump performance curve determination was initiated at this plateau and continued until the 100X Power plateau. Transient tests at this plateau included a 10X Load Swing developed to verify operation of .the Steam Generator Automatic Control System, other automatic systems, and a loss of feedwater heaters test to verify the reduction in feedwater temperature is less than that assumed in accident analysis. Results of individual tests completed during power ascension to and while at the 50X plateau are discussed in Sections 3.2 through 3.5 of this report. Upon completion of this testing phase, the plant was restored as directed by the Shift Test Coordinator. The 50X power testing plateau included the following tests'. 9105-S-12 Shield Survey 9105-S-15 Steam Cycle Sampling 9105-S-05 Core Performance Test at 50X 9105-S-18 Preliminary Incore/Excore Calibration 9105-S-06 Thermal Power Measurement and Statepoint Data Acquisition 9105-S-01 Calibration of Steam and Feedwater Flow Instrumentation 9105-S-16 Operational Alignment of Process Temperature Instrumentation 9105-S-09 Power Coefficient Determination c 9105-S-14 9105-S-13 9105-S-34 Reactor Coolant System Flow Measurement Turbine Generator Statepoint Data Main Feedwater Pump Performance Test MIS/StartupMan/19/OS3
0 9104-S-13 Steam Generator Test for Condensate Induced Water Hammer 9106-S-04 Load Swing at 50X 9105-S"10 Main Steam and Feedwater System Test 9105-S-11 Loss of Feedwater Heaters 9105-S-07 NIS Overlap Verification, Data Acquisition, Power Range Calibration and Setpoint Adjustment ( MIS/StartupMan/20/OS3
TABLE 2.5"1 50X POWER FLUX MAP RESULTS ACTUAL MAXIMUM LIMIT Reaction Rate Error Percentage 4.698K 10X FN 1.410 1.643 hH Fq(z)/K(z) 2.032 4.56 Quadrant Power Tilt Ratios 1.0068 1.02
'50K FLUX MAP EXTRAPOLATED TO 75X POWER ACTUAL MAXIMUM LIMIT FN 1.410 1.56 hH Fq(z)/K(z) 2.032 3.04 MIS/StartupMan/21/OS3
2.6 TEST SE UENCE'T 75X POWER The Power Ascension Test Sequence at 75X Power was utilized to define the activities which constituted the testing program during escalation from 50X to 50X power and at approximately 75X of rated thermal power. The Power Ascension Test Program - Power Escalation procedure ensured that the test sequence at 50X power had been completed and the results approved by the Plant Nuclear Safety Committee and plant management prior to increasing power above the 50X testing plateau. Prior to increasing power for this test sequence, power range high level trip setpoints were conservatively set to 94 + 1X power. A full core flux map was also obtained at 75Z, stable xenon (refer to Table 2.6-1 for tabulation of the flux map results) to assure adequate margin to hot. channel factor limits prior to increasing power to 90X. Plant operating procedures were utilized where appropriate to establish plant conditions and tb change reactor power. Testing at this plateau included a statepoint data acquisition at 75X, operational alignment of process temperature instrumentation, calibration of steam and feedwater flow instrumentation, NIS linearity verification, Turbine Ge'nerator statepoint data, Main Steam and Feedwater System tests, and Automatic Steam Generator Level Control System testing. Main Feedwater. pump performance continued at this plateau as well as the collection of initial data for the calibration of the Main Feedwater flow restricting flow elements'ransient testing at 75X power included a 10X load swing and a 50X large load reduction'both of which were successfully completed. At 75X, procedures on alignment of reference temperature and first stage turbine pressure were initiated, however, no adjustment was performed at this plateau based on Westinghouse recommendations. Also while at the 75X testing plateau, an axial xenon oscillation was induced so that the flux map data could be obtained to be used for calibration of the excore axial flux difference instrumentation. Indicated excore delta flux was driven to approximately -16.5X by insertion of control bank D concurrent with a boron dilution to maintain power. A full core flux map was then obtained and after approximately three hours, control bank D was borated out to the original position of greater than 180 steps. This induced an axial xenon oscillation and hI was allowed to drift to approximately +3X, at which time control bank D was inserted by boron dilution to drive AI back to the target value of approximately -4X. AI was then allowed to drift another 7X in the negative direction to approximately -11X, at which time control bank D was withdrawn to reposition hI back to the target value of approximately -4X ~ This maneuver induced an axial xenon oscillation which subsequently was dampened thereby successfully demonstrating axial xenon oscillation suppression control. Based on this calibration and the process alignment of II extrapolation, new full power AI values and excore full power total currents where calibrated into the required control and protection of individual tests completed during power ascension to and while at loops'esults the 50X plateau are discussed in Sections 3.2, 3.4, and 3.5 of this reports 4 c MIS/StartupMan/22/OS3
Upon completion of this testing phase, the plant was restored as directed by the Shift Test Coordinator. The 75X Power testing Plateau included the following tests'. 9106"S-01 Calibration of Steam and Feedwater Flow Instrumentation at Power 9106-S-06 Thermal Po~er Measurement and Statepoint Data Acquisition 9106-S-07 NIS Overlap Verification, Data Acquisition and Power Range Setpoint Adjustment 9106-S-08 Operational Alignment of Process Temperature Instrumentation 9106-S"13 Turbine Generator Statepoint Data 9106-S-16 Steam Generator Statepoint Data 9106-S-14 Main Steam and Feedwater System Data 9106-S"17 Calibration of Main Feedwater . Flow Restricting Flow Elements 9103-S-34 Main Feedwater Pump Performance Test 9106-S-10 Core Performance Test 9106-S-11 Incore/Excore Calibration 75X 9106-S-12 Start-up Adjustments of Percent Thermal Power vs. First Stage Turbine Pressure 9106-S-02 Start-up Adjustments of Reactor Control System 9106-S"04 Load Swing at 75X 9106-S-05 Large Load Reduction at 75X ( MIS/StartupMan/23/OS3
TABLE 2.6-1 75X POWER FLUX MAP RESULTS ACTUAL MAXIMUM LIMIT Reaction Rate Error Percentage 4.487X 10K N 1.349 1.56 AH Fq(z)/K(z) 1 987 2.988 Quadrant Power Tilt Ratios 1.0084" 1.02 75X FLUX MAP EXTRAPOLATED TO 9QX POWER ACTUAL MAXIMUM LIMIT FN 1.349 1.52 hH Fq(z)/K(z) 1.987 2.53 r MIS/StartupMan/24/OS3
2.7'EST
~ SE UENCE AT 90X POWER Ascension Test Sequence at 90X Power was utilized to define the
~
The Power activities which constituted the testing program during escalation from 75X to
~ ~ ~ ~
90X. power and at approximately 90X of rated thermal power. The Power Ascension Test Program - Power Escalation procedure ensured that the Test sequence at 75X power had been completed and the results approved by the Plant Nuclear. Safety Committee and plant management prior to increasing power above 75X testing plateau. Prior to increasing power for this test sequence, power range high level trip setpoints were conservatively set to the normal value of 108 + 1X power. A full core flux map was also obtained at 90X, stable xenon (refer 'o Table 2.7-1 for tabulation of the flux map results) to assure adequate margin to hot channel- factor limits prior to increasing power to 100X. Plant operating procedures were utilized where appropriate to establish plant conditions and to change reactor power. Testing at this plateau included a statepoint data acquisition at 90X, operational alignment of process temperature instrumentation, calibration of 'steam and feedwater flow instrumentation, NIS overlap verification, Turbine Generator statepoint data, automatic steam generator level control, and Main Feedwater pump performance and. flow restricting flow element calibration data acquisition.
'I Transient tests included loss of feedwater heaters and power coefficient determination. ~
~
Prior to escalation to 100X power, first stage turbine
~ ~ ~
'pressure was adjusted to allow reactor temperature to control at a higher
~ ~
value. Results of individual tests completed during power ascension while at
~ ~ ~ ~ ~
the 90X plateau are discussed in Sections 3.3 and 3.5 of this report.
~ ~ ~
~ ~
~
~
Upon completion of this testing phase, the plant was restored as directed by the Shift Test Coordinator. The 90X Power testing plateau included the following tests'. 9107-S-01 Thermal Power Measurement and Statepoint Data Acquisition 9107-S-02 NIS Overlap Verification, Data Acquisition, Power Range Setpoint Adjustment 9107-S"03 Calibration of Steam and Feedwater Flow Instrumentation at Power 9107-S-06 Power Coefficient Determination 90X 9107-S-08 Loss of Feedwater Heaters Test 9107-S-11 Turbine Generator Statepoint Data 9107"S-10 Operational Alignment of Process Temperature Instrumentation 9105-S-17 Calibration of Main Feedwater Flow Restricting Flow Elements 9103-S-34 Main Feedwater Pump Performance Test MIS/StartupMan/25/OS3
2.7-1 - 90X TABLE POWER FLUX MAP RESULTS ACTUAL MAXIMUM LIMIT Reaction Rate Error Percentage 4.445X 10K FN 1.367 1.521 hH Fq(Z)/K(Z) 1.938 2.542 Quadrant Power Tilt Ratios 1.0062 1.02 90X FLUX MAP EXTRAPOLATED. TO 100K POWER MAXIMUM VALUE ACTUAL'.367 FN 1.49 hH Fq(Z)/K(Z) 1.938 2.28 i MIS/StartupMan/26/OS3
2 8 TEST SE UENCE AT 100X POWER The Power Ascension Test Sequence at 100X Power was utilized to define the activities which constituted the testing program during escalation from 90X to 100X power and at approximately 100X of rated thermal power. The Po~er Ascension Test Program - Power Escalation procedure ensured that the Test sequence at 90X power had been completed and the results approved by the Plant Nuclear Safety Committee and plant management prior to increasing power above 90X testing plateau. Plant operating procedures were utilized where appropriate to establish plant conditions and to change reactor power. During ascension to the 100X plateau, power was stabilized near the 98X level to accommodate testing at this plateau. Testing at this plateau included a statepoint data acquisition at 98X, operational alignment of process temperature instrumentation, calibration o'f steam and feedwater flow instrumentation, NIS overlap data acquisition, Turbine Generator Statepoint data, Main Feedwater Pump performance, and Main Feedwater flow restricting flow element data acquisition. Adjustments were made to full power AT in both control and protection channels, however, no change in the reference temperature (Tref vs. First Stage Turbine Pressure) program was required. A shield survey was performed which did not meet containment neutron levels acceptance criteria in accordance with the FSAR survey maps. Also, Gross Failed Fuel Detection System high alarm setpoints were set and RCS Flow Measurement at 100X power was determined by calorimetric., The NSSS Acceptance Test was performed prior to the only 100Z transient test which was a 100X Turbine Trip. The previously scheduled for cycle 1 Large Load Reduction and Net Loss of Load (Generator Trip) have been delayed until cycle 2 start-up. The 10X Load Swing from 100X power has been deleted from the test program. Reactor Vessel Level Indicating System was verified to be within the required acceptance criteria after data obtained throughout Power Ascension was analyzed, a curve fit developed, and the coefficients were input to the system software. Results of individual tests completed during power ascension to and while at the 100X plateau are discussed in Sections 3.2, 3.4, and 3.5 of this report. A flux map was taken near the 100X power plateau and its results were examined to determine acceptability. (Refer to Table 2.8-1 for a tabulation of the flux map results.) Upon completion of this testing phase,. the plant was restored as'irected by the Shift Test Coordinator. The 100Z Power testing plateau included the following tests:- 9108-S-01 Calibration of Steam & Feedwater Instrumentation 9108-S-02 Start-up Adjustments of Reactor Control System 9108-S-07 NIS Overlap Verification, Data Acquisition Power Range Calibration and Setpoint Adjustment MIS/StartupMan/27/OS3
8' 9108-S-08 Operational Alignment of Process Temperature = 9108-S"06 Instrumentation Thermal Power Measurement and Statepoint Data Acquisition 9108-S-10 Core Performance Test - 100X 9018"S-14 Turbine Trip - 100X 9108"S-15 NSSS Acceptance Test 9108"S-19 Main Steam and Feedwater System Test 9108-S-21 Reactor Coolant System Flow Measurement Start-up Adjustment of Percent Thermal Power vs. First 9108"S-22'108-S-23 Stage Turbine Pressure Turbine Generator Statepoint Data 9108-S-24 100X Power RVLIS Data 9108-S-18 Gross Failed Fuel Detection System 9108"S-20 Shield Survey Test at 100X 9108-S-17 Calibration of the Main Feedwater Flow Restricting Flow Elements 9103-S-34 Main Feedwater Pump Performance Test 9108-S-16 Main Steam Isolation Valve Test 9108"S-03 Steam Generator Mois'ture Carryover Test MIS/StartupMan/28/OS3
TABLE 2.8-1 100X POWER FLUX MAP RESULTS ACTUAL MAXIMUM LIMIT Reaction Rate Error Percentage 4.212K 10K FN 1.377 1.49 hH F~(Z)/K(Z) 1.994 2.28 Quadrant Power Ti1t Ratios 1.0066 1.02 MIS/StartupMan/29/OS3
3 ~0 DISCUSSION OF HARRIS POWER ASCENSION TESTS The following sections discuss in some detail the individual tests comprising the Power Ascension Test Program. Procedures which were executed at various power levels are discussed as one section. In this manner, the final results of the power increase data acquisition is shown as a smooth transition. Transient test are shown in greater detail due to the importance of these types of test to overall plant performance. The test summaries are. grouped as follows with Table 3.0"1 providing a detailed list: 3.1 Core Loading 3.2 Post Core Loading Testing 3.3 Physics Testing 3.4 Transient Testing 3.5 Instrumentation and Calibration Testing MIS/StartupMan/30/OS3
3 0-1 LIST OF TEST SUMMARIES 3.1.3 Initial Core Loading 3.1.2 Core Loading Instrumentation Check 3.1.3 Reactor Coolant and Associated Systems Fill and Vent for Initial Fuel Load 3.1.4 Reactor Coolant System Boron Concentration Sampling 3.2.1 Automatic Steam Generator Level Control-Low Power 3.2.2 Automatic Steam Generator Level Control Test 3.2.3 Main Feedwater Pump Performance Test 3.2.4 Steam Generator Test for Condensation Induced Mater Manner 3 ' ' Incore Flux Mapping System Checkout 3.2.6 Rod Position Indication 3.2.7 Shield Survey Test 3.2.8 RTD Bypass Loop Flow Verification 3.2.9 Reactor Coolant System Flow. Measurement, Hot Standby 3.2.10 Reactor Coolant System Flow.Coastdown 3.2.11 Reactor Coolant System Leak Rate Test 3.2.12 Control Rod Drive Mechanism Timing Test 3.2.13 Rod Drop Time Measurement 3.2.14 Reactor Coolant System Flow Measurement 3.2.15 Steam Cycle Sampling 3.2.16 Pressurizer Sp'ray, Heater Capability, and Continuous Spray Flow Setting 3.2.17 Rod Control System Test 3.2.18 Incore Thermocouple and RTD Cross Calibration Automatic Rod Control 3.2.20 Main Steam Isolation Valve Test 3.2.21 Dynamic Automatic Steam Dump Control Test 3.2.22 Turbine Generator Statepoint Data 3.2.23 Steam Generator Moisture Carryover Test 3.3.1 InitialCriticality 3.3.2 Boron Endpoint Measurement ARO 3.3.3 Power Coefficient Determination 3.3.4 Isothermal Temperature Coefficient - ARO 3.3.5 Core Performance Tests 3.3.6 Reactivity Worth. of the Control and Shutdown Banks Utilizing the Rod Swap Technique 3.3.7 Incore/Excore Calibration 3.3.8 Reactivity Computer Initial Setup and Calibration 3.4.1 Remote Shutdown Tes't 3.4.2 Auxiliary Feedwater Turbine Driven and Motor Driven Pum p Endurance Test (48 hours) 3.4.3 Loss of Feedwater Heaters Tests 3.4.4 Load Swing Tests 3.4.5 Large Load Reduction Test 3.4.6 NSSS Acceptance Test 3.4.7'.4.8 Turbine Trip from 100X Power Station Electrical Blackout 3.4.9 Turbine Overspeed Trip Test MIS/StartupMan/31/OS3
3 4'10 Natural Circulation 3.5.1 Gross Failed. Fuel Detection Test 3.5.2 Calibration Procedure for the Feedwater Flow Restrictor Flow Element Instrumentation 3.5.3 Thermal Power Measurement and Statepoint Data Acquisition 3.5.4 Operational Alignment of Process Temperature Instrumentation 3.5.5 Reactor Vessel Level Indication System (RVLIS) 3.5.6 Start-Up Adjustment of Reactor Control System 3.5.7 ; Operational Alignment of Excore Nuclear Instrumentation 3 5.8 Calibration of Steam and Feedwater Flow Instrumentation 3.5.9 Main Steam and Feedwater System Test MIS/StartupMan/32/OS3
3 1 CORE LOADING 3 1.1 INITIAL CORE LOADING 9101-S-Ol TEST OB JECTIVES The Initial Core Loading Test Procedure was performed to ensure that the nuclear fuel assemblies were loaded in a safe and cautious manner such that an inadvertent criticality was avoided. This procedure was also utilized to verify placement of the fuel assemblies into their proper core locations upon completion of core load. TEST METHOD The test procedure began by loading the temporary core loading instrumentation into their initial positions and determining background count rates for all source range and temporary nuclear instrumentation channels. The two primary source bearing assemblies and six additional assemblies, comprising the "source nucleus", were loaded next. Audible indication of neutron population changes from one of the two installed plant channels was maintained in both the control room and containment for the duration of the core loading process (two source range and three temporary channels). The first reference value, for use in inverse count rate ratio (ICRR) monitoring, was determined from these sets of counts after appropriate background values had been subtracted. 'ubsequent reference values were calculated whenever core loading was suspended for four hours or longer, a temporary detector was used, a primary source bearing assembly was moved, to a= different core location, or a change of greater than 100 ppm was made in the RCS boron concentration.
, Predictions were made prior to fuel load to verify that the reactor would-remain at least ten percent shutdown throughout the loading process. Inverse count rate ratio monitoring was used following each fuel assembly move to ensure that the reactor was not approaching criticality.
To ensure reliability in the monitoring, a minimum of two of the five nuclear instrumentation channels 'were required to be zesponding to source neutron population changes throughout core loading and all responding channels were subjected to a Statistical Reliability Test. The Statistical Reliability Test provided a quantitative means of evaluating performance based on a Chi-squared 'est. Upon completion of the loading, the core was mapped using a video camera to verify proper placement of assemblies into the reactor vessel. RESULTS and ACCEPTANCE CRITERIA COMPARISON Core loading was completed in a safe and cautious manner as required by the acceptance criteria of the core loading procedure. Problems encountered during the test were primarily associated with non-responding or malfunctioning neutron detectors not passing the statistical reliability test initially and intermittent gripper problems which required minor lubrication along with bridge drive gear cover adjustment. The first fuel assembly was loaded into the reactor vessel at 1706 houzs on 11/17/86 and the final assembly went in at 0146 hours on 11/21/86 for a total duration of 79 hours and 40 minutes (3 days, 7 hours and 40 minutes). Figures 3 1.1-1 through 3.1.1.-6 depict the core loading sequence while figure 3 ~ 1 1-7 ~ MIS/StartupMan/33/OS3
depicts shutdown and control bank locations and 3.1.1-8 shows the burnable poison rod loading pattern. FIGURES AND TABLES Figure 3.1.1-1 thru =-3.1.1-6 Core Loading Sequence Figure 3.1.1-7 Burnable Poison Rod and Source Locations Figure 3.1.1-8 Control and Shutdown Rod Locations r MIS/StartupMan/34/OS3
OSR 180' P N N L K J H G F E D C 8 A I I I 4 HC03 HC2I HC28 fC48 HA03 A ISO' 270'0 l2 13 l4 15 00 DEPICTS FUEL ASSEMBLY CONTAINING A PRIMARY SOURCE QRR A, Q, C INDICATES LOCATION OF TEMPORARY NEUTRON DETECTORS ( Fulgur e 3.1.1-1 CORE LOADING SEQUENCE
QSR 180' P N M L K J H G F E D C B A I I I HC2l HC24 a HC02 HA03 HC49 A H82l Hh24 HBl l HA45 }$47 270'0 l2 13 14 HC26 15 0, DEPICTS FUEL ASSEMBLY CONTAINING A PRIMARY SOURCE OsR A, B, C INDICATES LOCATION OF TfMPORARY NfUTRON DETECTORS Figure 3.1.1-2 CORE LOADING SEQUENCE
QSR 180' R P N M L K J H G F E, D C B A I I HC03 HC21 HC24 0 HC02 HA03 HC49 HA21 HB2)
@HO HA02 &02 HA44 HB36 HA36 l
90' HB11 HA48 HB47 270' 9 HC48 10 Hh) 3 HB13 HA40
%28 HA14 i%14 HAOe f$05 HA)S 0
HC28 15 00 ~ DEPICTS FUEL ASSEMBLY CONTAINING A PRNARY SOURCE QSR A, B, C INDICATES LOCATION OF TEMPORARY NEUTRON DETECTORS F)guI e 3,1.1-3 CORE LOADING SEQUENCE
OSR 180' P N 8 L K J H G F E .D C B A HC21 HC02 H621 HB40 HAOI HA46 A 270'0 HA47 HA52 HB51 HA51 HC27 HB lb HA13 H613 12 HA14 13 HC26 HC15 00 o DEPICTS FUEL ASSEMBLY CONTAINING A PRIMARY SOURCE OsR A, B, C INDICATES LOCATION OF TEMPORARY NEUTRON DETECTORS F)guI-e 3.1.1-4 CORE LOADlNG SEQUENCE
OsR 180 A P N M L K J H 6 F E D C B A f f f HC03 HC21 HCA HC02 HA03 HC49 HC I 0 HC33 HA2\ 1$ 21 ~ t$ 24f HC31 I%40 HA02 t$ 02 HA50 1$ 8 9 HAI0 HC12 HCA5 tCOI HAOI t$ 37 HA3S tOI S HAI S HA 12 HAH HB36 HA36 t$ 52 HA53 HA35 HC32 HC12 90' 8 HBI I HANS HBW7 HA09 HB09 HA22 t$ 22 HA42 A 9 HA%7 f&H HA52 HB40 HAM HAS I HEI HC27 270'BOS HAOS HB16 HA I 7 HBOS HBI7 HAS HA13 HB13 HA%0 HB39 HA30 12 t%2B HAI I t$ 18 HA19 HB19 HAOS I$06 HA 15 HB 1 5 HC25 lC13 0 C HCSS HA37 'HC2S HC07 HCOS HC15 00 DEPICTS FUEL ASSEMBLY CONTAINING A PRIMARY SOURCE Qsa P,, f3, C INDICATES LOCATION OF TEMPORARY NEUTRON DETECTORS ' Figure 3.1.1-5 CORE LOADlNG SEQUENCE
QSR 180' P N M L K J H 6 f E D C B A I I I HC02 HA03 HC49 HC I 0 HC33 HA21 HB21 HA24 H824 HC31 f&IO HA02 H802 HASO H849 HAIO H802 HCI 8 HBIO H833 HA34 H834 HA29 H829 HA31 H831 HC12 HC45 H823 8301 MAOI M837 HA38 HB I 8 HAI8 HA 12 HC30 7 HCS2 HC35 HA12 HA44 H836 HA30 H852 HA53 HA35 HC32 HC42 ~90' HCI I HA32 H832 Hhl I HB I I HA48 H847 HA09 H809 HC47 270'C27 H827 HA47 H844 HAS2 H840 HA04 HBSI HA51 HC41 10 1 1 esi HCI6 H805 HA I 3 H828 HA08 H81 6 HB I 3 HA14 HA40 H814 HA17 H839 HAI9 HB08 HA30 HB19 HA07 HCI 7 HA06 HBOO HA I 5 HB15 HC25 HC13 MC48 HA37 MC28 HC 14 HC19 HCO7 HC06 HC1 5 00 0- DEPICTS FUEL ASSUMABLY CONTAINING A PRIMARY SOURCE CSR I A, B, C INDICATES LOCATION CF TEMPORARY NEUTRON DETECTORS Figure 3.1.1-6 CORE LOADING SEQUENCE
= OsR 180' P N M L K J H 6 F E D C B A I I 16 20 12 20 20 16 45 16 20 20 16 20 16 20 16 16 20 16 16 16 20 16 16 O90' 12 20 20 20 12 20 16 16 16 10 20 16 16 .20 20 20 16 20 12 20. 45 16 20 20 12 20 270'UMBERS 14 16 00 INDICATE THE NUMBER 1040 12.5 W/0 B20z OF BURNABLE POISON RODS.. CSR BURNABLE POISON RODS 5 INDICATES SECONDARY SOURCE RODS P !NDICATES PRIMARY 50URCE RODS ' Figure Ã1.1-7 BURNABLE POI5QN ROD AND SOURCE LOCATIONS
160 R P N M L K J H G F E D C B A I I I D SA SC B SC SB SD SD A 7 SA SB SB SA 90' D D 270 10 'A SA B SD SB SB SD SA SC A 12 C C 13 SC SA, SA 14 A D A 0 CONTROL NUMBER SHUTDOWN NUMBER OsR BANK OF RODS BANK OF RODS A SA B SB C SC D SD TOTAL TOTAL 24 Figure 5.1.1-8 CONTROL AND SHUTDOWN ROD LOCATIONS
3 1.2'ORE LOADING INSTRUMENT'HECK 9101-S-04 TEST OBJECTIVES The purpose of this test was to verify the proper alignment and calibration of the temporary core loading instrumentation prior to the start of initial fuel loading. The test setup and reestablish the original Westinghouse calibration conditions, such that obtained test data would validate NI/instrumentation operability. Three (3) NI detector high voltage and discriminator settings were varied in order that specific NI performance plateaus (flat horizontal portions of the performance curve) could be identified. The high voltage and discriminator, settings which established the plateaus, were then utilized during the actual core loading. TEST METHOD I Specialized Westinghouse neutron detecting instrumentation was positioned on the Containment286'efueling deck and then verified against the Westinghouse specifications. 'hree (3) neutron detectors were then positioned approximately 1 foot apart and within 3 feet of a temporary neutron source (3.88 Ci Am-Be). At this position, with the instrument set at a high voltage setting of 2000 volts, 9989 CPM resulted. This was established in "order that the resulting CPM/high voltage plateau be within the known and expected testing bounds (see Figure 3.1.2-1). Following this initial setup specific high voltage and discriminator settings selected by varying the discriminator setting from 0 to 6. A discriminator setting positioned at the midpoint on the plateau was chosen for operation (Figure 3.1.2-2) ~ RESULTS and ACCEPTANCE CRITERIA COMPARISON Temporary detectors had their high voltages and discriminator voltages adjusted utilizing the methodology outlined above. The final voltage utilized was 1950 volts while the discriminator setting was 2.5 ~ FIGURES and TABLES Figure 3.1.2-1 Temporary NI Voltage Plateaus Figure 3.1.2-2 Temporary NI Discriminator Settings HIS/StartupMan/43/OS3
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%I 0 THROUGH 6 gil F I GURE 3.1.2-2
3.1.3 REACTOR COOLANT AND ASSOCIATED SYSTEMS FILL AND VENT FOR INITIAL FUEL LOAD TEST OBJECTIVES Following the extensive preoperational and flushing test program in which testing was accomplished using demineralized water it those systems connected to the RCS with borated water of a certai' is necessary to fill concentration. The purpose of this test was to perform the initial the 470,000 gallon Refueling Water Storage Tank (RWST), the 36,000 gallon fill of Boric Acid Tank, the Reactor Coolant System, ECCS Systems, and Transfer Canal with the proper concentration. of boric acids The. following systems in part or in entirety were filled: Chemical and Volume Control System Residual Heat Removal System Safety Injection System Boric Acid Transfer System Passive Safety Injection, System Purification
~
Spent Fuel Pool I Containment Spray System The performance of thisr procedure was a prerequisite to Initial Fuel Load. TEST METHOD Prior to any filling, all tanks and systems were verified to be completely drained to ensure no dilution occurred during the fill process'n order to speed the batching process from the Boric Acid Batch Tank (375 gallons) the plant operating procedure was not utilized. Instead "Hot Loads" of approximately 7900 ppm were mixed- and sent to the BAT. The BAT was initially filled to 6X (3,500 gallons) with demineralized water to meet Boric and Transfer pump recirculation net positive suction head requirements. The batching process continued until the BAT was filled then in turn the RWST was blended through the use of RCS makeup along with individual batching directly to the RWST. In order to ensure adequate mixing the Containment Spray Pumps were operated in recirculation on the RWST through the system test line. In addition, the Spent Fuel Pool Purification Pumps were operated in recirculation through the RWST and the systems backflushable in line filter. Both these systems were operated until the final boron concentration was achieved in the RWST. s The Reactor Coolant System was gravity fed from the RWST through High and Low Head Safety Injection Systems and in this manner, a partial BTRg was accomplished. fill Venting was perdormed as necessary and vessel. level of CVCS and MIS/StartupMan/46/OS3
was established at 6 to 12 inches above the vessel nozzles. At this point RHR pumps and charging pumps were operated auxiliary spray, high to fillinjection, all other flow paths including, alternate charging, and low head safety letdown, normal charging, and emergency boration. All CVCS and BTRS demineralizer beds were filled; however, were not flushed for sulfides or equilibrium boron at this time. Passive Safety Injection Accumulators were filled using normal blended flow and the refueling cavity transfer canal was filled above the transfer canal twice to complete the test. At the test completion all systems were restored per plant operating procedures. RESULTS and ACCEPTANCE CRITERIA COMPARISON A total of systems 435 batches; (<<7700 ppm) were required to fill all associated to the proper boron concentration by dilution. All systems were properly filled and vented prior to initial fuel load with the following results.'WST
- 2078 ppm BAT 7632 ppm FIGURES and TABLES None MIS/StartupMan/47/OS3
3 ~ 1.4 REACTOR COOLANT SYSTEM BORON CONQQG.'RATION SAKPLING 9101-S-03 'ja TEST OBJECTIVE Prior to initial fuel load it is necessary to ensure uniform boron concentration in all areas directly connected to the RCS so that the starting of an idle pump will not cause a change in reactivity by the insertion of dilute makeup water. This test was performed to verify correct, and uniform boron concentration in unisolated portions of the reactor coolant system (RCS) and the directly connected portions of the auxiliary systems as required for core loading. This test was also designed to ensure that the possibility of an inadvertent dilution of the RCS during core loading was minimized by performing technical specification required lineups. TEST METHOD
, Prior to the commencement of core loading, the RCS vas sampled and verified to meet the specified water chemistry criteria stated in the test. Each of the RCS hot legs, the Safety Injection System Accumulators, the Safety Injection System, both RHR Systems, all three Charging Safety Injection Pumps, the Containment Spray System (Refueling Water Storage Tanks) emergency and normal boration paths vere sampled, and that water was verified to contain at least 2000 ppm boron. An exception to this was the boric acid storage tank which had a limit of > 7000 ppm boron. In the case of dual safety trains, the pump in each train was operated prior to sampling.
' Following the initial verification of the chemistry in the reactor coolant system, four samples were taken at equidistant depths from the reactor vessel, along with a sample from the operating residual heat zemoval train. samples were then analyzed for boron to verify a uniform boron concentration These i throughout the entire system. All samples were verified to be within 30 ppm of each other. At this time, sampling continued of the RHR train every one hour throughout the coze loading process in accordance with the Initial Fuel Load procedure. RESULTS and ACCEPTANCE CRITERIA COMPARISON During the execution of this test, all acceptance cziteria were adequately met for each system that was sampled. No corrective actions in the core loading process vere needed to meet the acceptance criteria of this test. All systems that weze sampled weze shown to contain a boron concentration of at least 2000 ppm. The boric acid storage tank had a concentzation of 7509 ppm bozon. These results ensured that there was no inadvertent dilution of the RCS boron level during core load. The lowest boron concentration found vithin the system during core load was 2084 ppm on November 17, 1987. The largest boron concentration within the RCS was a maximum value of 2110 ppm on November 18, 1987. FIGURES and TABLES None MIS/S taz tupMan/48/OS3
3 ~2 POST" CORE LOADING TESTING C 3.2.1 AUTOMATIC STEAM GENERATOR LEVEL CONTROL LOW POWER 9103-S-29 TEST OBJECTIVES Steam generator automatic control at low power consists of nuclear power rate of change circuit and a standard level deviation circuit to maintain steam generator level at a programmed 66X. Changing feedwater flow configuration and major power changes necessitated the need for multiple performances of automatic steam generator level control tests. Level control stability of the three steam generators was- demonstrated while operating on the feedwater bypass regulating valves and the main feedwater regulating valves. Level control stability was also demonstrated while transferring feedwater flow between the feedwater regulating bypass valves and the main feedwater regulating valves. TEST METHOD In order to verify level control stability while operating on the bypass or main feedwater regulation valves, a 5X level deviation 'was manually established in each steam generator. The control system was then transferred to the automatic control position. The actual steam generator level was monitored to verify it returned to the programmed level of 66X 2X within three times the process instrument reset time constant. Following the level demand change, a step change equivalent to 1.25X increase in nuclear power was input to the power demand portion of the control system. The actual steam generator level was again monitored to verify it returned to the program level of 66 + 2X within three times the process instrument reset time constant. In order to verify level control stability while transferring between the feedwater bypass regulating valves and the main feedwater regulating valves, steam generator level was monitored while transferring from one to the other. Initially the bypass valve was placed in AUTO with the main valve in MANUAL. At that time, the main valve was opened manually while observing the bypass valve automatically closing. At 15 20X open the bypass valve was placed in MANUAL and the main valve was placed in AUTO. The bypass valve was then completely shut while observing automatic opening of the main valve. Actual level was verified to stabilize after completing transfer of controls This evolution verified stability when transferring to the main feedwater regulating valves in the case of power ascension or to the bypass regulating valve in the case of power discension. RESULTS and ACCEPTANCE CRITERIA COMPARISON When given a 5X level deviation (high or low) or a 1.25X nuclear power deviation, the bypass regulating valves returned steam generator level to the programmed level within. 37 ' minutes as expected. This was performed at 7.5X power.. MIS/StartupMan/49/OS3
When transferred to automatic operation the main feedwater regulating valves returned the steam generator level to the programmed level within 10 minutes. as expected. Steam Generator Level overshoot and undershoot was monitored during automatic operation. Steam Generator A was shown to have a 2X offset in the flow control circuit. The offset was recalibrated by maintenance and verified acceptable against acceptance criteria. No changes to process instrumentation setpoints (gain of reset) were made at this power level. Tables 3.2.3-1 through 3.2.3-3 summarize the results. FIGURES and TABLES Table 3.2.1-1 Bypass Reg. Valve Level Control Response (Level Deviation) Table 3.2.1-2 Bypass Reg. Valve Level control Response (Nuclear Power Deviation) Table 3.2 1-3 Transfer Response From Bypass To Main Feedwater Regulating Valve at 20X Power MIS/StartupMan/50/OS3
BYPASS REGULATING VALVE LEVEL CONTROL RESPONSE (LEVEL DEVIATION) TABLE 3.2.1-1 ACCEPTANCE ACTUAL TIME STEAM LEVEL CRITERIA RESPONSE GENERATOR DEVIATION SECONDS IN SECONDS 5X INCR 2250 690 5X INCR 2250 1800 5X INCR 2250 1350 5X DECR 2250 2230 5X DECR 2250 2112 5X DECK 2250 2070 BYPASS REGULATING VALVE LEVEL CONTROL RESPONSE (NUCLEAR POWER DEVIATION) TABLE 3.2.1-2 ACCEPTANCE ACTUAL TIME STEAM POWER CRITERIA RESPONSE A'UCLEAR GENERATOR DEVIATION IN SECONDS IN SECONDS 1.25 INCR 2250 1770 1.25 INCR 2250 1570 1 '5 INCR 2250 1332 1.25 DECR 2250 1220
~
B 1.25 DECR 2250 2080 1.25 DECR 2250 1230 MIS/StartupMan/51/OS3
TRANSFER RESPONSE FROM BYPASS TO MAIN FEEDWATER REGULATING VALVE AT 20K POWER TABLE 3.2.1-3 ACCEPTANCE ACTUAL TIME STEAM CRITERIA RESPONSE GENERATOR IN SECONDS IN SECONDS A 540 < 600 540 < 600 C 348 < 600 MIS/StartupMan/52/OS3'
3 ~ 2.2
~ AUTOMATIC STEAM GENERATOR LEVEL CONTROL TEST 9104-S-05 9106-S-16 9107-S-12 TEST OBJECTIVE Steam generator automatic control consists of a steam/feed flow deviation circuit and a standard level deviation circuit to maintain steam generator level at a programmed 66X .. The Automatic Steam Generator Level Control Tests during the increase in powez were performed to demonstrate the proper response of the Automatic Steam Generator Level Control System and the Main Feedwater Control Valves at the 30X, 75X, and 90X power plateaus.
TEST METHOD Four test methods of testing were used to verify proper Steam Generator Level Control System operation. First a stability test of steam generator level control at steady states was performed by transferring the S/G level control switch to auto from manual at 66X of S/G level. Next a response test of the steam generator level control to a deviation of programmed level setpoint was performed by step increasing the S/G programmed level from 66X to 71X using a voltage simulator in the process instrument control system. A steam generator level control response test to a Feedwater/Steam Flow deviation was performed by step increasing and decreasing the steam flow by + 0.5 volts (equivalent to 7X of steam flow) 'using a voltage simulator. Finally a steam generator level control response test to an actual S/G Level deviation was performed by transferring the level control switch to auto after manually increasing and decreasing the S/G level to 71X and 61X. RESULTS and ACCEPTANCE CRITERIA COMPARISON The Automatic Steam Generator Level Control Test at 30X power was commenced with Westinghouse recommended initial proportional gains of 2.0X Flow/X Level Span and reset time of constant 1800 seconds for the level controllers, and 0.6X Value Lift/X Flow and reset time constant of 200 seconds for the flow controllers. This recommendation was to reduce the chances of a controller instability causing a reactor'rip. Various test exceptions were initiated at 30X due to erratic valve instabilities at any system setpoints ~ During the testing at 75X plateau, the following adjustments were made in order to verify the acceptance criteria.'. Adjusted the flow and level controller gain and reset times. GainReset Level Controller 3.0X420 sec Flow Controller 0.3X 60 sec MIS/StartupMan/53/OS3
- 2. Closed down the needle valve between valve positioner and volume booster of the Feed Regulating Valve from a setting of 6.0 t'o 2.5.
(scale of 10 units) to decrease a transport coupling time from positioner to booster and ultimately reduce overshoot.
- 3. Reduced AP across the Feed Regulating Valve by throttling of MFP discharge valve. This action dropped the value of 4P from approximately 1000 psid to 150-250 psid and significantly reduced irratic instabilities.
The final automatic steam generator level control test at 90X plateau was successfully completed and all test results were acceptable however, the Main Feedwater Pump Manual Discharge valve remained throttled. Table 3.2.2-1 shows
. the final values for the level and flow controller gains and reset time constants after completion of 90X plateau.
FIGURES and TABLES 3.2.2-1 100X Steam Generator Automatic Control Gain Setpoints c C MIS/StartupMan/54/OS3
100X STEAM GENERATOR AUTOMATIC CONTROL GAIN SETPOINTS TABLE 3.2.2-1 GAIN RESET TIME Level Controller 3.0X/X 420 seconds Flow Controller 0.2X/X 60 seconds MIS/StartupMan/S5/OS3
3 2.3 MAIN FEEDWATER PUMP PERFORMANCE TEST 9103-S-34 I. TEST OB JECTIVES The Main Feedwater Pumps were unable to be run at any significant capacity prior to power ascension. The purpose of this test was to verify that the Main Feedwater Pumps would meet or exceed their respective head/capacity curves and the Main Feedwater Pumps and Motors would operate with beaxing vibration and temperatures, speeds, voltages, and currents within acceptable limits. TEST METHOD Main Feedwater Pump parameters were recorded at low power, 50X, 75X, 90X, and 100X. powex test plateaus. The following information was recorded from the ERFIS computer at each of the power levels for each Mai:n Feedwater Pump and Motor.'uction temperature and pressure, discharge pressure, suction flow, stator temperature, and bearing temperatures. Data collected locally in the field included bus voltages, motor currents, speed, and vibration. The suction temperature and px'essure were used to density compensate the suction flow measurement. The suction pressure and discharge pressure were then used to calculate total developed head after which the suction flow and total developed head were then plotted for each pump at each of the test power levels. ' RESULTS and ACCEPTANCE CRITERIA, COMPARISON Each Main Feedwater Pump met or exceeded vendor., Therefore, the Acceptance Criteria its was pump met. curve supplied by the The other parameters that were measured, stator temperature, bearing temperatures, bus voltages, motor currents, and speed for each of the Main Feedwater Pumps at each of the power levels, met the Acceptance Criteria. However, Main Feedwater Pump and/or Motox Vibration at each of the power levels for each of the pumps were in excess of the Acceptance Criteria'pon completion of the test, all of the vibration data that did not meet the Acceptance Criteria was compiled via a plant change request and sent to plant engineering for their review and evaluation. Engineering evaluated the data and justified continued opexation. Tables 3.2.3-1 and 3.2.3-2 summarize the 100Z power vibration data for MFW pumps 1A 6 1B respectively. FIGURES and TABLES Figure 3.2.3-1 Main Feed Pump 1A 100X Data Figure 3.2.3-2 Main Feed Pump 1B 100X Data MIS/StartupMan/56/OS3
MAIN FEED PUMP 1 A I OOFo VALUES Fl GURE X2,3-1 MFP 1A t1FP 1A MOTOR MFP 1 A 100Po REACTOR POVlER FLO'WRATE 14,457 gprn MFP 1A MOTOR VIBRATION (DISPLACEMENT) ACCEPTANCE DIRECTION FREQ. CRITERIA MORIZONTAL 3600 cpm .38 mi)s .75 mils i 1mil VERTICAL 3600 cpm .46 mils 1.0 mils < 1mil AXIAL 3600 cpm .72 mils c 1mH MFP 1A PUMP VIBRATION (VELOCITY) ACCEPTANCE DIRECTION FREQ, (I ~FR ~Q. g} CRITERIA MORIZONTAL 25,200 cpm 275 ips 25.200 cpm .13 ips .314 ips VERTICAL 25,200 cpm .15 ips 25,200 cpm .069 ips .314 ips AXIAL 25,200 cpm .23 Ips < .314 ips.
HAIN FEED PUMP 18 100Fo VALUES F I GURE X2.3-2 MFP 18 MFP IB MOTOR 04 03 NFP 18 100%%u'EACTOR POV/ER FLOV/RATE 13,790 gprn MFP 1B MOTOR VIBRATION (DI SPLACEllENT)
. ACCEPTANCE DIRECTION ~
FREQ. 2 CRITERIA HORIZONTAL 3600 cpm 1.81 mils .94 mils < 1mil VERTICAL 3600 cpm 2.25 mils I.M mils < 1mil AXIAL 3600 cpm 2.88 mils < 1mil NFP I B PUNP VIBRATION (VELOCITY) ACCEPTANCE DIRECTION FREQ.(1) FREQ. CRITERIA HORIZONTAL 360Q cpm .081 ips 25,20Q cpm .076 ips < .314 ips VERTICAI. 25,200 cpm .17 ipa 25,2QQ cpm .026 ips < .314 fps AXIAL 3600 cpm .044 ips < .314 ips
3 2.4 STEAM GENERATOR TEST'OR CONDENSATION INDUCED WATER HAMMER 9104-S-13 TEST OBJECTIVES During normal plant start-up, feedwater. to the steam generators is realigned from the auxiliary feedwater nozzles to the main feedwater nozzles as plant output increases to 20K. The purpose of this test was to demonstrate that this realignment of flow can be performed without causing any condensation induced water hammer due to bubble collapse in the steam generator preheater section or main feedwater piping. TEST METHOD As plant output was being increased from 15K to 20X, test personnel were stationed to observe feedwater piping from the turbine building through the steam tunnel to the secondary shield wall in co'ntainment. The main feedwater isolation bypass control valves were opened to begin forward flushing (i.e, warmup) of the main feedwater piping as the test personnel observed for any indication of water hammer. When the proper permissives were met, the main feedwater isolation valves were opened and test personnel again observed for any indication of water hammer. RESULTS and ACCEPTANCE CRITERIA COMPARISON Throughout the test, no pipe motion of any kind was observed by test personnel, indicating that the transfer'rom auxi.liary feedwater nozzles to main feedwater nozzles was performed smoothly with no water hammer. FIGURE and TABLES None MIS/StartupMan/59/OS3
3.2.5 INCORE MOVABLE DETECTOR SYSTEM CHECKOUT 9101-S-09 9102-S-20 TEST OBJECTIVES The Incore Movable Detector- System enables incore monitoring to be performed from a remote location for the purposes of obtaining a core flux map and ultimate evaluation of incore parameters including Fq (z), FdH and Quadrant Power Tilt Ratio. The purpose of this test was to verify the ability of the Incore Movable Detector System to position detectors in all paths and to start and stop the detector properly. Some of the features verified include, but are not limited to.') Operation of the safety limit"switches.
- 2) Operation of the withdraw limit switches.
- 3) Cable drive encoders properly zeroed.
- 4) Operation of the 5-Path Selector Device, interlocks, and indicator lights.
- 5) Operation of the 10"Path Selector Device, interlocks, and indicator lights.
- 6) Operation of the Path Display Panel on the incore instrumentation rack.
- 7) Verification of drive unit travels at the designed speed of 12 0.36 ft/min., in low speed and 72 2.16 ft/min. in high speed.
- 8) Each drive unit accesses and inserts the detector in each position in the Normal and Calibrate modes in automatic control such that a neutron flux map can be performed.
- 9) Use of the as-built information to setup top and bottom core limits for the incore drive units.
- 10) As neutron flux becomes available, top and bottom core limits were set based on grid strap locations for Normal and Calibrate mode.
- 11) As neutron flux becomes available set the top and bottom core limit set points for Emergency and Common mode of operations.
- 12) The chart drive units operates when in scan and record mode.
- 13) The operation of the Movable Detector System, Leak Detection System, and drain.
TEST'METHOD The tests were conducted by actually operating the system as describe in the Technical Manual and in accordance with plant procedures. Initially a dummy detector on a cable wag used. to set, upper and lower limits, but later, at power a set of five U detectors and cables were installed .and used. The items in the objectives were verified during operation. MIS/StartupMan/60/OS3
Using the as-built design information, the top and bottom core limit settings. were determined as follows'. Top of Core Setting = Thimble Path Total " 14 inches Bottom of Core Setting = Top of Core Setting " 170 inches. Automatic stops were verified at both the bottom and top limit setting. Similar checks for each detector in the Calibrate and Storage paths were performed. Once substantial neutron flux became available the top and bottom settings were fine tuned by locating the fourth grid strap and position (hr ) and then performing the following calculation: Top of Core Setting = hr X + 78 inches Bottom of Core Setting = Top of Core Setting - 169 inches. Emergency and Common, top and bottom settings were measured by running different detectors through a common path, locating the fourth grid strap center and finding Ce, the emergency path correction factor from Ce = hre-hrx where hre is the forth grid strap position in emergency. This correction factor is then applied to the other Normal settings to determine the emergency settings. A similar procedure was'sed for the common mode settings. ( RESULTS and ACCEPTANCE CRITERIA COMPARISON Many problems were encountered during the performance of these tests. A majority have been corrected; however, some problems were not corrected during power ascension but are scheduled for the initial refueling outage. The items not corrected are currently being tracked as Plant Nuclear Safety Committee action items. It was discovered, that the tubes connecting the five and ten path rotary devices were too narrow and did not permit detector passage without periodic binding. This was corrected by replacement with proper size tubes'ost other problems involved electronic logic, encoders, or indicator lights and were corrected. A more serious problem that currently remains is with Detector C travel in its normal paths. At various times during Power Ascension Testing Detector C satisfactorily accessed location 1, 2, 7, and the calibrate channel while the other positions were blocked. with hardened debris and neolube. Westinghouse Technicians were employed to clean the tubes during an early maintenance outage however, that work did not allow the blocked paths to be traversed. None of the "good" paths proved reliable enough to risk during subsequent flux mapping and currently the Incore Detector System has 41 reliable paths. The solution to the Detector C problem is to check the 10 path transfer device alignment or replace the incore thimbles which is scheduled for the next refueling outage. MIS/StartupMan/61/OS3
FIGURES and TABLES None c MIS/StartupMan/62/OS3
3.2.6
~ ~ ROD POSITION INDICATION"9102-S-12 TEST OBJECTIVES The Rod Position Indicating System monitors control rod position in the core. These systems are technical specification related and include Digital Rod Position Indication and Bank Demand Step counters. The Rod Position Indication checkout test procedure was performed to verify the following indication and alarm functions fox- each individual RCCA: system accuracy for digital rod position indication (DRPI), Pulse-to-Analog Convertor, Readouts, Process Computer (ERFIS) indication, calculated P/A voltage steps and rod at bottom indication. In the process of demonstxating the indication and alarms above, it was shown that all RCCAs operated over their full range of travel in accordance with Operation Surveillance Tests.
TEST METHOD Prior to testing a Statistical Reliability Test (Chi-Squared) was performed on both source range channels to ensure pxoper perfoxmance during rod movement. The method of testing involved using actual rod position data by moving individual RCCAs and observing. .indications and alazms that resulted. Individual rods were disconnected from their group using the manual disconnect switches in the Main Control .Room. All RCCAs were'ested in this lift manner. RESULTS and ACCEPTANCE CRITERIA COMPARISON Accuracy zequirements for the digital .rod position indication system from the vendor technical manual were +4 steps in comparison with associated group step countez's. All control banks met this criterion over the entire range of rod travel from rod bottom to 228 steps. Shutdown banks met this criterion in the ranges from zod bottom to 18 steps and from 210 to 228. steps. The transition 'x'egion of each shutdown bank was shown to indicate correctly between 21 +4 steps as indicated on the step counters. Rod bottom indication was shown to occur for all shutdown and control rods 0 steps on the step counters. The rod control system P/A Converter Voltages, digital zeadouts were verified to be within 1 step of the group counter position. Process computer indication agreed within 4 steps of the DRPI indication. FIGURES and TABLES None MIS/StartupMan/63/OS3
3.2 7 SHIELD SURVEX TEST 9103-S-33 9105-S-12 9108-S-20 TEST OBJECTIVES The shield survey tests were performed to determine dose levels at specified radiation base points throughout the plant, and to verify the effectiveness of radiation shielding to gamma and neutron radiation in accordance with FSAR radiation zone maps. TEST METHOD Gamma radiation dose rate values were established by surveying with portable survey instrumentation in the Waste Processing Building, Reactor Auxiliary Building and the Reactor Containment. Gamma and neutron radiation dose rate values were established in the Containment and certain penetration areas with a,corrected dose rate of gamma p1us neutron dose rates. RESULTS and ACCEPTANCE CRITERIA COMPARISON The effectiveness of neutron radiation shielding in Containment was found to be in-excess of radiation zone maps at. 50X and 100X. During the. performance of the 50X power test, eleven test, exceptions were noted. All of these exceptions were for radiation base points in The highest dose rates occurring on the 286'refueling deck)
~
containment. elevation and ranged fro'm 30 mrem/hr to 960 mrem/hr. These exceptions were
. acceptable based on evaluation and the FSAR changes were initiated to modify the radiation zone maps.
At 100X power a total of 25 test exceptions were noted. The 25 included the same radiation base points in containment plus some in the Reactor Auxiliary Building. Again, these were to be evaluated by .Engineering and a change initiated to the FSAR. A question arose during results review by Plant Nuclear Safety Committee about equipment qualification in high radiation areas since surveys were showing inaccuracies in the FSAR zone maps. Evaluation by Engineering and Ebasco Services showed the integrated 40 year dose and the integrated 1 year dose following a design basis accident to be approximately 8.9 x 10 Rads ~ According. to Ebasco, all equipment is qualified to approximately 1 x 10 Rads ~ FIGURES and TABLES None c MIS/StartupMan/64/OS3
3.2 ~ 8 RTD BYPASS LOOP FLOW VERIFICATION 9102-S-05 '~CTIVE The RTD Bypass Loops contain the RCS control and protection RTDs. These circuits develop Tavg and hT control and protection signals to various automatic control systems and OPAT and OTAT reactor trips and runback. The RTD Bypass Loop Flow Verification test procedure was performed to verify the actual hot leg RTD bypass loop flow rates were greater than the flow rate required to meet a 1.0 second transit time, which is used as accident analysis design basis. In addition, RTD bypass low flow alarm actuations were verified. TEST METHOD Required minimum flow for a one second transit time was first calculated from actual pipe dimensions and piping diagrams. Next, actual flow rates were determined for all three hot and cold leg RTDs by isolating the hot 'leg and recording the cold leg value and then repeating the steps for determining the hot leg flow. These measured values were then compared to the minimum values to verify acceptability. V RESULTS and ACCEPTANCE CRITERIA COMPARISON The calculated flow rates deri~ed from the measured values exceeded the minimum required flow'o'r the hot leg RTDs in all cases and therefore met the loop transport time acceptance criteria of less than 1.0 second. Loop three was the least conservative with a margin of 2 4 gpm. Loops one and two exceeded the minimum required value with flow rates in excess of the minimum of 12.4 and 12.9 gpm, respectively. Table 3.2.8-1 Summarizes the test results. FIGURES and TABLES Table 3.2.8-1 RCS RTD Bypass Hot Leg Transport Times MIS/StartupMan/65/OS3
RCS RTD BYPASS HOT LEGS TRANSPORTS TIME TABLE 3.2 '-1 Actual Difference Actual Calculated Required Cal. Req. Transit Loo Flow ( m) Flow ( m) ( reater than 0) Time (sec) 135.7 123.3 12.4 0.909 136.2 123.3 12.9 0.905 125.7 123.3 2.4 0.981 ( 6 MIS/StartupMan/66/OS3
3~2~9 REIACTOR COOLANT SYSTEH (RCS) STOW HEASUREHAOIT HOT STANDBY 9102-3-03 TEST OB JECTIVES RCS flow determination is an instrument calibration adjustment to determine for the first time, RCS flow instrument differential pressures with the fuel core installed. The RCS Flow Measurement at Hot Standby test procedure was performed to determine the RCS flow rates for each of the 3 loops and then the total RCS flow rate. TEST METHOD Prior to criticality, data was obtained for the installed elbow tap differential pressure (d/p) instrumentation and used to determine the RCS flow rates, Data was recorded every minute for ten minutes which included the following: RCS cold leg RTD resistance readings, and the d/p transmitter output voltage. Then the RTD resistance readings were evaluated to ensure the temperature did not deviate from 557 + 2'F during data acquisiti.on. Each loop has three flow transmitters from which a d/p measurement was taken and corrected for zero shift. The average of ten d/p readings per transmitter were used to determine three flow .,rates for each loop by using the most current s'caling document for Reactor. Coolant Cold Leg Volumetric Flow Rate. These three flow rates were averaged to obtain the loop average flow, and then all three loops average flow rates were added to obtain the total RCS flow rate. 4 RESULTS and ACCEPTANCE CRITERIA COMPARISON The total RCS flow rate was expected to be equal to or greater than 263, 520 gpm and less than or equal to 321,300 gpm. During the initial performance of this test all transmitters were found out of tolerance while determining the transmitter zero shift. Upon retest, the expected flow rate for each loop was greater than or equal to 87,480 gpm with the actual measured average loop flow rates being.'oop 1 = 104,952 gpm', Loop 2 = 105,725 gpm9 Loop 3 = 107,516 gpm. The sum of the average loop flow rates gives the total flow rate of 318,194 gpm Table 3.2.9-1 summarizes the test results. The RCS cold leg temperature was also verified to remain between 555'F and 559'F so as not to invalidate the calculation of flow rates. EIGURES and TABLES Table 3.2.9-1 RCS Flow Rate at Hot Standby MIS/StartupMan/67/OS3
RCS FLOW RATE AT HOT STANDBY TABLE 3.2.9-1 INDIVIDUALLOOP TOTAL FLOW FLOW Loo 1 104 952 m 318,194 gpm Loo 2 105 725 m Loo 3 107 516 m C MIS/StartupMan/68/OS3
3.2;10 EEACTOE COOLAET STSTEE FLOW COASTOOWN 9102-9-04 TEST OBJECTIVES Adequate RCS flow coastdown is necessary to ensure necessary margin to DNBR upon a loss of forced reactor coolant flow. Without coastdown effects a rapid increase in reactor coolant temperature would ensue. The RCS Flow Coastdown test was performed with the unit at Hot Standby to verify the measured core flow exceeds or is equal to the flow assumed in the FSAR accident analysis. In addition, the time delay for low flow, trips was verified to be within acceptable limits. TEST METHOD Permissive P-8 was bypassed to allow the trip of all three RCPs simultaneously. Strip chart recorders were connected. to the solid state protection system to monitor all three loops of reactor coolant flow characteristics, reactor trip breaker positions, and RCP'reaker status' trip of all three RCPs was actuated by a single test switch in the protection cabinets, all nine sensor (flow transmitters) were evaluated for data quality (Chavenets Criterion) and eliminated from the final calculations if shown as unreliable. Data from the strip charts was then plotted on various graphs to verify acceptability of the measured flow values (inverse loop flows and flow coastdown time constant) and low flow time delays'ESULTS and ACCEPTANCE CRITERIA COMPARISON The time delays for the low flow trip met the required maximum value of 1.0 seconds. The actual value obtained was 0.73 seconds. Based on Westinghouse design flow calculations, the minimum Flow Coastdown Time Constant (TAU)D was determined to be 11.71 seconds. The acceptance criteria stated the time constant must have been greater than 11.71 and the actual time constant measured (TAU)m was 13.13 seconds. FIGURES and TABLES None MIS/StartupMan/69/OS3
3.2.11 REACTOR COOLANT SYSTEM LEAK RATE TEST 9102-S-02 TEST OBJECTIVES The purpose of this procedure was to verify the Reactor Coolant System (RCS) leak rate after the system had been closed, to measure RCS identified and unidentified leakage rates, and verify the rates are less than the maximum allowable in accordance with Technical Specifications. TEST METHOD With the. plant in Hot* Standby conditions, prior to Initial Criticality, the reactor coolant system was tested to verify leak tightness. While RCS temperature remained constant, a 'monitoring of VCT level, RCDT level, Pressurizer level, and PRT level was initiated. The procedure was run in conjunction with operations normal surveillance. test for leak rate determination,'owever, the duration of the monitoring period was increased to three hours instead of one hour. At the completion of the monitoring period a calculation was performed to determine identified and unidentified leakage. RESULTS and ACCEPTANCE CRITERIA COMPARISON The acceptance criteria for this test was to'erify that RCS leakage would
.be.'ess than or equal to 1 gpm unidentifiable leakage and less than or equal to 10 gpm ident'ifiable leakage. Included in the calculation were the normal contai'nment floor sumps leak rate (which was zero) and the reactor vessel .<lange leakoff (which was zero). No leakage was indicated (i.e., no increase
. in level), and during the test duration, the containment floor sumps did not run. After the initial run of the procedure and upon NRC inspector review an inconsistency was found in the calculation of Pressurizer Gal/X level and Gal/'F of Tavg change. A retest of the calculation was performed after the curves of Pressurizer Gal/X level. and Gal/'F were modified. The unidentified leakage was determined to be 0.4 gpm. The identified leakage was determined to be 0.33 gpm. FIGURES and TABLES None MIS/StartupMan/70/OS3
3 2 12 CONTROL ROD DRIVE MECHANISM TIMING TEST 9101-S-06 (COLD) 9102-S-08 HOT) TEST OBJECTIVES The purpose of the test were to verify the proper slave cycler timing, to perform a mechanism timing check of each control rod drive mechanism (CRDM) with a rod cluster control assembly (RCCA) attached prior to initial use of the mechanism, under the conditions stated below. TEST METHOD A Statistical Reliability Test (Chi-squared) was performed prior to any rod movement to ensure source range channel response. This test was performed under two plant conditions: Mode 5 Cold, No Flow, and Mode 3 - Hot, Full Flow. The proper operation of the slave cycler was verified under cold, no flow conditions. The CRDM operational check, was performed under both conditions, as was the verification of rod speed. During the slave cycler timing procedure a single rod was withdrawn 48 steps to ensure the rodlet tips were at least six steps above the constricted thimble tube dashpot region. The rod was withdrawn 6 steps then inserted 6 steps, while slave cycler timing was recorded. The data monitored included lift coil currents, movable and stationary gripper currents, and a sound pickup from a 'carbon microphone attached to the top end of the rod travel housing and timing trace. The tested rod was inserted to the bottom of the core and the above procedure was repeated for each power cabinet. The CRDM operational check was performed with all rods positioned at the core bottom. A single rod was withdrawn 48 steps. Next, data was recorded while the rod was withdrawn 12 steps, and then inserted 12 steps. The same parameters were monitored here as in the slave cycler timing procedure. This was completed for all control and shutdown rods (Reference Figure 3.1.1-8 for core locations). RESULTS and ACCEPTANCE CRITERIA COMPARISON The slave cycler timing traces were found to be acceptable for all five po~er cabinets. The operability of the CRDM was verified for all 52 CRDMs by demonstration of control rod insertion and withdrawal. FIGURES'nd TABLES None MIS/StartupMan/71/OS3
3.2.13 ROD DROP TIME MEASUEBKNT 9101-SW7 9101-SW8 9102-S-09 AND 9102-S-10 TEST OBJECTIVES The purpose of these procedures were to determine the amount of time required to drop each RCCA from its fully withdraw position, 228 steps, to the point of entry into the dashpot region. This was done in accordance with Technical Specifications which states the maximum drop time as 2.2 seconds for hot full flow conditions. TEST METHOD With all 52 rods fully inserted and the RCS boron concentration greater than 2000 ppm, one bank of rods was withdrawn to 228 steps. At that point, the digital rod position indication (DRPI) was deen'ergized and fuses pulled to release the stationary gripper for one RCCA ,and drop that rod. A carbon microphone was attached to the top of the control rod drive mechanism to obtain a sound trace on a strip chart recorder. 'ther signals monitored were from the DRPI Data A cabinet only, the DRPI Data B cabinet only, DRPI Data A and B, and the stationary gripper coil voltage. Drop times were evaluated from the Data A and B voltage traces. The proper operation of the dashpot was also verified from the traces. Those rods which exhibited drop times outside the two-sigma (standard deviation) statistical limit were re-dropped an additional six times. This test was performed at four plant conditions.'old
'no flow, cold full flow, hot no flow, and hot full flow conditions.
C RESULTS and'CCEPTAHCE CRITERIA COMPARISOH All rods in all test conditions dropped in less than the Technical Specification requirement of 2.2 seconds. Table 3.2.13-1 shows times recorded for the conditions listed (bottom of dashpot). At all four test conditions, the voltage traces were examined and proper operation of the dashpot, region was verified. All rods outside the two-sigma limit. exhibited repeat time measurements with a band of 0.020 seconds. FIGURES and TABLES Table 3.2.13-1, Rod Drop Time Results Table 3.2.13-2 2-Sigma Results MIS/StartupMan/72/OS3
ROD DROP TIME TABLE 3.2.13-1 CONDITION AVERAGE FASTEST SLOWEST Cold No Flow 1.67 seconds 1.62 seconds 1.79 seconds Cold Full Flow 1.96 seconds 1.89 seconds 2.06 seconds Hot No Flow 1.56 seconds 1.52 seconds 1.59 seconds Hot Full Flow 1.76 seconds 1.72 seconds 1.87 seconds ROD DROP 2-SIGMA RESULTS TABLE 3 ' '3-2 No. Rods >2 Si ma Rods Cold No Flow F-8 L-ll Cold Full Flow B-6 C-9 L-11 Hot No Flow L-13 Hot Full Flow B-6 B-8 K-14 L-13 MIS/StartupMan/73/OS3
3.2
~ ~ 14 REACTOR COOLANT SYSTEM FLOW MEASKUBKHT 9105-S-14 9108-S-21 TEST OBJECTIVES RCS flow was measured at 50X to ensure adequate flow prior to exceeding power to 100X. At 100X power, technical specification compliance was verified. 'Adequate flow is essential to ensure design limits on peak local power density and minimum DNBR are not exceeded and that in the event of a LOCA the peak fuel clad temperature will not exceed the 2200'F ECCS acceptance limits. The RCS Flow Measurement test procedure was performed at 50X and 100X reactor power levels to determine the individual loop and total RCS flow rate.
TEST'METHOD While the plant was at 50X and 100X reactor power levels, data was obtained to determine the RCS flow pate. Using precision secondary test instrumentation on feedwater flow and steam pressure along with Process Instrument Cabinet voltage readings for feedwater pressure, 'feedwater temperature, RCS hot and cold leg temperatures, and pressurizer pressure, the resulting data was input to a calorimetric calculation after scaling equations were applied to the voltages.
- Feedwater Enthalpy and Steam Enthalpy values were determined from the acquired data and used to calculated Thermal Power.'
W(fw) x [h(steam) " h(fw)]
.Qr Qs 42 '6 MBTU/hr RCS'flow was calculated by determining RCS hot and cold leg enthalpies at 'the calculated pressurizer pressure.
P Loop Flow . x u
- 10 6
/[hHL h x 8.0208 (ft3 ~
min) Q Z CL ] gal hr RESULTS and ACCEPTANCE CRITERIA COMPARISON Table 3.2.14-1 summarizes the individual RCS flow rates at 100X and 50X power, as determined by calorimetric measurement. Both test procedures based acceptance on total RCS flow. At 50X, the following acceptance criteria was applied to the total flow '. RCS Total Flow > 298,950 gpm based on Technical Specification where RCS Total Flow > 292,800 x (1.0 + Cl); where Cl is currently equal to 2.1X uncertainty. ACTUAL RCS TOTAL FLOW AT 50X: 309,970 gpm At 100X, the acceptance criteria was as follows: RCS Total Flow > 298,950 gpm but < 321,300 gpm ACTUAL RCS TOTAL FLOW AT 100X: 305,623 gpm MIS/StartupMan/74/OS3
298,950 is based on Technical Specification values while 321,300 gpm is based on maximum system thermal hydraulic limits., 'All results were consistent with . expected values and met minimum flow requirements for total RCS flow rate. FIGURES and TABLES Table 3.2.14-1 RCS Flow Rates ( MIS/StartupMan/75/OS3
Flow Rates RCS TABLE 3.2 14-1 LOOP FLOW RATE g 50X FLOW RATE 100X A 104 210 m 102 579 B 104 500 m 100 911 101 260 m 102 133 TOTAL 309 970 10 305 623 m (' ( MIS/StartupMan/76/OS3
3 2.15 STEAM CYCLE SAMPLING 9105-S-15 TEST'B ELECTIVES Steam Cycle Sampling points S7, S8, S9, S10, and Sll could not be verified during Hot Functional Testing due to inqadequate flows. The purpose of this test is to verify the operation of secondary sample points S7, S8, S9, S10> and Sll, verifying that samples could be obtained and that sample temperature was adequately reduced. SAMPLE POINT DESCRIPTION S7 Heater Drain Pump lA & 1B Discharge S8 HP Feedwater Heater 5A & 5B Outlets S9 MS Drain Tanks 1A & 1B Slo MSR Crossover Pipe to LP Turbine B S11 LP Turbine Stage 10 Extraction TEST METHOD At. each sample point, the process root valve, was opened, flow was verified, and grab sample temperature was taken (S7 and SS only)." The test was performed, at SOX power. RESULTS and ACCEPTANCE CRITERIA COMPARISON All samples were obtained and S7'and S8 'temperatures were within 77 + 5'F SAMPLE PT. TEMP ~ S7 73'F S8 74'F FIGURES and TABLES None MIS/StartupMan/77/OS3
' 3.2. 16 PRESSURIZER SPRAY SETTING 9102-S-06 TEST OBJECTIVES HEATER CAPABILITY AND CONTINUOUS SPRAY FLOW This test had several objectives to accomplish., First, the test established the settings of the manual bypass valves around the pressurizer spray control valves to maintain spray line temperatures above the low temperature alarm setpoint. The test then demonstrated pressurizer control spray effectiveness by observing the pressure transient caused by a full spray actuation. Pressurizer 'heater effectiveness was also demonstrated by observing the pressure transient caused by full heater actuation. Finally, the test verified the ability of the pressurizer heaters to maintain sub"cooling during charging and steam flow transients'EST METHODOLOGY The settings of the manual bypass valves around the pressurizer spray control valves, was performed by initially closing each bypass valve and slowly opening each until the spray line low temperature alarm cleared on the Main Control Board. This was performed very slowly to allow for temperature change stabilization. Proportional heater and backup heater actuation and response was then observed for a 60 minute time period to verify the bypass spray was not too high causing abnormal heater demand. Pressurizer spray effectiveness was demonstrated by turning off all pressurizer heaters and manually opening from the MCB both pressurizer spray valves. Pressure was allowed to drop from approximately 2235 psig to 2000 psig prior to closing the spray valves and re-energizing the heaters. The observed transient pressure response was then compared to acceptance criteria limits. Auxiliary spray actuation was performed in a similar method as to the control, spray valves above. No acceptance criteria for the auxiliary spray valves was required. Pressurizer heater effectiveness was demonstrated by manually closing both pressurizer spray valves and energizing all pressurizer control and backup heaters. Pressure was taken from approximately 2235 to 2300 psig prior to de-energizing the heaters. The pressure transient was, then compared with the acceptance criteria limits. Pressurizer heater effectiveness to maintain sub-cooling margin during a charging transient was verified next. Charging flow was increased to maximum with one pump and with pressurizer heaters in automatic and pressurizer level contxol .in manual. Pressurizer level was allowed to increase from approximately 25X to 30K prior to stopping the transient. RCS Sub-cooling margin was then compared to the acceptance criteria. Pressurizer heater effectiveness to maintain. sub-cooling margin during a steam flow transient was the last transient verified. The Main Steam PORVs were used to establish a 10'F/hr cooldown rate in the RCS and a cooldown from approximately 557'F to 552'F was performed prior to reclosing the PORVs. RCS sub-cooling was then compared to the acceptance criteria. MIS/StartupMan/78/OS3
RESULTS and ACCEPTANCE CRITERIA COMPARISON All acceptance criteria except one was met during this test. The continuous spray flow valves were set to maintain the spray line temperature between 450'F and 550'F and above the spray line low temperature alarm. The pressurizer pressure response to full pressurizer spray actuation was slightly lower (faster depressurization occurred) than the nominal response, but fell within the allowable deviation in the acceptance criteria Figure 3.2.16-1) ~ The pressurizer heaters responded to maintain at least 50'F of RCS sub-cooling during a charging and steam flow transients. Actual'ub-cooling was approximately 85'F throughout each transient. The only acceptance criteria that was not met was the pressurizer pressure response to full pressurizer heater actuation (Figure 3.2.16-2). The actual pressure -rise that occurred was slightly less (4 psig) than the lower limit of acceptance criteria after. 240 seconds. The data was submitted to Westinghouse for evaluation, and the. Westinghouse recommendation was reported on letter CQL-9547. Their evaluation showed the degree of deviation noted in the pressure response was acceptable based on analysis that had been performed which indicated significant pressurizer heater capacity reductions (due to heater burnout, for example) do not materially affect the plant transient capability. The test exception was accepted as is the Plant Nuclear Safety Committee and by plant management. FIGURES and TABLES Figure 3.2.16-1 Nominal Pressure Response to Opening of. Pressurizer Spray Valves Figure 3.2.16-2 Nominal Pressure Response to Actuation of All Pressurizer Heaters MIS/StartupMan/79/OS3
NOMINAL PRESSURE RESPONSE TO OPENING OF. BOTH PRESSURI 2ER SPRAY VALVES (VIITH ALLO%ABLE DEVIATIOI<) - 2185 2135 2085 tu l R sp ns 2035 L w Ll N min esp ns pe LI lt 1985 20 40 60 , 80 100 120
. TIVE (SECONDS)
FIGURE 3.2,) 6-1
I N(FINAL PRESSURE RESPONSE TO ACTUATION OF ALL PRESSURIZER HEATERS (VflTH ALLOWABLEDEVI AT)ON) 2335 u ver LI 23 ls ln 2295 Lo er LI IX EU fV I 2275 Ac al e on e, 2255 2235 0 gp 80 '20 )60 200 240 Tl (ATE (SECONDS) F I GURE 3.2.16-2
3.2.17 ROD CONTROL SYSTEM TEST 9102-S-ll TEST OB JECTXVES The rod control system test demonstrated that the rod control system performed the required control and indication functions in the areas listed below, and verified the system was operational for use just prior to initial criticality.
- 1. 'ndividual Bank Rod Motion Test
- 2. Bank Overlap Operation Checkout
- 3. - Rod Control System Rod Blocks and Alarms TEST METHOD Each Rod Contxol Cluster (RCC) bank was singly withdrawn from the core 48 steps, inserted to 8 steps, and then fully inserted to 0 steps. This was done to verify the proper operation of the demand step counter, digital rod position indication (DRPI) system, and proper annunciator response. Bank overlap was set to 12 steps and all shutdown banks were withdrawn to 48 steps. Control banks were withdrawn in overlap until control bank D was at 18 steps to demonstrate proper overlap. All shutdown and control banks were then verified at 48 steps and a manual reactor trip was initiated.
1 The following rod blocks and alarms were checked by using jumpers and tripping various bistables:
- 1. Low Power Blocks of, Automatic Rod Withdrawal (C-5)
- 2. Automatic Rod Withdrawal Block When Control Bank D is above Withdrawal Limit (C-ll)
- 3. Intermediate Range High Flux Rod Step (C-1)
- 4. - Power Range High Flux Rod Step (C-2)
- 5. OTAT Rod Stop and Runback (C-3)
- 6. OPAT Rod Stop (C-4)
RESULTS and ACCEPTANCE CRITERIA COMPARISON The rod motion indicator (rod in/rod out) operated satisfactorily for all 9 RCC banks. The demand step counters functioned properly and rod speed indication was acceptable for each RCC bank and all speeds were acceptable. Bank overlap performed properly and all alarms and rod steps actuated in accordance with proper setpoints. FIGURES and TABLES None MIS/StartupMan/82/OS3
3.2.18 INCORE THERMOCOUPLE and RTD CROSS CALIBRATION 9102-S-01 TEST OMECTIVES Incore thermocouple and RTD Cross Calibration was initially performed during Hot Functional Testing with new composite calibration factors being installed prior to fuel load. The objective of the Incore Thermocouple and RTD Cross Calibration was to provide a functional checkout and cross calibration data for the incore thezmocouples and reactor coolant system resistance temperature detectors, verify temperature element characteristics, measure insulation resistance for all RTDs, and determine individual thermocouple isothermal corrections. TEST METHOD This procedure'id not gather data but analyzed data obtained by permanent plant procedure MPT-I0020, Incoze Thermocouple and Reactor Coolant System RTD Cross Calibration test procedure. RTD lead insulation resistances were checked to assure no faults existed. Test connections were made in the appropriate process instrumentation cabinets and brought out to switch boxes. These switches were used to select and RTD to measure its ohmic value at a tempezatuze plateau. The instrumentation used automatically compensated for lead resistance so only the actual RTD resistance was measure.. Extensive precaution was taken to assure that protection channels were measured one at, a time and not grouped with other RTDs in a cabinet for testing. Grouped RTDs and protection channels were returned to service prior to taking readings from the next group or protect<on channel. Concurrent with RTD readings, incore thermocouple readings were taken using Reactor Vessel Level Indication System (RVLIS) display and the plant computer output. An average of all thermocouples and deviations from that average wear calculated. RTD and thermocouple readings were taken at the 240'F, 350'F, 450'F, and 557'F temperature plateaus. Every effort was made to keep the plant stable at those temperatures while taking readings as rapidly as possible. RTD ohm values were averaged and converted to temperature readings for analysis using a computer program which matched values against individual RTD calibration curves provided by Westinghouse. RESULTS and ACCEPTANCE CRITERIA COMPARISON Connection problems were found at the 250 F plateau and corrected to the extent possible., Partial data was zun for comparison. Excessive temperature drift occurred at the 557'F plateau requiring a subsequent data collection. One RTD remained beyond acceptable limits and was declared inoperable. Many RTD and thermocouple installation corrections did not maintain a consistent tzend when comparing the 250'F and 557'F plateaus despite reasonable temperature contzol at both levels. MIS/StartupMan/83/OS3
Collection of test data took much longer than the 10 minutes suggested by Westinghouse. This was due in part to the instrumentation used to compensate, for lead resistance taking approximately 18 seconds per reading, and partly due to restoration of channels after each individual reading. 250'F PLATEAU Data collection lasted approximately one hour and 45 minutes. However, temperatures remained very stable during the period. Thermocouple data was not retained from the computer points. RVLIS data was used for this plateau trend since RVLIS receives its signal from the computer providing the same data only to fewer decimal places. Nineteen thermocouples exceeded +1.2'F deviation from the overall average. TC36 had the most significant isothermal correction of +4.51'F. RTD installation corrections exceeded +0.2'F for seven narrow range devices (two in excess of +1.2'F), and exceeded +1.2'F for five wide range devices (one in excess of +8.4'F). Connections were checked and found to be loose for the three worst devices, All were adjusted. Comparison resistance readings were taken and deemed acceptable with the exception of TE-432A. Cabinet and test equipment connections secure, a TE-432A lead resistance check was made. Further corrective, action was not possible at the time. calculation of data was run neglecting the three bad readings to ~ A second determine installation corrections. In this case seven narrow range RTDs
~ exceeded, +0.2'F correction with none greater than +1.2'F, and none of the wide range RTDs exceeded +1.2'F correction.
RTD manifold deviations exceeded +0.1'F in twelve cases after deleting the two narrow range RTDs which were bad. 350'F PLATEAU Data collection took one hour a tremendous improvement from the 250'F plateau. Collection rate was enhanced using more personnel. Temperatures
- 'remained stable through the plateau.
Thermocouple data was obtained from the computer and RVLIS. Note that computer readings are a snapshot in time, whereas the RVLIS readings are continuously updating during data acquisition. Based on the computer data, 26 thermocouples exceed +1.2'F isothermal correction, 21 when the worst case thermocouple is neglected. RTD installation corrections were evaluated with and without TE-432A-Neglecting the bad RTD, six narrow range RTDs exceeded +0.2'F with the greatest correction at 0.4338. No wide range RTDs exceeded +1.2'F with two deviating by approximately +0.78'F. Twelve RTDs exceeded 0.1'F manifold deviations'his was consistent with the 250'F plateau., MIS/StartupMan/84/OS3
450 F PLATEAU Data collection time was comparable to the 350'F plateau at one hour. Plant conditions remained stable through the test. Thermocouple data from the computer and RVLIS reflected some deviations consistent with how the readings were obtained as noted above. Greatest deviation occurred with TC36, same as with the previous plateau When neglected, twenty-two thermocouples exceed +1.2'F with 0.3386'F the most significant. The greatest wide range deviation was 0.5078. Six RTDs exceeded manifold deviations. of +0.1'F, only half'he number from the previous plateaus. 557'F PLATEAU Two tests were run for this plateau due to temperature swings in excess of 1'F per minute. Although Data Set A did not reflect any additional inoperable narrow range RTDs, correction factors in excess of +0.2'F increased from three in the 450'F plateau to twelve. This data is provided to Westinghouse for information only and was not analyzed further or discussed. Data Set B collection time took one hour and ten minutes. Temperature remained within acceptable criteria except for a brief period in the third data column.~ A fifth data column. was taken for the affected RTDs. Data was analyzed as Set Bl for data in columns one through four, and Set B2 substituting data from column five into column three,
~
Both are discussed below. 'nly RTD data was affected. Thermocouple data from the computer and RVLIS reflected expected differences due to data collection methods. TC36 deviated the most as expected and was neglected in the correction calculations. Corrections exceeded 1.2'F in 27 cases, an increase of five from the previous plateau. The greatest deviation was 7.79'F. RTD corrections neglected TE-432A. Eight narrow range RTDs exceeded +0.2'F in Data Set Bl with six exceeding in Data Set B2. Greatest corrections were 0.3886'F in Data Set Bl and 0.4446'F in Data Set B2. The largest wide range deviations were 0.4929'F in Data Set Bl and 0.475 for Data Set B2. Seven RTDs exceeded manifold corrections of +O.l'F for Data Set Bl and eight for B2, both slightly higher than the previous plateau, but much less than the 250 F and 350'F plateaus. OVERALL TESTING Test'quipment contact drift could not be determined for the 557'F plateau due to test equipment limitations. Based on evaluation of drift at the lower plateaus, the probability of drift greater than +0.02 ohms was judged negligible. Neither thermocouples nor RTDs reflected consistent trending in relation to calculated averages. Corrections shifted from positive to negative (or vice-versa) for many devices between the first and last plateaus. HIS/StartupMan/85/OS3
The above'nformation and the data sheets were forwarded to Westinghouse for. analysis. The resulting recommendations were'. Install a new composite calibration for TE-432D provided by Westinghouse. Continue to use the laboratory (8-point) calibrations for TE-413A and TE-430. Continue to use the HFT cross calibrations for the remaining RTDs. The, new composite calibration was subsequently installed. FIGURES and TABLES None 1 MIS/StartupMan/86/OS3
3 2'.19 AUTOMATIC ROD CONTROL 9104-S-04 TEST OBJECTIVES The Rod Control System receives inputs from RCS process temperature instrumentation (Tref and auctioneered high Tavg), turbine first stage pressure, and nuclear power to generate rod motion and speed signals which can be used. to automatically position control bank D rods to maintain constant Tavg. The objectives of this test were to:
- 1) Demonstrate that automatic rod control can maintain Tavg within
+ 1.5'F of Tref and under steady state conditions.
- 2) Demonstrate that automatic rod control can correct an induced 6'F Tavg error to within + 1.5'F of Tref.
.TEST METHOD ~
Q1th the reactor operating at the 30K power plateau, rod control in manual, and Tavg within 1.5'F of Tref, rod control was placed in automatic. Plant parameters were monitored for 10 minutes to verify that no instability occurred due to rod control being in automatic. Rods were then placed in manual control and control bank D was withdrawn until Tavg was 6'F + 1'F higher than Tref. Rod control was returned to automatic and the resultant transient was monitored as control bank D automatically stepped in to bring Tavg to within + 1.5 F of Tref. The same evolution was then repeated in the oppositedirection by initially positioning control bank D such that Tavg was 6'F + 1'F lower than Tref. RESULTS and ACCEPTANCE CRITERIA COMPARISON When rod control was placed in automatic for the first time, control bank D
.rods moved out 3 steps, but Tavg was maintained within 1.5'F of Tref without any manual intervention. When Tavg was manually raised 6'F above 'ref, automatic rod control recovered to within 1.5'F of Tref with no oscillations in 95.8 seconds'hen Tavg was manually lowered 6'F below Tref, automatic rod control recovered to within 1.5'F of Tref with no oscillations in 431.4 seconds. No manual intervention was needed during either transient.
FIGURES and TABLES None c MIS/StartupMan/87/OS3
3 2.20 MAIN STEAM ISOLATION VALVE TEST 9108-S-16 TEST OBJECTIVES The Hain Steam Isolation Valves (HSIV) function as containment isolation valves upon steam generator tube rupture. They are held open with air pressure and spring closed. The purpose of this test was to demonstrate the capability of the MSIVs "test feature" to operate per design under steam flow conitions near 100X power. TEST METHOD Reactor power was reduced to 95K power. prior to performance of the test and monitoring of reactor power, steam flow, S/G level and RCS average temperature was initiated to ensure no deviations in those parameters occurred. One at a
'ime each HSIV was cycled thr'ough its test feature. The valve moved from 100X
. open to 90X open and returned to 100K open. System conditions were monitored, logged, and evaluated. Generator load was monitored from DEH controls. RESULTS and ACCEPTANCE CRITERIA COMPARISON In each case, no discernable changes were noted in the system parameters identified. Each HSIV closed to 90K and reopened in accordance with design. FIGURES and TABLES
, None MIS/StartupHan/88/OS3
' 3.2.21 DYNAMIC AUTOMATIC STEAM DUMP CONTROL TEST OBJECTIVES 9103-S-28 Each individual steam dump valve (both atmospheric and condenser) was tested during Hot Functional at No-load temperature and pressure. The purpose of this test was to verify the proper operation of the Steam Dump Control System in the pressure control mode and the. Tavg mode (Turbine Trip and Load Rejection). TEST METHOD The reactor was critical at no-load temperature and pressure in a condition to allow an increase in power to approximately 30K prior to test performance. The Turbine Trip Controller response was tested by increasing the pressure control setpoint to 1132 psig in the steam pressure control mode, then increasing reactor power to approximately 5X (560'F). At this point, the mode selector switch was changed to the Tavg mode position while Tavg and steam pressure was monitored to verify controller stability. Reactor power was then increased to 9X and controller stability was verified. Reactor power was reduced to 4X power with stability being verified. The Steam Pressure Controller was tested by 'lacing the steam dump control mode switch in the steam pressure position. The controller then matched steam header pressure to the setpoint, then adjusted the setpoint to 1092 psig and verified controller stability. The -Load Rejection Controller was tested at 9X reactor power by simulating a 10K Loss of Load. AT 9X the tubrine was syncronized to the grid and turbine load increased to 15Z in accordance with operating procedures. Tavg was then increased 5'F greater than Tref and the controller placed in Tavg mode. A 10X Loss of Load is then simulated and reactor power increased to 25K power. Controller response was verified by no divergent oscillations. RESULTS and ACCEPTANCE CRITERIA COMPARISON During all three modes of operation~ Turbine Trip, Load Rejection and Steam Header Pressure Controller maintained stable Tavg after steady state was achieved in each mode with no divergent oscillations. FIGURES and TABLES None C MIS/StartupMan/89/OS3
3.2.22 TURBINE GENERATOR STATEPOINT'ATA 9104-S-21, 30X 9105-S-13 50X 9106-S-13 75X 9107-S-11 90X 9108-S-23 100X TEST OBJECTIVES The purpose of this series of test was to obtain baseline statepoint data for the turbine generator at 5X and 10X before the Turbine Overspeed Trip Test and at 5X, 10X, 20X, 30X, 50X, 75X, 90X, and 100X generator load. TEST METHOD The prerequisite generator load was established and maintained for at least 30 minutes prior to the data acquisition. Data takers were assigned to the Control Room (1), Turbine Deck (1), and the Turbine Building, Elevations 261'1). One maintenance mechanic was utilized to measure the spindle 286'nd end movement. Additional monitoring was done by the plant process computer and the Turbine Generator Stator Monitoring System computer at specified intervals. Three sets of data was obtained at each power level with the maximum values being compared to acceptance criteria. RESULTS and ACCEPTANCE CRITERIA COMPARISON All the'ecessary data was obtained at al 1 power levels, however some did not meet the acceptance criteria. In those cases, maintenance work tickets were initiated and work !completed. At 100X power, all acceptance 'criteria was met. Table 3.2.22-1 summarizes the 30X, 50X, 75X, 90X, and 100X data. FIGURES and TABLES Table 3.2.22-1 Turbine Generator Statepoint Data MIS/StartupMan/90/OS3
TURBINE GENERATOR STATEPOINT DATA TABLE 3.2.22-1 PROCESS ACCEPTANCE 30X 50X 75X 90X 100X CRITERIA Turbine Bearing Metal Tem . <210'F 158'F 157'F 162'F 166'F 166.5'F Turbine Lube Oil Tem . <170'F '140'F 140'F 148'F 152'F 152'F Turbine Generator Bearin Vib. <7 mils 3.3 mils 2.6 mils 2.7 mils 2.2 mils 2.0 mils Exciter Bearing Vibration <6 mils 0.4 mils 0.4 mils 0.3 mils 0.3 mils 0.5 mils Casing Expansion Differential <7 mils 1 mils 0 mils 0.004 mils 8 mils 7 mils Steam Chest (Sha1.low vs. Deep) <125'F Ri ht 41'F 42'F 41'F 40'F 39'F Differential Temp. Left 16'F 15'F 15'F 14'F 15'F HP Cylinder Base vs Cover Differential Tem . <75'F 7.2'F 20.6'F 48'F 20.1'F 57.9'F LP Exhaust Hood Tem . <175 F 93'F 111'F 117'F 122'F - 127'F EH Fluid Temp.
<130 F 107'F 106'F. 105'F 118'F 96'F Seals Oil Temp.
<120'F 124'F 108'F 107'F 108 F 110'F Mr Seal Oil Temp.
<120'F 124'F ill'F 109'F 108'F 108'F H2 Cooler Cold Gas Outlet Tem . <46.1'C 39.7'C 39.5'C 39.7'C 41.9'C 44.8'C 2 Side 6 Air Side Seal Oil Temp Differential <2 O' O' 34F 2'F O' 2'F r
MIS/StartupMan/91/OS3
3'.23 STEAM GEHEBATOR MOISTURE CARRYOVER TEST TEST OBJECTIVES Moisture Carryover from the steam generators is limited to 0.25X to ensure no accelerated turbine blade damage will occur. The purpose of this test was to provide guidance for the injection and sampling of a sodium tracer and the subsequent calculations to determine the steam moisture carryover content. TEST METHOD Temporary test chemical addition tanks and equipment were installed in the feedwater headers to each steam generator across the Feedwater Bypass Flow Elements along with a through inspection for secondary plant leaks as prerequisites to starting the test. The plant was maintained at 100X for the duration of the test with condensate polishers out-of-service, steam generator level within 66X + 3X level, and steam generator blowdown out-of-service. At a specified time a Sodium-24 tracer of equal proportions was injected to all three generators. After at 'east 30 minutes of wait time,, steam, feedwater, and blowdown sample lines were opened and purged for an additional 30 minutes. Three sets of samples were obtained at 15 minute intervals and a radioactivity analysis completed as soon as possible after sampling. Subsequent calculations involving feed and steam flowrates hand time of decay determined individual steam generator and average moisture carryover. RESULTS and ACCEPTANCE CRITERIA COMPARISON The measured moisture carryover from each steam generator was less than 0.25X moisture. Table 3.2.23-1 summarizes the results. FIGURES and TABLES Table 3.2.23-1 Moisture Carryover Results MIS/StartupMan/92/OS3
MOISTURE CARRYOVER RESULTS TABLE 3.2.23-1 SG-A CO SG-B CO SG-C CO CO SAMPLE gl 0.0004 0.09 0.03 0.04 SAMPLE f2 0.03 0.11 0.0004 0.05 SAMPLE 83 0.04 0.11 0.0004 0.05 AVERAGE 0.02 0 '0 0.01 0.05 C j.' MIS/StartupMan/93/OS3
3 3 PHYSICS TESTING 3.3.1 INITIAL CRITICALITY 9103-S-01 TEST OBJECTIVES The test procedure purpose was to achieve initial criticality and to continue the increase reactor of power to the point of adding nuclear heat in order to determine the upper and lower limits for the zero power physics testing plateau. Upon successful achievement of criticality, a dynamic check of the reactivity computer to verify agreement with design parameters was performed. TEST METHOD Prior to any approach to criticality, initial conditions were established with the RCS at 557'F and 2235 psig, RCS boron concentration of approximately 2200 ppm with all RCC banks fully inserted. All pressurizer backup heaters were energized to ensure less than 20 ppm boron concentration difference between the pressurizer and the RCS during the approach to criticality. Both source range channels were verified in operation in accordance with the proper maintenance surveillance procedures, as well as verification of a channel signal to noise ration of greater than 2 cps. All neutron channels (intermediate and power range) were verified in operation utilizing the required surveillance test. Reactor makeup water was verified in service to support the initial approach to criticality with only the alternate dilute path to the charging pump suction being used. This would minimize the dilution of the volume control tank. Special surveillance monitoring of technical specification items was initiated just prior to gaininq Plant General Manager approval. Programs including ICRR monitoring and 0 (Chi-square) were initiated to ensure source range reliability and proximity to critical prior to starting rod withdrawal. To begin the approach to criticality, the reactor trip breakers were closed, the source range Statistical Reliability Test was completed and an Estimated Critical boron concentration verified. The critical boron concentration with control bank D at 160 steps was determined to be 1320.5 ppm. Shutdown banks were then withdrawn in increments of 50 steps and the value of ICRR was determined prior to continuing (Figure 3.3.1-1). Control banks were then manually withdrawn in the overlap configuration and was stopped when control bank D at 160 steps (Figure 3.3.1-1). The remaining reactivity insertion which was necessary to achieve criticality was calculated to be a 772 ppm decrease in boron concentration. A boron dilution of 21,000 gallons was then initiated at 50 gpm until ICRR value fell below 0.1, at which time a rate of 25 gpm was used. Also at a ICRR value of 0.1, a straight line extrapolation indicated a total dilution of 19,800 gallons, resulted in an ICRR value of 0 (Figure 3.3.1-3). At this time, dilution was discontinued with a total of 19,854 being added. Final critical conditions were 1348 ppm at a control bank D position of 160 steps. Flux level increase was continued while source intermediate range overlap data was obtained until 1 x 10 amps on the intermediate range was achieved. The reactivity computer which, was previously checked out with the MIS/StartupMan/94/OS3
internal exponential generator, was utilized to determine the zero power
~
physics testing range.
~
Control Bank D was withdrawn to produce a start"up. . rate of 0.3 + .1 DPM and flux level was allowed to increase until nuclear heating was observed. Reactivity and Tavg were then observed until reactivity decreased due to Doppler fuel temperature coefficient while Tavg increased due to fuel temperature increase. A dynamic checkout of the reactivity computer was performed. Using three positive reactivity increases (25, 50, and 70 ppm) and three negative reactivity increase (-25, -50, and -70 ppm), control bank D was moved to produce the required reactivity change. Reactor period employing doubling time measurement was determined and compared to theoretical values. Testing then immediately continued with zero power physics testing. RESULTS and ACCEPTANCE CRITERIA COMPARISON Initial criticality was achieved at 1347 ppm with control bank D at 156 steps. The acceptance criteria required criticality to occur 50 ppm of the expected boron concentration. Expected boron concentration was 1318.6 ppm for a difference of 28.4 ppm. The zero power testing plateau as shown on intermediate range channels was determined to be as follows: Upper Limit: 3 x 10 amps Lower Limit: 3 x 10 amps The dynamic check of the reactivity computer for the three positive period measurements and three negative period measurement, was less than 4X as shown in Table 3.3.1-1. FIGURES and TABLES Table 3.3.1-1 Dynamic Reactivity Test Results Figure 3 3.1-1 ICRR vs. Control Rod Bank Position During Approach to Criticality Figure 3 3.1"2 ICRR vs. Time Figure 3.3.1-3 ICRR vs., Total Time of Dilution During Approach to Criticality MIS/StartupMan/95/OS3
Table 3.3.1-1 REACTIVITY COMPUTER DYNAMIC TEST RESULTS Reactivity INDICATED THEORETICAL DIFFERENCE In ut PERIOD PERIOD
+25 m 24.5 25 2.0X
+50 m 51 50 2.0X
+75 m 64 63 1.6X 25 m -24 -24.78 3.15X
-50 m -49 "48.84 0.3X 75 m -69 -71.31 3.2X c
MIS/StartupMan/96/OS3
lCRR vs. ROD POSlTION FOR N32 1.0 0.9 0.8 0.7 O W o.6 o.s 8 N og 03 0.2 O.I 0 oIA ~ O IA A D
~
Q CO V 0 V O 0 0 0 Ci D.g 'C
)U 0 CID Po R 8 8 vi vl 8 o0
$ Po Q CI lO 5 m 8 56 8 ~8 5 85 5 0 C ACC BA,)K POSITION o
rc e4 rc
'4 IQ RA CA IQ I
CJ AA 55 5 55 5 55 F I GORE 3.1,1-1
ICRR vs. TINE FOR N31 1.0 0.9 0.8 0.7 O 0.6 0.5 O W cx OA 0.3 0.2 0.1 0 0 10 20 30 40 50 60 10 20 30 40 50 60 10 20 30 40 50 60 1 HOUR 2 HOURS ~ ~ 3 HOURS TIME (MlNUTES) F I GURE 3.1.1-2
1CRR vs. Tlt"lE FOR N31 1.0 0.9 0.8 0.7 I-I- 0.6 lX ~ 0.5 8 cr OA X 03 0.2 0.1 0 0 10 20 30 40 50 60 10 20 30 40 50 60 10 20 30 40 50 60 0 HOURS 5 HOURS 6 HOURS TIVE (t1INUTES) F I GURE 3.1.1-2
ICRR vs. TINE FOR H31 1.0 0.9 0.8 0.7 O 0.6 0.5 Ul 5 OA X 0.2 0.1 0 10 20 '0 40 50 60 10 20 30 40 50 60 10 20 30 40 50 60-7 HOURS 8 HOURS 9 HOURS TIME (MINUTES) FIGURE 3.1.1-2
'C
ICRR'vs. REACTOR MAKEUP IAJ'ATER ADDITION FOR N32 1.0 0.9 0.8 0.7 O I-o.6 I-o.s D O C3 N 0.$ ) 0.5 0.2 0 12 16 20 2< 28 REACTOR MAKEUP hYATER ADDITION (THCUSANDS OF GALLONS) FIGURE 3.1.1-3
3.3 2 BORON ENDPOINT MEASUREMENT ALL RODS OUT 9103-S-05 TEST OBJECTIVES Endpoint boron concentration is the critical boron concentration with all rods out. The data is obtained'rom a "just critical" condition. The purpose of this test was to determine the critical RCS boron concentration at hot zero power (HZP) with all rods out (ARO). TEST METHOD To initiate the test, the reactor was critical at'HZP with Control Bank D at a position such that full .withdrawal of Bank D would result in < 50 pcm of inserted reactivity. Once the reactor power and RCS boron samples were stable, Control Bank D was fully w'ithdrawn and the reactivity was measured using the reactivity computer. 1 Following the withdrawal and reactivity measurement, Control Bank D was inserted to reestablish initial conditions. This method was repeated two additional times'he reactivity data, and RCS boron concentration recorded during the test was then used to calculate a final boron endpoint with all rods out. This value was then compared with the Nuclear Design Report-Harris Cycle 1 predicted value of 1328 + 50 ppm. RESULTS and ACCEPTANCE CRITERIA COMPARISON The .calculated value of 1353.19 ppm for the Critical Boron Concentration with all rods out using the measured reactivity above, was well within the acceptance criteria of 1328 + 50 ppm, FIGURES and TABLES None MIS/StartupMan/102/OS3
3'.3.3 POWER COEFFICIENT DETERMINATION 9105-S-09 9107-S-06 TEST OBJECTIVES The combined effect of moderator temperature and fuel temperature changes as the core power level changes is called the total power coefficient and is expressed in terms of reactivity change per percent power change. The purpose of these tests were to calculate the measured value of the Doppler Power Coefficient Verification Factor at 50K and 90X Power and compare them to the predicted Nuclear Design Report, Harris Cycle 1 value. The dopper power coefficient verification factor is the ratio of the dropper only power coefficient to the ARO Isothermal Temperature Coefficient. This was accomplished by monitoring RCS parameters during alternate decreasing and increasing step changes in power and performing a subsequent calculation. TEST METHOD With reactor power, xenon reactivity, boron concentrations, and axial flux differences at equilibrium or constant, and with Rod Control Bank D held fixed above 180 steps, the turbine generator load was alternately decreased and increased by 3 to 4X (29 to 38 MWe) producing six step transients, and then when the plant stabilized at the new power levels, the following four parameters were recorded on data sheets:
- l. RCS Loop "C" Tavg 2~ RCS Loop "C" AT 3~ 'ref 4~ Nuclear Power (N44)
C , the measured value of the doppler power 'coefficient verification factor, was then calculated from the measured values of the above parameters. Cp, the predicted value of the doppler power coefficient verification factor, was calculated from.'so where <<D is the Doppler Only Power Coefficient and <<.iso is ARO Isothermal Temperature Coefficient. Both coefficients are from the Nuclear Design Report, Harris Cycle 1. RESULTS and ACCEPTANCE CRITERIA COMPARISON At'oth the 50K and 90K power level, the agreement between the predicted and measured value of the doppler power coefficient verification factor easily met ,the acceptance criteria. MIS/StartupMan/103/OS3
at 50X'ower I-1 ~ 18(-[1.88[ = 0.07
~ ~ ~ 0.5 at 90'ower
-0 982 0'.958 = 0.024 < 0.5 FIGURES and TABLES None c
MIS/StartupMan/104/OS3
3.3
~ ~4 ISOTHERMAL TEMPERATURE COEFFICIENT-ARO 9103-S-10 TEST OB JECTIVES The objective of the test was to measure the core isothermal temperature coefficient, (ITC) at hot zero powez with all shutdown and control rods withdrawn and to calculate a moderator temperature coefficient (MTC) from the isothermal data for verification of technical specifications'EST METHOD Using the Reactivity Computer'"Y plotter, signals were set up using Reactivity (Y-Axis) and RCS Tavg (X-Axis). All changes in Reactivity due to boron were" minimized by defeating automatic makeup~ ensuring BTRS control switch off, and letdown bypassed the CVCS mixed bed. The diffezence in boron concentration between the pressurizer and reactor coolant loops was less than 20 ppm.
1 reactor coolant system cooldown of 5-10'F/hour was established by opening the main steam Power Operated Relief Valves and was terminated after a total 3 to 4'F cooldown. After completion of the cooldown graph, the heatup was performed. The heatup was terminated after temperature was returned to the initial value prior to performance of the cooldown. The isothermal temperature coefficient was determined from the best fit slope of the Reactivity versus RCS Tavg X-Y graph for both the cooldown and the
~
The resulting isothermal tempezature coefficient was used in the
~
heatup. ~ .--following a equation to determine the moderator temperature coefficient.
~
am = aISO,- aDOPPLER where aDOPPLER = -1.89pcm/oF (Nuclear Design Report, Harris Cycle 1) RESULTS and ACCEPTANCE CRITERIA COMPARISON Results Acce tance am ~ + 0.44 pcm/oF S + 5.9 pcm oF aISO = -1.46 pcm/oF -2.28 + 3pcm/oF The>> cooldown curve was performed twice due to pressurizer/RCS boron concentration difference of what was analyzed to be 6 ppm. The curve appeared to be skewed by the difference and subsequent equalization upon cooldown and heatup. Individual cooldown and heatup aISO values were as follows'.
~Heatu Cooldown
-1.33 pcm/'F -1.58 pcm/'F FIGURES and TABLES None MIS/StartupMan/105/OS3
3.3.5 CORE PERFORMANCE TESTS 9103"S-13 OX 9104-S-10 30X 9105-S-05 50X 9106-S-10 75X 9107-S-04 90X 9108-S-10 100X TEST OBJECTIVES The core performance test consisted of'enon Equilibrium Full Core Flux Maps utilizing the Incore Movable Detector System. The purpose of this set of tests was to verify the operating characteristics of the nuclear reactor core at increasingly higher power levels by comparing the measured results to the predicted power distr'ibutions and operating limits. The operating characteristics compared include.'
- 1. QPTR, Quadrant Power Tilt Ratio
- 2. 'e'action Rate Error
- 3. Fq(Z), Heat Flux Hot Channel, Factor N
4~ F , Nuclear Enthalpy Rise Hot Channel Factor 5.. F , Radial Peaking Factor TEST METHOD Core Performance is calculated by a semi-empirical computer program entitled INCORE, with input from a measured full core flux map. A full core flux map is obtained by using the Incore Movable Detector System. The Incore Movable Detector System is the standard Westinghouse system consisting of five miniature fission chamber detectors with associated cables and drives with each detector accessing up to ten independent thimbles and a calibration thimble all of which traverse the core. The process computer reads and records the current produced as the detector is withdrawn from the core and when all of the available thimbles have been accessed and all the usable detectors properly calibrated, the measured currents which are proportional to the thermal neutron flux level are collected from the process computer and stored on a floppy disk. The flux data from the disk along with core exposure, thermal power level, control rod position and boron concentration are used as input to the semi-empirical ENCORE program which calculates a three dimensional core power distribution. This power distribution is used to determine the operating characteristics as listed in the objective. RESULTS and ACCEPTANCE CRITERIA COMPARISON All Core Performance Tests were well within acceptable limits. As most parameter limits are Table 3.3.5-1 includes the measured
~
power dependent, values along with the limits.
~ ~
~
MIS/StartupMan/106/OS3
FIGURES and TABLES Table 3.3.5-1 Core Performance Characteristics and Limits ( MIS/StartupMan/107/OS3
CORE PERFORMANCE CHARACTERISTICS AND LIMITS TABLE 3.3.5-1 Nominal Power OX 30X 50X 75X 90X 100X Actual Power 25.6X 48.6X 76.3X 89.7X 98.2X QPTR 1.013 1.0074 1.0068 1.0084 1.0062 1.0066 Limit 1.02 1.02'.081X 1.02 1.02 1.02 1.02 Reaction Rate Error 7.41X 4.70X 4.49X 4.45X 4.21X Limit 10X 10X 10X 10X 10X 10X Fq(Z) K Z 2 313 2.041 2.032 1.987 1.983 1.995 Limit 4.56 4.56 4.56 2.988 2.542 2.28 N AH 1.498 1.435 1.410 1.349 1.367'.377 Limit 1.77 1.71 1.643 1.56 1.521 1.495 1.523 1.509 1.501 1.482 1.511 1.53 1.53 1.53 1.53 1.53 MIS/StartupMan/108/OS3
3 3.6 REACTIVITY WORTH OP THE CONTROL AND SHUTDOWN BANKS UTILIZIHG THE ROD SWAP TECHNI UE 9103-S-26 TEST OB JECTIVES The rod swap method has replaced the boron dilution method previously used for rod worth measurement by providing an indirect method for determining rod worth relative to a reference bank. The purpose of this test was to determine actual control rod bank worths for all control and shutdown banks using the rod swap technique. Specifically, the objectives were to'.
- 1) Verify that the integral reactivity worth of Control Bank B (the largest reactivity worth bank and therefore the reference bank for rod swaps) was within lOX of the predicted integral worth.
- 2) Verify that the integral reactivity worth of all 'other rod banks were within 15X or 100 pcm of the predicted integral worth.
- 3) Verify that the shutdown margin was greater than 1770 pcm.
- 4) Verify that the total worth of all rod banks was greater than 90X but less than 110X of the predicted total rod worth.
- 5) Verify RCS boron worth by performing boron endpoint measurements.
TEST METHOD This test was performed by first determining . the worth of the predicted highest worth rod bank, then using this "reference bank" to determine the worth of all other rod banks. Based'n nuclear design, the highest worth bank for Shearon Harris Cycle 1 is Control Bank B. Using the Reactivity Computer> the integral and differential worth of Control Bank B was measured from fully withdrawn to fully inserted, while diluting the RCS to compensate and keep the time-averaged reactivity at 0. Boron endpoint data was obtained three times each when the zeference bank was fully inserted and fully withdrawn. The worth of this reference bank was compared to the predicted value before proceeding. The ~orth of all other rod banks was then determined by ISO-Reactivity Interchange (ie, swap) with the already measured reference bank. The "swap", which was performed at constant RCS boron concentration, was accomplished by inserting the bank to be measured in -20 pcm steps (as determined by the Reactivity Computer) while withdrawing the reference bank in +20 pcm steps to keep the net reactivity change at 0. Once the bank to be measured was fully inserted, the reference bank was used to bring the reactor to "just critical" conditions and the required reference bank position was recorded This process was then repeated in reverse to fully withdraw the bank to be measured The required reference bank position for "just critical" was again recozded for the condition of the bank being measured fully withdrawn. The worth of the bank being measured could then be found from the difference in worth of the reference zod bank at the "just critical" positions recorded, allowing a correction factor for relative reference bank worth with and without the bank being measured in the coze. MIS/StartupMan/109/OS3
The results for all rod banks and the total worth of all rod banks were then compared to the acceptance criteria. Having verified the design predictions,, the shutdown margin was then determined for critical conditions using the normal Engineering Surveillance Test. Finally, the RCS boron worth by the difference in the boron endpoint values for the reference bank withdrawn and inserted. This last calculation was performed separate from the test procedure, but used data from the test. RESULTS and ACCEPTANCE CRITERIA COMPARISON Table 3.3.6-1 summarizes the results of rod bank worth measurements. It can be seen that Control Bank B is within 4.7X of the predicted worth, which is within the 10X required. All other banks are within 15X or 100 pcm of predicted values. The total worth of all rods is 95.5X of the predicted total worth, also within the 90X to 110X acceptance criteria. The shutdown margin was found to be 5267 pcm, well above the minimum 1770 pcm required. The RCS boron worth was found to be -10.28 pcm/ppm, which is also well within the required range of -16 pcm/ppm to -7 pcmfppm. FIGURES and TABLES Table 3.3.6-1 Rod Worth Data Summary MIS/StartupMan/110/OS3
ROD WORTH DATA
SUMMARY
TABLE 3.3.6-1 MEASURED PREDICTED BANK WORTH WORTH DIFFERENCE DIFFERENCE ( cm) ( cm) ( cm) (X) C 0 672.1 675 2.9 0.4 N T 1316.5 1382 65.5 4.7 R 0 970.4 1030 59.6 5.8 L 450.6 464 13.4 2.9 S H 1128.3 1163 34.7 3.0 U T 963.4 1050 86.6 8.2 D 0 447.8 454 6.2 1.4 W 554.2 624 69.8 11.2 TOTAL 6536.3 6842 305.7 4.5 MIS/StartupMan/111/OS3
3 3 7 INCORE/EXCORE CALIBRATION 9105-S-18 9106-S-11 TEST OBJECTIVES h The purpose of the test was to assure that a linear relationship existed
.between the excore neutron detector currents and the incore axial flux distribution. Once established, this linearity was used to 'rovide calibration data for the Nuclear Instrumentation System (NIS) top and bottom detector isolation amplifiers, the F(AI) component of OTAT inputs, axial difference meters and'he plant process computer constants for Constant Axial Offset Control (CAOC).
TEST METHOD Incore/Excore Calibration was performed in two parts, a preliminary calibration at 50X and a final calibration at. 75X. The preliminary calibration was performed after data was obtained from the 30X Core Performance Test and the 50X Core Performance Test. Using the FDELTAI Computer code, the nuclear instrumentation power range detector currents, and the INCORE axial offsets, the resulting linear relationship of incore axial offset versus normalized detector currents was developed. The computer code calculated a best fit line through the data and was iterated by the test engineer to obtain a fit correlation coefficient greater than .99 (note the iteration was only performed during the 75X calibration). The program then developed a. chart of Normalized to New Full Power Total Currents versus Incore (i Axial Offset.
=The data was then used by the I6C Section to calibrate the upper and lower isolation amplifiers for the power range detectors and input normalization factors to the plant computer.
The 75X Incore/Excore calibration w'as performed with data from an induced xenon oscillation by control rod movement (compensation for boration or dilution). The test established varying axial offset values after a initial Full Core Flux Map was obtained. quarter Core Flux Maps were taken at different axial offsets simultaneously with calorimetrics and recordings of detector currents. The FDELTAI computer program was then used in the same manner as with the preliminary calibration. After final calibration was completed, a verification of the OTdT flux penalty was conducted. RESULTS and ACCEPTANCE CRITERIA COMPARISON The preliminary calibration was done at axial offsets of -8.17 and -19.40. The final cal,ibration was performed at axial offsets of -8 '90, -11.610~
-15.044, -17.703, -22.090, -8.595, and -3.055. By the FDELTAI iteration, the -15 044 and the -8.595 flux maps were deleted as unreliable, possibly due to caliormetric inaccuracies. The Incore/Excore Process Computer Normalization Factors are a. good comparison of calibration results between power 3.3.7-1 shows the 50X. and 75X values.
plateaus'able MIS/StartupMan/112/OS3
The verification of the OTAT flux penalty resulted in discovering the negative flux penalty did not begin early enough to collect dI penalty points.. Subsequent investigation determined the gain on the upper detector flux signal was being multiplied properly, however the lower detector signal was not. It was shown a grounding problem existed when the NIS was disconnected for amplifier calibration and to correct the problem the gain was adjusted to produce the proper penalty acquisition at the proper axial offset. FIGURES and TABLES TABLE 3.3.7-1 PROCESS COMPUTER INCORE/EXCORE NORMALIZATION FACTORS ( MIS/StartupMan/113/OS3
PROCESS COMPUTER INCORE/EXCORE NORMALIZATION FACTOR TABLE 3.3.7-1 50X 75X CHANNEL FACTORS FACTORS N41 21.168 21.711 N42 20.867 20.759 N43 21.233 21.146 N44 20.200 20.159 MIS/StartupMan/114/OS3
3 3.8 REACTIVITY- COMPUTER INITIAL SETUP AND CALIBRATION 9102-S-18'EST OB JECTIVES . The reactivity computer is an online system which determines the relationship between reactivity and the neutron population., of a fixed fuel, spatially independent reactor. The purpose of this test was to connect, calibrate, and ensure proper operation of the reactivity computer used for zero power physics testing. TEST METHOD The test initially deener'gized NIS power range channel N-43 and connected the N"43 signal, Tavg and pressurizer level signals to the reactivity computer strip chart recorder (Tavg loop 422D and pressurizer level loop L-459) ~ I A computer static calibration check was performed to verify operations, amplifiers, and power supply settings, and was followed by the input of computer voltage constants. The voltage constants represented the delayed neutron decay constants and delayed neutron fractions. A reactivity exponential test was performed on four test cases. '50, 100, 200, 400 second . periods. The exponential test was performed on a daily basis to ensure no operational amplifier drifting had occurred and'as documented on data sheets. Finally, the Reactivity Computer was disconnected and permanent plant connections reestablished.- RESULTS and ACCEPTANCE CRITERIA COMPARISON
,The acceptable calibration of'he Reactivity Computer was determined by the maximum average absolute difference of the reactor period being less than 1X:
Absolute Difference= Apc Ape Apx Apc = the computer indicated reactivity dpi' the theoretical predicted reactivity The, maximum absolute difference of the four test case average results was 0'.5975X, which was less than 1.0X. FIGURES and TABLES None MIS/StartupMan/115/OS3
3" 4 TRANSIENT TESTING 3 4 1 REMOTE 'KlTDOWN TEST 9104-S-19 TEST OB JECTIVES An Auxiliary Control Panel. is available to operators to provide safe shutdown capability remote fzom the main control room. The purpose of the Remote Shutdown Test was to demonstrate that the plant could be shutdown and maintained in a safe condition, assuming that the main control room has been evacuated by operations personnel and is no longer available for plant operation. Specifically, the test objectives were to perform the following from outside the main control room.') Demonstrate that the plant could be taken from greater than 10X power to hot standby and maintained .in hot standby for at least 30 minutes using only the minimum shift crew. as defined in plant technical specifications. Demonstrate that the plant could be further cooled from hot standby such that the Residual Heat Removal (RHR) system could be placed in service and used to cool the RCS an additional 50'F. TEST METHOD With the P lant o P eratin g at g reater than 10X p ower the normal operating shift evacuated the main control room and assumed control of the plant from the Auxiliary Control Panel (ACP). An additional crew of operating personnel 'emained in the main control room to observe all operations and re-assume control if the normal operating shift at the ACP had difficulty controlling the plant. Specific guidelines were provided for aborting the test based on key parameters such as RCS temperature and pressure. Test personnel observed operations both .in'he -main -control .room and at the ACP and recorded any problems encountered and any help which the main control room provided to the ACP- These observations were evaluated after the test to determine if any of them invalidated the test. Throughout the test, actual abnormal operating procedure steps were used as much as possible to demonstrate their adequacy. Abnormal opezating procedures could not be used in some instances since equipment such as reactor coolant pumps and support systems had to be left in opezation to simulate decay heat. RESULTS and ACCEPTANCE CRITERIA COMPARISON The main control room was evacuated by the normal operating shift at 0839, the reactor was tripped from the reactor trip beakers, and control was established at'he ACP by the minimum tech spec crew. - The plant was declared stable in hot standby 1 hour and 40 minutes later. In obtaining stable hot standby conditions, steam generator levels and pressures could not be brought within the target bands for hot. standby due to insufficient decay heat, however, these parameters were stable at their respective values and hot standby as defined in technical specifications was maintained for 30 minutes. The main control room observer personnel notified the ACP personnel that steam generator levels were high, but ACP personnel were already aware of this and MIS/StartupMan/116/OS3
were taking action to correct the situation. The plant cooldown was continued and RHR was placed in service 7 hours 31 minutes after the control room was . evacuated. The RCS was cooled 56 F in 1 hour 8 minutes using RHR. The cooldown was then stopped and control was returned to the main control room to complete the test. During the cooldown, several minor equipment problems occurred and were documented by observer personnel. The equipment problems did not prevent the operating shift'rom maintaining control of the plant. The most significant of these problems was the failure of a switch on the ACP to cause a Train B SI block for Main Steam Pressure. Observers in the main control room notified the ACP that the block signal had not been accomplished. The problem was circumvented by sending an operator to place the train in "test" from outside the control room so that cooldown could continue without a Safety Injection occurring. The problem was immediately traced to the bad switch, which was replaced and demonstrated to. be operating correctly while still controlling the plant from the ACP during the test. Later evaluation concluded that this problem and communications with the main control room concerning the problem did not invalidate 'the test since a full Safety Injection cannot occur when control of the plant is transferred to the ACP by virture of the design. The problem therefore would not have prevented initiation of RHR. In summary, the remote shutdown test fulfilled the objective of demonstrating plant shutdown from outside the main control room. It also demonstrated that abnormal operating procedures for performing a remote shutdown were adequate. ( FIGURES- and TABLES None I MIS/StartupMan/117/OS3
3,4.2 AUXILIARYFEEDWATER TURBINE DRIVEN AND MOTOR DRIVEN PUMP ENDURANCE TEST,(48 HOURS) 9104-S-20 TEST OB JECTIVES The Auxiliary Feedwater System provides the capability to maintain steam generator water level upon loss of main feedwater. The purpose of this test was to demonstrate that the motor-driven and steam-driven auxiliary feedwater pumps can continuously feed two or more steam generators for a 48-hour period without exceeding 104'F in the pump cubicle and without exceeding design limits on bearing temperatures, bearing oil temperatures, and vibration. This test also demonstrated that the auxiliary feedwater pumps will not trip on low suction pressure when the motor-driven pumps are simultaneously started, while the turbine driven pump is running with the flow control valves wide open. In addition, this test demonstrated that main steam supply valve (1MS-70) to the turbine-driven auxiliary feedwater pump will close in less than 24 seconds under normal steam flow conditions. TEST METHOD Both motor"driven auxiliary feedwater pumps were started and had their total flow adjusted to between 300 and 400 gpm to Steam Generators 1A, 1B, and 1C. The pumps were then run for 48 ,hours while bearing and motor bearing vibrations and temperatures,'uction and discharge pressures, cubicle temperatures and flow parameters were recorded. Upon completion of the 48" hour run for the motor-driven pumps, then the steam-driven pump was energized c and run for 48 hours'hile monitoring the same design parameters'pon completion of the 48-hour run, the steam-driven auxiliary feedwater pump was secured by closing steam supply valve 1MS-70. The closure time of valve 1MS-
, 70 was obtained at this time.,
The motor-driven pumps and then the steam-driven pump were run again for an additional hour and had the additional. data recorded restart after which the motor-driven pumps were secured. While the steam-driven pump was still running, the motor-driven pumps were simultaneously started with the flow control valves to the steam generators wide open to verify that none of the auxiliary feedwater pumps would trip on low suction pressure. RESULTS and ACCEPTANCE CRITERIA COMPARISON The turbine-driven and motor-driven auxiliary feedwater pumps were run for 48 continuous hours. The motor-driven pumps had no problems whatsoever; however, the turbine-driven pump experienced high outboard bearing temperatures during its initial run. The pump was repaired and placed back in service. During the retest, the pump tripped due to a faulty tachometer. The tachometer -was replaced, and the test was completed satisfactorily. The turbine-driven auxiliary feedwater pump was secured by closing steam supply valve 1MS-70. The valve closed against full steam flow conditions in 20.3 seconds which was within the required time limit of. 24 seconds. The steam-driven pump was restarted and had the flow control valves to the steam generators fully open.. The, motor-driven pumps were then simultaneously started, and it was shown that none of the pumps tripped due to low suction pressure or for any other reason. MIS/StartupMan/118/OS3
. 3.4.3
~ ~ LOSS OF FEEDMATER HEATERS TEST 9105-S-ll 9107-S-08 TEST OBJECTIVES Loss of Feedwater Heaters is a FSAR analyzed accident which was actually verified during power ascension. The Loss of Feedwater Heaters Tests were performed to determine the reduction in final feedwater temperature after bypassing various combinations of feedwater heaters and simultaneously tripping the Heater Drain Pumps. The'temperature reduction for each transient was then checked to see if it was more or less than 43.95'F, which is the amount analyzed for in FSAR chapter 15.1.1. The worst case transient was also identified.
TEST METHOD The test at 50X powe'r was made up of the following transients, one at a time. Between transients, all systems were restored to normal and stabilized prior to the next transient.
- 1. Simultaneously trip both Heater Drain Pumps and open the bypass valve around feedwater heaters 3A, 4A, 3B, and 4B.
- 2. Simultaneously trip both Heater Drain Pumps, isolate feedwater heaters lA and 2A and open the bypass valve around feedwater heaters 1A, 2A, 1B, and 2B. The isolation and bypass was automatically initiated by simulating high-high level in feedwater heater 1A.
c 3.. Simultaneously trip both Heater Drain Pumps, isolate feedwater
.heaters 1B and 2B, and open the bypass valve around feedwater heaters 1A, 2A, 1B, and 2B. The isolation and bypass was automatically initiated by simulating high-high level in feedwater heater 1B.
The only -transient conducted at 90K power was the tripping of both Heater Drain Pumps simultaneous to opening the bypass valve around feedwater heaters 3A, 4A, 3B, and 4B. This was the worst case transient at 50K power, therefore this was the only transient performed at 90K power. This reduced the number of plant runbacks on a Heater Drain Pump trip. RESULTS and ACCEPTANCE CRITERIA COMPARISON The worst case transient at the 50K power level was the bypassing of feedwater heaters 3A, 4A, 3B, and 4B while simultaneously tripping the Heater Drain Pumps. The final feedwater temperature was reduced by 11'F. At 90K power, this was the only transient performed and it resulted in* a final feedwater temperature reduction of 21'F. Both of these are well below the analyzed value of 43.95'F.. FIGURES and TABLES MIS/StartupMan/120/OS3
( 3 4.4 LOAD SWING TESTS 9104-S-14 9106-S-04 TEST OBJECTIVES The design of the NSSS portion of the plant allows for step load increases and decreases of 10'ated load. The purpose of the load swing tests was to verify the proper nuclear plant transient response, including automatic control system performance, when 10K load. changes, both decrease and increase were introduced at the turbine generator. Tests were performed at the 30Z, 50Z, and 75X power test plateaus. TEST METHOD The tests were started with stable plant conditions at the desired test plateau and the following systems in automatic:
- 1. Rod Control System 2~ Pressurizer Level Control 3~ Pressurizer Pressure Control
- 4. Steam Generator Level Control
- 5. Steam Dump Control in Tavg Control After initial plant data was collected" to verify plant stability, the Turbine Generator Digital Electro-Hydraulic (DEH) Controller was used to achieve a 10X load decrease as rapidly as .possible. When the plant was in a stable condition, additional data was collected. During the transient, certain parameters were monitored on either multichannel strip chart recorders or the data acquisition computer.
The DEH controller was then used to increase the plant output as rapidly as possible to achieve a 10'oad increase and attain a final plant level at approximately the original test plateau. After the plant was in a stable condition, a final set of data was collected. The acceptance criteria for these tests were:
.1. No reactor trip was generated,
- 2. No turbine trip was generated,
- 3. Safety injection was not generated,
- 4. Neither the Steam Generator Safety Valves, Steam Generator Power Operated Relief Valves, nor Atmospheric Steam Dumps lifted,
- 5. Neither the Pressurizer Safety Valves nor Pressurizer Power Operated Relief Valves lifted,
- 6. No manual intervention was required to,bring plant conditions to steady state,
- 7. Condenser steam dump did not actuate,
- 8. Primary pressure changes during the load decrease/increase MIS/StartupMan/121/OS3
transients did not exceed psi, c 9. Steam Generator 50 levels did not vary by more than +5X from the initial levels during the load decrease/increase transients,
- 10. Steam Header pressure did not overshoot/undershoot the final values by more than 25 psi during the load decrease/increase transient, ll. The minimum differential temperature margins were nearer to their respective trip limits during:
- a. Steady state before load decrease than during the load decrease transient,
- b. Steady state after the load increase than during the load increase transient,
- 12. Tavg"did not undershoot/overshoot its stabilized final value during the load decrease/increase transient,
- 13. Nuclear Power did not undershoot/overshoot its final stabilized value by more than 3X during the load decrease/increase transient-RESULTS and ACCEPTANCE CRITERIA COMPARISON The test at 30X power was first performed on February 17, 1985. The test was stopped during the down-power maneuver because the C-5 rod stop actuation was encountered, and manual intervention of automatic rod control was necessary to maintain Tavg. Upon consultation with Westinghouse, it was suggested that this test be reperformed at a higher power level in order to avoid actuation of the C-5 interlock.
The test was reperformed on February 18, 1985, at approximately 40X Nuclear Power and all of the acceptance criteria were either met or "accepted as-is" with the appropriate review by Westinghouse. The test exceptions on the retest were.'. B"S/G PORV (1MS-60) cracked open and immediately closed. Work ticket 87-AFKL1 verified that its setpoint was within tolerance and in-line with the other valves.
- 2. The following parameters were outside of their expected band:
- a. Primary pressure changes during the load decrease transient exceeded 50 psi (actual value, 56 psi),
- b. Steam pressure during the load decrease transient overshot the final value by more than 25 psi (actual value, 65 psi).
The test was also run at the 50X power test plateau on March 27, 1987. This load swing test was not originally scheduled to be run at 50X power, but was deemed necessary due to the plant tripping problems associated with the Condensate and Main Feedwater Systems. The test ran very smoothly with no divergent or. continuing oscillations experienced with the Steam Generator MIS/StartupMan/122/OS3
Level Control System or any other= plant systems. All of the acceptance ~ criteria were either met or "accepted
~
~
~ ~
as-is" with the appropriate review by. Westinghouse. ~ The major test exception identified was.,
- 1. The following plant parameter fell outside of its expected band Steam pressure overshot by more than 25 psi during the load decrease transient, (actually 40 psi), and undershot by more than 25 psi during the load increase transient (actually 51 psi).
The test at 75X Power began on April 12, 1987. On this date; the 10X load decrease was performed satisfactorily with all acceptance criteria met with minor exceptions. They are as follows'. Steam pressure overshot the final value by more than 25 psi (actual ya1ue was 50 psi).
"1 2~ Primary pressure changed by more than 50 psi (actual value was 55 psi).
This data was reviewed by Westinghouse and found to be "accepted as-is". The initial load increase was also attempted on April 12, 1987, but several problems developed. The IBM PC used for test data collection stopped 4 seconds into the load increase=- transient for no apparent reason. Secondly, the turbine generator DEH computer loops kicked out. After consulting with Westinghouse, it was decided that the cause for the DEH computer rejection could have been that the governor valve limit was being reached, thereby causing loop rejection. It was recommended that the test be repeated with the governor valve limit left at 120X per GP-005 Number One was performed on April 13, 1987.
'etest However, as before, the MWe and Imp loops rejected out, and the net load increase was only approximately 3X versus 10X planned. Upon further consultation with Westinghouse, '. could have been "too it was suggested that our acceleration rate of 1900 MWe/min.
fast" resulting in a DEH computer rejection, and that the lag of the impulse pressure could also have given us a DEH computer rejection. It was therefore recommended that the acceleration rate be changed to 1000 MWe/min., and that the test be reperformed with the imp"loop out. Retest Number Two was performed on April 13, 1987, as recommended by Westinghouse. However, the MW-loop rejected and the resulting plant power increase was ~ 18X (170 MWe) versus the planned 10X (95 MWe). All of the Acceptance Criteria were met for the load increase transient with the following exceptions'. The DEH computer system did not produce a 10X step increase as required. Westinghouse reviewed this problem and stated "It is still possible that the rate of increase selected (1000 MWe/min) caused the governor valves to hit their upper limit, which would reject the loop, even if the limit happens to be 100X; the rapid changes could cause the error signal between demand and actual MW to MIS/StartupMan/123/OS3
be large enough to cause rejection. Westinghouse further recommended that if the test, were to be repeated, it should be run . with loops out. "Once this unit has had its Valve Management Parameters corrected to this specific site, the reference demand will be much more accurate without the loops than it is now." Based on this evaluation, this exception was "accepted as-is".
- 2. Because of the larger than planned load increase, the control operators had to take manual control of the Steam Generator Level Control System in order to avoid a plant trip on S/G High-High Level. Westinghouse reviewed this data and stated, "Taking manual control of S/G Level does not impact test results since the current Harris flow control system gain setpoints have been adjusted to achieve a stable performance at steady state. The current setpoints will always result in a slower response during a fast transient."
Westinghouse later stated that the size of the load increase was instrumental in the failure of the Steam Generator Level Control
'ystem and the manual intervention. Based on this evaluation, this
'xception was "accepted as-is".
- 3. The following plant parameters fell outside of their normal operating band:
a.'team header undershot its final value by more than 25 psi (actual value 126 psi),
- b. Primary pressure exceeded a 50 psi swing (actual value.
72.7 ps'),
- c. S/G Levels varied by more than 5X (actual level swings were S/G-A (+13/-10.6); S/G"B (+10/-9.8); S/G-C (+12.7/-9.0)).
Westinghouse reviewed these deviations and found them to be acceptable since no divergent control system oscillations were observed. Based on this evaluation, this exception was "accepted as"is" ~ FIGURES and TABLES Figure 3.4.4-1 10K Load Decrease from 75K Power Figure 3.4.4-2 10X Load Increase form 75K Power MIS/StartupMan/124/OS3
3 4.6 NSSS ACCEPTANCE TEST 9108-S-15 TEST OBJECTIVES The objective of the NSSS Acceptance Test was to demonstrate the reliability of the Nuclear Steam Supply System (NSSS) by maintaining the NSSS at its rated output of 2775 MWt (+0/-5X) for 100 hours without a load reduction or plant trip. TEST METHOD The reactor power was raised to'ear 100X and stabilized. Reactor power was being monitored by computer point URE1118, "Reactor Total Thermal CIM Q." The time period was initialized and power was maintained within the acceptance criteria for 100 hours. The reactor power from URE1118 was recorded in the procedure every hour and it was also being monitored and printed from the process computer trend printer every five (5) minutes. Some additional points were monitored by the process computer such as, Net Generator Megawatts, Power Range Channel Flux, Feedwater Flows, Feedwater Temperatures, and Main Steam Pressures. RESULTS and ACCEPTANCE CRITERIA COMPARISON The test was started on two separate occasions and tripped shortly afterward; once due to a perturbation in the heater drain system, and once due to an air line becoming disconnected from the heater drain 1'evel control valve. Both perturbations resulted in heater drain pumps tripping thus causing turbine runbacks and eventually manual reactor trips due to feedwater system forty (40) trouble. On the third attempt, the test lasted for approximatelybourse'he hours when the "A" Main Feedwater Isolation Valve failed closed due to a leak in the hydraulic oil system. The test continued during the reduction in power but the time period accumulated prior to and during the reduction was not counted. After the valve was fixed, the power was raised back to 100X and maintained within the acceptance criteria for 100 continuous average MWt for the 100 hour period was 2755.4 MWt. FIGURES and TABLES None MIS/StartupMan/134/OS3
3 4.7 TURBINE TRIP FROM 100X POWER 9108-S-14 TEST OB JECTIVES
'I The purpose of the Turbine Trip from 100K Power test was to manually trip the turbine from the main control board and verify primary and secondary system responses were adequate. The secondary system responses involved the ability of the secondary plant to sustain a trip and to bring the plant to a stable condition following the transient without lifting steam generator safety valves. The primary plant response include the following: 1) Safety Injection does not initiate, 2) the reactor trips and all rods drop to reduce flux in the required 2 seconds, 3) Pressurizer Safety valves do not lift, 4) the overall RTD response time is less than 6.6 seconds, and 5) the primary responds properly following a trip to maintain stable conditions.
TEST METHOD The turbine trip was initiated from the Main Control Board. Test personnel were stationed throughout the plant and control room to observe those various plant responses which were necessary for test acceptance. The plant response was monitored using three methods. Main Control Board readings and Control Board Strip Charts were monitored throughout the .test until stabilization occurred as well as process computer trends of primary and secondary computer points which were established on 30 second trend periods. Various inputs were connected to a computer data acquisition system and plant parameters were monitored and recorded throughout the test. Plant stabilization was obtained by using normal operation procedures. Data used to evaluate specific Acceptance Criteria was taken from the computer data acquisition system. 5 RESULTS and ACCEPTANCE CRITERIA COMPARISON The following acceptance criteria were met:
- 1) The overall RTD response time was less than 6.6 sec (actual 6.4 sec).
- 2) All Rod Cluster Assemblies released and dropped.
- 3) Safety Injection did not initiate.
- 4) Nuclear Flux dropped to 15X within 2 seconds (actual 1.0 sec) after Reactor Trip Breakers open.
- 5) Pressurizer safety valves did not lift.
- 6) Steam Generator safety valves did not lift.
- 7) The Minimum Pressurizer level was greater than 20X of span
' (actual 24.12K). MIS/StartupMan/135/OS3
- 8) The Minimum Pressurizer pressure was greater than 1950 PSIG (actual 1954.7 PSIG).
')
The Maximum Pressurizer pressure during the transient did not increase above its initial value.
- 10) Feedwater flow went to full shutoff prior to reaching a Tavg 0 f 5 5 7 F ll) Steam dumps modulated closed following the transient.
- 12) The Main Generator remained connected to the grid at least 30 seconds (actual 36.0 seconds) following a turbine trip.
The Acceptance Criteria not met was as follows'.
- 1) T avg stabilizes at or above no-load value of 557 + 2'F, without manual intervention of feedwater flow.
This Acceptance Criteria was not met due to both feedwater pumps tripping off in about 6 seconds following the turbine trip and manual control of Auxiliary Feedwater was taken when it automatically started. LER-87-028-0 was written due to the loss of both main feedwater pumps and actuation of Auxiliary Feedwater Pumps. Loss of the Feedwater pumps was due to a loss of both Condensate Booster pumps which tripped on high discharge pressure. The Condensate Booster pumps had previously shoM too slow in response to flow demand changes and the automatic controls did not. reduce flow quick enough to match the feedwater regulating valve closure. This transient resulted in the high Condensate Booster Pump discharge pressure and the subsequent trips of the Main Feed Pumps and Condensate Pumps. This problem is being addressed by LER-87-028"0. FIGURES AND TABLES Figure 3.4.7-1 Turbine Trip from 100X Power MIS/StartupMan/136/OS3
3.4 ~ 8
~ STATION ELECTRICAL BLACKOUT 9104-S-05 TEST OB JECTIVES The purpose of this procedure was to demonstrate that the necessary equipment, controls, and indications are available to remove decay heat following a loss of off-site power using only'mergency power supplies. Diesel Generator load sequencing was verified and plant conditions were maintained for at least 30 minutes using only emergency on-site power sources'EST METHOD The reactor was stabilized between 10K and 20X with the generator synchronized to the grid at the start of the test. The plant was placed in a normal lineup excluding the Diesel Auxiliary Lube Oil pumps which were pxe-started to minimize the challenge on the diesels. The station electrical blackout was initiated by opening all S/U Transformers from the Main Control Board.
Proper response of the plant was verified in four ways:
- 1) Personnel wexe stationed throughout, the plant and the- Control Room,
- 2) Process computer group- trends were established to print out every 30 seconds throughout the test,
- 3) a chax't recorder was conhected to various RCS parameters in the process instrument cabinets,
- 4) Process computer archive data was retrieved following the test.
The plant was then stabilized at hot standby utilizing plant abnormal opexating procedures and maintained for 30 minutes. Following the required 30 minutes, normal plant power was reestablished. RESULTS and ACCEPTANCE CRITERIA COMPARISON r Following the Station'Electrical Blackout, emergency power supplies functioned properly to assume safety loads as required'o achieve hot standby conditions. Acceptance Cxiteria one was then achieved by maintaining hot standby for at least 30 minutes using only these emergency on"site power supplies. Other procedure acceptance criteria required by the test, was not fully met because of an equipment problem. Of the 81 pieces of equipment required to be sequenced on following a Diesel Generator Start, one piece, Fan S-64 did not show a start condition on the archive data pxintout. It was later found that there was a bad contact. on the breaker position relay feeding the computer. That, contact was replaced, and the auto sequence of the fan S-64 was later xetested. It was also noted during the test that Process Instrumentation Cabinets (PICs), C5, C7, and C9 did not have power during the test causing a loss of MCB indicators., This was due to an impxoper alignment of the 7.5 KVA NNS invexter following- maintenance. This did not however affect the results of the test. MIS/StartupMan/139/OS3
PIGURES and TABLE None MIS/StartupMan/140/OS3
3.4.9 TURBINE OVERSPEED TRIP TEST TEST OB JECTIVES The main turbine can be tripped on overspeed by an electrical or a mechanical trip signal. The mechanical overspeed trip device is a spring-retained weight in the turbine extension shaft which, as turbine speed increases, is acted upon by centrifugal force to move it outward, striking a trigger which opens a valve to drain the emergency lube oil trip header and ultimately trip the turbine. The objective of this test was to demonstrate that the mechanical trip, mechanism would actually trip the turbine of 110K + 1X of rated speed (1800 rpm). TEST METHOD This test was performed with the main generator unloaded. A plant operator was stationed at the turbine governor pedestal with a local speed indication to act as a safety man during the test and trip the turbine manually if The electrical overspeed trip was defeated for this test. The 'ecessary. turbine speed was increased above 1800 rpm by setting the reference speed on the turbine operator's panel to 2015 rpm (112X) with an acceleration of 50 rpm/min, then pressing the "GO" button to initiate .the speed increase. The maximum speed attained before the turbine tripped was recorded from the local speed indication at the governor pedestal as well as from the Operator's panel. The test was repeated for a total of three trips. RESULTS and ACCEPTANCE CRITERIA COMPARISON During the first of the three trips to be performed, the turbine tripped at 1952 rpm which was below the acceptance criterion range of 1962 to 1998 rpm. It was decided to perform the next two trips even though the first trip failed in the conservative direction.: The next'two trips occurred at 1953 and 1952 rpm, also low. All three trips therefore occurred with good consistency. Both speed indications used during the test were also in agreement for all three trips. Westinghouse evaluated the test results and found that they were marginally acceptable from a load rejection standpoint and did not alter the conclusions of the non-LOCA chapter 15 accident analyses in the FSAR. However,'estinghouse did recommend that the'echanical overspeed trip setpoint be adjusted higher prior to performance of any load rejection testing. In accordance with this recommendation, a work request was initiated to increase the trip setpoint which will then be retested by an Operations Surveillance Test before performing the Generator Trip from 100X power at the beginning of Cycle 2. FIGURES and TABLES None MIS/StartupMan/141/OS3
k-
-3.4.10
~ ~ NATURAL CIRCULATION 9103-S-23 TEST OBJECTIVES Inherent in the design of the RCS is the ability to achieve natural circulation upon loss of forced pumping capability. The purpose of the test was to verify natural circulation of the Reactor Coolant System and verify the temperature data is similar to a prototype plant (North Anna). In addition, it was shown that natural circulation is maintained upon loss of pressurizer heaters and the resulting data was used to improve plant specific simulator response to more closely match the actual plant conditions.
TEST METHOD Using core AT indication and the appropriate scaling as the most accurate indication of reactor power at low power, a power level of 3 to 3.5X . was established to simulate core decay heat. At that point the Reactivity Computer flux level indication was used to monitor power level (when RCPs are deenergized RCS loop AT is unreliable). All three Reactor Coolant Pumps were then tripped simultaneously with the following expected responses'.
\
, -Th increase (26'o 45'F)
-TC. constant or slight decrease Core exit'thermocouples increase (26 to 45'F)
- Pressurizer level increase (10 to 16X)
- Pressurizer pressure increase (up to 50 psi)
- Tavg indication unreliable
- AT indication unreliable Rod Control Bank D was used to maintain reactor power in the 3 to 3.5X range as indicated by flux indication. After establishing natural circulation, all pressurizer backup and proportional heaters were deenergized to verify natural circulation was maintained. The RCS was then returned to normal by starting all three RCPs.
RESULTS and ACCEPTANCE CRITERIA COMPARISON The test showed the establishment of natural circulation conditions with the following values: r MIS/StartupMan/142/OS3
I Parameter Actual 599.6'F
~Ex ected 584'F 604'F
-558.8'F 552'F - 562'F 40.8'F 32'F - 47' Time to Stability 20 min. , 10 20 min In addition, natural circulation was maintained for 30 minutes with pressurizer heaters deenergized.
FIGURES and TABLES None c MIS/StartupMan/143/OS3
3 ~5 INSTRUME2KATION AND CALIBRATION TESTING 3 5.1. GROSS FAILED FUEL DETECTION TEST 9104-S-07 9108-S-18 TEST OBJECTIVES The Gross Failed Fuel Detection System is designed to monitor for gross fuel failure by monitoring delayed neutron activity. This monitoring is dependent on sample flowrate and temperature. The purpose of these tests was to verify proper operation of the Gross Failed Fuel Detection (GFFD) System at 30X and 100X power as evidenced by proper sample temperature, flow, and high activity alarm. TEST METHOD The tests began by verifying the detector high voltage reading was within tolerance 'and if it was not, called for a recalibration of the detector per plant procedure. Static readings were then taken of sample activity (baseline data), sample flow,, and sample temperature. The sample activity and sample flow were read at the GFFD console while the sample temperature was read locally in the RAB at the GFFD'kid. In addition, the 100K power test
'directed to have a background count estab1,ished by chemistry and to input this to I&C to reset the high activity alarm setpoint. Th'e alarm point was then verified in the 100X power test by placing, the GFFD console in test and adjusting a test potentiometer.
RESULTS and ACCEPTANCE CRITERIA COMPARISON ~ 4 Table 3,5.1-1 summarizes the data and acceptance "criteria of the tests. In all cases the acceptance criteria was met and no test exceptions were written. The high activity alarm adjustment by I&C, as described above, was not performed however, by request from chemistry/I&C. This was due to the low background count in rela)ion to the high alarm setpoint. The tolerance for the high alarm was + 10 CPM and the activity was 10 CPM. Therefore even without adjustment, the alarm setpoint was well within the acceptance criteria given .by the procedure. FIGURES and TABLES Table 3.5;l-l GFFDS Results MIS/StartupMan/144/OS3
GFFDS RESULTS c TABLE 3 ~ 5 ~ 1-1 Reading 30X 100X Acceptance Criteria Detector Volta e 2150 VDC 2125 VDC 2150 + 25 VDC Sample Tem erature 70' 80' < 135' Sample Plow 0.46 GPM 0.44 GPM 0.44 + 0.02 Sample Activit 17 CPM 100 CPM Baseline Data High Activity Alarm N/A 1.0 X 10 CPM 1.01 x 10 + 10 CPM MIS/StartupMan/145/OS3
3~5 ~2 CALIBRATION PROCEDURE FOR THE PEEDWATER FLOW RESTRICTOR FLOW ELEMENT INSTRUMENTATION FEW481 FEW482 AND FE-0483 9105-S-17 TEST OBJECTIVES The feedwater flow restricting flow elements ensure that flow directed to the steam generator preheater section does not exceed design values in order to prohibit unnecessary tube flow vibration. The, purpose of this procedure was twofold. First, to develop calibration curves for the Feedwater Flow Restrictor Flow elements (FRFE), FE-0481~ FE-0482, and PE-0483. Secondly, to ensure that at 100X Feedwater Flow, the Main Feedwater Nozzle Flows were not less than 76.5X and not greater than 80.5X of total flow. TEST METHOD With the preheater bypass valves closed at 65X, 75X, and 85X total feedwater flow, the differential pressures were measured across both the'ain Feedwater Flow Venturis and the Feedwater Flow Restrictor Flow Elements for each of the three loops. With system temperatures and pressures also measured, it was possible to calculate the mass flowrate through the Main Feedwater Flow Venturis. Since the preheater bypass valves were closed, the mass flowrates through the Main Feedwater Flow Venturies were the same as the mass flowrates through the Feedwater Flow Restrictor Flow Elements. Knowing the mass flow rates and system temperatures and pressures, it was then possible to calculate a discharge coefficient for each of the Flow Restrictor Flow Elements at each c of the "mass flowrates. The Reynolds Number was then calculated for each of the mass flowrates,and a plot- was made of Discharge Coefficient versus Reynolds Number for each of the Flow Restrictor Plow Elements. The test was repeated as stated above at 80, 85, 90, 95, and 100X Feedwater Flows with one exception', the preheater, bypass valves were open per their normal lineup. With these valves open, the mass flowrates through the Main Feedwater Flow Venturis were no longer equal to the mass flowrates through the Flow Restrictor Flow Elements. Therefore, an iterative technique was used to solve for the mass flowrates through the Flow Restrictor Flow Elements. Using, the Discharge Coefficient versus Reynolds Number plots for each of the Flow Restrictor Flow Elements, a Reynolds Number 'as guessed. A discharge coefficient could then be obtained from the plots. With this discharge coefficient, the volumetric flowrate through the Flow Restrictor Flow Elements could then be calculated. Once the volumetric flowrate was obtained, a "new" Reynolds Number and subsequent "New" discharge coefficient was obtained and the process was repeated. Once the two Reynolds Numbers were essentially equal, the process was stopped, and the last volumetric flowrate was used to calculate the mass flowrate through the Flow Restrictor Flow Element. Now that the flowrates through both the Main Feedwater Flow Venturis and the Plow'estrictor Flow Elements were known, the percentages of Feedwater Flow through the Steam Generator Main Nozzles at 100X were easily calculated. MIS/StartupMan/146/OS3
( RESULTS and ACCEPTANCE CRITERIA COMPARISON The final Steam Generator Main Nozzle flowrates were 80.5, 79.6, and 79.5X for Loops 1, 2, and 3 respectively. These values were within the Acceptance Criteria of 78.5 + 2X. The data collected at 65, 75, and 85X Feedwater Flows was forwarded to scaling personnel so that flow transmitters FT-2003A, B, and C could be rescaled. FIGURES and TABLES None f MIS/StartupMan/147/OS3
(.. 3.5.3 TflEBHAL POMER MEASUREM19iT AND STATEPOINT DATA AC UISITION 9102-S-17 OX 9104-S-06 30X 9105-S-06 50X 9106-S-06 75X 9107-S-01 90X 9108-S-06 100K TEST OBJECTIVES Using a standard caliometric calculation during initial power ascension, thermal power is measured and applied to instrumentation systems which are power dependent for scaling modification. The purpose of this data acquisition test is to acquire plant system data under "stable plant conditions" used for calculating reactor thermal power. and applying the'ata to instrumentation/control systems. While in a stable plant configuration the following data was obtained:
- 1) RCS Process Temperature Instrument readings applicable to Thot, Tcold, Thot-spare, Tcold-spare, Tavg and AT channels of protection and control channels were obtained for Operational Alignment of Process Temperature Instrumentation.
- 2) Feedwater and Steam, Flow Instrument readings applicable to inches of water column (INWC) and Millions Pound Mass per hour (MPPH) were obtained as simultaneou'sly as practical along with precision test instrument readings taken locally at ,the Feedwatei Venturi. These comparative readings provided input for the plant calibration of the Steam Flow/Feed Flow Mismatch channels and main steam full power INWC.
- 3) NIS Overlap Verification . Data was acquired as a result of simultaneously recording the plant Power Range Nuclear Instrumentation (NIS) channels while obtaining plant data necessary to calculate reactor thermal power.
- 4) RCS Flow Determination (50K S 100K) - Data was acquired using precision instrumentation to calculate RCS flow. Specifics involved Feedwater Flow (MPPH) Feedwater Pressure (psia), Steam Pressure (psia), Pressurizer Pressure (psia), and RCS Thot and Tcold.
TEST METHOD: 30 minutes of plant stability data is obtained prior to recording any plant data. Parameters monitored for stability include:
- 1) Tavg g + 2 F
- 2) Pressurizer Pressure g +20 psig
- 3) Pressurizer Level Q + 6X
- 4) S/G Level Q + 6X
- 5) Rx Power Q
+ 1Z MIS/StartupMan/148/OS3
Once stability has been maintained for 30 minutes, data taking was initiated. During the data taking evolution, the maintenance of stability values was essential to accurate data reduction. Data obtained form the PICs and local test stations was acquired in specified sequence points as directed by the test engineer. Sequence testing ensures that associated points such as Feed Flow/Steam Flow channels are monitored at the same instant. Main control board data and Process Computer data is obtained continuously through out the duration of the test. RESULTS and ACCEPTANCE CRITERIA COMPARISON Procedure acceptance criteria required that:
- 1) All test data be obtained successfully
- 2) Reactor Thermal Power be calculated'successfully
- 3) Tke test results be submitted to the responsible groups performing:
a) Operational Alignment of Process Temperature Instrumentation b) Calibration of Steam and Feedwater Flow'nstrumentation c) - NIS overlap verification d) Reactor Coolant System Flow Determination (8 SOX and 100X'power levels) Tables 3.5.3-1 and 3.5.3-2 summarize the important test parameters on the primary and secondary plant, respectively. The most critical- point in this testing was obtaining a stable plant
~
condition. Although, the "stability documentation" required a defined stability over the entire testing period (approx. 50 minutes), it was difficult maintaining an absolute stable condition through out the test. As a result of mild plant perturbations, Feed flow or Steam flow fluctuated beyond the acceptance as defined in, the applicable analysis procedure. Small Feedwater oscillations may have caused RCS temperature fluctuations beyond the acceptance bounds of the Alignment of Process Temperature instrumentation. In an attempt to minimize these affects, data was obtained by sequence and by set number along with an increase in total number of data sets taken per sequence point. As a result of this change, a more accurate "snap shot" of the plant was obtained thereby enabling more points to pass the acceptance criteria. It was not'as critical that stability, channel to channel be as tight for thermal power determination as that above due to the overall data averaging methodology. The most dominant factor in determining RX thermal power was the factor of feedwater flow. This value was determined utilizing precision Honeywell dp Transmitters located at the feedwater venturi. INWC was read directly followed by flow MPPH calculated using vender supplied constants and equations. All retests applicable to these procedures were initiated to support the data requirements of the dependent test procedures. FIGURES and TABLES Table 3.5.3-1 Primary Plant Data Summary Table 3.5.3-2 Secondary Plant .Data Summary MIS/StartupMan/149/OS3
PRIMARY PLANT DATA
SUMMARY
TABLE 3.5.3-1 Calc. Parameters Average for 3 Loops Power Level T-HOT T-COLD X POWER PRZ PRESS MPPH S1 S1 0.00 NA NA NA NA 31;0 573.2 553.2 35.0 2231 49.08 584.9 553.9 56.46 2242 75.27 602.1 555.4 85.81 2242 89.83 611.4 556.7 90.4 2244 98.38 616.34 556.7 99.39 2243 SECONDARY PLANT DATA
SUMMARY
TABLE 3.5.3-2 < Gale. Power Level FW Parameters Tem FW Average Flow for 3 Loops FW Press Stm Press 3 MPPH S1 S1 0.00 NA NA NA 31.0 316.01 1.101 1022 1017 49.08 349.1 1.798 1033 998 75.27 404.69 2.945 968 955 89.83 419.52 3.581 957 937 98.38 428.14 3.956 951 933 MTS/Star tupMan/150/OS3
3.5 ~ 4
~ OPERATIONAL ALIGNMENT OF PROCESS TEMPERATURE INSTRUMENTATION 9102-5-15 OX 9104-S-18 30X
. 9105-S-16 50X 9106-S-06 75X 9107-S-10 90X 9108-S-08 100X TEST OBJECTIVES Reactor Coolant System temperatures are monitored by Resistance Temperature Detectors (RTDs) in the hot and cold legs which provide input signals to the Process Instrumentation System, which in turn uses these inputs to generate Tavg and AT values for use in. plant control and protection circuits. For each RCS loop, there are two pairs of RTDs providing temperature input for the control and protection functions respectively~ and a third pair of RTDs which serve as spares for the protection function.
A series of six tests was performed to verify and/or establish the following with respect to the. above instrument'ation for each loop:
- 1) Highest value of Tavg is within +1'F or -2'F of 588.8'F at 100X power.
- 2) Control and protection values of XhT are within + 1X of reactor power as determined by calorimetric calculations.
%P 3) Tavg as determined by the process
+ 0.5'F of actual calculated Tavg.
instrumentation summing amps is within s
- 4) Spare protection RTDs agree within + 1.2'F of control and protection active RTDs.
TEST METHOD During power ascension, statepoint data acquisition procedures were used to obtain data at nominal steady state reactor power levels of OZ (hot zero power), 30X, 50Z, 75X, 90X, and 100X. Data relevant to process temperature instrumentation consisted of process cabinet voltages for Thot, Tcold, Tavg, and X4T for protection and control functions in each loop. Spare RTD resistances and necessary data to calculate reactor power by calorimetric were also obtained. Raw data in the form of voltage and resistance values was then converted, again via the statepoint data acquisition procedure and appropriate scaling, to final values of temperature and XAT. Calorimetric determination of reactor power was also performed in the statepoint data acquisition procedure. At . all six power plateaus, temperatures from the spare Thot and Tcold RTDs were compared with the temperatures from the protection and control Thot. and Tcold RTDs ~ Also at all six power plateaus, actual Tavg was calculated from Thot and Tcold for the protection and control channels and compared to the respective measured Tavg value determined from process cabinet voltage. MIS/StartupMan/151/OS3
At the. 75X power plateau, Thot. and Tcold. temperatures were extrapo1ated using least squares fit of data obtained thus far- to predict Tavg and XhT for 100X ~ power. These predicted values were compazed with expected values to verify correct tracking of Tavg and XdT'uring power ascension. Measured Tavg was again compared with expected Tavg at the 100X power'plateau and measured XAT was compared to actual reactor power by calorimetric at the 90X and 100X. power plateaus. Adjustments were made to process instrumentation scaling and calibration as necessary.. RESULTS and ACCEPTANCE CRITERIA COMPARISON
.RCS temperature trends during the power ascension program are shown in figures 3.5 4"1 and 3.5.4-2 for protection and contzol channels respectively. A summazy of process temperature data obtained at the 100X power testing plateau is presented in Table 3.5.4-1. The data in this table includes actual measured values recorded at 98.63X reactor power (as determined by calorimetric) as we11 as values corrected to exactly 100X power. It can be seen that the highest Tavg value of 590.2"F exceeds the allowable Tavg of 588 F +1'F/-2'F by 0.4'F. Westinghouse evaluation concluded that this value of Tavg is still acceptable. All Tavg values are within 0.4'F of each other and well within the required 0.5'F of their respective calculated Tavg values. All loop AT values used to determine X4T are well below the maximum expected 4T of 63'F which is assumed for minimum RCS flowrate and within 0.8'F of the expected hT of 59.7'F.
During power ascension, comparison of measured .vs. calculated Tavg failed to meet the acceptance criterion on three occasions. All three failures were -found to be a result of data acquisition errors. At the 75X power plateau, Tavg values extrapolated for 100X exceeded the maximum a1lowed value of 589.8 'F. Westinghouse determined that no real problem existed and that the data analysis methods being used were not consistent with Westinghouse methods. Specifically, least squares fitting of data should have used a straight line vice a curve fit and assumed- values of 557'F and 2250 psia should have been used for OX power. A new extrapolation of data revealed that all Tavg values for 100X power were'elow the minimum Tavg of 586.8'F. Westinghouse recommended making no adjustments to the Tavg pxogram due to apparent steam cycle inefficiencies observed at the 75X power plateau. Tavg was adjusted at the 100X power plateau since main steam pressure was still low and'll Tavg values were still less than 588.8'F. The result is the slightly high Tavg values already discussed. Comparison of spare RTDs with operating RTDs resulted in several failures to meet acceptance criteria during power ascension. With the exception of Loop C RTDs; all failures were corrected. The RTD for Loop C Protection Tcold was determined to be suspect at the 30X power plateau and was consequently interchanged. with the spare RTD, which was in good agreement with all other RTDs ~ No further failures were experienced after the, interchange, indicating that the problem may have been a loose or dirty terminal connection which went undetected but was corrected, when the RTD wiring was changed. The spare RTD for Loop C Thot failed to compare with operating RTDs within the required 1.2 F on four out of six occasions., This RTD will be replaced in a future outage. MIS/StartupMan/152/OS3
During power ascension up to 75K power, %AT was determined using a conservative assumed full power AT of 59.4'F. All dT summing amps to new full power hT'alues using the extrapolation of data at the were'escaled 75X plateau. At the 90X plateau, Loop B Protection %AT was still mote than 1X greater than actual reactor power, but Westinghouse recommended taking no action since the value was conservative and rescaling would likely be required at full power. At the 100'ower plateau, Loop B Protection ZEST was within 14 of reactor power, but Loop A Control XAT was more than 1X lower than reactor power. All AT summing amps were rescaled using the most current (i.e, 100X plateau) data and retested. Loop A Protection and Loop C Protection and Control XAT indications exceeded reactor power by more than 1X on the retest. Westinghouse evaluated the test data and concluded that it was acceptable until the next regular calibration when the AT values should be optimized. FIGURES and TABLES Table 3.5.4-1 RCS Process Temperature Data for 100X Power Figure 3.5.4"1 RCS Temperature Trends - Piotection Channels Figure 3.5.4-2 RCS Temperature Trends Control Channels MIS/StartupMan/153/OS3
RCS PROCESS TEMPERATURE DATA FOR 100X POWER TABLE 3.5.4-1 4 hot cold T avg (Fate.) Measured 619.0 559.7 589.4 589.4 59.3 100.1 LOOP. A 100X. 2 619.9 559.7 589.8 60.2 101.5 Measured 619.5 559.9 589.5 589.7 59.6 98.99 . LOOP B 100X 620.4 559.9 590.2 60.5 100.3 Measured 619.1 560.3 589.8 589.7 58.8 100.0 LOOP C 100X 620.0 560.3 590.2 59.7 101.0 Measured 619.3 559.7 589.5 589.5 59.6 98.5 LOOP A N 100X 620.2 559.7 590.0 60.5 100.2 Measured 619.4 559.9 589.6 589.6 59.5 98.64 LOOP B 100X 620.3 559.9 590.1 60.4 100.3 Measured 618.9 560.5 589.7 589.7 58.4 100.7 LOOP C 100X 619.8 560.5 590.2 59.3 100.7 Notes.') Data at 98.63X power as'etermined by; calorimetric.
- 2) . Data extrapolated to obtain exact 100X power values from 98.63X data.
- 3) Process output.
- 4) Calculated form (Thot Tcold /2.
- 5) Calculated from Thot Tcold'IS/StartupMan/154/OS3'
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3.5 5 REACTOR VESSEL LEVEL INDICATION SYSTEM (RVLIS) 9102-S-19 ~ 9108-S-21 EPT-36T TEST OBJECTIVES The. Reactor Vessel Level Indication System (RVLIS) utilizes differential pressure measurements across the reactor vessel compensated for operating pumps and temperature to visually indicate reactor vessel level during normal operation and transient situation. The purpose of the Reactor Vessel Level
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Indication system procedures was to obtain baseline data for the evaluation of the RVLIS operating characteristics during the initial primary plant heatup and the power ascension to 100X power. Subsequently, the data obtained was input to the RVLIS software and 100X values were verified. TEST METHOD During plant heatup a plant computer trend block was monitored and data recorded at 50'F intervals along with supplemental RVLIS data which included one, two, and three Reactor'oolant Pump data. The data obtained included upper, full, & dynamic range differential pressure; upper, full, & dynamic range level, RCS pressure, and hydraulic isolator, and RVLIS ERROR'essage display values. Compensating system RTD values and local Reactor Auxiliary building temperatures were also obtained. Following data acquisition a determination of polynomials for dynamic range differential pressure compensation was performed. A polynomial of Dynamic Head vs. saturation pressure at Thot and of Dynamic Head vs. RCS wide range temperature for both Train A and B 'of RVLIS were developed and using the software maintenance terminal, the polynomial coefficients were input to the microprocessor. At Hot. Standby, while the RCS Flow Coastdown Test was in progress, data was taken with zero, one, two, and three RCPs in service and compared to predicted values. During the increase to 100X power, EPT-36T, RVLIS Baseline Data During Power Ascension gathered baseline data from OX power to 100X power at the major test plateaus. The acquired data was also input to the microprocessor. Once power was stabilized at 100X power, RVLIS values were compared to expected 100X values. RESULTS and ACCEPTANCE CRITERIA COMPARISON RVLIS values were compared to expected values within +2.5X at Hot Standby conditions with zero, one, two, and three RCPs in operation. Table 3.5.5-1 is a summary of Hot Standby data. At 100X RVLIS values were verified to be within +6X from expected values. Table 3.5.5-2 is a summary of 100X values. FIGURES and TABLES i Table 3.5.5-1 RVLIS Hot Standby Data Table 3.5.5-2 RVLIS 100X Power Data MIS/Star tupMan/157/OS3
RVLIS HOT STANDBY DATA TABLE 3.5 5-1 A Train B Expected Dynamic Dynam 1 c Dynamic No. RCPs 0 Head Level Head Level Head Level 0 62X'rain 36X 36.070 37.087 43X 41.015 42.099 62.735 63.834 100X 98.402 98.400 RVLIS 100X POWER DATA TABLE 3.5.5-2 Parameter Expected Value Train A Train B D amic Head Level 110X 110X 108X U er Ran e Level Off-Scale (Low) 60.0X 60.0X + MIS/StartupMan/158/OS3
3.5.6 START-UP ADJUSTMENT 'OF REACTOR CONTROL SYSTEM 9106-S-02 9108-S-02 TEST OBJECTIVES The purpose of Start-Up Adjustment of Reactor Control System tests was to determine the Tavg program that produces the highest steam generator outlet pressure (and optimum efficiency) without exceeding the design full power Tavg nor the turbine pressure limitations. In accordance with design, Tavg program should not exceed the allowable Tavg of 588.8'F, +1, -2'F, and Steam Generator outlet pressure should not exceed 964 psia + 10. TEST METHOD Steam generator outlet pressure, first stage turbine pressure, and percent thermal power were recorded for 0, 30, 50, 75, 90, and 100X power ascension test plateaus Lower power data was extrapolated to expected 100X values that the Tavg program was properly aligned to produce the optimum design correlation between steam generator outlet pressure, first stage turbine pressure, and percent core power. RESULTS and ACCEPTANCE CRITERIA COMPARISON At 75X power first stage turbine pressure was found to be low producing a lower than-expected Tavg of -578.9 vs 581'F expected and steam generator outlet pressure of -969 psia. Due to inefficiencies of secondary plant, adjustment of Tref was postponed in order to trim up secondary losses. At 100X power first stage turbine pressure required 'adjustment of Tref as steam generator outlet pressure was approximately 18 psi lower than design (947 psia). This adjustment resulted in an acceptable value for steam generator outlet pressure (977 psia), Tavg (590'F), and first stage turbine pressure. An Engineering performance test was performed to determine steam generator pressure transmitter head correction values. These new values reduced the steam generator outlet pressure value form 977 psia to 972 psia which was within the acceptance criteria. FIGURES and TABLES None MIS/StartupMan/159/OS3
3 5.7 OPERATIONAL ALIGNMENT OF EXCORE NUCLEAR INSTRUMEHTATION 9103-S-25 OX 9104-S-08 30K'0K 9105-S-07 9106-S-07 '5X 9107-S-02 90X 9108-S-07 100X TEST OBJECTIVES Tests associated with Operational Alignment of Excore Nuclear Instrumentation were to verify the excore nuclear instrumentation to be operating in accordance with design and to be serving as a valid extension of the plant control system's ability to sense and respond to desired and undesired reactivity changes. This involved the monitoring and alignment of the nuclear instrumentation during the approach to criticality and during power ascension via plant surveillance procedures. TEST METHOD Chosen parameters at various power levels are monitored and evaluated via the associated controlling surveillance procedure. Voltage and trip settings are aligned or verified to be within tolerance for Source, intermediate, and power> channels per the applicable Technical Specification. Overlap between source, intermediate, and power', flux deviation alarm settings, high level trip setpoints for source, intermediate, and power, linearity of detector response verse core power via precision calorimetric, characteristic curves for intermediate and power channels generated; and verification of voltage plateau regions are included in the nuclear instrumentation alignment. RESULTS and ACCEPTANCE CRITERIA COMPARISON I Required adjustments calibrations, and setpoint determinations were performed in accordance with the controlling I6C surveillance procedure. Data taken during 0~ 30, 50, 75, 90, and 100X power plateau values provided data sufficient to establish acceptable overlap, acceptable correlation between Nl-indicated power and precision calorimetric power, and acceptable linearity relationship between detector response and reactor power. Additional baseline data defining general Nuclear instrumentation system initial configuration were also tabulated Figures 3.5.7-1 through 3.5.7-4 are graphs of Power Range Total Currents vs. Percent Power Level. FIGURES and TABLES Figure 3.5.7-1 Channel N41 Current Figure 3.5.7-2 Channel N42 Current Figure 3.5.7-3 Channel N43 Current Figure 3.5.7-4 Channel N44 Current MIS/StartupMan/160/OS3
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~ ~ IYr s s J l p p - ~ -l-r r ~ I ~ ~ ~ ~ ~ ~ ~ J l ~ I ~ ~ ~ 700 -rvJ-J-I -I"V ~ ~ ~ I r1-J s ~ '-I I ~ J ~ s lI s I ~ ~ J rvo-J- ~ I ~ I I lI l s C1-l-I-s ~ ~ l l rv>>-J ~ ~ I g q I ~ ~ C1 J ~I g ~ eh)- ~ ~ ~ e'L )->>- ~- I.) ~ ~ ~ ~ ~ L)>> ~ I l.). ~ ~ ~ . }.)>>I ~ -'C)- ~I - ~- ~ I )- ~I - ~- Ih) I'L g ~ ~ Il. JI ~ ~ ~ I L)+-~I .L) ~I . ~ ~ I L J I ~I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ LJ ~ ~ ~ LJ ~ LJ ~ ~ I J~ s ~ LJ ~ ~ LJI s LJ ~ LJ ~ ~ lJ s ~ ~ '-'-r.r 1 l 1I 1 ~ 1 ~ ~ ~ ~ 1 ~ l lI p ~ ~ ~ ~ ~ p '-or r -l- ~ ~ ~ ~ ~ ~ ~ I ~ ~ ~ ~ -r-r ~ ~ J ~ e l1 ~ ~ ~ ~ ~ I l-r r ~ ~ ~ ~ ~ J ~ I I l ~ J I ~ I ~ I ~ g ~ g I ~ J~ I ~ ~ J ~ l~ g ~ s ~ I I l I lI l ~ ~ ~ ~ ~ g ~ ~ ~ I I 600 I -r1- ~ J- J- -rI elI s I I J~ I I J l rw-J-J- ~ ~ I s J I -rw I s l-~- I ~ J ~ I J J .CVJ--I ~ I I -r 1- J- J.I ~ Cg J C1 I C1 ~ J p1 ~ ~ .h).~,~ - ~ . ~ ~ LJ ~ ~ ~ l.J ~,' ~ ~ ~ I ~ ~ ~ ~ ~ -}.)>>-~- -}-) ~ ~ ~ ~ W) I ~ ~ ~ ehJ ~I I -}.{->>- ~ h) ~ ~ ~ ~ .l.).>>I ~ s LJ 1 1 ~ LJ ~ ~ ~ ~ LJ ~ ~ ~ LJ ~I J ~ ~ LJ ~ ~ ~ I J I ~ ~ LJI ~ ~ I J ~ I J S ~ ~ I LJ I S l l rC s ~ I 1 1 l-l-rI r lI l ~ I ~ ~ I 1 ~ ~ ~ ~ ~ ~ l-r.r I ~ J lI s J l I ~ I ~ l-r-r ~ ~ ~ 1 ~ ~ J lI0 ~ ~ g ~ 1 I' ~ ~ lI ~ 1 ~ I J ~ l I I ~ ~ ~ g ~ ~ ~ g p ~ I I I I I p p ~ I ~ ~ I p p ~ ~ ' I ~~ ~ g g ,I I p p sa' ~ 500 ~ 1 ~ ll e ~ 1 J~ ~ ~g 1 J~ lI I s 1 J~ lI s r l~ ~ I 'I~ c ~ I J e l o ~g s I J J I a lI c 'a I a J I 1 ea' Cq l J g h)1 ~I - ~I q 1 g g g g -h)->>- ~- ~ ~ ~ ~ -} {-~ - ~- ~ ~ h) ~ ~ ~ ~ I IL) ~ ~ ~ ~ I ~ ~ ~ ~ ~ 4 4 ~ ~ ~ )~ ~ I ~ L{ ~ ~ ~ l.J' ~ ~ . l. ). ~ ~ ~ ~ ~ I ~ eLJ LJ I J LJ LJ LJ s, ~- LJ lrr ~ ~ ~ ~ ~ ~ ~ ~ s ~ ~ ~ g s s s 'I 8 I ~ I I 1 l-r-r 1 ~ ~ ~ I l ~ ~ ~ g ~ ~ ~ I lrr ~ ~ ~ ~ ~ I I 1 C 1~ I II' ~ I ~ I I lr ~ ~ I lI ~ ~ ~ I ~ ~ g ~ g lI l~ I'a g r 1 ~a I -r-rI ~ ~ ~ 1 lI p ~ llI ~ ~ 1 ~ s ~ I ( I I 1 I ~ g ~ ~ <oo ' r1'-I J. l-l- l I I J r1- J- J- reI l-J- I ~ I -rvJ-J- I I -rI V J-l I I J ~ ~ ~ ~ I ~ -rw I I .r1 ~ ~ ~ ~ e s ~ s ~ ~ ~ ~ pq J ~ I 1 ~ ~ I 1 J~ ~ e pq -)I .hI J. ~~ lJ l ~ 1 ~ I ~ ~ l.) ~ I ~ l ~ J ~I I ~ ~ ~ 1 ~ LJ~ l-l-r-r ~ ~ 1 I I ~ 1 s ~ L) I LJ~ ~ l ~ ~ ~ ~ ~ I ~ ~ ~ ~ I ~ 'Jl l } )->>~ I I I s \J ll 1 S ~ I ~ }'{>> I eLJ ~ 1 ~ ~ L) I J I s I e ~ ~ LJ, LJ~ l1 ~ ~ ~- ~ ~ LA~ a LJ lII ~ ~ I ~ I ~- ~ ~ LJI ~ lI ~ ~ ~ ~ ~ g ~ J ~ ~ I p ~ ~ I I ~ ~ J ~ ~ ~ g ~ p ~ ~ lI ~ ~ g s 2 ~ ~ p ~ ~ ~ ~ ~ g ~ g I or ~ s r s I I I I ~ ~ I ~ ~ g ~ ~ I p ~ g J ~ I ~ g 300 l-l- lI r1 J.l- -r1 lelI .CV J- J- r1 I I o I ~ ~ ~ -r1-J-J- I .r1 ~ ~ r1 a J I ~- ~ g ~ 1 J~ ~ a ~ ~ C1 g pv J-~ ~- ~ ~ ~ ~ ~ ~ ~ ~ -rs J ~- r1 ~ ~ h) ~ e I ~ ~ ~ ehJ~ ~ ~ I } )- - I ~ e ~- lJ ~ LJ ~ ~ l.J ~ ~ -} {->>-~- L) ~ ~ ~ ~ ~ ~ ~ h)>> I ~ ~ LJ I I ~I ~ ~ h J ~ I ~ J J ~ ~ 1 ~ LJ ~ 1 s ~ LJ ~ ~ ~L J 1 I s a s LJI s s ~ LJ ~ ~ ~ LJ ~ ~ I J ~ I s ~ ~ ~
- l. J
~ LJ~ ~ l ~ ~ I s g ~ s g ~ O I l ~ ~ r ~ ~ p ~ ~ ~ 1 l Ip ~ ~ ~ l ~ I ~ ~ l l ~ ~ e g 1 ~ g ~ ~ I 1 ~ ~ -l l Ir-r I ~ ~ ~ ~ I ~ I II' ~ ~ ~ ~ I I p 1 ~ ~ p lI Il ~ ~ ~ p ~ ~ l I I g ~ ~ ~ J ~ lI ~ ~ g ~ g 200 lI -r1-l-I I lI lI lI -r v"- ~ ~ I ~ ~ I ~ I I -rw J-J- I I J I ~ ~ ~ ~- s I p1 J r1 ~ s I pe- ~ e J I ~ C1 ~ J J ~ p1 J pq s J ~ ~ ~ . .I" {-~ - ~ . Ld- ~ ~- l J>> ~ ~ ~ ~ LJa ~ ~ ~ ~ ~ ~ ~ ~ ~ -}.)-~II - ~- -h{->>- ~- h) ~ ~ ~ I ~ ~ ~ ~ 'L) ~ ~ ~ ~ ~ I l~ JI 1~ ~~ -L J LJ~ ~I I ~ ~ ~ ~- eLJ 1 LJI ~ ~ s LJ ~ ~ LJI ~ ~ ~ LJ ~ ~ LJI ~ ~ J ~ LJ '-l-r-r 1 1 -l-l r-r 1 1 1 S ~ ~ 1 ~ I I ~ ~ ~ I ~ ~ ~ '-l.rerI ~ ~ ~ I I l -r-rI ~ ~ ~ I r r ~ ~ J l ~ I I ~ g ~ g ~ ~ ~ ~ ~ ~ J ~ I I l ~ g 1 ~ g, J ~ ~ I p p I l ~ e g ~ I p ll ~ ~ ~ ~ p ~ ~ ~ I ~ ~ l ~ g ~ p J ~ ~ ~ I ~ 100 s r1 ~ ~ ~ ~ l I rs s J-l- r1-l-J-s ~ ~ -rs a a J ll -rw ~ ~ l ~ ~ ~ -r 1- J- ~- r1 a e ~ ~ lI ss' J J I ~ J -ra- J- J. ~ ~ ~ h)1 I C g Q ~ I l.) ~ ~ ~ ~ I ~ ~ I l J ~I I I ~ ~ l,) ~ ~ ~ I ~ ~ ~ ~ ~ ~ ~ ~ -h)- ~ ->>- ~ ~ ~ ~ }{>> h)~ ~ ~ ~ ~ ~-I l. ). ~ I ~ ~ I e L{ ~ ~ LJ LJ LJ LJ . ILJI LJ~ '-l r ~ ~ J s s LJ ~ ~ J ~ ~ ~ ~ I J ~ ~ e ~ s 0 r Ir e ~ ~ ~ ~ II' ~ I II ~ l ~ ~ ~ ~ g ~ g ~ ~ ~ ~ 1 ~ C 1 I' ~ ~ ~ ~ ~ 1 l-r-r ~ ~ ~ ~ ~ J ~ lI ~ 1 ~ 1 ~ ~I ~ l r-r ~ a a l-lrr ~ ~ ~ ~ 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ g ~ g J ~ ~ ~ I l ~ ~ I ~ ~ ~ ~ I. J ~ ~ ~ 1 p 0 20 40 60 80 100 120 I REACTOR POh/ER (Fo) F I GURE 3.5.7-2 n gga CHANNEL N45 CURRENT , DATA AT 100Fo POWER 1000 -r1-'- I . r1 l I r1-'- ~- ~ ~ ~ r1- J- ~- I'1 ~ ~ ~ ~ ~ ~ ~ ~ I I s ~ ~ I ~ 4) J I ~ g ~ .4). ~ . II 4) ~ ~ I -4)- ~ ~ ~ ~ C1 ~ J I J ~ C1 ~ J I ~ I ~ ~ C1 J ~I ~ ~ ~ ~ ~ I'1 I JI ~ I J l~ ~ - ~- -} )- ~ ->>- -4)->> ~- -} )- ~I ~- ~ ~ ~ }J ~ >>. I I ~ ~ ~ ~ ~ I ~ ~ ~ ~ ~ I ~ I ~ -4{-~ - ~- ~ -} {-~I -4)- ~ I ~ ->>- L) ~ ~ ~ ~ 4~ J I ~ I lI C ~ ~ LJ lI IlI r ~ ~ ~ ~ ~ ~ LJI 1- ~ ~ l ~ I I r ~ ~ ~ ~ LJ I ~ ~ ~ L I 1 ~ g 1 LJ l IlI ~ ~ ~ ~ ~ g ~ LJ~ lI lI ~ s ~ ~ ~ I.J 1 ~ -4 J J L I I I I ~ rr I ss J I I LCI ~- lII l Ir ~ s ~ IJ L I I I I I ~ I ~ J~ ~ lI ~ ~ ~ ~ ~ ~ ~ J I.J I ~ I 1 lI I r ~ ~ ~ 900 ~ ~ ~ I -r1 J-l- -r1 l-lI -r1 l- ~- lII ~ ~ ~ I I I .r1-l- I ~ ~ g ~ 1 JI ~ ~ e s s ~ g 1 J ~I -r1 J ~ ~ s s 1 J -r1-J-J.s ~ I ~- ~ ~ pJ ~ ~ ~ J ~ I s C1 ~ }{>> 4J ~ e ~ ~ -4{>>-~- 4)- ~ -e L)>> ~I -4)->>- ~ I J e ~ ~ ~ ~ LJ ~ ~ ~ ~ LJ~ ~ s I ~ ~ LJ. ~ . ~ . ILJ ~ ~- -} {-~ - ~- sLJ>> ~ ~ I g -4I Jee- ~ I ~ ~ I -}.) ~I ->>- I -}.)-~ - ~- }'{>> ~- 4{ ~ ~ ~ ~ I ~- s{>> ~ ~ ~ 1 ~ 1 ~ ~ I ~ ~- LJ~ 4 J.>>s s LJ 4J' s LJ I I l Il I ~ ~ ~ ~ g , I ~ ~ l ~ ~ ~ sr~ ~ I ~ l ~ g g ~ ~ I ~ C ~ lI r cI I J l ~ 1 ~ C C ~ ~ l-r I r ~ ~ I 1 I' ~ ~ ~ ~ I ~ C C ~ ~ 1 I r ~ ~ ~ l r-r 1 ~ e s J ~ l ~ 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ I I I 800 r1-l- ~ ~ ~ ~ ~ ~ ~ ~ ~ I r1 i)>> ~ I -r1 I L) ~ J ~ I ~ ~ I ~- ~ I ~ g 1 4)I ~ J J ~ I I g s 1 J~ JI .4) ~ ~ J I I J ~ 4) ~ r1 lI I ~ ~ I g ~ 1 J~ ~ I -r 1- ~ ~ l.I I ~ I"I I' s s -}. )- ~ - ~ ~ ~ ~ LJ ~ ~ ~ I.J ~ ~ ~ eL{->>- ~ ~ ~ I ~ -4{->>- I I ~- ~ ~ ~ ~ ~ ~ I I ~ ~ 4)->> ~ -%)- ~ I ~ ~-~ L)>> I ~ ~ }{>> I I ~ I J a \ JI LJ I J 1I ~I ~ ~ ~ s ~ ~ sLJ 4J ~ LJI 1 ~ s LJ 1~ ~~ 4J s LJ l1 1 1 ~ ~ ~ ~ 1 ~ 1 1 lI Il lI I'l-r-r J lI ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ g ~ ~ ~ ~ g ~ ~ ~ ~ g ~ -'-l-r-r I I I I lI LI ~ ~ I ~ I ~ ~ l-l I I r-r ~ ~ J I I ~ I I I ~ ~ ~ l ~ g ~ ~ I I 1 l s, r l ~ ~ ~ ~ ~ ~ ~ g 700 l ~ ~ ~ ~ ~ ~ O r1I ~ 4)>> -l"V ~ I J- J ~ ~ r1- II J- ~- ~ g 1 I J l ~ C1 J I s ~ r1-l-l -r 1-'-I ~- -r1I l-l- -r1 ~ ~ s ~ I ~ l- I . -r1-l-l- ~ ~ ~ I ~ -r 1- l- l- ~ ~ l 'I J>>I ~I -4{->>-~- -%)I ~I -4)>>- ~ ~ ~ ~ ~ ~ ~ LJ ~ ~ ~ ~ I ~ ~ ~ ~ ~ ~ ~ ~ ~ -}. J- ~ e ~ ~ I ~ }.)>> e ~ ~ L)+ I e ~ I I CL'3 I J ~ ~ s 4J LJI 1 ~ LJ 1 ~ ~ i.J.>>. ~ ~ 4J 1 LJ s s IJ 1 s LJ 1 I .i.J. ~I ~ ~ LJ I lrr ~ I ~ 1 ~ ~ ~ lr J l ~ K ~ ~ ~ ~ c -J~ ~ ~ I rI ~ I- ~ lI l-r-r I e I I ~ ~ ~ g ~ ~ ~ ~ l IC C I-l r r -l-l-r-r ~ s ~ ~ I I I ~ ~ ~ l-l-r-r lel-r ~ ~ ~ ~ I e ~ r l lI ( ~ ~ ~ ~ ~ ~ I' ~ I I I ~ 1 ~ ~ ~ 600 lI ~ ~ ~ ~ ~ ~ ~ r1 I I' 1 J lI I r1 l I r1 l I I 'I Ir1-l-l ~ ~ ~ s s s s 1 JI J -r1- J- ~ C1 J I ~ s I"VJ- ~ ~ ~ ~ I g C1 ~ I ~ ~ 1 JI I ~ J-LJ I ~ ~ ~ -4{>>I I ~- ~ 4)- ~ - ~- ~ ~ 4) I ~ ~ ~ ~- .4). I I ~ ~ ~ ~ ~ .4). I ~ ~ g ~ . -} )- ~ ~- ~ g I ~ ) ~ LJ ~ - I -4)->>- ~ ~ I I ~- LJ 4J I I ~ ~ I J 1~ ~ ' LJ 1 ~ ~ ~ LJ 1 1 II J 1 ~ ~ ~ ~ ~ LJ 1 ~ ~ ~ 4J 1 ~ ~ ~ I I 4J e 1 I ~ LJ I I lI lI I ~ ~ 1 ~ 1 ~ J l c r I I 1 ~ I ~ g C ~ ~ ~ ~ I L Ir I ~ ~ ~ I ~ g ~ I I ~ ~ ~ ~ ~ ~ I ~ ~ ~ ~ I I ~ ~ I ~ l .I I L g Is lI I l I C ~ l L I C ~ ~ ~ l-r-r I ~ ~ ~ lI l ~ I ~ ~ 500 Ir1-l-l- ~ ~ ~ ~ ~ ~ I I -rI 1-l-l- C1 J -r 1-I - '- 5'- r1 l-l ~ ~ ~ ~ ~ J ~ ~ ~ ~ s I ~ I ~ ~ 8 s ~ ~ g e'4{->>- 1 ~ ~ ~ C1 ~ e L)>>I ~ 4)I ~ - -} )->>- II -4)- ~I - ~- r4 ~ ~ g 1 J ~ C1 ~ ~ ~ C1 ~ ~ -r1- J-I J-I ~ ~ ~- ~ ~ e ~ ~ ~ ~e ~
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- i. J
~ ~ ~ IJ>>I ~ s ~ LJ>> ~ 1 ~ ~ 4J ~ 1 LJ 1 1 ~ LJ 1 s s I 1- ~- LJ I ~ ~ ~ ~ LJ 1 s LJ ~ ~ ~ ~ ~ LJ ~ ~ lI lI I JI I ~ g g ~ ~ ~ ~ ~ g ~ l LI ~ g ~ I I I I lsr ~ ~ I l r I r-r I I C C I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ g ~ ~ g, -lI r-r -g-l-r-r ~ I ~ I ~ I ~ I l ~ ~ g ~ l l C l ~I 1 1 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I g g g}00 ' ~ ~ ~ ~ ~ ~ I)>>I -r1'-'- -r1-l-l I J ~ ~ ~ 4)>> ~ ~ ~ r1 J I r1-'- ~ ~ s I ~ . C1 J I I J s s ~ ~ ~ re J-J- i)>> I ~ ~ I 1 JI JI ~ ~ ~ ~ 1 JI J s s C1 JI lI I ~ ~ ~ ~ ~ I 4{ ~I I ~ ~- 'L)- ~ - ~- 4) ~ ~ I ~ ~ )~ ~ ~ ~ } J-o ~ ~ ~ g e g }'{>>>> ~ LJ>> I I .i.)>> ~ ~ . 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I I' I ~ 1 ~ ~ ~ l I I ~ ~ ~ I s I s J J ~ 0 ~ I J ~ e ~ ~ I ~ LJI LJ~ ~ ~ ~ ~ ~ -I4 LJ {-~ - ~ e LJ>> ~ ~ ~ s ~ ~ I ~ ~ .i.J. ~ ~ I I -~~ g -}.) ~ ~ ~ ~- -L)e e ->>- ~ ~ g -}{>> ~ I I ~ ~ I ~ I I ~ ~ . lrr ~ ~ I ~ 1 ~ ~ ~ s 1 ~ I~ I J 1 ~ s LJ' s s 4 J 1s s LJ ~ I LJ LJ ~ s l I I ~ ~ ~ ~ ~ I ~ ~ g ~ ~ J I L I I CJ}e ~ l C ~ l ~ ~ ~ l-r r ~ ~ ~ J I I ~ L ~ ~ ~ I s J I ~ I ~ l ~ ~ ~ l ~ ~ l r-r I ~ I ~ ~ lI g s 200 ~ ~ ~ ~ ~ ~ ~ I ~ ~ I I I ~ C1 ~ J J I ~ g ~ 1 J~ ~ J I I J ~ C1 I ~ J ~ lI ~ s C1 ~ J lI ~ 1 ~ ~ J r1 ~ I ~ -r1 ~ s J r1 lI I I ~ r1- I I ~ s J ~ ~ I C1 JI J~ -rvJ I ~ ~ ~ ~ 4{ ~ 4)>> LJ ~ .4)>> ~ . 4) g ~ ~ ~ ~ -}.{->>- ~ I sL) ~- ~ -}{>> ~- 4) }.J>> ~ I "rr ~ ~ 4 J. ~ ~ I ~ ~ ~ ~ I ~ ~ ~ ~ IL{ ~I ~ ~ ~ ~ ~ ~ ~ LJ s ~ ~-~ LJ ~ LJ ~ LJ~ ~ I LJ LJ I I LJ I I sLJ ~ ~ I ~ ~ I ~ 1 ~ ~ ~ LJ ~ ' 1- ~- ~ ~ LJ ~ ~ J L II ~ r ~ ~ ~ lI ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I -l-lI r Ir ~ ~ ~ ~ ~ r sr l lI r ~ 1 ~ ~ l ~ I -J-l ~ I I lr I I r r J L ~ J ~ ~ ~ ~ s < s ~ C ~ ~ ~ ~ ~ ~ I ~ ~ ~ I I I I I ~~ I 100 l ~ ~ ~ I JI ~ ~ ~ -r1-I J- ~- -r1- J.I ~ . l r1 l I l- J l~ r 1- l I ~ ~ ~ 1 J~ ~ ~ ~ s ~ ~ ~ ~ g ~ )- ~ - ~- ~ I 1 J ~ ~ 1 ~ ~ C1 ~ ~ -r1 ~- r1 JI ~ ~ ~ ~ ~ s ~ ~ } )i>>s g ~ ~ ~ ~ s'4 {- ~ ~ ~ - ~- ~ ~- 4)>> ~ ~ ~ }'{>>-e- ~ I -I-)- g I ~ ->>- ~ ~ eL) ~ ~ I ~ -4{-~ - ~- ~ ~ -4 {->>-~- -4)- ~ - ~- -4{->>- ~- ~ ~ ~ ~ LJ~ 1I ~ I J I J ~ LJ ~ I .LJ ~I ~ I LJ~ I I LJ I I ~ ~ ~ ~ 1 ~ ~ ~ 1 ~ LJI s s I J ~ LJ~ ~ ~ LJ ~ s LJ I I ~ ~ r.r ~ ~ I ~ l ~ ~ ~ ~ ~ ~ rr ~ ~ ~ ~ l-r r ~ ~ I ~ ~ I I ~ ~ g ~ J ~ ~ ~ ~ I llcr ~ ~ ~ ~ J ~ L ~I I ~ ~ r '-'-r-r I ~ ~ ~ ~ ~ J ~ lr 1 ~ ~ ~ ~ ~ J l ~ ~ ~ ~ I ~ 1~ .J-l-r-r 1 ~ ~ ~ ~ ~ I I g I g 0 ~ ~ ~ ~ ~ ~ ~ ~ 0 20 40 60 80 100 120 REACTCA PQVER (/o) F I GOBE 3.5.7-3 CHANNEL N44 CURRENT DATA AT 100% PO hI'ER 1000 -r 1'- J-I ~ I fLJ ~ ~ ~ I -rwI J- ~- ~ ee' r YJ- rwI J-J I I ' I -rYJ-J-(Y I ~ ~ ~ ~ ~ a ~ s s s rg s ~ ~ ~ ~ J J ~ ~ ~ I ~ ~ J J g 1 J~ ~I ~ ~ I J Cl J J I ~ -LJ ~ I ~ ~ L{>>I ~ I -s. 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L{ ~ ~ I ~ ~ LJ ~ ~ ~ ~ I ~ ~ . .L J ~ A ~ ~ ~ ~ LJ>> ~ }. { ~I I ~ ~ I ~ I ~ I ~ I ~ ~ ~ ~ LJ o ~ ~ ~ LJ ~ a J,I ~ ~ e LJ 1 LJ ~ 1 I J ~ ~ ~ ~ ~ ~ ~ I J 1 ~ ~ ~~ ~ ~ ~ ~ L J ~ ~I '~ I ~ LJ ~ I ~ J' 1 ~ ~~ J l p p J l Ip l ~ ~ ~ J l I C I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ l ~ ~ r-r ~ ~ ~ ~ ~ l ~ p ~ J l ~ ~ ~ ~ ~ g ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ rY~ ~ ~ J ~ p I ~ ~ ~ ~ .J-l ~ ~ ~ r ~ r ~ ~ ~ p -~ ~ ~ ~ ~ I I J ~ I ~ g ~ 800 YJ-J-I I J J I I YJ- I -r I YJ-J- I I I ~ ~ I I I -r ~ ~ J J r s s ~ . Cl ~ J ~ ~ ~ ~ g J J (1 J ~ ~ J ~ ~ 1 s J ~ ~ ~ I'a I ~ J J .L J,.I . IJ>> g LJ ~I I I g I a.J ~ ~ ~ ~ -L {-~ - ~-~ I a.J I I ~ ~ ~ -} {>> .LJ ~ ~ I I ~ ~ ~ -}.{-~I - ~ . 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I p LJ ~ ~ ~ I ~ 1 I ~ 1 LJ I I ~ J ~ lI ~ I I ~ ~ I I' ~ I ~ ~ ~ s I' ~ s ~ LJ ~ ~ lrr s I s ~ LJ' ~ s 'I s I 1 I J ~ I ~ l I ~ I s ~ -"J ~- p p . ~ r-r s s ~ ~ ~ I 100 I ~ Ir1-J-'- I I ~ I -r1 J-J- I ~ ~ ~ r1 J I -' f1 ~ ~ ~ ~ J ~ rw~ J ~ rw J ~ ~ ~ 1 J~ JI ~ ~ ~ ~ J J~ (1 ~ ~ J J 1 J ~ ~ ~ s J ~ -L{ ~ - ~- ~ ~ ~ J' ~ ~ ~ ~ I.J ~ ~ ~ ~ -H. ~ ~ I ~ ~ 4 g J->>- ~ I }-{ ~ ~ ~ ~ } J ~ ~ I -L~ J->>- ~- ~ I g J I I Is I I -L{-~ - ~- ~ I -L{-~ - ~- ~ ~ LJ ~ I J~ ~ LJ1' II s s LJ ~ LJ ~ ~ ~ LJ ~ .L J. ~ ~ ~ LJ 1 ~ ~ ~ ~ I .LI J.>>.e. I J ~ ~ e J~ ~ ~ ~ I r-r ~ ~ ~ ~ lp ~ ~ J l ~ ~ ~ g J I ~ ~ l I I p ~ ~ J ~ l c Ir ~ ~ ~ ~ . ~- I ~ ~ ~ ~ J ~ lp ~ ~ ~ ~ ~ g J-l r ~ ~ ~ ~ ~ r J I lp ~ ~ ~ p -J-l ~ I I r-p ~ .J-'r ~ ~ ~ I 1 ~ ~ r ~ ~ J I ~ ~ ~ c"r~ 0 0 20 40 . 60 80 100 120 REACTOR P(MR (Fo) F1GUBE 3.5.7-4 3 5 8 CALEBRATION OF STEAM AND FEEDWATER PLOW INSTRUMENTATION 9104-S-OL 30X 9105-S-01 50X 9106-S-01 75X 9107-S"03 90X -9108-S"01 100X. TEST'BJECTIVES Steam and Feedwater instrumentation calibration is essential to the accurate determination of reactor power via calorimetric calculation. Proper calibration also ensures no feedflow/steamflow mismatch occurs. The purpose of the Calibration of Steam and Feedwater Flow Instrumentation Test was to check the calibration of the steam and feedwater flow transmitters, as well as the flow indicating signals from the plant process computer, Main Control Board and Square Root Extractor at various power levels. TEST METHOD The ~ test performed no data gathering in itself, but rather obtained data from the Thermal Power and Statepoint Data Acquisition procedure at the various power levels. In that procedure, measurements and readings were obtained at synchronized times from the plant feedwater and steam flow transmitters, the process instrumentation square root extractors, the Main Control Board indicators, and the plant process computer address points. ~ In addition,' readings were obtained from 0.1X accurate Honeywell test, differential pressure ~ ~ - cells that were connected to the same taps- as .the permanent plant feedwater flow instrumentation. ~ ~ At the 30X and 50X power plateaus the data was used to verify that the installed permanent plant feedwater flow transmitters were reading within + 0.5X of full scale differential pressure when compared to the Honeywell test instruments. In addition, feedwater and steam flow was calculated using scaling equations based on their square root extractor voltages and extrapolated out to the next power plateau to ensure that steam/feedwater flow mismatch would not occur before the next power plateau. Because of the large measurement uncertainty of feedwater flow at low power levels, the data from the Main Control Board and the plant process computer was used for baseline data only. At the 75X,: 90X, and 100X power plateaus, the acceptance criteria was more stringent'nce again the differential pressure and corresponding flow as measured by the Honeywell test instrumentation was the benchmark for comparing to the steam and feedwater flows as measured by the permanent plant instrumentation. The dP of the plant feedwater flow transmitters was verified to be within 0.5X of full scale dP when compared to the Honeywell test instrumentation. The differential pressure of the plant feedwater instrumentation was also used to calculate a corresponding flow from the equation'. calculated. flow = 5 MPPH transmitter full scale AP MZS/StartupMan/165/OS3 where 5 MPPH equals full scale flow. C This flow was then. compared. to the flows obtained from the square root extractor, the 'Main Control Board, and the plant process computer. The allowable tolerances for these indications were as follows: Square Root Extractor: 0.5X, of 5 MPPH or 0.025 MPPH Main Control Board: 2.0X of 5 MPPH, or 0.10 MPPH ERFIS computer. 0'75X of 5 MPPH or 0.0375 MPPH The steam flow as calculated from the square root extractor was verified to be within 0.070 MPPH of the corresponding feedwater flow as calculated from the Honeywell test. instrumentation. If it was not within tolerance, the steam flow transmitter was rescaled to more accurately reflect actual conditions. The calculated plant steam flow was also compared to the readings obtained from the Main Control Board and the plant process computer. The allowable tolerances for these indications were as follows: Main Control Board: 0.120 MPPH ERFIS Computer. 0.0575 MPPH In all 'cases, at the 75X, 90X, and 100X .power plateaus, a Work Request Authorization ticket was written to check the calibration and recalibrate as necessary any loop that showed out of tolerance readings on the Main Control Board, plant process computer, and/or the Square Root Extractor (feedwater t ransmitters only). RESULTS and ACCEPTANCE CRITERIA COMPARISOH All acceptance criteria was met at the 30X and. 50X power plateaus. At the 75X power plateau Tables 3.5.8-1 & 3.5.8-2 summarizes whether or not each flow indicating instrument fell within the acceptance criteria. As a result of the 75X data FT-484 and FT-494 had their transmitters rescaled and calibrated prior to the 90X power plateau. ERFIS computer points were "accepted as is" after learning that the ERFIS computer does not temperature compensate. At the 90X power plateau, Tables 3.5.8-3 and 3.5.8-4 summarize whether or not each flow indicating instrument fell within the acceptance criteria. As a result of the 90X,data feedwater flow transmitters FT-477, FT-486, FT-487, FT-496, and FT-497 were recalibrated prior to the next power plateau. All loops except FT-496 had their calibration checked and recalibrated as necessary-prior to the 100X power plateau. Steam flow transmitters FT-485 and FT-494 had their transmitters rescaled and calibrated prior to-the next power plateau. Feedwater loops FT-475, FT-484, FT-485, and FT-494 were calibration checked and recalibrated as necessary prior to the next power plateau. At the 100X. power plateau, Tables 3.5.8-5 and 3.5.8-6 summarize whether or not each flow indicating instrument fell within the acceptance criteria. ( MIS/StartupMan/166/OS3 ( As a result of the were recalibrated. 100X data feedwater All of the feedwater checked and vere recalibrated as necessary. flov transmitters PT-477 and FT"496 flow loops had their calibrations.. A retest was performed afterwards and found everything within the acceptance criteria except PT-496. A work ticket was written to recalibrate FT-496. Steam Transmitters FT-475 and FT-485 had their loops calibration checked and recalibrated as necessary. A retest was performed afterwards and found the ERPIS indications to still be out of calibration. Work tickets were written to recalibrate flow loops FT-475 and FT-485. FICURES and TABLES Table 3.5.8-1 75X Feedwater Flow Instrument Data Table 3.5.8-2 75X Steam Flow Instrument Data Table 3.5.8-3 90X Peedwater Flow Instrument Data Table 3.5.8-4 90X Steam Flow Instrument Data Table 3.5.8-5 100X Feedwater Flow Instrument Data Table 3.5.8-6 100X Steam Flov Instrument Data ( MIS/StartupMan/167/OS3 75'EEDWATER FLOW INSTRUMENTS DATA TABLE 3.5.8-1 SQUARE ROOT MAIN CONTROL ERFIS TRANSMITTER dP EXTRACTOR BOARD COMPUTER FT-476 FT"477 FT-486 N FT-487 FT"496 N FT-497 FT-486 and FT-496 were recalibrated prior to the next power plateau. 75'TEAM FLOW INSTRUMENTS DATA TABLE 3 '.8-2 SQUARE ROOT MAIN CONTROL ERFIS EXTRACTOR BOARD COMPUTER FT-474 Y FT-475 N FT-484 N N FT-485 N FT-494 N N FT-495 MIS/StartupMan/168/OS3 90X FEEDWATER FLOW INSTRUMENTS DATA TABLE 3 5.8-3 SQUARE ROOT MAIN CONTROL ERFIS TRANSMITTER dP EXTRACTOR BOARD, COMPUTER FT-476 FT-477 N N N FT-486 N N N FT"487 N N N FT-496 N FT"497 N N 90X STEAM FLOW INSTRUMENTS DATA TABLE 3.5.8-4 SQUARE ROOT MAIN CONTROL. ERFIS EXTRACTOR BOARD COMPUTER FT-474 FT-475 N N FT-484 N FT-485 N N N FT-494 N FT-495 YIS/StartupMan/169/OS3 100X FEEDWATER FLOW INSTRUMENTS DATA TABLE 3.5.8-5 SQUARE ROOT MAIN CONTROL ERFIS TRANSMITTER dP EXTRACTOR BOARD COMPUTER FT"476 N N FT-477 N FT-486 N FT-487 Y N N FT-496 N N N FT-497 N 100X- STEAM FLOW INSTRUMENTS DATA TABLE 3 ~ 5 ~ 8-6 SQUARE ROOT HAIN CONTROL ERFIS EXTRACTOR BOARD COMPUTER c FT-475 N FT"484 FT"485 N FT-494 FT-495 c MIS/StartupMan/170/OS3 3.5.9 MAIN STEAM and FEEDWATER SYSTEM TEST'104-S-16 30X 9105-S-10 50X 9106-S-14 75K 9108-S-19 100X TEST OaaZCTIVES The purpose of the Main Steam and Feedwater System Test was to collect sufficient secondary cycle heat balance data,.at each plateau for comparison to the design thermal performance data from Westinghouse and to the more recent CP&L heat balances calculated from as-built cycle component information. The test collected, corrected, and reduced the data. The resulting data has been provided to plant performance personnel for analysis and comparison to design data. A secondary objective of the test was to collect enough cycle and component data to provide a baseline or benchmark against which future performance test results can be compared. TEST METHOD This test utilized a valve line-up that isolated various bypass, recirculation, and drain valves in order to make the plant match the design heat, balance as much as possible within normal operating constraints. Condenser make-up and Steam Generator blowdown were also isolated for the duration of the test. This line-up helps to minimize the corrections that need to be made to the data for comparison to the design heat balances. During each test, data was collected from approximately 265 test points. Of these, about 205 points were monitored with special high accuracy test instrumentation purchased for performance testing and maintained under the M&TE program. Test Measurements were generally made over a period of 2 hours with data taken at frequent intervals to reduce uncertainties associated with fluctuations in the readings. Test data was averaged and corrected for barometric pressure, water-leg static pressure, datum elevation, and instrument calibration error as applicable. The acceptance criteria was the same at all plateaus'to successfully obtain all the test point data listed in the procedure and then to submit the reduced (converted, averaged, and corrected) data to the Plant Performance Group for analysis and comparison to the design heat balance data. RESULTS and. ACCEPTANCE CRITERIA COMPARISON Since this test utilized such a large amount of test instrumentation, it was very difficult to assure that every instrument would operate satisfactorily for each test; therefore, the acceptance criteria that all data be obtained successfully was sometime difficult to meet.: MX S/S tar tupMan/171/OS3 30X Plateau Experienced problems ~ with ~ 9 test instruments due to severe system perturbations, water hammer, and piping the cycle during that time. computer vibrations'laguing secondary points wexe substituted for 2 of these, 5 of the points were ~ able to be infexred fzom other data points,. and the other 2 instruments were not needed at this plateau since only one main feed pump was operating. This test was determined to be acceptable-as-is and no retest was required. 50X Plateau - During this test, all instrumentation for this test was operating satisfactorily', however, two other operating constraints affected the performance of this'est. (1) Various level control valves and alternate dzain valves were modulating and needed to be left in these modes to allow for adequate level contxol at this time. = Valve positions vere noted on the lineup sheets and reviewed and evaluated by the Test Engineer and Performance Personnel. The decision was made to go ahead with the test. (2) The test had to concluded after 1 hour and 15 minutes of data collection instead of the usual 2 hours because the plant had gone into an LCO and had to reduce power. The amount of data collected was judged to be sufficient as conditions during the test had remained very stable and no major oscillations in generator output or feedwater flow had occurred during the data collection period. This test was determined to be acceptable-as-is and not retest was requixed. unavailable, 75X Plateau Experienced problems at 5 test points. Two instruments had failed prior to the test and since no replacements were computer points wexe substituted. Two other instruments had to be isolated because steam leaks had developed on theix root valves. One of these points could be inferred from another data point, the other point was not considered crucial as it was not an input to the heat balance model but was being collected from baseline information. The fifth point for which data could not be collected was on the Heater Drain Pump B motor. The pump motor power measurement could not be made due to a wiring problem on the terminal board in the motor bxeaker compartment; however, this point was also being collected fox baseline purposes. This test was determined to be acceptable-as-is and no retest was required. 100X Plateau This test began by doing the valve lineup in a methodical manner in order to determine how many megawatts weze gained by each section of the lineup. From beginning of lineup to completion of lineup, plant output involved by about 38 MWe. MIS/StartupMan/172/OS3 During, thi.'s test, additional data was taken to determine Cooling Tower performance. Problems were experienced with: three test instruments but computer points were available as substitutes. Also, still unable to collect Heater Drain Pump B motor power data due to wiring problem as existed at 75K Plateau. This test was determined to be acceptable-as-is and no retest was required. PIGURES and TABLES None MIS/StartupMan/173/OS3 4 0 REFERENCES 4.1 Regulator Guide 1.68; Initial Test Programs for Water-Cooled Nuclear Power Plants, Revision 2, August 1978 4.2 Harris Start-Up Manual, Vol. I and Vol. VI Revision 35 4.3 Shearon Harris Nuclear Power Plant Technical Specifications 4.4 Shearon Harris Nuclear Power Plant Final Safety Analysis Report 4-5 Nuclear Design and Core Physics of the Shear Harris, Unit 1 Nuclear Power Plant CYCLE 1 WCAP-10781 and Addendum MIS/StartupMan/174/OS3 TABLE OF CONTENTS Pacae Introduction..........................................;.. l II. Standards for Deciding Whether a Show Cause Proceeding Should be Initiated........................... 4 III. The Allegations in the Petition Do Not Raise Issues..................... Significant Health and Safety 7 A. Electrical Separation............................... 8 B. Department of Labor Compl'aints...................... l2 C. Confidential Informant's Allegations................ 23 I V. Conclusion............................................... 29 December 15, 1986 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE DIRECTOR OFFICE OF NUCLEAR REACTOR REGULATION In the Matter of ) ) CAROLINA POWER & LIGHT COMPANY ) and NORTH CAROLINA EASTERN ) Docket No. 50-400 MUNICIPAL POWER AGENCY ) (10 C.F.R. 5 2.206) ) (Shearon Harris Nuclear Power ) Plant) ) LICENSEES'ESPONSE TO CASH/EDDLEMAN SHOW CAUSE PETITION I. Introduction Carolina Power & Light Company ("CP&L") and North Carolina Eastern Municipal Power Agency are the holders of Facility Oper-ating License No. NPF-53 for, and co-owners of the Shearon Harris Nuclear Power Plant (" Harris" ). The Coalition for Alternatives r to Shearon Harris and Mr. Wells Eddleman (" Petitioners" ) filed "Wells Eddleman and Coalition for Alternatives to Shearon 'Harris Petition Pursuant to 10 C.F.R. 2.206," dated October 17, 1986 (" Petition" ), with the Director of Nuclear Reactor Regulation. The Director acknowledged receipt of the Petition on November 12, 1986. 51 Fed. Reg. 41711. CP&L herein provides this Response, which includes the attached joint affidavit of Kumar V. Hate'nd Leonard I. Loflin, and the affidavits of Ray A. Somers, Michael D. Holveck and Joseph W. McKay. Petitioners have requested the Director to revoke, suspend or modify the Construction Permit for Harris based -upon the alle-gations contained in their Petition.l/ See Petition at 1, 17. However, the presence of unresolved safety issues (the existence of which have not been established here) does not require revoca-tion of a-construction permit. Porter Count Cha ter v. NRC, 606 F.2d 1363, 1368-69 (D.C. Cir. 1979). Moreover, the Director has already informed the Petitioners, in his letter of November 12, 1986 acknowledging receipt of the Petition, that the issues raised in the Petition were screened; and that it had been deter-mined that those issues did'ot present significant safety con-cerns which had to be resolved prior to the issuance of CPSL's low-power operating license. Similarly, to the extent that the Petitioners harbor an unspoken desire to have the Director stay full-power licensing of Harris, their use of a section 2.206 petition to achieve such a stay is untenable and improper. A section .2.206 petition may be / denied on procedural grounds where the requested relief concerns the licensing of the facility and not an enforcement action. Carolina Power & Li ht Co. (Shearon Harris Nuclear Power Plant), 1/ On October 24, 1986, after the Petition was filed, the NRC issued an operating license for Harris. Thus, that enforcement action be taken with respect to the Petitioners'equest construction permit is moot. In any event, as shown below, ,.such sweeping action as Petitioners request is not even re-motely supported by the disparate and vague allegations in the Petition. DD-86-13, 24 N.R.C. ~ , slip op. at ~ 2 n.l ~ (Oct. 15, 1986); ~ Cleveland Electric Illuminatin Co.~ (Perry Nuclear Power Plant, Units 1 and 2), DD-86-4, 23 N.R.C. 211, 214 n.l (1986). More-over, Petitioners'nspoken assumption that the licensing pro-ceedings must be delayed pending resolution of its Petition is incorrect. Even if the Petition had rais'ed safety concerns (which it does not), the investigation thereof and the subsequent resolution of the Petition would not stay the issuance of an operating license for Harris. See Union Electric Co. (Callaway Plant, Unit 1), DD-85-7, 21 N.R.C. 1552, 1555 (1985). Finally, it is noteworthy that the Director has recognized that he does "not have authority under 10 C.F.R. 5 2.206 to direct the presid-ing Licensing Board to suspend the operating license proceeding." Cleveland Electric Elluminatin Co. (Perry Nuclear Power Plant, Units 1 and 2), DD-85-14, 22 N.R.C. 635, 642 n.4 (1985) (cita-tions omitted). The same is true here, where the Commission and the Atomic Safety and Licensing Appeal Board have jurisdiction over the adjudication. As discussed below, under applicable legal standards,. Peti-tioners have utterly failed to establish a basis for the issuance of a show cause order or any other relief pursuant to 10 C.F.R. 5 2.206. II. Standards for Deciding Whether a Show Cause Proceeding Should be Initiated Section 2.206 of the Commission's regulations provides a mechanism whereby members of the public may request initiation of an enforcement action to modify, suspend, or revoke a license, or for such other action as may be proper. It also vests authority in the director of the appropriate NRC office to decide whether to institute an enforcement action by the issuance of a show cause order. The only criterion set forth in the rule itself for judging the sufficiency of a petition is the requirement that "[t]he requests shall specify the action requested and set forth the facts that constitute the basis for the request." 10 C.F.R. 5 2.206'(a). The apparent reason for the absence of a more specific stan-t dard in the regulation is that the decision to institute an en-forcement action is 'not an adjudicative one, but rather is a mat-I ter of "prosecutorial" discretion. -See Consol.idated Edison Co. of New York Inc. (Indian Point Units 1, 2, and 3), CLI-75-8, 2 N.R.C. 173, 175 (1975) . Nevertheless, the Commission has in pre-vious decisions provided guidance delimiting the exercise of this discretion. In Indian Point, ~su ra, the Commission affirmed a Director's decision denying a 2.206 petition. In so doing, the Commission stated that "[t]he Director correctly understood that a show cause order would have been required had he reached the conclu-sion that substantial health or safety -issues had been raised. a mere dispute over factual issues does not suffice" as a basis foe issuance of such an order. Indian Point, ~su ca, 2 N.R.C. at 176 8 n.2.2/ This standard has been acknowledged in dicta by the D.C. and Seventh Circuits. Lorion v. NRC, 712 F.2d 1472, 1475 (D.C. Cir. 1983), rev'd on other rounds sub nom., Florida Power & Li ht Co. v. Lorion, 105 S. Ct. 1598, 1601 (1985), on remand sub nom,, Lorion v. NRC, 785 F.2d 1038, 1041 (D.C. Cir. 1986); Rockford Lea ue of Women Voters v. NRC, 679 F.2d 1218, 1222'7th Cir. 1982). The Commission has reiterated the "substantial health and safety issues" standard in Northern Indiana Public Service Co. (Bailly Generating Station, Nuclear-l), CLI-78-7, 7 N.R.C. 429, ~ ~ ~ 433 (1978), aff'd sub nom, Porter Count Cha ter v. NRC, 606 F.2d ~ 1363 (D.C. Cir. 1979). In that case, the Commiss-ion also re-jected a claim that the Director erred in failing to permit peti-tioner to comment on, respond to, or cross-examine the views of the NRC Staff: 2/ The directors have adhered to the "substantial health and safety issues" test. See, e.cC., Philadel hia Electric Co. (Limerick Generating Station, Units 1 and 2), DD-85-11, 22,. N.R.C. 149, 152 (1985); Washin ton Public Power Su 1 ~Sstem (WPPSS Nuclear Project No. 2), DD-84-7, 19 N.R.C. 899, 923 (1984). .[The Director] is not required to accord pre-sumptive validity to every assertion of fact, irrespective of its degree of substantiation, or to convene an adjudicatory proceeding to determine whether an adjudicatory pro-in'rder ceeding is warranted. Rather, his role at this. preliminary stage is to obtain and assess the information he believes necessary to make that determination. Provided he does not abuse his discretion, he is free to rely on a variety of sources of information, including staff analy-ses of generic issues, documents issued by other agencies, and the comments of the licensee on the factual allegations. Id. at 432-33. In order to meet the "substantial health and safety issues" standard, a petitioner must do more than merely, state its disap-proval of NRC policy or its belief that the accused utility may be found to have been in violation of the Commission's regula-tions.r Indeed, a petitioner must set forth evidence of some wrongdoing by the utility that goes beyond mere violations of the ~ ~ ~ Commission's regulations. In order to satisfy the substantial health and safety issues standard, a petitioner must set forth / evidence of violations of sufficient significance that the public health and safety may be affected thereby. Thus, for example, in Limerick, ~au ra 22 ,N.R.C. at 166, the Director determined that the petitioners'howing that the plant suffered from a trend of 'perator errors did not amount to a significant safety problem warranting a show cause order. The Director noted that errors may occur at a nuclear plant, but that most violations discovered through NRC inspections are of minor significance. Id. at 161. If more significant violations are discovered, escalated enforce-ment action may be considered by the Commission, including the imposition of civil penalties, short of instituting a show cause proceeding. See id. If, however, a truly major deficiency is identified through the inspection process, or otherwise, then the NRC could issue a variety of orders, including a show cause order, to assure appropriate remedial action. See id. But, as the Director stated: Isolated deficiencies in the licensee's pro-gram, however, do not necessarily undermine the program to such an extent as to give rise to a significant safety concern. What is required, when a violation is identified, is a careful assessment as to the significance of the viola-tion, its cause, and the corrective action taken to preclude recurrence. Id. at 161-62 (footnote omitted). Thus, even before reviewing ~ ~ Petitioners'pecific allegations in detail, it is clear that in the present case the Petition must fail. Petitioners have failed to present cogent evidence of any violations of the Commission's regulations that rise to a level that would warrant the institu-tion of an enforcement proceeding against Licensees. III. The Allegations in the Petition nificant Health Do and Safet Not Issues Raise Si The Petition consists of three sections: "I" largely addresses electrical separation issues; "II" addresses two Department of Labor cases involving Harris employees; and "III" concerns the allegations of a confidential informant. Licensees below address each section of'he Petition. A. Electrical Separation Petitioners allege that CP&L's QA program at Harris has suf-fered a systematic breakdown as evidenced by the difficulties CP&L has experienced with electrical separation interactions at Harris. See Petition at 1, 8. In support of this allegation, Petitioners cite six violations which have been charged against CP&L over a period of five years.3/ Five of the six cited viola-tions have already been resolved by CP&L and closed by the NRC. The remaining violation, 50-400/85-48-03, was previously cited by Petitioners in support of their section 2.206 petition dated July 2, 1986.4/ This issue was subsequently analyzed by the Di-rector, who determined that this violation had been addressed to the satisfaction of the NRC Staff and that it did not provide a basis for the issuance of a show cause order. See Carolina Power N.R.C. , slip op. at 11 (Oct. 15, 1986).5/ Moreover, only one 3/ With the exception of violation 50-400/85-48-03, which was addressed in CP&L's August 15, 1986 response to CASH's July 2, 1986 2.206 petition, see infra, each of the cited violations is addressed in detail in the joint affidavit of Kumar V. Hate'nd Leonard I. Loflin (" Hate'/Loflin Affida-vit,") %% 7, 19-22. See "Request for Institution of, Proceedings Pursuant to 10 C.F.R. 2.206," dated July 2, 1986 at 9. See also "Applicants'esponse to CASH's Show Cause Peti-tion" (August 15, 1986) at 29-32; Affidavit of Thomas W. Brombach, %% 3-9. of the cited violations involved an electrical separation inter-action. Thus, Petitioners have requested the Director to insti-tute show cause proceedings against CP&L on the basis of six pre-viously resolved issues. This section of the Petition hardly presents the requisite cogent evidence of the existence of any significant health and safety issues necessary to justify the im-position of the requested sanctions. Therefore, on this ground alone, the Director would be justified in dismissing this allega-tion. The physical spatial separation requirements for electric cables of safety-related circuits are set forth in Regulatory Guide 1.75, "Physical Independence of Electric Systems." CP&L is committed to compliance with Reg. Guide 1.75 at Harris, as aug- ~ . mented in the FSAR, and had generally succeeded in meeting the criteria of Reg. Guide 1.75 in, the construction of Harris. How- ~ ~ ~ ever, a relatively small number of electrica'1 separation interac-tions went undetected after acceptance by the Construction / Inspection ("C.I.") organization. Subsequent to the NRC's July, 1986 discovery of previously undetected cable separation interac-tions, CP&L intensified its efforts to comply with Reg. Guide 1.75. CP&L's corrective measures included the institution of a walkdown of safety related raceway, cable and equipment by En-ginering with assistance from QA. Identified interactions were reworked and reinspected as required. CP&L's efforts have been successful; and, as a result, reasonable assurance exists that Harris is in compliance with the separation requirements. There-fore, notwithstanding Petitioners'llegation to the contrary, ~ ~ the electrical separation issue is resolved and does not present a substantial health and safety issue. See Hate'/Loflin Affida-vit, 55 4-15. The problems QA experienced in the electrical separation program were isolated to that program. When the electrical sepa-ration concerns were first identified, CP&L and the NRC examined the possibility that the difficulties encountered with separation might be indicative of more pervasive deficiencies in the overall QA program. CP&L reviewed this possibility and determined that the QA electrical separation problems were not indicative of weaknesses in other areas of CP&L's QA program. CP&L created a special task force to investigate this problem. The task force first analyzed 'the root cause of the separation problem and de-termined that the primary cause was the large number of deficiencies built into the plant, partially due to the extensive amount of field routing involved. The large number of deficiencies coupled with the complexity of inspection created a system overload that made it nearly impossible for the inspectors to locate all of the deficiencies. This system overload problem did not exist in the remainder of the QA programs. Hate'/Loflin Affidavit, 5 16. In order to assure itself that similar root cause deficiencies did not exist in- the remaining programs, the task force conducted a review of those programs. The task force exam-ined information from audits conducted by the NRC, INPO and CP&L. It also reviewed quality data including nonconformance reports, deficiency reports, trend analyses and QA surveillance results. The task force also supplemented its examination with information gathered through interviews with personnel re'sponsible for the design, installation, and inspection of the hardware involved in these programs. After carefully reviewing and analyzing this data, the task force concluded that there was no evidence of any systematic breakdown of QA at Harris. Hate'/Loflin Affidavit, 17. The NRC confirmed CP&L's conclusion that generic deficiencies do not exist in the QA programs at Harris. The NRC organized a 6-man team to conduct a 7-day review of CP&L's QA program in order to ensure that CP&L's conclusions were correct. / The NRC team reviewed CP&L's findings in addition to reviewing the raw data that the CP&L task force had reviewed. Although the NRC did not totally agree with the methodology employed by the CP&L task force, it did agree with CP&L's conclusion that generic deficiencies do not exist -in CP&L's QA program. See NRC Inspec-tion Report No. 50-400/86-69, dated November 14, 1986 (Hate'/Loflin Affidavit, Exhibit 5). Thus, the Petitioners'l-legation that the electrical separation issues evidence a breakdown in the QA program for Harris has already been addressed and dismissed by CPSL and the NRC. Hate'/Loflin Affidavit, ll 18. This allegation, therefore, does not present a substantial health and safety issue. B. Department of Labor Complaints In support of their Petition, CASH and Eddleman rely, in part, upon two recent decisions regarding employee complaints under Section 210 of the Energy Reorganization Act of 1974, 42 U.S.C. 5 5851'. One decision involves a contract employee -- Marvin Van Beck -- who filed a complaint under Section 210 against his employer, Daniel Contruction Company.6/ Van Beck was an electrical raceway inspector whose employment Daniel terminated after he refused to perform inspections in the containment building during hot func-tional testing ("HFT"). The second contested case involves a contract employee -- John J. McWeeney -- who filed a complaint / under Section 210 against CPEL. McWeeney was an engineer em-ployed in reviewing the installation of electrical cable 6/ Petitioners loosely attribute actions with respect to Van Beck to "CPEL management." Petition at l. In fact, Van Beck was employed by Daniel, the chief construction contrac-tor for Harris, and the decision to terminate his employment was made by Daniel supervisors.'an Beck's complaint was filed against Daniel, not *CPGL. supports.7/ He was released during ongoing reductions in force associated with completion of the Harris construction project. Petitioners argue that these complaints indicate that CP&L lacks the "requisite character" and "technical capability"-to op-erate the Harris Plant. Petition at l. Contrary to Petitioners'laims, neither of the complaints calls into question CP&L's E "character" or "technical capability."8/ Nor do they warrant Pe-titioners'eneralized indictment of Licensees'nspection pro-grams. 7/ Petitioners incorrectly state that McWeeney was "responsible for design characteristics of safety-related cables." Peti-tion at l. In fact, McWeeney was not involved in engineer-ing for safety-related cables at all. Instead, his engi-neering work involved electrical cable supports, not the cables themselves. Nor was McWeeney involved in the initial design of plant equipment. His work involved the technical justification for dispensation of inspection reports on cable supports. These inspection reports concern dif-ferences between the design and the as-built condition of cable supports. 8/ CP&L',s management and technical capability to operate the Harris plant safely were the subject of an admitted conten-tion in the Harr.is operating license proceeding (Joint Con-tention I). Based on the hearing record, the Licensing Board decided the contention in favor of CP&L and endorsed the NRC Staff's conclusion that "CP&L is technically quali-fied to operate the Harris facility within the purview of the regulations and with due regard for public health and safety." Carolina Power & Li ht Co. (Shearon Harris Nuclear Power Plant), LBP-85-28, 22 N.R.C. 232, 257 (1985). To the extent Petitioners seek to relitigate this issue through the mechanism of a petition under Section 2.206, their petition should be denied. Carolina Power & Li ht Co. (Shearon Harris Nuclear Power Plant), DD-86-13, 24 N.R.C. , slip cp. at 8 n.3 (Oct. 15, 1986), ~citin General Public Utilities Nuclear Cor . (Three Mile Island Nuclear Station, Units 1 and 2), CLI-85-4, 21 N.R.C. 561 (1985). Petitioners have utterly failed to demonstrate that these are more than isolated labor disputes of the kind that periodi-cally arise at most nuclear power plant construction sites (and, indeed, of the same kind that occur on any large construction site). As discussed infra,'he two complaints involve disparate factual situations and in no way suggest a pattern of retaliatory action against construction employees who raise nuclear safety concerns. Compared to many other plant construction sites, few complaints under Section 210 have been lodged by Harris employees and even fewer have been successfully pursued. Petitioners'f-forts to use these two complaints as the basis for a broad as-sault on CPSL's "character" and "technical capability" fall far wide of the mark. In no way do they justify the relief sought by Petitioners -- i.e., revocation, suspension or modification of the Harris construction permit. With respect to both Department of Labor case's, Petitioners do not accurately state the facts surrounding the cases and the initial findings of the Department of Labor. Accordingly, the two cases will be addressed separately below.
- 1. Van Beck Com laint On September 17, 1986, a DOL administrative law judge issued a "Recommended Decision and Order" in the case of Van Beck v.
Daniel Construction Com an , Case No. 86-ERA-26. The ALJ con-cluded that Van Beck was terminated because of actions protected by Section 210 of the Energy Reorganization Act and ordered his reinstatement with back pay. Recommended Decision at 14-15. The Secretary of Labor has ninety days from September 17 in which to accept or reject this Recommended Decision. The case is cur-rently under appeal pursuant to procedures established by DOL regulations. Daniel Construction Company has requested an oppor-tunity to present written arguments to the Secretary of Labor on why the Recommended Decision should be rejected and why the com-plaint should be dismissed. An additional level of review through the federal court sy'tem is also available. Thus, con-trary to the Petitioners'lai.ms (Petition at 1), the DOL has not resolved the case finally against CPEL (which is not even a party / to the case) or Daniel. The facts of the Van Beck case revolve around an employee's perceived concern for his personal safety. The integrity of the construction of the Harris plant is not called into question by the facts in this case. Daniel has sought further review in this case because it be-lieves that the facts show that'Van Beck did not engage in activity protected by Section 210. Van Beck was released from employment at the Harris site in January 1986 when he refused to perform work assignments because he claimed work conditions were not safe. Van Beck was a contract employee hired by Daniel as an electrical raceway inspector. Prior to his termination, Van Beck made no complaints to the NRC regarding nuclear safety. Thus, Daniel maintains that he did not participate in a "proceeding" in furtherance of the Atomic Energy Act or Energy Reorganization Act, which is the sine gua non of protected activity under Sec-tion 210. Van Beck's primary and overriding concern was for his own personal safety. Although Daniel made repeated efforts to convince Van Beck that inspection work inside the containment building during hot functional testing would be safe, he refused
- that work assignment and was released. Van Beck's concerns over his personal safety have no significance with regard to the con-struction of the plant and nuclear safety.
The ALJ found that jurisdiction under 210 would not attach solely by reason of an employee's fear for his personal safety. Although the ALJ found that Van Beck also expressed concerns about the ability of inspectors "to perform adequate inspections in the [containment building], given conditions there. during HFT" (Recommended Decision at 12), Daniel maintains that there is no substantial evidence in the record that any such concerns were conveyed by Van Beck to his supervisors. Thus, there is not sub-stantial evidence to support the ALJ's finding of jurisdiction, and Daniel will appeal on that issue. L Even if the ALJ decision is upheld after further review, there is no basis for suggesting, as Petitioners do, that a "com-piete re-inspection" of electrical raceway inspections performed during HFT is required. Petition at ll. The attached Affidavit of R. A. Somers ("Somers Affidavit") addresses the reasons why there is assurance that electrical raceway inspections were prop-erly performed in the reactor containment during HFT. Mr. Somers was employed by Daniel as Project Quality Manager and functioned as Construction Inspection Superintendent at Harris from June 1985 to November 1986. His duties included su-pervising the electrical inspection program at the Harris Plant. Mr. Somers held the position of Construction Inspection Superin-tendent during the time period when Marvin Van Beck was employed as an electrical raceway inspector at Harris and when he was ter-minated from employment in January 1986. Somers Affidavit, '0 1. In his affidavit, Mr. Somers states that supervisor audits are conducted on each inspector each month to ensure that ade-quate inspection proficiency is maintained. The supervisors con-duct a second inspection of a sample of- the work done by each in-spector to re-verify the inspections and to confirm that the inspector did not overlook nonconformances. Supervisor audits were conducted on the inspectors during the time period they ac-tually performed inspections in the containment building during HFT. No concerns or indications of impaired proficiency were noted. Somers Affidavit, I 3. Another basis for assurance that inspections were properly performed is that electrical inspectors have not expressed con-cern that their inspection proficiency was impaired during HFT. Both Daniel and CP&L maintain an "open door" policy for all employees. Employees are regularly encouraged to express all concerns they may have to their supervisors or to Quality Check Program personnel. Employees are also encouraged to report con-cerns to the NRC if they are not comfortable with these avenues or if their concerns are not satisfactorily resolved. Mr. Somers is unaware of any electrical raceway inspector who had or has a concern that his inspection proficiency in the reactor contain-ment building,may have been impaired during HFT. According to Mr. Somers, each Lead Inspector over the field inspectors was asked if he would provide a statement, on a voluntary basis, as to whether any inspector had voiced such a concern. A statement from each Lead Inspector is attached to Mr. Somers'ffidavit. No Lead Inspector received any indication from the inspectors re-porting to him that their inspections during HFT were in any way deficient. Mr. Van Beck did not express concerns to his supervi-sors relative to inspection proficiency until approximately one month after his termination -- during a hearing on his appeal for unemployment benefits which had previously been denied. Somers Affidavit, 5 4. Mr. Somers states that some inspectors did express concern that some inspections they may be assigned to perform during HFT would require them to work in close proximity to thermally hot pipes and that the possibility of receiving burns existed. How-ever, in these cases, the inspectors were not required to com-plete the inspections during HFT. In order to assure personal safety as well as inspection proficiency, the inspectors were in-structed to return all inspection packages with which they felt uncomfortable or which might involve the risk of receiving a burn to a holding file established by the supervisors. A number of inspection packages were returned by inspectors for these rea-sons, and those inspections were completed at a later date after 'HFT had ended. Somers Affidavit, I 5. Thus, Mr. Somers concludes there is every reason to be as-sured that electrical raceway inspections in the containment building were properly performed during HFT. Ho indications of impaired performance were foun'd by the periodic supervisory au-dits conducted at that time. To his knowledge, no inspector has reported to his supervisors or to other persons that his perfor-mance was impaired by the conditions in the containment building. during HFT. Finally, any inspector who was uncomfortable 'per-forming a particular inspection during HFT was able to return the inspection package for completion at a later date after HFT ended. Somers Affidavit, 0 6. For these reasons, a reinspection of electrical raceway inspections performed during HFT is unnec-essary and unwarranted.
- 2. McWeene Com laint On July 23, 1986, John J. McWeeney filed a complaint against CP&L with DOL under Section 210 claiming that he "was terminated because I raised concerns about the acceptability of several safety-related problems relating to engineering design calcula-tions." McWeeney Complaint at l. McWeeney had been employed as a contract engineer at the Harris site from April 28, 1986 through July 18, 1986. On July 18, he was released from employ-ment, along with a number of other contract engineers. Over the past several months, large numbers of contract engineers have been released from employment at Harris as the plant neared com-pletion of construction and beginning of operation.
Pursuant to DOL regulations, the Raleigh office of the DOL Wage and Hour Division conducted an investigation of McWeeney's allegations. No hearing on McWeeney's complaint has been held. Based on this investigation, the Raleigh Area Director of the Wage and Hour Division issued a letter finding that McWeeney had been discriminated against for engaging in "protected activity" under Section 210. The letter also notified CP&L of its right to T request a formal hearing on the record regarding the McWeeney Complaint. On September 26, 1986, CP&L requested a h'earing before an Administrative Law Judge of the Department of Labor. On December 3, 1986, McWeeney and CP&L entered into a Set-tlement Agreement resolving all'isputes and claims arising out of McWeeney's work for CPEL as an engineer at the Harris plant. Under the terms of the Agreement, CP&L agreed to pay McWeeney an amount based upon his compensation by Central Technical Services for a period of weeks, his attorney's fees, and costs. Pursuant to the Agreement, McWeeney has filed a motion to dismiss his DOL complaint. The parties acknowledged in the Agreement "that the settle-ment entered into by the parties is made in compromise of dis-puted claims and in no way represents an admission of wrongdoing by any party." The parties further acknowledged that they "have entered into this settlement in order to avoid the additional ex-pense and inconvenience of further litigation." Thus, the labor dispute has been amicably resolved between the parties. CPGL has not and does not concede that McWeeney's release from employment was other than a normal job termination incident to ongoing re-ductions in force at Harris. It was determined,,however, that further litigation would not be in the interest of the Company, given the costs and diversion of resources and personnel from important activities. 'ther In addition to filing a complaint with DOL, McWeeney raised a number of technical issues with the NRC. Petitioners allude to these issues, particularly the so-called "Detail G" engineering calculation, in their pleading. Petition at 9. These technical concerns have already been thoroughl'y investigated by the NRC Staff, and CP6L has taken action to address them. As explained in the Affidavit of Michael D. Holveck, Mr. McWeeney had raised concerns with an engineering calculation used in the design of electrical supports in the reactor containment building. The Harris Plant Engineering Section performed an analysis to demonstrate the adequacy of the "Detail G" frame con-nections, and conducted a mock-up test. Based on this test and analysis, it was determined that the ultimate strength of the "Detail G" connection was greater than that required to resist the load it was designed to support. Thus, the "Detail G" issue did not raise a safety concern. Holveck Affidavit, 11% 6-9. A further computer analysis, however, showed that one of the six "Detail G" connections in the model had stress levels which exceeded levels allowed in the American Institute of Steel Con-struction ("AISC") code. Since the stress levels for this eon- ~ nection did not approach the ultimate capacity of the connection, there is not a cause for concern about the'connection's failure. Thirteen locations were identified where the specific configura-tion of the "Detail G" connections matched those of the overstressed joint in the model. As a matter of prudency and to permit greater flexibility for future plant modifications, HPES prepared engineering drawings instructing construction personnel to strengthen the 13 connections identified as having possible overstress. In November 1986, all. field modifications were com-pleted. This work ensures that the stress levels in the "Detail G" connection are within limits*allowed by the AISC code. Holveck Affidavit, %% 10-11. C.~ Confidential Informant's Allegations ~ Section III of the Petition contains a series of allegations that are purportedly based on the statements of an unidentified confidential informant. See Petition at 2, 12. CP6L has been unfairly hampered in its efforts to address these allegations be-cause, inter alia, CPGL does not know the specifics (e.cC. time, location, personnel involved, etc.) forming the factual bases for the vague and sweeping allegations of the confidential informant. II Nevertheless, CPGL has addressed each of the allegations raised in Section III of the Petition. The attached affidavit of Joseph W. McKay ("McKay Affidavit") demonstrates that the aforementioned allegations are unfounded and do not present evidence of any sub-stantial health and safety issues at Harris. Thus, the allega-tions in Section III of the Petition do not form the requisite basis for a 2.206 Petition. Petitioners'llegation that improper sign-off procedures were followed in order to meet CPSL's construction completion requirements reflects a misunderstanding of CPSL's Anchor Place-ment Report ("APR") design approval sign-off procedures. See Pe-tition at 12. Petitioners cite several APR's in which Section B of the APR's were signed-off by degreed discipline Resident Engi-neers, Cockerill and Willett. See McKay Affidavit, Exhibit 2 APR's lIS190016, 019, 024, 038, 042, 045, 046). Work Procedure ("WP") 33 governs the sign-off procedures for APR's. When the cited APR's were signed, WP-33, Rev. 7 was in effect. WP-33, Rev. 7 stated that "the Area/Discipline Engineer shall then com-piete 'Section B'as per FCR/PW recommendations) of the Anchor Placement Report, and sign the, final design approval." WP-33, Rev. 7, dated October 10, 1983 at 20-21. Thus, notwithstanding Petitioners'llegation that Section B of the cited APR's should have been signed by an area engineer, it is clear that Messrs. Cockerill and Willett were acting within the scope of their au-thority when they signed the cited final design approvals. McKay Affidavit, %% 3.-4. Petitioners next allege that CPGL compromised the integrity of the Phillips Red Head expansion anchors by pouring sand into oversized anchor holes in order to cause the anchor to torque properly. See Petition at 12-13. Although Expansion Anchor Placement Nos. 1RA305003, 006,,007 were cited by Petitioners, these documents simply do not show that anyone poured sand on the expansion bolts in order to achieve minimum torque values. It is unlikely that the Petitioners'llegation is true. A C.I. in-spector is always present during the installation of the anchor bolts. McKay Affidavit, I 5. An i.nspector would not allow the craft installers knowingly to place sand in the anchor hole, since CPEL's installation procedures require that foreign sub-stances shall be cleaned form the anchor holes prior to installa-tion. See WP-33, Rev. 15, 1 3.1.3.9. at 11. Moreover, even if sand had been introduced into the anchor'hole, this would not create a significant health and safety issue because the presence of sand would not alter the performance of the anchor. See McKay Affidavit, 8 6. Similarly, Petitioners'llegation that certain unidentified construction personnel substituted plate material for Q material does not present a significant safety issue. Petitioners allege that the anchor general foreman and two or more other unidentified general foremen had A-36 stamps made with which they supposedly forged A-36 material from non-Q stock material at the site. See Petition at 13. Standard ASTM A-36 steel plates were used for the expansion anchor base plates. McKay Affidavit, 1I 7. CPGL's procedures require the use of Q material, such as A-36 steel, for all Q (safety-related) installations. The Quality Control ("QC") group was responsible for identifying stock mate-rial delivered to the site and for stamping A-36 steel with a special stamp that was only issued to authorized QC personnel. Id. Although it is very unlikely that the cited foremen had their own counterfeit stamps, the substitution of the material that would have been forged would not present a significant health and safety issue. CPEL conducted a review of its purchase orders, installed materials and stock materials to determine the extent and significance of the possible installation of stock non-Q material. CPEL's research revealed that only a small per-centage possibility existed that non-Q material had been in-stalled.- Moreover, it was dete'rmined that the yield strengths of the stock material which potentially could have been installed were in excess of those required by the design basis for the A-36 steel. In light of the acceptability of the potential substitu-tions, CPEL issued a permanent waiver, with which the NRC has concurred, allowing the acceptance of the installation of unidentified stock material. See McKay Affidavit %tl 8-9. Thus, even if Petitioners'llegation were true, CPEL and the NRC have already addressed and resolved this issue. Petitioners'ontention that craft personnel falsified de-sign documents in order to facilitate timely completion of their tasks is not supported by the facts. See Petition at 13-14. CPSL has no record of any attempted falsifications of design documents by craft personnel. McKay Affidavit, 5 ll. Document Control issued separate controlled copies of design documents to the construction inspectors in addition to the controlled copy issued to the craft personnel. The inspectors are free to use either their own controlled copy or the craft's controlled copy / for inspection purposes. A very remote possibility therefore ex-ists that a craft worker could have falsified a design document without being caught, but only if the C.I. inspector did not com-pare his copy of the design document against the craft copy. However, it is extremely unlikely that craft personnel falsified their design documents for several reasons: the risk of detec-tion was high; craft personnel knew that detection would result in termination of their employment; craft personnel had pride in their workmanship; and access to the materials needed to create an authentic forgery were difficult to obtain. See McKay Affida-vit %% 10-11. Moreover, the risks associated with forging a de-sign document were unacceptably high by comparison to the rela-tive ease with which one could obtain a legitimate engineering resolution. Id. For these and other reasons (see McKay Affida-vit %Sf 10-11) it is extremely unlikely that this allegation can be substantiated. Petitioners certainly have not seen fit to put forth any specific evidence of any of the alleged forgeries; nor have they demonstrated that the alleged forgeries will adversely affect health and safety. Abs'ent such evidence, this allegation does not raise any significant health and safety concerns. CPGL did not fail to check undercut tolerances for holes drilled to receive "maxi-bolt" anchors, as alleged by Petition-ers. See Petition at 14. Maxi-bolt hole undercuts for Maxi-bolt s ~ expansion anchors installed prior to mid-1983 were verified visually by C.I. Thus, the presence of the undercut was assured. / Subsequently, in mid-1983, procedure TP-39 (" Inspection of Drilled In Expansion Anchors" ) was revised to require that Maxi-bolt hole undercuts shall be checked to 'ensure that the hole had been fully undercut at the correct embedment depth by utilizing 'a calibrated undercut tool. All Maxi-bolt anchor diameters have been retested and requalified at the current tolerances. The test results indicated that the anchors perform satisfactorily. Therefore, CPEL is confident th'at undercut tolerences at Harris are acceptable. See McKay Affidavit, 5 12. Petitioners'llegation that craft personnel made rampant material substitutions on installations in areas that would be under water because they felt that these placements would be unverifiable is specious. See Petition at 14. CPSL personnel did not make any underwater placement installations. Moreover, all placements made in areas that would subsequently be under water were subject to the same inspections as any other place-ments in the plant. Craftsmen making such installations were fully aware that their work would be inspected by C.I. Thus, it is confident that the craftsmen did not make the rampant material substitutions alleged by P'etitioners. See McKay Affidavit, tf 13. Petitioners'llegation that shear plate locations were altered by craft personnel is not credible. See Petition at 14. All shear plate installations are inspected by C.I. C.I. inspec-tions are made from control lines that are established by the field engineers. Any inconsistency between the control lines and the shear plate location would be caught. Thus, CP6L is confi- / dent that craft personnel did not alter the location of shear= plates without prior approval. See McKay Affidavit, 5 14. Petitioners'inal allegation is that the integrity of those anchor bolts that are attached to base plates supported by concresive 1411 epoxy grout in the Diesel Generator Building could have been destroyed by the heat applied to the concresive grout during plate attachment welding. See Petition at 14-15. This allegation is based upon a number of misperceptions. Concresive 1411 epoxy grout was not used as an anchor base for expansion anchor bolts as alleged. The anchor bolts are torqued against steel shims when concresive 1411 epoxy grout is used for leveling purposes. Thus, the condition of the 1411 epoxy grout does not affect the integrity of a shimmed anchor bolt. This al-legation, therefore, does not present evidence of a safety sig-nificant issue supporting the issuance of a show cause order. See McKay Affidavit, Tll 15-16. IV. Conclusion Petitioners have asserted a series of unrelated, unsubstantiated, or previously resolved allegations in an effort to demonstrate that CP&L has suffered a systemmatic breakdown of its QA program at Harris. CP&L's QA program, including the QA Attribute Surveillance program, was the subject of extensive lit-igation during the operating license proceedings. See Carolina Power & Li ht Co. (Shearon Harris Nuclear Power P3.ant), LBP-86-11, 23 N.R.C. 294, 353-64 (1986), affirmed, ALAB-852, 24 N.R.C. , (Oct. 31, 1986). During those proceedings, the NRC Staff endorsed the effectiveness of CP&L's QA program at Harris. Id. at 354. In addition, the Senior Resident Inspector for Con-struction at Harris testified that CP&L's inspection program is one of its strengths; and that through this program CP&L is capa-ble of identifying safety related hardware deficiencies regardless of its cause. See Id. On the basis of the record of the full evidentiary hearings, the Licensing Board concluded that the QA "attribute surveillance program is convincing evidence that the Shearon Harris overall quality assurance program is effective...." Id. at 357. In making its determination that "[t]here is reasonable as-surance .that defective work. . . will be detected by the QA pro-gram," the Licensing Board properly noted that QA deficiencies should be examined in terms of safe plant operation. Harris, ~su ra, 23 N.R.C. at 304. As the Appeal Board noted in affirming the Licensing Board's decision, "[w]e recognized that even the best quality assurance program cannot assure that every possible construction deficiency . . . will be detected." Carolina Power ~ ~ ~ ~ h . ~ < '* ), -85 ~ N.R.C. ~ ~ , slip op. at 13 (Oct. 31, 1986). ~ ~ ~ The Appeal Board has stated the following standard for assessing the effectiveness of construction QA programs: In any project even remotely approaching in magnitude and complexity the erection of a nuclear power plant, there inevitably will be some construction defects tied to quality as-surance lapses. It would therefore be totally unreasonable to hinge the grant of an NRC oper-ating license upon a demonstration of error-free construction. Nor is such a result man-dated by either the Atomic Energy Act of 1954, as amended, or the Commission's implementing regulations. What they require is simply a finding of reasonable assurance that, as built, the facility can and will be operated without endangering the public health and safety. 42 U.S.C. 55 2133(d), 2232(a); 10 C.F.R. 5 50.57(a)(3)(i). Thus, in examining claims of quality assurance deficiencies, one must look to the implication of those -deficiencies in terms of safe plant operation. Union Electric Co. (Callaway Plant, Unit 1), ALAB-740, 18 N.R.C. 343, 346 (1983) (footnote omitted). Hence,'lthough CPEL had ex-perienced some QA problems during plant construction, these prob-. lems were few and isolated. Further, CP6L's corrective measures have ensured that its QA program is adequate to ensure that rea-sonable assurance exists that the plant, as constructed, can and will be operated without endangering the public health and safe-ty. As the discussion above demonstrates, Petitioners have not presented any cogent evidence of the existence of significant health and safety issues at Harris. Hence, as there is no basis for an enforcement action against CP&L, the Petition must be de-4 nied. Thomas A. Baxter, P.C. Wilbert Washington II SHAW P I TTMAN/ POTTS & ~ TROWBR I DGE 2300 N Street, N.W. Washington, D.C. 20037 (202) 663-8000 Richard E. Jones Dale E. Hollar CAROLINA POWER & LIGHT COMPANY P.O. Box 1551 Raleigh, North Carolina 27602 (919) 836-8161 Counsel for Licensees Dated: December 15, 1986 CERTIFICATE OF SERVICE This is to certify that copies of the foregoing "Licensees'esponse to CASH/EDDLEMAN Show Cause Petition" were served by de-posit in the United States mail, first class, postage prepaid, this 15th day of December, 1986, to the following: Mr. Harold Denton, Director Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Mr. Bart Buckley Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555 James Lieberman, Esquire Assistant General Counsel for Enforcement U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Docketing and Service Section Office of the Secretary U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Mr. Wells Eddleman 812 Yancey Street . Durham, North Carolina 27701 Coalition for Alternatives to Shearon Harris (CASH) 604 W. Chapel Hill Street Durham, North Carolina 27701 *Mr. David M. Verrelli U.S. Nuclear Regulatory Commission Region II 101 Marietta Street Atlanta, Georgia 30303 l Wilbert Was ington II
- Mr. Verrelli was served by Federal Express'.}}