ML19263C263
| ML19263C263 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 02/08/1979 |
| From: | Jeffery Grant TOLEDO EDISON CO. |
| To: | James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| References | |
| 1-46, NUDOCS 7902130149 | |
| Download: ML19263C263 (100) | |
Text
_
l THIS DOCUMENT CONTAINS P00R QUAllTY PAGES TOLEDO m%::s EDISON February 8, 1979 JAMES S. GRANT
%ce President
"'m Saa
Serial No.1-46 I4191 259-5232 Docket No. 50-346 License No. NPF-3 Mr. James G. Keppler Regional Director, Region III Office of Inspection and Enforcement U. S. Nuclear Regulatory Commission 799 Roosevelt Road Glen Ellyn, Illinois 60137
Dear Mr. Keppler:
Attached are copies of Chapters 1, 2, 4, 8, 9, 10, and 12 as revised by Supplement 3 of the Davis-Besse Unit 1 Initial Startup Report.
This report, which covers testing completed during the period from October 6,1978 through January 5,1979, is being submitted in accordance with Tech-nical Specificatien 6.9.1 of Appendix A to the Davis-Besse Nuclear Power Station Operating License and the Regulatory Guide 1.16, Section C.l.a.
Very truly yours, JSG/lj k Attacinent cc:
Dr. Ernst Volgenau, Director Office of Inspection and Enforcement Encl:
25 copies Mr. William G. Mcdonald, Director Office of Management Inf ormat ion and Program Control Encl:
2 copies b
4I
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7902130199-THE TOLEDO CD!SCN CO*.TANY E0! SON CAN 200 MAD! SON AVENUE TOLEDO. OHIC 43652
i Instructions for inserting Supplement 3 revision to Davis-Besse Unit 1 Initial Startup Report RD40VE INSERT Supplement 2 Title Page Supplement 3 Title Page Entire Tabic of Contents Entire Tabic of Contents Pages 1-1 thru l-14 Pages 1-1 thru l-16 Pages 2-1 thru 2-4 Pages 2-1 thru 2-4 Pages 4-1 thru 4-12 Pages 4-1 thru 4-13 Pages 8-1 thru 8-15 Pages 8-1 thru 8-15 Pages 9-1 thru 9-16 Pages 9-1 thru 9-22 Pages 10-1 thru 10-3 Pages 10-1 thru 10-4 Pages 12-1 thru 12-4 Pages 12-1 thru 12-5
DAVIS-BESSE NUCLEAR POWER STATION UNIT ONE INITIAL STARTUP REPORT COVERING APRIL 23, 1977 THROUGH APRIL 5, 1978 SUPPLDIENT 1 COVERING APRIL 5,1978 THROUGH JULY 5,1978 SUPPLDENT 2 COVERING JULY 5,1978 'nlROUGH OCTOBER 5,1978 SUPPLDENT 3 COVERING OCTOBER 6,1978 THROUGH JANUARY 5,1979 9
L._..Z l. TOLE 00
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TABLE OF CONTENTS Page Section 1-1
1.0 INTRODUCTION
2-1 2.0
SUMMARY
3-1 3.0 INITIAL FUEL LOADING 4.0 POST FUEL LOAD PRECRITICAL HOT FUNCTIONAL TESTING 4-1 4-1 4.1 Reactor Coolant System Flow Measurement 4.2 Reactor Coolant System Flow Coastdown 4-2 Measurement 4.3 Reactor Coolant System Hot Leakage Test 4-2 4.4 Pressurizer Operational and Spray Flow Tests 4-3 4.5 Control Rod Drive System Operational Test 4-3 5-1 5.0 INITIAL CRITICALITY 5.1 Preliminary Approach to Criticality 5-1 5-1 5.2 Final Approach to Criticality 6.0 CORE PERFORMANCE DURING ZERO POWER PHYSICS TESTS 6-1 6.1 Nuclear Instrument Overlap 6-1 6.2 Sensible Heat Determination 6-1 6.3 Reactimeter Response Checkout 6-2 6.4 All Rods Out Boron Concentration 6-2 6.5 Temperature Coefficient of Reactivity "6-3 Measurements 6.6 Control Rod Reactivity Worth Measurements 6-3 6-4 6.7 Ejected Rod Worth Measurements 6.8 Stuck Rod Worth and Shutdown Margin 6-4 Measurements 6-6 6.9 Soluble Poison Worth Measurements i
Page Section 7.0 CORE PERFORMNiCE DURING POWER ESCALATION 7-1 SEQUENCE TESTS 7.1 Nuclear Instrumentation Calibration at Power 7-1 7-3 7.2 Reactivity Coefficients at Power 7-5 7.3 Rod Worth at Power 7-6 7.4 Core Power Distribution Tests 7.5 Pseudo Control Rod Ejection Test 7-6 7-7 7.6 Dropped Control Rod Test 7-8 7.7 Incore Detector Test 7.8 Power Imbalance Detector Correlation Test 7-9 8.0 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PERFORMANCE 8-1 8-1 8.1 Unit Load Steady State Test 8-1 8.2 NSSS Heat Balance Test 8.3 Integrated Control System Tuning at Power 8-2 9.0 UNIT PERFORMANCE L' IRING TRANSIENT AND ABNORMAL 9-1 CONDITIONS 9-J 9.1 Turbine / Reactor Trip Test 9-2 9.2 Unit Load Transient Test 9-3 9.3 Unit Power Shutdown Test 9-3 9.4 Unit Load Rejection Test 9-4 9.5 Natural Circulation Test 9.6 Loss of Offsite Power Test 9-4 9.7 Shutdown From Outside the Control Room 9-5 10.0 SECONDARY PLANT PERFORMANCE AND STARTUP EXPERIENCE 10-1 10-1 10.1 Turbine / Generator 10-1 10.2 Condenser 10.3 Circulating Water System 10-3 10-3 10.4 Feedwater Systems 11.0 UNIT MONITORING - CilEMISTRY AND ilEALTil PIlYSICS 11-1 11-2 11.1 Shield Survey 11
Section Page 11.2 Site / Station Survey 11-3 11.3 Reactor Coolant Chemistry Test 11-3 11.4 Steam Generator Chemistry Test 11-4 11.5 Initial Radiochemistry Test 11-4 11.6 Process Area Radiation Monitoring Test 11-5 12.0 UNSCHEDULED UNIT TRIPS 12-1 13.0 CORE PERFORMANCE FOLLOWING BPRA AND ORA REMOVAL 13-1 13.1 Core Performance During Zero Power Testing 13-1 13.2 Core Performance During Power Escalation Testing 13-6 iii
i
1.0 INTRODUCTION
Davis-Desse Nuclear Power Station (DBNPS) Unit 1, located on the southwestern shore of Lake Erie near Oak Harbor, Ohio, is a Babcock and Wilcox pressurized water reactor rated at 2,772 MWt.
l The turbine-generator is capable of a net electrical output of 906 MWe. The Nuclear Steam Supply System (NSSS) employs once through 3
I The Facility Operating License (NPF-3) for DBNPS Unit 1 was issued to the Toledo Edison Company on April 22, 1977. The first fuel assembly was loaded into the core on April 23, 1977, and fuel loading was completed on April 27, 1971, after a total fuel load time of 83 hours9.606481e-4 days <br />0.0231 hours <br />1.372354e-4 weeks <br />3.15815e-5 months <br />.
Initial criticality v.-p achieved on August 12, 1977, after a Post Fuel Load Precritical Hot Functional Test Program.
Zero power physics testing commenced af ter achieving initial criti-cality on August 12, 1977, and was completed on August 20, 1977.
The zero power measurements of core performance were performed at a Reactor Coolant System temperature of 5300F, and a pressure of 2155 psi.
Power escalation commenced on August 24, 1977, and the turbine gen-erator was initially loaded on August 28, 1977. Further power level increases were successfully completed at each of the four major power level plateaus as defined by the Power Escalation Sequence Test Procedure. The four major power level plateaus and dates attained are as follows:
Power Level Date 15%
September 2, 1977 40%
November 14, 1977 75%
December 21, 1977 100%
April 4, 1978 Figures 1.0-1 through 1.0-9 show the chronological power history 3
during the startup test program. Figures 1.1-1 through 1.1-5 show the <hronological core burnup during the startup test program.
i The initial transmittal on May 8, 1978, of the Startup Report contained test data which summarized the startup test program and unit performance from initial fuel loading on April 23, 1977, through 100% full power opera-tion on April 5,1978.
Since the power escalation program was not com-pleted by April 5, 1978, it could not be included in the initial trans-mittal.
Technical Specification 6.9.1.3 requires supplemental reports be submitted to the Startup Report on a quarterly basis until testing is completed and the unit resumes commercial power operation. Davis-Besse Unit 1 was shut-therefore, no further testing was com-down for a maintenance outage ano, pleted in the period ' rom April 5,1978 through July 5,1978.
1-1
The second supplement updated the Startup Report to contain test results of testing completed between July 5,1978 through October 5,1978.
The third supplement updated the Startup Report to contain test results of testing completed between October 6,1978 through January 5,1979.
3 The changes made to the Startup Report by supplements are indicated by a vertical line in the left hand margin with a number to indicate by which supplement the revision was incorporated.
Supplemental reports will continue to be submitted on a quarterly basis until the testing is completed.
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2.0
SUMMARY
The unit has been operated at power levels up to and including 100% full power since the completion of startup testing. The performance of the unit has generally been satisfactory. Testing and operation of the NSSS and the turbine generator revealed some minor problems / conditions that were other than predicted, however, none of them adversely affected plant safety. The problems encountered were not unusual for the startup program of a unit this size. A significant problem at a similar ranctor did arise during power escalation that could affect Davis-Besse Unit 1. Two burnable poison rod assemblics (BPRA) were found outside of their fuel assem-blics at Florida Power Corporation Crystal River Unit 3 reactor. This initiated an investigation by the reactor vendor for both Crystal River Unit 3 and Davis-Besse Unit 1, Babcock and Wilcox. On April 5, 1978, Toledo Edison personnel were notified a possible design deficiency could allow wear in the BPRA locking mechanism especially under high reactor coolant flow conditions. Although Babcock & Wilcox personnel felt the chance of such a failure due to wear during the first fuel cycle was extremely remote, they y recommended, as a precautionary measure, the reactor coolant flow be reduced. Reactor Coolant Pump 1-1 was shutdown on April 5, 1978. l No BPRA locking mechanism failures have occurred at Davis-Besse, nor in five previous Babcock and Wilcox units using the same BPRA lock-ing mechanisms. All 68 BPRA and all 48 orifice rod assemblies were f removed from the core by May 27, 1978 during the maintenance outage 2 as recommended by Babcock and Wilcox to insure no failures of the locking mechanism at Davis-Besse. Modified orifice rod assemblies for the two neutron source holddowns were installed. 2.1 INITIAL FUEL LOADING (SECTION 3.0) Initial fuel loading commenced on April 23, 1977 at 1357 hours. The entire fuel loading sequence experienced only minor delays and was accomplished in approximately four days. 2.2 POST FUEL LOAD PRECRITICAL HOT FUNCTIONAL TESTING (SECTION 4.0) Following initial fuel loading and prior to initial criticality, a Post Fuel Load Precritical Hot Functional Test Program was conducted from July 2, 1977 to August 10, 1977. This testing included a Reactor Coolant System Flow Measurement, Reactor Coolant System Flow Coast-down, Pressurizer Operational and Spray Flow Test, and Control Rod Drive System Operational Test. All test results satisfied the Davis-Besse Unit 1 Technical Specifications and all test acceptance criteria were met. The tests completed were: (a) Reactor Coolant System Flow Measurement, TP 200.11 (b) Reactor Coolant System Flow Coastdown Measurement, TP 200.11 (c) Pressurizer Operational and Spray Flow Tests, TP 600.13 (d) Control Rod Drive System Operational Test, TP 600.17 (c) Reactor Coolant System Hot Leakage Test, TP 600.10 (ST 5042.02) 2-1
2.3 INITIAL CRITICALITY, TP 710.01 (SECTION 5) I Initial criticality was achieved at 1729 hours on August 12, 1977, at reactor conditions of 530 F and 2155 psig. Control Rod Groups 1 through 5 and 8 were withdrawn to the top limit (100%) and com-bined Groups 6/7 were withdrawn to the 75% position. Criticalit) was then achieved by deborating from an initial reactor coolant boron concentration of 1843 ppm to a final concentration of 1520 Ppm. 2.4 CORE PERFORMANCE DURING ZERO POWER PHYSICS TESTS, TP 710.01 (SECTION 6) Following initial criticality, core performance measurements were conducted during the Zero Power Physics Test Program from August 12, 1977 to August 20, 1977. All test data and results satisfied Davis-Besse Unit 1 Technical. Specifications and test acceptance criteria. The following parameters were verified: (a) Nuclear Instrumentation Overlap (b) Sensible Heat Power Level (c) Reactimeter Response Checkout (d) All Rods Out Boron Concentration (c) Temperature Coefficient of Reactivity Measurements (f) Control Rod Reactivity Worth Measurements (g) Ejected Rod Worth Measurements (h) Stuck Rod Worth and Shutdown Margin Measurements (i) Soluble Poison Worth Measurements 2.5 CORE PERFORMANCE DURING POWER ESCALATION SEQUENCE TESTS, TP 800.00 (SECTION 7.0) Core performance measurements were conducted during the Power Esca-lation Sequence Test Program. Testing was conducted at the power level plateaus of 15%, 4G%, and 75% of total thermal core power. All test data and results satisfied the Davis-Besse Unit 1 Technical Specifications and test acceptance criteria. The power escalation core performance data and measurements are contained in the following tests. 3 (a) Nuclear Instrumentation Calibration at Power, TP 800.02 (b) Reactivity Coefficients at Power, TP 800.05 (c) Rod Reactivity Worth Test, TP 800.20 (d) Core Power Distribution Test, TP 800.11 (c) Pseudo Control Rod Ejection Test, TP 800.28 (f) Dropped Control Rod Test, TP 800.29 (g) Incore Detector Test, TP 800.24 (h) Power Imbalance Detector Correlation Test, TP 800.18 2-2
2.6 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PERFORMANCE (SECTION 8.0) A list of the tests performed during power operation related to the monitoring of the NSSS performance is presented below. In all, the Test performance of the NSSS was satisfactory, and as expected. (c) below still requires some additional data prior to completion. 3 (a) Unit Load Steady State Test, TP 800.12 (b) NSSS Heat Balance Test, TP 800.22 (c) Integrated Control System (ICS) Tuning at Power, TP 800.08 3 UNIT PERFORMANCE DURING TRANSIENT AND ABNORMAL CONDITIONS (SEC 2.7 The purpose of the unit performance tests is to verify the unit can be maintained in a safe condition during and following load tran-sients and various abnormal conditions. Tests (a), (c), (d), (c), and (f) listed below will be sunnarized in Supplement 4. 3 (a) Unit Load Transient Test, TP 800.23 (b) Unit Power Shutdown Test, TP 800.15 (c) Turbine / Reactor Trip Test, TP 800.14 (d) Loss of Offsite Power, TP 800.26 (e) Unit Load Rejection Test, TP 800.13 (f) Shutdown From Outside of the Control Room, TP 800.25 3l (g) RCS Natural Circulation Test, TP 800.04 2.8 SECONDARY PLANT PERFORMANCE (SECTION 10) This section provides a brief summary of the major difficultics encountered with the secondary systems during power escalation. The secondary systems that are covered include: (a) Turbine-Generator (b) Condenser (c) Circulating Water System (d) Feedwater System 2.9 UNIT MONITORING (CHEMISTRY AND HEALTH PHYSICS) (SECTION 11) This section presents a list of the unit monitoring and testing per-formed with regard to health physics and chemistry during various Tests were conducted during phases of the startup test program. initial fuel loading, reactor startup, power escalation and power operation. (a) Shield Survey, TP 800.01 (b) Site / Station Radiation Survey, TP 800.03 (c) Reactor Coolant Chemistry Test, TP 500.01 (d) Steam Generator Chemistry Test, iP 500.02 (c) Initial Radiochemictry Test, TP 500.03 (f) Effluent Monitoring Test, TP 360.01 2-3
2.10 UNIT TRIPS (SECTION 12) This section is a listing of all unit trips and applicable information which occurred during the period from initial fuel loading through power escalation and operation. 2.11 CORE PERFORMANCE FOLLOWING BPRA'S AND ORA'S REMOVAL (SECTION 13) This section contains a description of physics testing performed af ter the outage which removed the BPRA's and ORA's. Testing described includes: 2 (a) " Post Refuelied Physics Testing", ST 5010.03 (b) " Reactivity Coef ricients at Power", TP 800.05 (c) " Core Power Distribution", TP 800.11 (d) " Rod Reactivity Worth Measurements", TP 800.20 (c) Incore Detector Test", TP 800.24 (f) " Pseudo Ejected Rod Test", TP 800.28 (g) "NI Calibration at Power", TP 800.02 (h) " Power Imbalance Detector Correlation Test", TP 800.18 2-4
4.0 POST FUEL LOAD PRECRITICAL FOT FUNCTIONAL TESTING A Post Fuel Load Precritical Hot Functional Test Program was conducted following initJal fuel loading. This section of the report presents the scope and results of that testing. Control rod drop times were obtained dur. ng the performance of TP i 0600.17, " Control Rod Drive System Operational Test." Measurements were taken at reactor coolant system conditions of approximately 265 F and 250 psig with 0 and 2 reactor coolant pumps in operation and at approximately 532 F and 2155 psig with 2 and 4 reactor coolant pumps running. Reactor coolant system flow and flow coastdown measurements were con-ducted at reactor coolant system conditions of approximately 532*F RCS and 2155 psig to determine the core flow characteristics. the reactor coolant leakage measurements were performed to verify that Pressurizer testing system leak rate was within acceptable limits. was also conducted at hot conditions to adjust the spray and mini-spray flow settings and to verify proper pressurizer heater and spray actuation setpoints. In all cases, the applicable test criteria and Davis-Besse Unit 1 Technical Specification requirements were met. t i 4.1 REACTOR COOLANT SYSTEM FLOW MEASUREMENT TP 200.11 The Reactor Coolant System flow rates for various pump combinations were determined both before fuel loading and af ter fuel Joading. Since the acceptance criteria applies only when the reactor core and all 40 peripheral orifice rods are installed, the data acquired the acceptance values. prior to fuel loading was not required to meet Due to the relative insignificance of the pre-fuel load measurements, only the post-fuel load data is covered in this report. The RCS flow with all four reactor coolant pumps running simultane-ously was determined to verify that the total RCS flow was within the acceptable range. Likewise, the RCS flow rate with the three lowest fJow pumps running simultaneously and the RCS flow rate with flow pump in each loop running simultaneously were de-the lowest termined to verify that the minimum flow requirement for three pump and two pump operation respectively were surpassed. After th,e DPRA and ORA were removed, the RCS flowrate with all four RCPs in operation The 3 The acceptable criteria were again verified. was re-determined. results of the flow measurements are compared with their respective acceptance criteria in Table 4.1-1. As shown, all measurements were well within their appropriate limits. TP 200.11 4.2 REACTOR COOLANT SY M EM FLOW C0ASTDOWN MEASUREMENT RCS flow coastdown measurements were obtained prior to fuel loading and again after the core was loaded. For the reason mentioned in Section fuel load measurements are discussed in this report. 4.1, only the nost for a trip of one of four RCPs was repeated The flow coastdown test 3 af ter the removal of the BPRAs and ORAs. 4-1
With a RCS pressure of 2155 + 30 psig and a cold leg temperature of 530 + 10*F, the following pump trips were initiated. Case Pumps Initially R: aning Pumps Tripped 1 All four pumps Highest flow pump 2 Three lowest flow pumps Pump with highest flow in loop with 2 running pumps 3 All four pumps Highest flow pump in each loop 4 All four pumps All four pumps Prior to tripping a given pump combination, equilibrium conditions were established and steady state flows were recorded with the computer line printer, brush recorders, and the reactimeter. Following each trip, the resultant flow transient continued to be monitored on the recording devices mentioned above. The flow coastdown of each trip combination is compared with the appropriate acceptance criteria on 3l Figures 4.2-1 through 4.2-5. For each case, the coastdown flow exceeded the limiting rate. 4.3 REACTOR COOLANT SYSTEM HOT LEAKAGE TEST TP 600.10 The Reactor Coolant System (RCS) Hot Leakage Test and measurements were performed to accomplish the following: A) Determine the RCS leakage. EB) Determine the accuracy of the RCS leakage measurement by imposing a simulated leak. C) Verify that the RCS leakage is within the Davis-Besse Unit 1 Technical Specification limit. D) Verify the adequacy of the RCS Water Inventory surveillance test. The RCS hot leakage and surveillance test procedures were performed during the hot functional test program. RCS conditions were main-tained as steady as possible at about 532'F and 2155 psig throughout the test. During the initial portion of the testing (prior to fuel load), the RCS leak rate was determined by performing TP 600.10 and ST 5042.02, RCS Water Inventory Balance. Results indicated a total leak rate of less than 0.02 gpm. This calculated leak rate is well within the Davis-Besse Unit 1 Technical Specification limit of 1.0 gpm unidentified leakage from the RCS. A simulated leak rate of 1.0 gpm was then established through the leak test valves for the seal return isolation valve. Measurements were then taken in order to calculate the total leak rate. The calculated 4-2 i
k leak rate was then adjusted for the unidentified RCS leakage meaeured previously. The resultant calculated value for the simulated leak rate was 0.95 gpm. This was in close agreement with the 0.91 gpm (average over the test interval) simulated leak rate. The percent i deviation in the measured and actual simulated leak rate was 4% which meets the acceptance criteria of 4 35%. Af ter fuel load was completed, the RCS leakage was measured at least 5042.02. every 72 hours while in steady state conditions using ST RCS leakage during the post fuel load precritical hot functional testing never exceeded the Technical Specification limits of 1.0 gpm unidentified leakage. 4.4 PRESSURIZER OPERATIONAL AND SPRAY FLOW TEST TP 600.13 Pressurizer operational testing was conducted after fuel loading and prior to initial criticality. This included the setting and testing of the pressurizer spray flow and mini-spray flow, and the testing of the pressurizer spray and heater actuation setpoints. The testing and verification of the pressurizer level setpoints, level control, and heater interlocks were performed during pre-fuel load hot function-al testing. The techaique used to set pressurizer spray flows was based upon bal-ancing the heat input to and the heat losses from the pressurizer. The pressurizer spray flow valve RC2 was adjusted near 190 gpm at re-duced RCS temperature and pressure so that the heaters could maintain a nearly constant pressure and temperature. The actual spray flow was then calculated using the measured data and equation in Table 4.4-1. The spray flow was calculated to be 190 gpm which satisfiad the test acceptance criteria of 184 to 209 gpm. The pressurizer mini-spray flow calve RC 49 was adjusted near 1.0 gpm in a similar manner for the spray flow valve, and the actual flow was also calculated using the measured data and equation in Tabic 4.4-1. The mini-spray flow was calculated to be 1.6 gpm which satisfied the test acceptance criteria of.75 to 3.0 gpm. The pressurizer spray and heater actuation setpoints were tested by varying RCS pressure using the pressurizer heaters and spray valves. The results of these measurements along with respective acceptance criteria are sumnarized in Table 4.4-2. All recorded setpoint data met the test acceptance criteria. 4.5 CONTROL ROD DRIVE SYSTEM GPERATIONAL TEST TP 600.17 Testing of the control rod drive system was performed during the hot functional testing program prior to fuel loading. These tests were performed to assure proper operation of the control rod drive mechanisms under actual thermal operating conditions. All test results were acceptable. 4-3
control rod drop times were measured and verification of In addition, control rod full insertions were performed af ter fuel loading, prior to initial criticality. These control rod drop time measurements were taken to ensure compliance with the requirements of the Davis-1 Technical Specifications and the assumption stipulated Besse Unit in the FSAR accident analysis. The control rod drop time measurements were performed for all rods in groups 1 through 7 at RCS conditions of approximately 265 F and 250 psig with 0 and 2 reactor coolant pumps running, and at approxi-The mately 532 F and 2155 psig with 2 and 4 RCP's in operation. actual procedure and measurements were performed in accrodance with ST 5013.02, " Control Rod Assembly Insertion Time Test." Each rod was withdrawn to its fully withdrawn position and dropped into the Test core using the auxiliary power supply trip C and D switches. data was tabulated on brush recorders. Time signals were furnished to the recorders to show the initiation of each trip and closure of the 25% reference switch for the individual rods. All rod drop times from the fully withdrawn position were 4 1.30 seconds from power interruption at the control rod drive cabinets to This met the Davis-Besse Unit 1 Technical Specification 3/4 insertion. limit of $ 1.58 seconds. The accident analysis requirement of drop times, from the fully withdrawn position being 41.4 seconds from The actual power interruption to 2/3 insertion was also satisfied. rod drop times for the four pump condition are summarized in Figure 4.5-1. 4-4
REACTOR COOLANT SYSTEM FLOW MEASUREMENTS Reactor Coolant Pumps Minimum Acceptable Maximum Acceptable Measured Flow Rate Flow Rate Flow Rate No. Pump Combination GPM GPM GPM 102,400 1 1-1 99,300 1 1-2 103,800 1 2-1 105,600 1 2-2 186,390 2 Lower flow pump 172,500 in each loop 1-2, 2-1 3 Three lowest 262,000 284,180 flow pumps 1-1, 1-2, 2-1 4 1-1, 1-2, 2-1, 2-2 352,000 410,100 378,890 Post BPRA and ORA Removal Retest 3 4 1-1, 1-2, 2-1, 2-2 387,200 429,400 403,818
- Indicates that no acceptance criteria was established.
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l i i L _ -.. - - -DBNPS - Unit #1. s STARTUP REPORT Post BPRA/ ORA Renoval i riow Coastdown 4-10 Figure 4.2-5
I i i PRESSURIZER SPRAY FLOW CALCULATIONS f Spray Flow = 3 (VRCS) A h(K)
- where, Q = heater input (KW)
RCS = specific volume of RCS cold Icg (ft /lbm) V -3 K = constant 2.35x10 ft - min - KW gal-BTU / Ah = enthalpy of pressurizer - enthalpy of spray water (BTU /lbm) RCS RCS Pressurizer Pressurizer Calculated Pressure Temperature Temperature 'llcater Power Flow Pressurizer Spray 1280 psig 532 F 577 F 1224 KW 190 gpm Pressurizer Mini-Spray 2150 psig 532 F 647 F 30 KW 1.6 gpm DBNPS - UNIT 1 STARTUP Rl! PORT PRI!SStiRIZliR SPRAY FLOW CAI.CUI.ATION TABLl! 4.4-1 4-11
l PRESSURIZER SPRAY AND IIEATER ACTUATION SETPOINT DATA Measured Acceptance Value (psig) Criterls (psig) Pressurizer Spray OPENS 2205 2205 1 16 Flow Valve CLOSES 21C5 2155 1 16 Heater Bank 1 ENERGIZES 2155 2155 1 16 DE-ENERGIZES 2155 2155 i !! cater Bank 2 ENERGIZES 2138 2135 1 16 DE-ENERGIZES 2155 2155 1 16 IIcater Bank 3 ENERGIZES 2115 2120 1 16 DE-ENERGIZES 2140 2140 1 16 IIcater Bank 4 ENERGIZES 2115 2105 i 16 DE-ENERGIZES 2125 2125 1 16 DBNPS - UNIT 1 STARTUP REPORT PRESSURIZER SPRAY AND-IIEATER ACTUATION SETPOINT I)ATA TABl.E 4.<!-2 4-12
ROD DROP TIMES f h IIOT FULL FLOW CONDITION ~ R P O N M L K H G F E D C B A f 1 CR6-9 CR7-8 CR6-11 2 1.26 1.23 1.27 CR3_3_ CR2-6 CR1-4 CR4-4 3 1.24 1.23 1.28 1.22 CR5-9 CR5-10 CR5-1? 4 1 17 1.27 1.25 _Q_ 7-9 QR3-4 5 R CR4-3 CR7-7 1.21 1.25 1.20 1.25 CR6-8 CRS..8_ CR6-lC CR5-11 CR6-12 6 1.27 1.29 1.28 1.27 1.27 CR1-3 CR2-5 CR2-7 CR2-8 7 1_.28 1.24_ 1.23_
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CR7-6 CRS-7 CR6-7 CR7-1 CR6-1 CR5-1 CR7-2 8 1.23 1.28 1.28 1.22 1.28 1.28 1.23 CR2-4 CR2 _3 C R2_-1_ CR1-1 9 1.23 1.24 1.23' 1.28 CR6-6 CRS-5 CR6-4 CR5-2 CR6-2 10 1.28 1.28
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.1. 2 2,. 1.27_ 15 DBNPS - Unit 1 Startup Report CRY -7. Control Rod Z of Croup Y Drop U mes X.XX ._ Drop Titae from Power Interruption at . Figure 4.5-1 the Cabinets to 3/4 Insertion (sec.) 4-13
8.0 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PERFORMANCE The purpose of the tests described in this section is to monitor the performance of the Nuclear Steam Supply System (NSSS) to obtain baseline a data and to verify the NSSS performs as designed. Four tests are used to complete this purpose. Two of the NSSS performance tests are entirely completed - TP 800.12, " Unit Load Steady State Test", and TP 800.22, "NSSS Heat Balance Test".
- Also, 3
TP 800.08, " Integrated Control System Tuning at Power", is complete except for the 15% test data. 8.1 UNIT L6AD STEADY STATE TEST, TP 0800.12 Primary and Secondary System steady state parameters were measured during power escalation to obtain baseline data. This information was gathered during Phase I of TP 800.12, " Unit Load Steady State Test", at approximately 0%,15%, 30%, 40%, 65%, 75%, 90% and 100% full power. Steady state condi-tions were established before any data was obtained. Several parameters were compared with design values to verify that the response for these parameters, as a function of power, was as expected. These comparisons are shown in Figures 8.1.1 through 8.1. 7. Where appropriate, the recorded values were derived from an average of the measured readings. As shown on Figures 8.1-1 through 8.1-7, all parameters recorded responded within their acceptable bands. Phase II of TP 0800.12 was performed from 0% to 15% full power. Data was accumulated to check the relationship between Tave and reactor power. This information was used to adjust the OTSG low level setpoint to bring Tave within 582 + 1 F at 15% power. 8.2 NSSS HEAT BALANCE TEST, TP 0800.22 TP 0800.22, "NSSS Heat Balance Test", was performed during power escalation with the intent of achieving the following objectives: 1. Verify the accuracy of the computer's heat balance calculation. 2. Provide baseline data for comparison with subsequent heat balance checks. 3. Determine the reactor coolant flow rate. This test was conducted at power levels of 15%, 30%, 40%, ~ 65%, ~75%, 90%, and 100% full power. Data for primary and secondary heat balances was taken at each testing point. The balances were compared to the computer calculated heat balances. In all cases, the hand calculated and computer calculated values agreed to within the required 12% acceptance criteria. The results of these computations are summarized in Table 8.2-1. At 100% of full power, the hand calculated primary heat balances for each loop were compared to their respective secondary heat balance. Since the deviation for'both loops was greater than 1%, a new range for the primary flow meters for both loor has h en calculated by setting the primary heat 3 balance equal to the secuad y heat balance. A retest was performed to verify the deviation is less than 1%. 8-1
8.3 INTEGRATED CONTROL SYSTEM TUNING AT POWER, TP 0800.08 2 All but the 100% full power transient testing portion of TP 0800.08, " Integrated Control System Tuning at Power", were performed throughout hot functional testing and during power escalation. This procedure was performed to verify that optimum plant performance and control is obtained by means of the integrated control system. The major ICS related control functions tested are listed below: 1. Thermal efficiency between the primary and secondary system. 2. Electrical output versus feedwater flow. 3. Feedwater temperature versus feedwater flow. 4. Steam generator startup level versus reactor power. 5. RCS inlet and outlet temperature versus reactor power. 6. Plant parameter signal levels which input to the ICS. 7. ICS capability to run the unit back to the desired load at the specified rate. Selected functions are shown on Figures 8.3-1 through 8.3-6. All plant parameters tested were within their respective acceptance criteria. t 8-2
TABLE 8.2-1 HEAT BALANCE
SUMMARY
Noninal LOOP 1 LOOP 2 Power P1 (Comp) P1 (Hand) P2 (Comp) P2 (Hand) % DIFF P1 (Comp) P1 (Hand) P2 (Comp) P2 (Hand) % DIFF (%) Wt Wt Wt Wt (Pl-P2)(Hand) MWt Wt Wt Wt (P1-P2)(Hand) 15 193.56 184.63 0.32% 212.93 204.04 0.32% 30 427.44 435.98 414.54 443.40 0.27% 447.76 418.71 446.68 434.89 0.58% 40 564.80 572.82 599.39 588.80 0.58% 540.38 551.86 595.58 581.27 1.06% 62.5 947.45 842.00 903.26 895.29 1.92% 817.24 824.77 906.05 887.905 2.28% 72.7 961.95 991.508 925.17 1027.33 1.29% 1042.70 951.058 1039.19 1020.04 2.49% 83.5 1151.82 1162.01 1269.53 1245.66 3.02% 1107.33 1127.35 1253.06 1227.96 3.63% i 100 1272.82 1287.09 1381.73 1380.78 3.38% 1226.92 1262.145 1374.40 1374.57 3.98% Where: P1 (Comp) = Primary computer heat balance P1 (Hand) = Primary hand heat balance P2 (Comp) = Secondary computer heat balance P2 (Hand) = Secondary hand heat balance DBNPS - UNIT 1 STARTUP REPORT HEAT BALANCE
SUMMARY
TABLE 8. 2-1
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( STEAM G ENERATOR OPERATING RANGE LEVEL m vs POWER f g =IF_ T: 7:~. T.--t 7**-T....___...___..._.._ __ = 1=:n nns t r = =_ _ :. '..t _ :1..__. - -,.=__=.____ t__=__=.. _.:: =_ _= =r -.. _ _ _... 4 _b,._-. f... g - - - - -I 2 5_ih" 2iiEir EEE7_I'_25--~~==-- '-- - - - -
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LIO.llTS Oil T-AVE T-MOT,A;lD T-COLD WITH 4 RC PU?.!PS RU R!!;!G
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LIMITS ON STEAM T EMPERATURE vs POWER ..., h.., _.. f...,.Q*T. -. * .-.s ... !=. --. P: t: m o :t T"C
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.p .l.i.l. i..;. 400 800 1200 1600 2000 2400 2800 3200 MEGAWATTS THERMAL DBNPS - Unit Startup Report Steam Generator Startup Level vs. Megawatts Thermal Figure 8.3-5 8-15
9.0 UNIT PERFOINANCE DURING TRA'ISIENT AND ABNORMAL CONDITIONS The purpose of the unit performance tests is to verify that the unit can be maintained in a safe condition during and following load transients and various abnormal coaditions. A reactor trip test was completed at the 40% of full power level. A turbine trip from 75% of full power was alsu completed. 3 A unit load rejection test from 75% of full power was performed. A unit load rejection test will be conducted at an initial power level of 100% of full rated power. The plant will be shutdown from the Auxiliary Shutdown Panel from an initial power level of 15% of full rated power. A loss of offsite power test, including a loss of external load, will be conducted from an initial power level of 15% of full power. Load transient tests included 10% full power transients at 40% and 75% of 3 full power. The 50% full power transients at 90% of full power have yet to be completed. Proper operation of the integrated control system cross limits and rate limits were also verified. A natural circulation test was performed with the reactor at 3.8 - 3.9% of 3 full power and all Reactor Coolant Pumps tripped. A unit power shutdown test was performed on October 18, 1977, from an initLal power level of 15% of full rated power. 9.1 TURBINE AND REACTOR TRIP TEST TP 800.14 The reactor trip from 40% of full power was successfully completed on December 15, 1977. The reactor t.ip was initiated manually, and the Reactor Trip Emergency Procedure, EP 1202.04, was implemented. 3 A 75% of full power turbine trip was completed on April 2, 1978. This pro-vided more data to optimize the operation of the Integrated Control System. The 75% turbine trip was repeated on September 10, 1978, to test the blow - back of the main steam safeties and changes made to the Integrated Control System during the BPRA removal maintenance outage. The main stede safetics operated properly during the test but the ICS displayed the need for further tuning. As a result of the analysis of the ICS performance af ter the trip, adjustments were made to the ICS. Either a load rejection or a turbine trip test will be performed to verify proper operation. The turbine trip was manually initiated from EHC Panel fl on C-5713, and the Turbine Trip Emergency Procedure, EP 1202.03, was implemented. 9-1
Data on a turbine trip from 100% of full power may be obtained by a if the data obtained from the " Unit Lnad Rejection Test", C 3 turbine trio TP 800.13, is not sufficient to verify proper performance. A Reactimeter and Brush recorders were used to record the applicable The results of the reactor and turbine trip tests are summarized data. in Figures 9.1.1 through 9.1.10. The collected data verified that the reactor coolant system remained within its safety limits. TP 800.23 9.2 UNIT LOAD TRANSIENT TESTS The unit load transient tests demonstrated that the unit can be maneuvered in a controllable manner at 5% FP per minute from 15% to 75: and from 75% to 15% of full power. The unit load transient tests also verified proper operation of the ICS cross limits and verified satisfactory low power level response of the ICS to control the unit subsequent to the tripping of one j reactor coolant pump or one main feedwater pump. l Load transients of 10% FP were conducted at 5% FP per minute from 40% to 30% to 40% of full power in the integrated control mode and turbine following mode, and at 3% FP per minute in the steam generator / reactor following mode. Af ter tripping Reactor Coolant Pump 1-1, a load transient of 20% FP was conducted at 5% FP per minute from 40% to 20% of full power in the integrated control mode. Reactor Coolant Pump 1-1 was re-started and a load transient of 20% FP was conducted at 5% FP per minute from 20% to 40% of full power, also in the integrated control mode. ICS cross limits were verified by: from 40% to 50% of full Imposing a 5% FP per minute load transient 1. power with the feedwater control subsystem in the manual mode of control. The feedwater-to-reactor cross limits limited the reactor demand to 45% of full power when the feedwater demand exceeded feedwater flow by 5%. from 40% to 50% of full Imposing a 5% FP per minute load transient 2. power with the reactor control subsystem in the manual mode of control. The reactor-to-feedwater cross limits limited the feedwater demand to 45% of full power when reactor demand exceeded the neutron power by 5%. from 40% to 30% of full power Imposing a 5% FP per minute load transient The 3. with the reactor control subsystem in the manual mode of control. reactor-to-feedwater cross limits lir' ed the feedwater demand to 35% ed the reactor demand by 5%. of full power when the neutron power Load transients of 10% FP were conducted at 5% FP per minute from 75% to and turbine following 65% to 75% of full powec in the integrated control mode mode, and at 3% FP per minute in the steam generator / reactor following mode. 64% of full power, Main Feedwater Pump #1 With the reactor operating at was tripped, and the ICS initiated a plant runback to 59% of full power TP 800.08 at 50% FP per minute, in the integrated control mode. 9-2
A list of unit load transient tecting is given in Table 9.2.1. A reactimeter and brush recorders were used to record the app?icable data. The collected data verified that the unit can be maneuvered at 5% FP per minute in the interrated control mode, af ter optimization, without a reactor or turbine trip, relief valve or turbine bypass valve actuation, or exceeding any of the limits imposed by PP 1101.01 "NSSS Plant Limits and Precautions", thus satisfying the acceptance criteria. The follewing testing is yet to be completed: The high power positive rate limit will be verified by imposing 1. a 5% FP per minute load transient at 85% of full power in the TP 800.08 integrated control mode. t Load transients of 50% FP will be conducted at 5% FP per minute 2. from 92% to 42% to 90% of full power and at 3% FP per minute from integrated control mode and turbine 90% to 92% of full power, in the following mode, and at 3% FP per minute in the steam generator /reac-TP 800.23 tor following mode. TP 800.15 9.3 UNIT POWER SIIUTDOWN TEST The unit power shutdown test was performed to verify the adequacy of the Plant Shutdown and Cooldown Procedure, PP 1102.10, from 15% power to 0% power, and to obtain baseline data for subsequent shutdowns. The shutdown was performed from an initial power level of 15% of full rated The cooldown was conducted to a final reactor coolant system temperature of 531"F and the reactimeter data was obtained by the Plant power. The results of the unit power Computer's Operator Special Summary Group. summarized in Table 9.3.1, verified shutdown test, Shutdown and Cooldown Shutdown can be performed (Section 4 of Plantwithout exceeding the limits of the Nu Procedure, PP 1102.10) 1101.01, Section 1. Thus, the Supply Limits and Precautions, PP acceptance criteria was satisfied. TP 800.13 9.4 UNIT LOAD REJECTION TEST The purpose of the Unit Load Rejection Test is to demonstrate the untt can be satisfactorily controlled when a loss of load occurs and to assure no Technical Specification safety limits are exceeded during or fellowing the load rejection. the Unit Load Rejecticn Test was performed with the On November 11, 1978, the test was initiated by opening unit at 75% of full power. At 0009 hours, The Integrated Control System operated the main generator cutlet breakers. properly to initiate a runback to approximately 15% of full power, reducinf Both the main steam safety valves both reactor power and feedwater flow. 3 and the turbine bypass valves maintained main steam line pressure within and the turbine speed returned to 1800 RPM.
- limits, At 0039 hours, the generator was synchronized with the grid by closing the test was successfully completed without viola-main generator breakers. The A reactimeter and brush tion of any Technical Specification safety 11mits.
recorder were used to record the applicable data.
A 100% Unit Load Rejection Test is scheduled to be performed prior to February 15, 1979. Results of the 100% load rejection will be summarized in Supplement 4. TP 800.04 9.5 NATURAL CIRCULATION TEST The purpose of the Natural Circulation Test is to verify that on a loss of all forced reactor coolant flow, natural circulation will provide adequate core cooling for all possible levels of decay heat generation. Since under natural circulation conditions cold leg temperature (and therefore density) is significantly different from the value at which the power range instrumentation was calibrated, Phase One of this test determined a correc-tion factor for indicated power. On October 30, 1978, Phase One was com-oleted. At 1920 hours on November 3, 1978, the two operating Reactor Coolant Pumps were stopped with reactor power held at approximately 3.8 - 3.9% and a steam generator water level of 160 inches. Natural circulation flow was computed with the use of a heat balance to be over 5% of full flow, which is over three times the minimum required flowrate. Steam generator icvel was reduced in five increments to the low level limit, each time computing the natural circulation flowrate. The lowest measured flowrate was 4.64% of full flow which is over 2.5 times the required flow-rate. The reactor was held at 3.8 - 3.9% power for over seven hours on natural cir-culation with no operational limits violated. Further results of the Natural Circulation Test are depicted ir. Figures 9.5.1 3 through 9.5.3. 9.6 LOSS OF EXTERNAL LOAD INCLUDING LOSS OF 0FFSITE POWER TEST TP 800.26 The purpose of the Loss of Offsite Power Test is to demonstrate that the station can be maintained in a safe condition following a loss of offsite power. The loss of offsite power and loss of external load test is initiated by isolating the switchyard from the startup transformer supp1ffng unit housepower. The test uses a reactimeter and brush recorders to record the applicable data. The results of this test will be summarized in he fourth supplement to the Startup Report. 9-4
TP 800.25 9.7 SIIUTDOUN FROM OUTSIDE TIIE CONTROL ROOM The purpose of the Shutdown From Outside of the Control Room Test is to demonstrate that the plant can be safely shutdown and maintained in a hot standby condition from the Auxiliary Shutdown Panel, C-3630, and to verify 1202.33. the adequacy of the Emergency Operation of the NSS Procedure, EP 3 The test is performed by manually tripping the reactor from outside the Control Room at 15% of full rated power. Subsequent operations conducted from the Auxiliary Shutdown Panel, C-3630, establish the plant in a safe, hot standby condition. The results of this test will be summarized in the fourth supplement to the Startup Report. 9-5
e TABl.E 9.2-1 1: NIT IAAD TRANSIENT TEST St'MMARY 9 SETPOINT $820F SETPOINT 870 PSIC % FP 925MWe IRidSIENT ICS MODE OF Z FI' CIIANCE RATE % MIN MAXIMUM MAXIML'M DATE
- 1
- QER OPCRATION
%.TO AVERACE TAVC. DEVIATION *F TilP DEVIATION TIME ABOVE BFLOW ABOVE BELOW i 12/6/77 [,l 1 Integrated 40" to 30% 5% 0.5 2.0 12 36 2300 12/7/77 2 Integrated 30% to 40% 5% 1.5 1.0 30 22 0005 12/7/77 Turleine 3 Following 40% to 30' 5% 0.0 2.75 2.5 13.25 1600 12/7/77 Turbine 4 Followin g 30% to 40% 5% 2.0 1.25 9.0 3.75 1630 12/10/77 1(x/SG 5 Follo. in g 40% to 30% 3% 0.25 1.0 45 15 1245 12/10/77 Rx/SG 6 fal},winc 30~ to 40% 2.75* 0.0 1.0 12 37 1300 12/10/77 Rx lien:nd 7 In t'.unni 40% tn 30% 5% 3.0 _ p,. 0 7.0 9.0 1445 12/10/77 Rx Ikmand f 8 In. tt.in u al 30% to 40% 3% 2.5 1.0 13 8 1515 12/10/77 m Botti FW Demands 9 in !!miul 40% to 30% 5% 2.0 , ~15 0 7.5 1625 12/10/77 I lioth FW Demands 10 I in ?tmo:11 10* to 40% 4% 0.0 3.0 7 0 1635 12/14/77 Assymetric Rod l 11 1: unlock 40% to 18% 30% 0.5 3.0 42 0 1100 12/14/77 Loss of RCP 12 Ruulu ck 40% to 33% 50% 1.5 0.5 45 0 1300 12/14/77 Integra ted Ik>de 13 i 3 I; cps Runniga 33% to 20% 5% 0.3 0.25 30 0 1315 12/14/77 P 14 Interrated hide 2 :' to 40% 5% 0 0.8 12 30 1335 1/4/78 15 Integrated Mode 70% to 60% 5% 0.7 1.0 33 12 1035 Davis-Besse Unit 1 Startup Report O e e .-4 o e e
e e S o o 8 8 8 8 8 8 8 8 8 1 e 8 7 7 7 7 7 7 7 7 7 EE 7 / / / / / / / / / e t TP /5 85 35 80 85 30 80 85 85 90 i AI 45 1 1 1 ' 1 21 3 1 7 1 1 1 0 s 2 12 nt DT /0 /9 /9 /2/2 /J/3 /4 /4 /4 U r 1 1 10 10 11 1 1 1 I 1 1 1 1 1 1 11 o ep se sR e B p C - u I st S i r P va NJ 0 OF 8 2 9 2 8 3 2 2 8 7 at DS 7 I I 2 1 1 2 1 1 1 8 MTE UAB T MI N I V I XE P M V . 5 O ADE T I 6 5 1 5 0 6 8 6 3 0 PO 1 4 E I B 2 2 4 2 S TA a F" J' 5 5 O F NL 0 0 2 0 3 2 7 0 0 0 Y 0 OE 4 R 2 I B 1 1 0 0, 0 2 1 0 1 3 A 8 MT e t $ UA M MI L TI V S N X E WD I T O 1 S P .E E T GV 5 0 T E V0 0 5 2 0 0 5 0 5 5 2 S A3 2 0 3 1 1 1 1 1 0 3 9 T TA N e E. E t I B S A N N T A I R HE T C 5 %A D R 7 A EE Y D TV s 5 5 3 2 5 5 5 5 0 5 I AA R T I N U 5 2 5 E% C 6 7 N 0 2 5 5 5 5 5 9 A 7 6 7 6 7 o o 6 7 5 1 t t 1 O CT o o o o o o o o t t t t t t t t 5 5 P% F 7 2 5 5 4 0 5 5 5 5 2 6 7 6 7 6 7 6 7 6 6 s s e d d d e F o n n W ON M a a m m P O e e F1 5 EI d 2 DT e e r g
- r. d l dl l l Dl t a
ei ei in na n a a a n r n n iwG 9 OA uJ u f k WnPn a u a u R e n nw w mn i oc CO e bl bl Sl Sl fe!i mn i t giwio P E G o ei a t t F SP / l ! 9t h h I sb t. t s n ix oE In u n.# l /l t rl ruo xo Z I o n an ou n uo i C I CI pI P < F I TF TF RF T N. E1 R SE ND 6 7 8 9 0 1 2 3 4 5 1 1 1 1 2 2 2 2 2 2 A! RU TN .!i 1 eh
N TABLE 9.2-1 UNIT LOAD TRANSIE?TI TEST SUFe!ARY SETPOI!TT 5820F SETPOINT 870 PSIC %FP 925 INe MAXIMUM MAXIMIDI TRANSIENT ICS MODE OF % FP CHANGE RATE % MIN TAVG. DEVIATION OF TitP DEVIATION DATE NUMBER OPERATION _.__% TOJ AVERACE ABOVE BELOW An0VE_ BELOW TIME U/>//d 26 Mod e 40% to.30% 5% 0.2 1.0 24 0 2200 Integrated 8/5/78 27 ttode 30% to 40% 5% 0.5 1.0 0 26 2230 Integrated 7 8/5 78 28 Following 40% to 30% 5% 0.2 1.0 5 11 2300 Turbine 8/5/78 FoiIowing 30% to 40% l'. 0 0.5 8 5 2325 Turbine 8/6/78 29 ~ 'R3G 30 Following 40% to 30% 3% 0.2 1.0 50 3 0045 8/6/7a 31 Following 30% to 40% 3% 0.5 0.5 5 36 0115 Rx/SG 8/6/78 Both FW Domando 32 in Mjnual 40% to 30% 5% 1.7 1.0 6 8 0235 8/6/78 Coth;FU Demand:, 0.2 2.2 5 6 0250 33 in flanual 30% to 40% 5%- 9/9/78 Integrated 1 0950 34 Mo<ie 75% to 55% 5% 1.0 0.4 32 9/9/78 Integrated 35 !!od e 55% to 75% SI 1.5 0.1 7 31 1010 9/9/78 36 Following 75% to 55% 5% 0.2 1.3 9 15 1230 Turbine 9/9/78 37 Following 55% to 75% 5% 0.7 0.8 13 9 1240 Turbine 9/9/78 38 Following 75% to 55% 3% 0.3 1.0 36 13 1310 Rx/SG 9/9/78 39 Following 55% to 75% 3% 0.4 1.0 6 40 .1330 Rx/SG Davis-Besse Unit 1 Startup Report e
t TABLE 9.3.1 UNIT POWER SHUTDOWN TEST
SUMMARY
Initial Final Value Value Parameter Test Commenced / Completed 1009 hrs. 2359 hrs. Reactor Power / Source Range Level 15% FP 0% FP 581 F 531 F RCS Tave/RCS Tc WR 2150 psig 2150 psig RCS Pressure 195 in 188 in Pressurizer Level 62.5 la 71 in Makeup Tank Level 7% 47% SG #1 Operate Level 6% 46% SG #2 Operate Level 6 lbm/hr - 0 lbm/hr 0.55 x 10 SG #1 FW Flow 0.54 x 106 lbm/hr -- 0 lbm/hr SG #2 FW Flow SG #1 Steam Outlet Pressure 882 psig 871 psig SC #2 Steam Outlet Pressure 888 psig 873 psig 299 F 230 F Feedwater Temperature RCS Boron Concentration 1339 ppmB 1304 ppmB RCS Contraction (Makeup) Volume 4000 gallons 9-9
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1 + --a. a L o, .t.. .+ u. p..+ t 850 t 1 2 3 4 c. s ELAPSED T'.4E FROM TRIP (MINTTTES) DBNPS-Unit #1 STARTUP REPORT SG #2 OUTLET PRESSURE VS. ELAPSED TIME FROM TRIP FROM 40% FP FIGURE 9.1.2 9-11
.-. i. _.Ja 4 t,.- .4'_._.. , a.- ' 4. i < ..._ q a11 200 _--.. .. -. _ -.. +. .. a ,a.. ~... i .... A .~ ., +.... -..,_._ % -., r_+: -+--4t.~+.- ..t.._ u 4.... 175 _ . _ 4 L. i ., y.. ..4 . t a _.. _...m. ._.4_ u.._. .~. .... -.... -.. u._ m m 150 m . _...i,_....._i .O ..-_t_ ...,..i _- )$ _ a -.7. g y.... . __._ 4_ v 7. _ L, _ . _.,. ~ ~- _.i. g -..,.r .,.. ~ ..-_.y .. w. q. +- _p~, _7 g w w.+ _e y .s_. M m._ g . w. j.. _ _-......-, -. a - a.,_. a.-._.-. _, _ - - -.-.- N .a a. . + g g . 1.. 2__ p .r.. m m m 100 7 .._m .,_r _7 .._ u. O u. ~ _.. .mm._... e4 g a.7-d '*~~ - ~ ' ' - ~~ . +. } b ~ - ~ ~' - ~ ' ' - ' + ~ ~ ~ ~~ o u 75 .4.... ~. - - .'.a . 7... ( ~~~ ~ ~ .t.i_.. F ~' ~ 50 ~ ~~ ^ ..i. ..t. 25 v 4 o. 2 3. t 1 s ELAPSED TIME FROM TRIP (MINUTES) DBNPS - Unit #1 STARTUP REPORT COMPENSATED PRES-SURIZER LEVEL VS. ELAPSED TIME FROM TRIP 9-12 FROM 40% FP FIGURE 9.1.3
75 a -;.. a .._._a-. w .u_ -.. 4 _._._ ..._.4 __.-2_._ . u. 2.._ - _t_ y .J... ....a. m
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75 . J. n m g v ~~ ~ a 50 ^ g {j g A l o y I 25 t em ,i t. 0 1 2 3 4 ua ELAPSED TIME FROM TRIP (MINUTES) DBNPS - Unit #1 STARTUP REPORT SG #2 STARTUP LEVEL VS. ELAPSED TIME FROM TRIP FROM 40% FP FIGURE 9.1.5 9-14
.m. 2200 ..~.,. .. ~.. ..., + t.u. u, ...-.c e .g. _.,_.. 2.-,_ .-..~., - 5 ~ ~ ~ ~ ~ ~ [ ~ ~ ~ ~ ~~ ~ ~ ' ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~~' " ~'~' ' ~ ^ ' " ~ .- ~ '"~ 2100 _ l -+ a... r._ _._i .. a i. 2.. a -. 2.-
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g.. 4 l 1700 .. r.. e 4 3 1600 2 1 a eW ELAPSED TIME FROM TRIP (MINUTES) s DBNPS - Unit #1 STARTUP REPORT RCS PRESSURE VS. ELAPSED TIME FROM TRIP FROM 40% FP FIGURE 9.1.6 9-15
2300 a ..} .w._.- .+ ._,l . +. ' ~ ~ ~ ' ' '~ ~ ~ ^ ^ ^ ~ ~ ~ ~ ~ ~ ~ ~ ~ 2 L .}__.,. .._-u. l } ~ y i 1 ..p.
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10.0 SECONDARY PLANT This section will provide a brief summary of the major difficulties encountered with the secondary systems during power escalation. The secondary systems that will be covered include: 10.1 Turbine-Generator 10.2 Condenser 10.3 Circulating Water System 10.4 Feedwater System 10.1 TURBINE-GENERATOR During startup, the turbine and generator experienced relatively few major difficulties, but was plagued with numerous diversified prob-lems. High vibration during the second turbine roll led to a re-alignment of the exciter in August. The first time the generator was loaded, grounds in the generator exciter bearing and Number 8 Generator Bearing were discovered. The bearings were subsequently disassembled and the grounding problem resolved. The turbine over-speed trip mechanism did not operate when first tested in September with the trip point approximately 12 RPM above the limit. The mech-anism was cleaned, adjusted and inspected. The Steam Generator 1-1 Turbine Bypass Valves were cycling open, then closed just prior to shutdown which caused damage to the turbine by-pass headers in the High Pressure Condenser. The strap piping res-traints were replaced with rigid restraints to prevent excessive piping movemen:. In November, the Number 2 Turbine Control Valve position was found to be oscillating. This caused two unit shutdowns in which a function generator on the turbine EHC System and the servo valve for the Num-ber 2 Control Valve were replaced. The cause was found to be a defec-tive electrical connector which was the position feedback to the EHC. In January, 1978, the turbine control rotor of the overspeed trip mechanism was replaced in an attempt to solve the problem with reset-ting the oil trip. In February, 1978, it was discovered a defective oil trip solenoid valve was the cause of the overspeed trip difficul-2 ties and the solenoid valve was replaced. The inboard bearing on the turbine main oil pump was replaced and orifice plugs installed in the bearing oil supply lines of the front standard. 10.2 CONDENSER The condenser has encountered problems with condenser tube leakage. In September, 1977, approximately 28 tubes were plugged near a pene-tration where a high pressure steam header warmup drain from the main steam header had impinged on the tubes due to improper design of the baffle arrangement inside the condenser. A new baffle was installed which deflected the high pressure steam away from the condenser. 10-1
10.2 CONDENSER (Continued) On February 14, 1978, reactor power was increased to 90%. High con-ductivity was noted the next day which indicated a leak of a conden-ser tube. Power was reduced and one tube was plugged. On February 16, 1978, the unit returned to 90% power. On February 17, 1978, a tube leak was again reported. The unit was taken off line and five leaking tubes along with eleven adjacent tubes were plugged. The unit returned to 90% power on February 19, 1978. On February 20, a small condenser tube leak was discovered and the power was reduced to 75%. The unit was shutdown on February 24 and an eddy current inspection of various tubes indicated serious problems existed in numerous condenser tubes. Sixty-seven tubes were plugged. During the unit outage to remove the BPRA's, flow diffusers were added to the condenser internals in an attempt to correct the con-denser tube failures. While the unit was at 100% of full power on September 25, 1978, in-creasing condensate conductivity indicated condenser tube leakage. When the unit was shutdown (due to a failed Reactor Coolant System Flowmeter), a condenser inspection revealed one tube had developed a leak. The defective tube was plugged. With the unit at 100% of full power on September 6,1978, an increase in condensate conductivity was again discovered. When the unit was shutdown (due to defective Reactor Coolant Pump Seals), investigation revealed two leaking tubes which were then plugged. The condenser vendor, Ecolaire Condensers Incorporated, investigated the cause of these tube f ailures and installed some extra supports within the condenser while the unit was shutdown for repairs of Reactor Coolant Pump seals during October,1978. In December 1978, abnormally low pressure was noted in the Low Pressure Feedwater Heaters. The unit was shutdown, and the condensers were opened and inspected. Three expansion joints had failed in the conden-sers and had caused some condenser internal damage. The High Pressure Condenser extraction steam f airing door had been blown off and had dented eight tubes which were then plugged. Re-welding was required on some impingement baffles and a seam of one of the extraction steam fairing Instrument tubing in the vicinity of the expansion joints was replaced or repaired as required. The addition of extra tube supports was also 3 completed during the outage. It is believed the failure of the expansion joints was due to both under-designed expansion joints and excessive vibration. The original expan-sion joints were not designed to withstand the superheated steam present in the extraction steam lines. Additional bracing to stop the excessive vibration was installed per Ecolaire recommendations and expansion joints designed to withstand the superheated steam were installed in an attempt { to prevent a recurrence of the f ailure of the expansion joints. 10-2
10.3 CIRCULATING WATER SYSTEM The Circulating Water System has experienced problems with failures of the liners of the 54 inch discharge valves. In August, 1977, the Number 2 Circulatirg Water Pump Discharge Valve was rebuilt and the rotation reversed to reduce the amount of turbulence. During the plant outage in September, fragments of a valve liner were [ found in the condenser water bor Subsequent investigations showed i that the Number 3 Circulating Water Pump Discharge Valve was damaged. l The valve liner was replaced and the rotation reversed on Number 3 j Circulating Water Pump Discharge Valve. The amount of time these j butterfly valves are throttled is now being limited to minimize the damage from the turbulence. The Cooling Tower experienced some icing difficulties. In December, g 1977, several internal fill support concrete beams were broken and 6 others damaged by ice buildup. Ice falling inside the veil also l damaged some of the drif t eliminators and conduit was damaged from ) ice buildup. A revised operating procedure was provided by the vendor, Research-Cottrell to minimize the icing damage. Operating under the revised procedure has reduced the ice buildup and the damaged beams 2 l' were replaced during the outage to remove the BPRA's. l l c 10.4 FEEDWATER SYSTEMS Another area where major problems have been encountered is with the feedpumps. Main Feed Pump 1-2 was taken out of service in October l because of high vibration and flow rate difficulties. The pump was i disassembled and a piece of the pump impeller was found to be broken off. The entire impeller was replaced with the spare and the sharp radius corners between the impeller vanes and sideplates were ground out co remove a potential high stress area on the impeller. The impeller of Main Feed Pump 1-1 was also inspected and ground. Both feedpumps were returned to service and further impeller difficulties f have not occurred. In January, 1978, it was determined the drain system of the Main Feed Pump Turbines was not operating correctly and high turbine exhaust casing water levels were causing the turbines to trip. After an ex-tensive investigation of the drain difficulties during power operation, a modification which removed the lower source tap loop seal was com-pleted in February. The auxiliary feed pumps have had extensive difficulties in speed control. In July and August, 1977, repeated speed control relay failures rendered the auxiliary feed pumps inoperable. On August f 10, 1977, a' design modification was implemented which added a second set of identical speed relays in parallel to reduce the current carried by each relay. This did not totally eliminate the speed control failures and in January, 1978, the relays of the speed circuit were replaced with relays of a larger current carrying
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10-3
i Other design deficiencies were discovered in October when it was observed the Auxiliary Feed Pump 1-2 Turbine Governor Valve would close under certain vibrational conditions, rendering the Auxiliary A redesigned valve linkage was installed Feed Pump 1-2 inoperable. in which the force of a spring assured elimination of the vibrational closure. Feedwater chemistry control has encountered several problems during The moisture separator reheater drain tanks concen-power escalation. These tanks are located downstreem of the trate silica and sodium. condensate demineralizers and in 1977, it became necessary to return limit the silica Number 5 Feedwater Heater Drain to the condenser to This reduced the effi-and sodium concentration in the feedwater. ciency of the unit, therefore, a solenoid air control valve was added to allow Number 1 Moisture Separator Reheater Drain Tank to drain directly to the condenser. In November 1978, it was discovered that 19 tubes of Feedwater Ucater The failure was located within the drain cooler, 1-4-1 had failed. The cause of the failure approximately 8 feet from the tube sheet. was attributed to high velocity flow uhich resulted in excess vibra-The 19 failed tubes and 27 surrounding tubes were tion of the tubes. Insta11arion of 3 Further investigation is being performed. plugged, brackets between the tubes to reduce vibration has been planned for the During this outage, the tubes will also be in-January 1979 outage. spected for the results of a varied water level within the feedwater heater. 10-4
12.0 UNSCIIEDULED UNIT TRIPS During the power escalation phase of the testing program, a number of unscheduled reactor / turbine trips occurred. Infor-mation from these trips has been ured to improve plant perfor-mance by identifying tuning requirements in the Integrated Control System, and by demonstrating system deficiencies for which corrective actions have been initiated. The following paragraphs briefly describe the unscheduled trips 2 which occurred since initial criticality (August 12, 1977). This summary is intended to present the conditions surrounding each event, and not to present a detailed evaluation of each trip. 9/2/77 During the initial escalation to 15% power, feedwater flow was erratic. The main feed water pump controller was placed in automatic prematurely. The Steam and Feedwater Rupture Control System (SFRCS) tripped on differential pressure between steam and feedwater, leading to a reactor trip on low RCS pressure. The excessive blowdown of the main steam safety relief valves contributed to the reactor trip on low pressure. All the relief valves were reset by use of a hydroset on September 16, 1977. 9/24/77 With the turbine off line and the reactor at approxi-mately 8% power, a " half-trip" of the SFRCS caused the startup feedwater control valves to close. Reactor Coolant System (RCS) pressure increased and lifted the power relief valve on the pressurizer. After several cycles, this valve stuck open, blowing the rupture disc on the quench tank and causing a partial depressurization of the RCS. The power relief block valve was closed, and the plant was shut down for repairs. 10/23/77 An undetected half-trip of the SFRCS closed the startup feedwater control valve to steam generator 1-2. The steam generator water level decreased to 17 inches, giving a full trip of SFRCS and initiating auxiliary feedwater. The reactor tripped on low RCL pressure as a result of the addition of 70 F auxiliary feedwater to the steam generators, and due to lifting of the pres-surizer power relief valve. 11/29/77 The unit was operating at 40% with the Reactor Protec-tion System (RPS) overpower trips set at 50%. A faulty patch board was inserted into the startup test panel, producing a unit lo 4 demand signal equivalent to 50%. The plant responded to the increased demand, and the unit tripped on high flux when the reactor reached 50%. The automatic transfer of house loads from the auxiliary 12-1
transformer to the startup transformers was defeated, resulting in a plant loss of AC power. Auxiliary feed-water initiated natural circulation flow through the reactor, and the diesel generators assumed the essen-tial loads until off-site power was restored. 12/16/77 In the unit startup following the reactor trip test (TP 800.14) from 40% power, the turbine-generator was on-line and the reactor was at approximately 11% when the startup feedwater control valves began to oscillate. These valve position swings resulted in overfeeding of steam generator 1-1. The reactor tripped on low RCS pressure. Additional tuning of the ICS was performed to minimize these valve oscillations during startups. 12/30/77 Following nine consecutive days of steady-state power operations at 72% power, #1 main feed pump tripped on " indicated" high exhaust easing water level. An Inte-grated Control System (ICS) runback was initiated, but the pressurizer power relief valve lif ted resulting in a reactor trip on low RCS pressure. The response of the main feed pump speed controls was modified, using the data collected during this trip. 1/6/78 Two SFRCS trips occurred during startup operations. Both were caused by feedwater flow fluctuations which caused feedwater/ steam outlet pressure differential to exceed the limit. Following the second trip, Auxi-l liary Feedwater Pump 1-1 was declared inoperable because / the speed control circuitry malfunctioned. A circuit 1 modification was completed and tested to correct this problcm. 1/21/78 To check out the main feedpump speed control changes made as a result of the 12/30/77 trip, a #1 feed pump trip test from 70% power was conducted. For approximately one minute the runback went smoothly. Then the running pump tripped on high exhaust casing level. The reactor and turbine were tripped manually, and the plant was controlled with auxiliary feedwater during the cooldown to 532 F. 1/31/73 An SFRCS trip at 67% power resulted in a high pressure RPS trip of the reactor. The SFRCS trip was caused by a spurious half trip in conjunction with an intentional half-trip of the system while performing the monthly surveillance test. The monthly surveillance test has been modified to reduce the likelihood of a recurrence of this problem. I f 12-2
~ A failed RCS flow transmitter had placed RPS Channel 3 2/24/78 into a tripped condition. An erroneous RCS high tempera-ture signal to Channel 2 of the RPS tripped the unit off-line. Both problems were investigated and corrected prior to resuming power operations. 3/1/78 The reactor was at 49% power. The level control valve to deaerator 1-2 failed closed. The main feed pump ran out of feedwater which initiated an SFRCS trip on feed-water / steam pressure differential. The loss of feed-water and closing of the main steam isolation valves increased RCS pressure which tripped the reactor on RPS high pressure. Anabruptchangeinthesetpoi!ntoftheTavetemperature 3/29/78 controller by an operator placed the plant into a tran-Return of the controller to its original l sient condition. setpoint produced a direction error in the Control Rod temporartly transferring the Drive (CRD) Control System, CRD control station to " MANUAL", a condition in which The the CRDs would not respond to ICS signal demands. unstable plant condition coupled with the inability of the CRDs to respond to neutron error demands created a j mismatch between reactor power and feedwater,,resulting in overfeeding the steam generators and tripping the reactor on low RCS pressure. 4/2/78 A turbine trip test was performed at 75% power to evaluate piping modifications made on the extraction The feedwater flow exceeded steam lines to the deaerator. the feedwater demand during the runback, resulting in over-feeding the steam generators. This coupled with lifting of the pressurizer power relief valve caused a reactor trip on low RCS pressure. i While operating at 100% FP for the first time, B&W re-4/5/78 quested an immediate reduction in power and a change to 3 RC pump operation while a complete analysis of the The unit was reduced in LBPRA problem was conducted. Feedwater power to 65% and RCP 1-1 was manually tripped. demands were not properly ratioed and the feedwater valve 21 P crror signal in the ICS affected the main feedwater 2 the feedwater system pump speed to such a degree that reached an uncontrollabic oscillation, and the RPS Since that tripped the reactor on low RCS pressure. time, FCR 78-200 has been approved and implemented to de-tune the DP error signal during two MFP operations, I and adjustments have been made to properly ratio feed-l water after an RCP trip. l 12-3
4/29/78 While the shutdown for the screen outage was in progress, the unit experienced a reactor trip from approximately 20% FP. This was the first shutdown attempted with only three reactor coolant pumps in operation. As #2 steam generator approached " low-level limit", the operator used manual control of the main feed pump to maintain 45 psid across the main feedwater control valves. This resulted in overfeeding the steam generator, and although operator action was taken to stabilize the situation, a rapid coel-down took place, tripping the RPS on low RCS pressure, and initiating high pressure ir.jection for approximately 5 minutes. The Reactor Coolant System was returned to 2155 psig/5300F and a normal controlled cooldown to Mode 5 was performed. 8/2/78 In preparation for 40% reactor physics testing, the six second rod insertion step for differential rod worth measurement was attempted. The rod movement resulted mi a Reactor Coolant System upset. The positive temperature coefficient caused feedwater control of Tave to be un-stable. A divergent oscillation in feedwater lead to l overfeeding of the steam generators, and resulted in an RPS low pressure trip. 9/10/78 Conducted optional turbine trip test from 75% FP per TP 800.14. Excessive feedwater flow resulted in reactor 2 trip on low pressure. 9/28/78 While at 90% FP, the loop 2 RCS fiov transmitter FT RCIAl failed low. This low flow signal caused a trip of RPS Channel 1 and initiated an ICS runback at 20% per minute. The runback stopped at 700 MWe and resulted in feedwater to the steam generator ratioed as if the erroneously indicated flow condition actually existed. The operator took manual control of loop 2 main feedwater control valve, attempting to maintain level in #2 steam generator. This action resulted in feedwater flow greater than that required for the existing reactor power level, and decreased RCS pressure to below the 1985 psig RPS trip setpoint. The plant was placed in Hot Standby (Mode 3) and the RCS flow transmitter was repaired. 10/3/78 While operating at 73% FP, the second EHC pump was started to investigate the recent reduction in EHC header pres-A hydraulic perturbation was introduced, tripping sure. the turbine on low EHC pressure. The ICS initiated a reactor power runback at 20%/ minute. The increased steam generator pressure and the ICS " cross-limits" rapidly increased feedwater flow, overcooling the RCS and caus-ing an RPS reactor trip on low RCS pressure 84 seconds after the turbine trip. The analysis of this trip resulted in a recommended modification to the ICS cross-limits, reducing the amount of feedwater added following any turbine trip. 12-4
10/29/78 With reactor power at 4% of full power while lowering RCS temperature for the Natural Circulation Test, TP 800.04, tha reactor operator was controlling Main Feed Pump Turbine (MFPT) 1-2 speed in manual. The MEPT l-2 motor speed changer hung up at the high speed stop resulting in a high differential pressure across the control valve. As the operator kept trying to reduce the dif ferential pressure, the speed changer was freed and ran MFPT 1-2 back resulting fn a low differential pressure and a Steam and Feedwater a.pture Control System (SFRCS) full trip at 10:43:G6 hours. The resulting sequence of events resulted in a reactor trip from low reactor coolant pressure (1985 psig) on Channels 1 and 3 of the Reactor Protection System (RPS). The cause of thic trip is due to both the unusual plant 3 conditions while performing the Natural Circulation Test and the MFPT speed changer difficulties. The speed changer was repaired. It is also believed the pressurizer electro-matic relief valve or pressurizer spray valve may not have reset at the proper RCS pressure. The incident is still under investigation. 11/13/78 The reactor was at 99% power. The main power supply fuse to Relay Cabinet RC-3718 blew. This resulted in the loss of the 125 VDC power to auxiliary relays of the RCP control circuits for Reactor Ccolant Pumps 1-2 and 2-1. Reactor Coolant Pump 2-1 main breaker tripped eight seconds before Reactor Coolant Pump 1-2. This resulted in an RPS flux-delta flux-flow reactor trip. During the investigation, it was noted that the fuse had been improperly wired resulting in the loss of two Reactor Coolant Pumps for a single fault. This electrical deficiency has been corrected. e 12-5}}