ML19260A203
| ML19260A203 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 10/05/1979 |
| From: | TOLEDO EDISON CO. |
| To: | |
| Shared Package | |
| ML19260A201 | List: |
| References | |
| NUDOCS 7911080167 | |
| Download: ML19260A203 (42) | |
Text
{{#Wiki_filter:, Instructions for inserting Supplement 6 revision to che Davis-Besse Unit 1 Initial Startup Report. REMOVE INSERT Supplement 5 Title Page Supplement 6 Title Page Pages 1, ii,'iii Pages i, ii, iii Pages 1-1 through 1-23 Pages 1-1 through 1-24 Page 2-1 Page 2-1 Page 2-3 Page 2-3 Page 4-9 Page 4-9 Page 8-1 Page 8-1 Page 8-2 Page 8-2 Page 9-1 Page 9-1 Page 9-3 Page 9-3 Pages 10-1 through 10-5 Pages 10-1 through 10-5 . Page 12-6 Page 12-6 O e e 7911080 lh
DAVIS-BESSE NUCLEAR POWER STATION UNIT ONE INITIAL STARTUP REPORT COVERING APRIL 23, 1977 THROUGH A"RIL 5, 1978 SUPPLDIENT 1 COVERINO APRIL 5,1978 THROUGH JULY 5,1978 SUPPLEMENT 2 COVERING JULY 5,1978 THROUGH OCTOBER 5,1978 SUPPLLMENT 3 COVERING OCTOBER 6,1978 THROUGH JANUARY 5,1979 SUPPLEMENT 4 COVERING JANUARY 6,1979 THROUGH APRIL 5,1979 SUPPLDIENT 5 COVERING APRIL 6,1979 THROUGH JLU 5,1979 S'JPPLDfENT 6 COVERING JULY 6,1979 THROUGH OCTOBER 5,1979 n r- neoo 1295 184
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TABLE OF CONTENTS Page Section
1.0 INTRODUCTION
1-1 2.0
SUMMARY
2-1 3.0 INITIAL FUEL LOADING 3-1 4.0 POST FUEL LOAD PRECRITICAL HOT FUNCTIONAL TESTING 4-1 4.1 Reactor Coolant System Flow Measurement 4-1 4.2 Reactor Coolant System Flow Coastdown Measurement 4-2 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 5.0 INITIAL CRITICALITY 5-1 5.1 Preliminary Approach to Criticality 5-1 S.2 Final Approach to Criticality 5-1 6.0 CORE PERFOPJ1ANCE 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 Baron Concentration 6-2 6.5 Temperature Coefficient of Reactivity Measurements 6-3 6.6 Control Rod Reactivity Wor th Measurements 6-3 6.7 Ejected Rod Worth Measurements 6-4 6.8 Stuck Rod Worth and Shutdown Margin Measurements 6-4 6.9 Soluble Poison Worth Measurements 6-6 1 1295 185
Page . . Section 7.0 CORE PERFORENCE DURING ?OWER ESCALATION SEQUENCE TESTS 7-1 7.1 Nuclear Instrunentation Calibration at Pcwer 7-1 7.2 Reactivity Coefficients at Power 7-3 7.3 Rod Worth at Power 7-6 7.4 Core Power Distribution Tests 7-6 7.5 Pseudo Control Rod Ejc; tion Test 7-6 7.6
~
Dropped Control Rod Test 7-7 7.7 Incore Detector Test 7-8 7.8 Power Imbalance Detector Correlation Test 7-9 8.0 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PERFORMANCE 8-1 8.1 Unit Load Staady State. Test 8-1 8.2 NSSS Heat Balance Test 8-1 8.3 Integrat<,d Control System Tuning at Power 8-2 9.0 UNIT PERFJRMANCE DURING TRANSIENT AND ABNORMAL
- CONDITIONS 9-1 9.1 Turbine / Reactor Trip Test 9-1 9.2 Unit Load Transient Test 9-2 9.3 Unit Power Shutdown Test 9-3 9.4 Unit Load Rejection Test 9-3 9.5 Natural Circulation Test 9-4 9.6 Loss of Offsite Power Test 9-4 9.7 Shutdown From Outside the Control Room 9-5 10.0 SECONDARY PLANT PERF0PMANCE AND STARTUP. EXPERIENCE 10-1 10.1 Turbine / Generator 10-1 10.2 Condenser 10-2 10.3 Circulating Water System 10-3 10.4 Feedwater Systems 10 4 11.0 UNIT MONITORING - CHEMISTRY AND HEALTH PHYSICS 11-1 11.1 Shield Survey 11-2 1295 186 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 1295 187
INTRODUCTION l.0 Davis-Besse 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. I The turbine-generator is capable of a net electrical output of 906 The Nuclear Steam Supply System (NSSS) employs once through MWe. steam generators. The Facility Operating License (NPF-3) for DBNPS Unit 1 was issued to the Toledo Edison Conpany 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, 197/, after a total fuel load time of 83 hours. Initial criticality was achieved on August 12, 1977, after a Post Fuel Load Precritical Hot Functional Test Program.
'2ero power physics testing commenced af ter achieving initial criti-t 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 pressura 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 fcur 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 1.0-12 show the chronological power history during the startup test program. Figures 1.1-1 through 1.1-8 show the chronolo-gical core burnup during the startup test program. The initial transmittal on May 8',1978, of the Startup Report contained test data which su=marized the startup test program and unit performance from initial fuel leading on April 23, 1977, through 100% full power opera-tion on April 5, 1578. 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 attained 4' commercial power operation on November 22, 1977. Davis-Besse Unit 1 was shutdown for a maintenance outage and, therefore, no further testing was completed in the period from April 5,1978 through July 5,1978. 1-1 1295 188
t a 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 the test results c? <.esting completed between October 6,1978 through January 5,1979. The fourth supplement updated the Startup Report to contain test results of testing completed between January 6,1979 through April 5,1979. Since the unit was shutdowt. from March 31, 1979 to July 11, 1979, no further testing was completed. Therefore, only Chapter 1 was revised by Supplement 5 which covers from April 6,1979 to July 5,1979. The sixth supplement updated the S tartup Report to contain the test results of 6 testing completed between July 6,1979 through October 5,1979. As this com-pletes all testing, this is the final supplement. The changes made to the Startu- Report by supolements are indicated hv a vertical line in the lef t margin with a number to indicate by which supple-ment the revision was incorporated. 9 1-2
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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 nor unusual for the startup program of a unit this size. A significant problem at a similar reactor did arise during power escalation that could affect Davis-Besse Unit 1. Two burnable poison rod assemblies (BPRA) were found outside of their fuel assem-blies 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 recommended, as a precautionary measure, the reactor coolant flow be reduced. Reactor Coolant Pump 1-1 was shutdown on April 5, 1978. 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 removed from the core by May 27, 1978 during the maintenance outage 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 erperienced only minor delays and was 6 accomplished in approximately three and one half (3 ) 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 (e) Reactor Coolant System Hot Leakage Test, TP 600.10 (ST 5042.02) 2-1 1295 212
2.6 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PERFORMANCE (SECTION 8.0) A list of the tests performed daring power operation related to the monitoring of the NSSS perforcing is presented below. In all, the ' performance of the NSSS was satisfactory, and as expected. (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 2.7 UNIT PERFORMANCE DURING TRANSIENT AND ABNORMAL CONDITIONS (SECTION 9) 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. In all, unit response to the following load transients and abnormal conditions was satisfac-6 tory. ('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 (g) RCS Natural Circulation Test, TP 800.04, 2.8 SECONDARY PLANT PERFORMANCE (SECTION 10) This section provides a brief su= mary of the major difficulties 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 chenistry during various phases of the startup test program. Tests were conducted during 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, TP 500.02 (e) Initial Radiochemistry Test, TP 500.03 6 (f) Process and Area Radiation Monitoring Systec Pre-op Test, TP 360.01 2-3 1295 213
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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 data and to verif y the NSSS performs as designed. Four tests are used to complete this purpose. 6 Dele ted 8.1 UNIT LOAD STEADY STATE TEST, TP 0800.12 Primary and Secondary System steady state parameters ware 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 relatior. ship between Tave and reactor power. This icformation was used to adjust the OTSG low level setpoint to bring. Tave within 582 + 10F 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 wer* compared to the computer calculated heat balances. In all cases, the hand calculated and computer calculated values agreed to within the required !2% 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 loope has been calculated by setting th.e primary heat balance equal to the secondary heat balance. A retest was performed to verify the deviation is less than 1%. 8-1
. 1295 2\S
8.3 INTEGRATED CO'iTROL SYSTEM TICIING AT POWER, TP 0800.08 , This procedure was performed to verify that optimum plant performance and Actual control is obtained by tuning of the integrated control system. plant transients from TP 800.23, Unit Load Transient Test, were used to 6 evaluate MSS behavior. This transient data was carefully reviewed and tuning adjustments were made to opttnize plant performance. 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. 1CS 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. 8-2 1295 216
9.0 UNIT PERFOR".ANCE DURING TRANSIENT 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 conditions. A reactor trip test was completed at the 40% of full power level. A turbine trip from 75% of full power was also completed. A unit load rejection test from 75% of full power was performed. A unit load rejection test was conducted at an initial power level of 100% of full rated power. The plant was shutdown from the Auxiliary Shutdown Panel from an initial power level of 15% of full rated power. A loss of off site power test, including a loss of external loud, was conducted from an initial power level of 15% of f ill power. Load transient tests included 10% full power transients at 40% and 75% of 6 full power. The 50% full power transients at 90% of full power were also completed. Proper operation of the integrated contrcl system cross limits and rate limits were also verified. A natural circulation test was performed with the reace;c at 3.8 - 3.9% of full power and all Reactor Coolant Pumps tripped. A unit power shutdown test was performed on October 18, 1977, from an
- initial 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 trip was initiated manually, and the Reactor Trip Emergency Procedure, EP 1202.04, was implemented. 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 steam safeties 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, adjusenents were made to the ICS. The load rejection tests at 75% and 100% of. full 7ower verified proper operation (see Section 9.4). 9- 12c)5 217
A list af unit load transient testing is. given in Table 9.2.1. A reacti-meter and brush recorders were used to record the applicable data. The collected data verified that the unit can be maneuvered at 5% FP per minute in the integrated 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 high power positive rate Itnit was verifiea by imposing a 5% FP per minute load transient at 85% of full power in the inte-TP 800.23 grated control mode. 6 Load transients of 50% FP were conducted at 5% FP per minute from 92% to 42% to 90% of full power and at 3% FP per minute TP 800.23 from 90% to 92% of full power, in the integrated control mode. Load transients of 30% FP were conducted at 5% FP per minute from 60% to 30% to 60% of FP in the integrated mode during three pump TP 800.23 operation. 9.3 UNIT POWER SHUTDOWN TEST TP 800.15 The unit power shutdown test was performed to verify the adequacy of the " Plant Shutdown and Cooldown Procedure, PP 1102.3,, from 15% power to 0% power, and to obtain baseline data f or subsequeat shutdowns. The shutdown was performed from an initial power level of 15% of full rated power. The cooldown was conducted to a final reactor. coolant sys-tes temperature of 531 F and the reactimeter data was obtained by the Plant Computer's Operator Special Summary Group. The results of the unit power shutdown test, summarized in Table 9.3.1, verified that a Turbine-Reactor Shutdown can be performed (Section 4 of Plant Shutdown and Cooldown Proce-dure, PP 1102.10) without exceeding the itsits of the Nuclear Steam Supply Limits and Precautions, PP 1101.01, Section 1. Thus, the acceptance cri-teria was satisfied. 9.4 UNIT LOAD REJECTION TEST TP 800.13 The purpose of the Unit Load Rejection Test is to demonstrate the unit can be satisfactorily controlled when a loss of load occurs and to assure no Technical Specification safety limits are exceeded during or following the load rejection. On November 11, 1978, the Unit Load Rejection Test was performed with the unit at 75% of full power. At 0009 hours, the test was initiated by open-ing the main generator outlet breakers. The Integrated Control System oper-ated properly to initiate a runback to approximately 15% of full power, re-ducing both reactor power and feedwater flow. Both the main steam safety valves and the turbine bypass valves maintained main steam line pressure within limits, and the turbine speed returned to 1800 RPM. 9-3 1295 218
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 movement. 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-ties and the solenoid valve was replaced. The inboard bearing on the turbine main oil pusp was replaced and orifice plugs installed in the bearing oil supply lines of the front standard. During the January 1979 outage, an oil leak on turbine bearing number 8 was repaired by machining of the bearing cover sealin., surfaces. An vendor representa-inspection of the generator high voltage bushings b-tive revealed the need for replacement of a bushic' This is to be done during the first.. refueling outage. . ._,. __.. __ On February 22, 1979, electrical f aults in the turbine electro-hydraulic control (EHC) system caused a runback (see Section 12. " Unscheduled Unit Trips"). The electric faults were investigated by General Electric per-sonne"1 and several printed circuit cards were replaced. Further investi-6 gation by ' General Electric discovered defective capacitors in the circuit cards. 10-1 1295 219 .m- -~m~ .. , a- me e
The unit experienced dif ficulties with the turbine throttle pressure limiter circuit supplied by General Electric. The purpose of this circuit is to provide backup header pressure control in the event of
- r. failure of the normal mode of control. However, on August 22, 1979, c unit runback was initiated by a partial failure of the throttle pcessure. li=1. er power supply which overrode the normal ICS signal ,
and partially closed the turbine control valves. A complete f ailure of the power supply occurred on September 27, 1979 which resulted in a unit trip. 6 Toledo Edison is presently in the process of replacing all four of the originally supplied pressure transmitters and the power supplies with transmitters and power supplies from General Electric but manu-factured by a different vendor. The electro-hydraulic control (EHC) system has also caused unit trips on October 3, 1978 and September 18, 1979. On these occasions, the starting of a second EHC pump caused an instantaneous perturbation in pressure resulting in turbine trips on low EHC pressure due to sticking pump pressure controllers. Several design modifications are planned to reduce the sensitivity of the system. 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.
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. 1o_2 )
With the unit at 100% of full power on September 6,1978, an increase in condensate conductivity was again discovered. When che 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 failures and inctalled some extra supports wi.hin the condenser while the unit was shutdown for repairs of Reactor Coolant Pump seals during October,1978. In December 1978, abnor= ally 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 fairing door had been blown off and had dented eight tubes which were then plugged. Re-welding was required on some impingement baffles and a seas 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 completed during the outage. It is believed the failure of the expansion joints was due to bo$h 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. Addittpnal 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 recur ,ence of the f ailure of the expansion joints. During a planned unit maintenance outage in January,1979, two 18" extraction steam line expansion joints were replaced as per Z olaire's recommendation. One of these expansion joints was replaced in December 1978. Ecolaire's evaluation of the previous failures indicated a design problem with the joints, and as a result, the two new joints were installed. During the January 1979 outage, a total of 49 tubes in both the high and low pressure condensers were plugged. It is believed that most of the failures were caused by steam impingement; a sample of a broken tube is to be analyzed to determine the exact mode of failure. Only one additional tube was plugged in April,1979. Over three months 6 of almost entirely full power operacion has not caused additional failures. 10.3 CIRCULATING WATER SYSTEM The Circulating Water System has experienced problems with f ailures of the liners of the 54 inch discharge valves. In August, 1977, the Number 2 Circulating Water Pump Discharge Valve was rebuilt and the rotation reversed to reduce the amount of turbulence. 1295 221 10-3
Durlng the plant outage in September, fragments of a valve liner were found in the condenser water box. Subsequent investigations showed that the Number 3 Circulating Water Pump Discharge Valve was damaged. The valve liner was replaced and the rotation reversed on Number 3 Circulating Water Pump Discharge Valve. The enount of time these butterfly valves are throttled is now being limited to minimize the damage from the turbulence, f 6 All four of the discharge valves are to be replaced at the refueling outage. The Cooling Tower experienced some icing difficulties. In December, 1977, several internal fill support concrete beams were broken and others damaged by ice buildup. Ice falling inside the veil also 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 were repJ sced during the outage to remove the BPRA's. During the.1976-79 winter, approximately 14 horizontal and diagonal fill columns and several deicing pipe end caps were damaged in varying amounts due to normal _ ice. buildup. The fill colu=ns do not perform any support fun tion and were removed if heavily damaged. The deieing pipe end caps will be replaced. Although the damage to the cooling tower was not severe, the vendor, Research-Cottrell is investigating the possibility of modifying the deicing system to further eliminate icing difficulties. 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, 1977 because of high vibration and flow rate difficulties. The pump 6l was disassembled and a piece of the pump Lnpeller was found to be broken off. The entire impeller was replaced with the spare and the sharp radius corners between the Lneplier vanes and sideplates were ground out to remove a potential high stress area on the impeller. T'r impeller of Main Feed Pump 1-1 was also inspected and ground. Both feedpumps were returned to service and further impeller diffi-culties 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. 1295 222-10-4 .-- - - - . ~ . . . _
During January 1979, both Booster Feedwater Pumps "tre disassembled to replace the casing seal gaskets with a new type F <sket to reduce casing leaks. At this time, new seals were installed e s Main Feedwater Pump
? -l to reduce excessive seal leakage.
The auxiliary feed pumps have had extensive difficulties in speed .on-trol. In July and August 1977, repeated speed control relay failures rendered the auxiliary feed pumps inoperable. On August 10, 1977, a design modificat*on was implemented which accea a second set of identiaal speed relays in parallel to reduce the current carried by each relay. This did not totally eliminate the speed control failt as and in January 1978, the relays of the speed circuit were replaced with relays of a larger current carrying capacity. Other design deficiencies were discovered in October when it was observed the Auxiliary Feed Pump 1-2 Turbine Governor Valve would close under cer-tain vibrational condicions, rendering the
- txiliary Feed Pump 1-2 inopera-ble. A redesigned valve linkage was insts..ed in which the force of a spring assured elisination of the vibrational closure.
Feedwater chemistry control has encountered several problems during power escalation. The moisture separator reheater drain tanks concentrate silica And sodium. These tanks are located downstream of the condensate dcmineralizers and in 1977, it became necessary to return Number 5 Feedwater Heater Drain to the condenser to IL .it the silica and sodium concentration in the feedwater. This reduced the efficiency of the unit,
- therefore, a solenoid air control valve was added to allow Number 1 Mois-ture Separator Reheatet Drain Tank to drain directly to the condenser.
In November 1978, it was discovered that 19 tubes of Feedwater Heater 1-4-1 had failed. The failure was locateo within the drain cooler, approximately 8 f eet from the tube sheet. The cause of the failure was attributed to high velocity flow which resulted in excess vibration of the tubes. The 19 failed tubes and 27 surrounding tubes were plugged. Investigation of the tube failures resulted in the vendor recensending the modification of the feedwater heater drain cooler inlet and the in-stallation of anti-vibration strips between the tubes. These modifications were made to Feedwater Heaters 1-4 and 2-4 during Februrry and March 1979. Inspection of the tubes at that time revealed that water level control difficulty was not the source of the problem, but that the drain cooler inlet was improperly designed causing excessive water velocities and tube damage. 1295 223 10-5
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I e
- 2/13/7) T,he reactor was at 88% of full power when a loss of power to startup transformer 02 occurred due to Ohio Edison testing of Beaver Substation. This transformer was being fed from offsite and was supplying power to the 13.8 IV "B" Bus which in turn powers two of the Reactor Cc:lant Pumps (RCPs). The loss of power tripped the RCPs re sulting in a reactor trip.
The unit is temporarily operating with housepower loads supplied by the startup transformers in order to comply with FSAR commitments. This deficiency will be corrected at the first refueling outage. Ohio Edison has also been informed of the necessity of notifying Toledo Edison prior to the conduct of any relay testing of the sort which initiated this event. 2/22/79 With reactor power at 87% of full power, a malfunction in the turbine backup speed control circuit of the Electro-Hydraulic Control (EHC) System caused inappropriate move-ments of the turbine control and corbined intermediate valves. The resulting low main steam pressure initiated a full SFRCS trip as designed. The low feedwater flow caused Reactor Coolant System pressure to increase and - the Control Room personnel manually tripped the reactor. The faulty turbine backup speed control circuit has been
~
replaced. 9/18/79 The reactor was at approximately 99% of full power when an
- instantaneous perturbation in electro-hydraulic systen (EHC) pressure caused a turbine trip and an Anticipatory Reactor Trip System (ARTS) trip of the reactor. The EHC pressure transient was due to a sticking pump pressure controller.
General Electric has recommended several design changes to 6 reduce the sensitivity of the trip pressure switch. 9/26/79 The reactor was at approximately 100% of full power when a fsiled throttle pressure limiter power supply caused a clos-ing of the turbine control valves. The reactor tripped on high pressure followed by a turbine trip. Toledo Edison will replace all the identical pressure transmitters and their power supplies with an instrument supplied by General Electric but manufactured by a different vendor.
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. 1295 224
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