ML20148C764
| ML20148C764 | |
| Person / Time | |
|---|---|
| Site: | Rancho Seco |
| Issue date: | 02/24/1988 |
| From: | SACRAMENTO MUNICIPAL UTILITY DISTRICT |
| To: | |
| Shared Package | |
| ML20148C760 | List: |
| References | |
| NUDOCS 8803230050 | |
| Download: ML20148C764 (34) | |
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m i g eng m RANCHO SECO Nuclear Gen er a tin g Station FUTURE PLANT C AP ACITY FACTOR ENGINEERING ASSESSMENT FEBRUARY 24, 1988 Rev.
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Table Of Contents TAB I Executive Summary TAB II Hethodology For Past Operating History Capacity Factor
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Assessment TAB III Tabulation of Past Major Forced Outages 1
TAB IV Hajor Event Descriptions TAB V P'ojected Capacity Factor Calculation TAB VI Future Plant Improvements 1
TAB VII Fuel Cycle Improvements TAB VIII Industry Operating Experience
l EXECU TIVE
SUMMARY
I.
EXECUTIVE
SUMMARY
There has been much speculation on what Rancho Seco's capacity factor will be on resumption of full power operation; however, little has been done to quantify capacity factor expectations.
The purpose of this report is to present an organized engineering assessment of the plant capacity factor improvement which should be realized from modifications already completed and to evaluate the potential for additional improvements from future modifications.
Tab II details the engineering methodology used to asse s the benefits of modifications which have been completed.
Briefly, the corrective actions were evaluated for their potential to reduce or eliminate the outage cause.
It was then presumed that the forced outage days which could have been eliminated would have been available for additional power operation and a new capacity factor calculated based on this additional operating time.
Tab III lists the major forced outages analyzed.
Tab IV provides details for each event analyzed and the rationale for the projected reduction in forced outage days.
Tab V presents the actual operating history data for the period studied (start of commercial operation to December 26, 1985) and the calculation of a new capacity factor.
This new capacity factor shows operatirg levels the plant could have achieved had the corrective actions been in place prior to the related forced outage.
It is also the capacity factor expected for future operation with no further improvements except fuel cycle considerations which are discussed under Table VII.
1
I.
EXECUTIVE
SUMMARY
(Continued)
The actual capacity factor up to December 26, 1985 was 47%.
Existing improvements should raise this to 67%.
Increasing the number of operating days for each fuel cycle improves the capacity factor an additional one percent to four percent.
Tab VI evaluates the potential for additional near term improvements to capacity factor from work now in the planning stage.
The conclusion is that, for long term operation, the future capacity factor should fall in the range of 71% to 82%.
The range is due to variables in implementation of the future modification program (cost-benefit) and permissible variables in fuel cycle design.
Note that this capacity factor range is expected for long term operation and as the plant progresses through heat up, hot functional testing and initial power ascension, some problems are anticipated.
Because of the extent of modifications, this is not unlike a new plant startup.
Early problems are not indicative of the basic plant integrity and its ability to achieve an excellent future performance record.
The foregoing projections are consistent with the capacity factors being achieved by new plants coming on line.
If the median of the range of projections for Rancho Seco operation (76%) is compared to the overall pressurized water reactor operating record, Rancho Seco would be in the top 20%.
Industry operating experience is discussed in Tab VIII.
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t METHODOLOGY FOR PAST OP ER ATIN G HISTOR Y C AP ACITY FACTOR ASSESSMENT
.M.
I
II.
METHODOLOGY FOR PAST OPERATING HISTORY CAPACITY FACTOR ASSESSHENT A review of Rancho Seco's past operating history focusing on the major causes of reduced capacity factor was performed.
The purpose of the review was to assess the corrective actions taken and quantify their benefits.
The benefits were quantified by determining the capacity factor which could have been achieved had the corrective action been in place prior to, instead of after, the related forced outage.
The period evaluated was April 17, 1975 (the start of commercial operation) to December 26, 1985.
Table 1 (TAB III) lists 19 separate events or grCJps of events that have contributed to 83% of the plant's forced outages or reduced power operation during this period.
The table lists a projected percentage reduction in forced outage days for a
each item and a theoretical total of the forced outage days reflecting the reductions.
TAB IV of the report provides a brief description of each event listed in Table 1.
The description addresses the problem, the corrective action and the rationale for the projected reduction in forced outage days.
Finally, there is a summary calculation (TAB V) used to determine the revised capacity factor to show the benefit which could have been derived from improvements already made.
1
TAB U LATI ON OF PAST MAJOR FORCED OUTAGES Y
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TABLE 1 TABULATION OF PAST M AJOR FORCED OUTAGES BASED ON AN ENGINEERING EVALU ATION OF A 10.7 YEAR OPERATING PERIOD THE "PROJECTED FORCED OUTAGE DAYS PER 10.7 YEARS" REFLECT BOTH THE PROBABILITY OF OCCURANCE AND EXPECTED OUTAGE DURATION.
(A 5 day outage in the table could be a single 10 day outcqe expected to occur once in 20 years of oper. tion) 1 Reduction Projected Actual forced Corrective In Forced Forced Outage Outage Cause Outage Days Action
__Qutage Days Days Der 10.7 Years 1)
Westinghouse turbine 297 Short term - turbine 98 8
failures modi fied.
Long term - replace with BBC turbine.
2)
Main Generator /
229 Seal oil system 50 115 Hydrogen Seal Oil modified, procedures upgraded.
3)
OTSG Tube leaks 188 Install tube sleeves 95 9
a
.s, TABLE 1 (Continued)
TABULATION OF PAST MAJOR FORCED OUTAGES
- 7. Reduction Projected Actual Forced Corrective In Forced Forced Outage Outage Cause Outage Days Action Outage Days Days Der 10.7 Years 4)
NSS generic i:aterial 137 Replaced Aux. Feedwater 70 41 failures header 5)
Reactor Coolant System 101 1007. pipe support design 100 0
vent line crack evaluation and walkdown 6)
Power reduction due to 77 Purchased spare 75 19 main transformer failure transformer 7)
THI modifications 63 NRC approved living 100 0
schedule process 8)
Loss of Condenser 39 1007 plant system 100 0
Vacuum walkdown/ procedure upgrade 9)
Turbine Thrust Bearing 20 Bearing modified 50 10 Failure 10)
Integrated Control 13 Hultiple modifications, 80 3
System (ICS)
Class 1 Power supply problems and EFIC 11)
Pipe support modifi-9 1007. design 100 0
cations re-evaluation 12)
Revised 80 2
tube leaks operating criteria l
13)
Generator lead box 9
Modified lead box 100 0
A TAotE 1 (Continued)
TABULATION OF PAST HAJOR FORCED OUTAGES
% Reduction Projected Actual Forced Corrective In Forced Forced Outage OutagfLCause Outaae Days Action Outage Days Days ner 10.7 Years 14)
Loss of Non 7
Installed multiple 80 1
Nuclear Instrumentation fuses and EFIC 15)
Hain Feedwater pump 6
Hultiple modif1 cations 60 2
controls
-16)
Turbine control oil 6
Hodifications 100 0
17)
Inverter failures 6
Replaced inverters and 90 1
modified power distribution 18)
Loss of Instrument air 4
Installed backup 100 0
emergency compressor 19)
Pipe wall thinning 3
Predictive 80 1
maintenance inspections TOTALS 1222 212 l
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r 3
MAJOR EVENT D ESCRIP TI ON S V
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4 IV.
MAJOR EVENT DESCRIPTIONS
- 1) HESTINGHOUSE TURBINE FAILURES Turbine failures can be grouped into three general areas:
t shroud / blade failures, blade attachment failures and disc failures.
Improvements have been made in each of these areas as follows:
Shroud / Blade Failures - Numerous blade failures a.e attributed to the attachment of the shroud to the blades and the effect the shroud configuration has on a blade group's resonant frequency. A design change was implemented in 1983 to improve performance in this area.
This same change has been implemented on all other similar rotors.
Since implementation of the design change there have been no failures of any Hestinghouse units causing forced outages (four years operating experience for all Westinghouse Nuclear Turbines).
It should be noted that inspections on other modified units conducted since the modification have revealed the presence of cracking.
In all cases, the crack growth rate is time dependent and normal inspection intervals result in crack detection before failure.
Blade Attachment Failures - Blade attachment failures are attributed primarily to stress corrosion cracking.
Hestinghouse operating experience shows that maintaining condenser air in leakage (vacuum leaks) below 10 CFM produces a marked improvement.
In addition, one of the currently installed rotors has a strengthened root design to improve performance !:. this area.
1 l
IV.
HAJOR EVENT DESCRIPTIONS (Continued)
Disc Failures - The original rotors installed at Rancho Seco failed due to massive disc cracking and were replaced by rotors with a "heavy" disc design.
These rotors proved to be vulnerable to a keyway cracking problem that is now well understood. One rotor has been replaced with a key plate design which eliminates the problem.
The other has been inspected and found free of keyway cracks.
The keyway cracking phenomenon is known to be a slow acting mechanism and the probability of a forced outage during the next cycle due to keyway cracking is very low.
Westinghouse Availability Improvement Bulletin No. 20 also shows the keyway cracking problem has been eliminated on units where condenser air in leakage has been kept below 10 CFM.
Rancho Seco now meets this standard, j
The preceding changes were made to address the major areas of concern; however, their ability to eliminate future failures in long term operation is doubtful.
The various failure mechanisms inherent in the existing Westinghouse design are now well understood and known to be time dependent.
This knowledge, corpled with the known condition of the rotors gained through inspections, provides a relatively high level of assurance that they will operate without major failure during the comparatively short time remaining until their replacement by the Brown Boveri Turbines.
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IV. MAJOR EVENT DESCRIPTIONS (Continued)
An in-depth analysis of turbine reliability was conducted as a part of the District's decision making process regarding turbine replacement.
In this analysis, the BBC machines to be installed during the next refueling outage are projected to have 0.074 rotor failures and 0.609 blade failures in 25 years, resulting in 19 forced outage days.
For comparison purposes, the BBC turbine forced outage days for the 10.7 year interval evaluated in this report would be eight days.
This forced outage rate is also assumed for the remaining service time of the Westinghouse turbines.
2)
MAIN GENERATOR / HYDROGEN SEAL OIL Two major outages for repairs to the main generator can be traced to operational problems with the hydrogen seal oil system.
Modifications to this system have been made to improve its operational reliability.
In addition, its function is now more clearly understood. Operating procedures have been written to provide clear guidance on the operating sequences which must be l
followed to prevent recurrence of past system problems.
The system remains a sensitise system requiring a high level of operator skill for proper performance.
The improvements address the known weaknesses, but since they have only been in service for approximately a half fuel cycle, future forced outage rate is projected to be reduced by only 50%.
3
IV. MAJOR EVENT DESCRIPTIONS (Continued) 3)
OTSG TUBE LEAK OUTAGES Rancho Seco has experienced six forced outages due to OTSG tube leaks.
There have been a total of 43 forced outages in all B&W Reactors due to OTSG tube leaks. All but one of these leaks occurred in a localized area which we have now reinforced with sleeves to provide double wall protection or are from causes which cannot occur at Rancho Seco.
In this localized area there is a low probability of future leaks with associated forced outages; however, a 95% reduction is assumed.
In all B&H plants there has been only one leak outside this area in 57 effective full power years (EFPYs) of operation. Assuming a 30-day outage, this equates to a 0.1% availability reduction which, in this analysis, is not significant.
Therefore, the total reduction in the forced outage rate is 95% of past performance.
4)
NSS GENERIC MATERIAL FAILURES In 1982, a generic problem with the B&H OTSG auxiliary feedwater header design was identified which required immediate corrective action.
The probability of continued existence of these types of original design problems (or latent defects) decreases as additional operating time on all B&H NSSs is accumulated.
With a total of 57 EFPYs on all B&H systems, the projected future outage rate may be reduced by 70% of past experience, and a future reevaluation could reduce this number further.
(Rancho Seco has now accumulated five EFPYs.)
4
IV. HAJOR EVENT DESCRIPTIONS (Continued) 5)
REACTOR COOLANT SYSTEM VENT LINE CRACK The Reactor Coolant System vent line crack was the direct result of improper installation of pipe supports.
Due to this leak, a total walkdown of all safety significant pipe supports was performed.
This problem will no longer be a contributor to future outages.
In addition, these systems have been reevaluated against today's design standards and upgrades made to further improve system integrity.
6)
POWER REDUCTION DUE TO MAIN TRANSTORMER FAILURE A major transformer failure resulteo in operation at 72% capacity for 210 days (59 equivalent full power days) while repairs were being made. A spare transformer was purchased and is uvailable for immediate installation. An extended run at reduced power due to a main transformer failure would no longer be required. A reduction of only 75% is taken to account for the outage days necessary for this or other smaller transformer removal and installation time (19 days).
7)
THI H0DIFICATIONS A 63 day outage was required to incorporate modifications mandated by the NRC as a result of the THI accident.
Since that time, the NRC has accepted the living schedule concept.
It allows the utility industry to schedule mandated work in a manner that reduces the disruption to plant operations.
Because of this concept, it is not expected that there will be broadly imposed forced outages due to industry events.
5
IV. MAJOR EVENT DESCRIPTIONS (Continued) 8)
LOSS OF CONDENSER VACUUM The loss of condenser vacuum was caused by the mis-positioning of a valve in the system which was not shown on Control Room drawings or in the Operating Procedures.
In response to this, all plant systems have been carefully walked down. All control devices have been identified and incorporated into plant drawings and Operating Procedures. Another event of this type is not expected.
9)
TURBINE THRUST BEARING FAILURE The turbine thrust bearing failure was attributed to a weakness in design of a component within the thrust bearing assembly.
This component has been redesigned.
This type of failure is no longer considered possible; however, turbine bearing failures can occur for many reasons.
The forced outage reduction is therefore assumed to be only 507. of past experience.
- 10) INTEGRATED CONTROL SYSTEM (ICS) PROBLEMS Loss of power to the ICS and operational stability of this system have contributed to a significant number of transients and reductions in operaticg power level.
During the current outage, modifications have been made to remove the major causes of ICS instability.
In addition, major strides have been made on tuning the ICS to improve its performance.
The ICS is now supplied power from a safety-related power supply with on line backup rather than a single non-safety-related power supply with no backup.
This design change will significantly improve ICS performance.
6
IV.
HAJOR EVENT DESCRIPTIONS (Continued)
The ICS is still subject to component failure which can lead to transients and trips.
In the past, these trips have led to severe transients due to rapid cooldown from loss of control of normal and auxiliary feedwater.
Hith the installation of the Class 1 Emergency Feedwater Initiation Control (EFIC) system, these types of severe cooldown transients are no longer possible.
It is expected that any future plant trips due to ICS component failure or performance problems will be minor in nature and a rapid recovery will be possible.
No extended forced outages due to this cause are expected.
- 11) PIPE SUPPORT H0DIFICATIONS NRC IE Bulletin 79-02 required extensive review and redesign of pipe support attachments to concrete.
During this review, plant outages were required until corrective actions were complete when a pipe support was identified as sub-standard. All pipe supports have now been upgraded to meet today's design standards and the cause of these outages eliminated.
- 12) EEfpHATER HEATER TUBE LEAKS One major outage resulted from high pressure feedwater heater tube leaks.
The leaks were the direct result of an internal baffle failure brought about by incoming steam flow exceeding the maximum design allowable.
These excessive steam flows were permitted due to an improper interpretation of Westinghouse operating limit recommendations.
The operating limits for the various system operating configurations have been reviewed with Westinghouse and are now in agreement with design requirements and are clearly documented in Operating Procedures.
The cause of this failure has been eliminated.
However, feedwater heater tube leaks will continue to occur and will result in some reduced power operation
}
or outages; therefore a reduction of 807. is projected.
7
1 IV. MAJOR EVENT DESCRIPTIONS (Continued)
- 13) GENERATOR LEAD BOX The initial plant design provided inadequate grounding of the main generator lead box.
This lack of grounding ultimately led to a 4
major fault.
A modification was performed which will preclude a repeat of this event.
- 14) LOSS OF NON NUCLEAR INSTRUMENTATION (NNI)
A severe cooldown transient known as the "light bulb incident" resulted from 6 loss of Control Room indication and control functions. A simple ground fault at a light bulb socket resulted in loss of the complete NNI system.
A design change provided installation of multiple levels of fusing so faults will no longer result in loss of the complete system.
Also, with the r
installation of the EFIC System, this type of system loss would a
now be a routine trip with rapid recovery.
Since the NNI System is still vulnerable to single component failure which can produce trips, ii 3 forced outage reduction factor is assumed to be only 80%.
- 15) MAIN FEEDWATER PUMP CONTROLS During the life of the plant, numerous transie.its and trips have been caused by the main feed water pump controls.
During the 1985 outage and the current outage, extensive work has been done to instrument these controls to identify the various causes of system problems. Many problems have been identified and corrective actions taken. Although the investigations have been meticulous in detail and thorough in scope, the system is still subject to random component failure. The failure rate reduction is expected to be 60% of our past operating experience.
8 k
IV. MAJOR EVENT DESCRIPTIONS (Continued)
- 16) TURBINE CONTROL OIL Several plant trips were caused by Turbine control oil pressure problems.
The problems are attributed to oil contamination due to water mixing with the oil and system sensitivity to this contamination.
Modifications have been made to install additional filters and redundant control devices to prevent recurrences of these trips.
In addition, greater attention is paid to lube oil condition and steps are taken to prevent degradation to the point previously allowed.
17)
INVERTER FAILURES Inverter failures have been the largest single cause of plant trips at Rancho Seco.
The trips involved have resulted in numerous short forced outages and power reductions.
The original inverters proved to be unreliable devices during initial plant startup.
Despite extensive efforts to improve them, they continued to be a source of problems.
This reliability problem was compounded by the basic power distribution system design.
Each of six important busses were supplied by a single inverter and if the inverter tripped all bus loads were dropped.
Losing one of these busses frequently resulted in a plant trip.
During this outag3, the original inverters were removed from service.
The power feed! are now from new state-of-the-art Class 1 inverters. Also, each bus is now supplied from two inverters with static switching devices which assure that bus power is uaintained even in the event of an inverter failure.
This major re-design essentially eliminates the causes of the past trips.
Since the possitsility exists for an inverter failure when the backup is removed from service for maintenance, n.e forced outage rate is reduced by only 901,of previous experience.
9
IV. MAJOR EVENT DESCRIPTIONS (Continued)
- 18) LOSS OF INSTRUMENT AIR Two outages were created by a partial loss of instrument air pressure. Several steps have been taken to overcome this problem.
The most important step is the installation of a self contained, diesel driven, auto starting, backup air compressor dedicated only to emergency supply to the instrument air system.
The root cause of the normal compressor failures was inadequate preventive maintenance and high demand on the system.
The high demand was partially due to lack of attention to numerous small leaks.
Both of these problems have been corrected.
A plant shutdown due to loss of instrument air is no longer considered a credible event.
- 19) PIPE HALL THINNING Several power reductions and plant outages have resulted from piping leaks due to erosion of piping (pipe wall thinning).
An extensive wall thinning monitoring program which routinely inspects critical piping is now in place.
It is designed to identify problems so that they may be repaired prior to failure.
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1 PROJECTED C AP ACITY FACTOR C ALCU LATI ON
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V.
PROJECTED CAPACITY FACTOR CALCULATION A.
Actual Ooeratina History Days Full Power Days 1858 I 47.4 l Refueling Outage Days 596 15.2 Hiscellaneous forced outage / power reduction days - unanalyzed 241 6.2 Total actual forced outage days from Table 1 - analyzed 1224 31.2 TOTAL AVAILABLE DAYS 3919 100.0 B.
Conversion of Forced Outage Days To Ooeratino Days From Table 1, Projected reduction in forced outage days or days available for additional power operation - 1224 - 212 -
1012 f'
1012 additional &vailable days used as follows:
Full Power Days 775 Refueling Outage Days 120 Hiscellaneous forced outage /
power reduction days
- unanalyzed (6.2%)
62 New projected major outage rate analyzed (212 + 3919) x 1012 -
55 TOTAL 1012 1
V.
PROJECTED CAPACITY FACTOR CALCULATION (Continued)
C.
New Caoacity Factor Calculation Days Full Power Days 1858 + 775 - 2633 l67.2l Refueling Outage Days 596 + 120 -
716 18.3 Hiscellaneous forced outage / power reduction days - unanalyzed (6.2%)
241 + 62 -
303 7.7 New Major Outage Rate 212 + 55 -
267 6.8 TOTAL AVAILABLE DAYS 3919 100.0 D.
These oroiections show a caoacity factor imorovement from an actual 47.4% to an exoected 67.2%.
NOTE:
This data and calculation is based on plant operation from April 17, 1975 (commercial operation) to December 26, 1985.
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4 FUTURE PLANT IMPROVEMENTS V
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VI.
FUTURE PLANT IMPROVEMENTS The Plant Performance And Management Improvement Program provided a method of prioritizing recommendations which arose from the in-depth evaluation of problems at Rancho Seco.
The method focused our current efforts and resources on activities necessary to assure the safe operation of the plant in accordance with regulatory and operating license requirements.
There are many planned modifications and improvements which will improve the plant's future capacity factor that nave been deferred to post restart.
A review of the operating history shows a multitude of snort duration outages (one or two days) and many power reductions which have contributed to our past capacity factor of 47%.
It is these miscellaneous forced outages and further reductions in major forced outage causes discussed under TABS II, IV and V which will be affected by the future improvements.
The analysis under TAB V shows a capacity factor reduction of 7.7% for miscellaneous items and 6.8% for major causes or a total of 14.5%.
Certainly not all of the causes of forced outages and power reductions will be eliminated, nor is it likely that all of the possible causes have been identified.
The District is actively participating in the B&H owners group reactor trip reduction program.
The goal of this program is to reach a group average of 1.4 trips per reactor per year.
Based on an analysis of the data, significant progress has been made towards achieving the goal (see attached curve). During Rancho Seco's commercial operating history, the plant was forced off line approximately 100 times, or an average of nearly ten times per year.
This cycling of the plant produces the greatest stress on plant components.
The benefits of the trip reduction program and other improvements are compounded because wear on plant equipment is reduced.
1
i VI.
FUTURE PLANT IMPROVEMENTS (Continued)
The B&W Safety Performance Improvement Program (SPIP) reviewed all B&H operating problems.
The program recommended over 200 improvements in the B&H units.
Rancho Seco will have completed almost 100 of these recommendations prior to startup. No specific credit for current or future capacity factor improvement is reflected in this report for this group of improvements.
One factor remaining in the major outage category is performance of the main generator and its hydrogen seal oil system.
A capacity factor improvement of 3.7% can be obtained from this item.
Due to the limited operating experience obtained since the modifications (following the generator explosion). this item was conservatively estimated.
The average refueling outage durations for past operation have been 100 days.
Reducing this parameter would increase '.he capacity factor; however, for this study credit was not taken even though future reduced outage durations appear possible.
The significant number of improvements planned for near term outages and the uncertain regulatory climate which may continue to mandate modification work could have a negating effect on possible refueling outage duration reductions.
Although it is subjective, the future improvements in capacity factor should be not less than one fourth nor more than three fourths of the 14.5% available or, 4% to 11%.
2
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FUEL CYCLE IMPROVEMENTS V
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VII.
FUEL CYCLE IMPROVEMENTS The existing average fuel cycle life is 317 effective full power days TEFPD).
The current fuel load is designed for 340 EFPD and it is possible to raise this to 410 EFPD (as is done at the plants operated by Duke Power Company).
Assuming that refueling outage durations remain constant at 100 days per outage, the plant's future capacity factor is increased above the values shown in Tab VI by stabilizing at 340 EFPD.
This increase over i
past average performance would be one percent.
If the fuel cycle is extended to 410 EFPD, the capacity factor improvement will be four percent.
This extension involves other considerations, such as fuel enrichment and fabrication costs and other items which have significant economic impact.
The optimum point considering all costs including capacity factor improvement may not be the maximum possible core life.
For purposes of this report, it is assumed that fuel cycle life will stabilize at its present value and a minimum one percent improvement over past performance will be realized.
1
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INDUSTRY OP ER ATIN G EXPERIENCE V
e
VIII.
INDUSTRY OPERATING EXPERIENCE As an alternate approach to predicting the capacity factor for Rancho Seco following restart, industry experience was also evaluated.
Specifically, the operating history of all pressurized water reactor plants, of "new" nuclear power plants and of Davis Besse following their restart were investigated.
The weighted average of the cumulative capacity factors for all 59 of the U.S. commercial pressurized water reactors (PHRs), based on data from the most recent NRC "gray book," is 63%.
Individual capacity factors ranged from 84% to 37%. A future capacity factor of 76% woulii put Rancho Seco within the top 20% of all PHRs.
The cumulative capacity factors of ten recently completed PHR plants were averaged.
These plants have been in operation for one to three years.
The result was a capacity factor of 70%, with the best plant achieving 77%, and the worst, 58%.
Davis Besse has operated at a capacity factor of 68% since restart; however, the plant will shut down in March for an extended outage of six months to implement many of the reliability improvements already accomplished at Rancho Seco.
Since Rancho Seco has already passed through the learning experience and early equipment failures of a totally new power plant, and has implemented many plant improvements, a capacity factor better than "just average" can be reasonably expected.
1 1
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OPERATING EXPERIENCE OF RECENT PHRs Unii Ooeratina Years Caoaci ty Factor (%)
Callaway 1 3.10 72.8 Catawba 1 2.86 61.8 Catawba 2 1.54 62.5 Diablo Canyon 1 3.05 75.5 Diablo Canyon 2 2.11 70.8 Sharon Harris 1 0.87 62.3 Palo Verda 1 2.48 57.7 Palo Verde 2 1.53 77.9 Naterford 3 2.70 76.8 Holf Creek 2.47 76.8 Heighted Average 70.
1 Data taken from the December 1987 NRC Status Summary Report, "Licensed Operating Reactors," (NUREG-0020 Vol. II, No. 12) known as the Gray Book.
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