ML20086B905
| ML20086B905 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 06/28/1995 |
| From: | Saccomando D COMMONWEALTH EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM), Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 9507060165 | |
| Download: ML20086B905 (21) | |
Text
y yy O>mmonwealth hiivro Cornpany y
Ilyron Generating Station 4150 North German Church Road llyron. IL 6101W)"N i
'rcl til42M5 iii June 28,1995 Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Attention:
Document Control Desk
Subject:
Information Regarding Mid-Cycle Outage Start Date Byron Station Unit 1 NPF-37: NRC Docket No. 50-454
References:
See Attachment 1 In Reference 1, Commonwealth Edison Company (Comed) committed to conduct a mid-cycle steam generator inspection outage as a condition of application of voltage-based steam generator tube repair criteria. Comed specifically indicated the plant shutdown for the outage would be initiated no later than September 15, l
1995. The Nuclear Regulatory Commision (NRC) confirmed this commitment in the Safety Evaluation (SE) issued October 24,1994 (Reference 2).
With this letter Comed is requesting approval to move the start date of the mid-a cycle steam generator inspection outage from no later than September 15,1995 to no later'than October 27,1995.
In planning for the mid-cycle outage (designated B1P02), a number of considerations and options were evaluated. Projections of steam generator tubes requiring repair in subsequent outages show a high number of tubes that must be repaired by plugging or sleeving, assuming a 1.0 volt steam generator tube repair criteria. Based on these results, investigation was begun into the feasibility of a technically supported increased voltage limit for hot leg tube support plate indications. On February 13,1995, Comed submitted a license amendment request (Reference 8) for a 3.0 volt steam generator tube repair limit, based on limiting support plate motion by locking the tube support plates via a tube expansion process. The analysis and process supporting this amendment request were prepared by Westinghouse and documented in WCAP-14273. Consideration was given to the feasibility of using an alternate vendor to perform the steam generator tube expansion process, but since this would require an additional review by the Staff, the decision was made to limit consideration to the Westinghouse process. Approval of this increased repair criteria was requested for Fall 1995 to j
support both the Byron mid-cycle outage and the Braidwood refuel outage (beginning September 30,1995).
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Docurnent Control Desk June 28,1995 The tube repair projections have made the need for sleeving in future outages clear. Based on recent industry experience, the BWNT sleeving process, currently approved for use, was determined to be unacceptable during B1R06 for installation at Byron. Following the conclusion of B1R06 (November 1994), Comed began evaluation of various sleeving processes and determined that the Westinghouse laser welded sleeve and the Combustion Engineering (CE) TIG welded sleeve were technically acceptable for installation at Byron. The Westinghouse sleeve is currently licensed for Byron. 'A license amendment request package was prepared and submitted to the staff on May 17,1995 requesting approval of the CE sleeving process, in order to minimize Staff reviews associated with B1P02, a decision was made to request epproval of the CE sleeve for B1R07.
While these technical evaluations were being conducted and submittats being prepared, Byron Station management was considering which vendors to contract for performance of steam generator work during B1P02. Discussions included consideration for the steam generator inspection, repair of steam generators by sleeving, and locking tube support plates by the tube expansion process. The possibility of using multiple vendors to cover the different aspecto of the work was explored and found not to be practical. A decision was made to use Westinghouse for performance of all aspects of the steam generator work in B1P02 and negctiations began. While Comed was exploring technical and outage contractor options, Westinghouse had been making outage commitments with other utilities for the fall timeframe (including a significant sleeving outage at Maine Yankee). At the time Byron was prepared to award the contract, Westinghouse indicated that they were unsure of their ability to support the September 15,1995 outage start date. After evaluating their resources and commitments, Westinghouse i
determined that they could not support a Byron outage until late October 1995. details Unit 1 repair projections along with Westinghouse schedular commitments, illustrating the need to delay the outage.
Comed has also included in Attachment 2 an assessment of the delay in the start date for the outage on the safety significance. This assessment included a reevaluation of the probability of tube burst, a risk based evaluation and a review of the operational experiences during Cycle 7.
Comed concluded that safety significance was not adversely impacted. Additionally, Attachment 2 contains other issues that are related to the mid-cycle outage.
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Document Control Desk-June 28,1995 contains a detailed discussion of the following items:
1.
Steam Generator tube repair projections and options l
2.
Schedular considerations a.
Westinghouse b.
Cooling Tower Modification c.
Summer Peak Load 3.
Probability of burst assessment 4.
Risk based evaluation 5.
Operational considerations r
a.
Operational experience during Cycle 7 b.
Operational measures 6.
Other considerations a.
Circumferential cracking concerns b.
Effects of chemical cleaning Comed appreciates the Staff reviewing our request to delay the mid-cycle outage date. Clearly, we believe~that the Staff will agree that the delay of B1P02 until October 27,1995, is the only available and reasonable option. We also believe that this change in outage schedule will not adversely impact the safety significance of the public. Comed welcomes further communications with the Staff so that we can provide assistance in resolving this issue. We respectfully request your review and response by July 14,1995.
Please address any comments or questions regarding this matter to this office.
t P
Sincerely, hSJ 18-Denise M. Saccomando Nuclear Licensing Administrator a
p Attachments l
1 cc:
. D. Lynch, Senior Project Manager G. F. Dick, Byron Project Manager - NRR H. Peterson, Senior Resident inspector - Byron J. B. Martin, Regional Administrator - Region lli Office of Nuclear Facility Safety - IDNS
-Waa, wA:
l REFERENCES f
1.
' October 24,1994, letter from D. M. Saccomando to NRC transmitting Comed's date for a Byron Unit 1 mid-cycle outage.
i 2.
October 24,1994, letter from R. A. Capra to D. L. Farrar transm'itting Safety Evaluation for Use of a 1.0 Volt Interim Plugging Criteria for Byron Unit 1.
3.
. September 17,1994, letter from D. M. Saccomando transmitting Byron Station's evaluation of the impact of Unit 1 Chemical Cleaning on steam generator inspection results.-
4.
August 1,1994, letter from J. A. Bauer to W. T. Russell transmitting Byron Station's request for a license amendment to implement a 1.0 volt Interim Plugging Criteria, with supplements dated September 7,1994, September 17,1994, September 22,1994, Sytember 30,1994, and October 17, 1994.
. i i
5.
October 17,1994 letter from D. M. Saccomando to NRC transmitting Byron Station's Cycle 7 Safety Assessment.
6.
August 18,1994, letter from R. Assa to D. Farrar transmitting Safety i
Evaluation for Use of interim Plugging Criteria for Braidwood Unit 1.
l 7.
January 30,1995, letter from G. K. Schwartz to J. B. Martin transmitting j
the Byron Unit 1 Cycle 6 Interim Plugging Criteria 90 day report and includes WCAP-14277, "SLB Leak Rate and Tube Burst Probability Analysis Methods for ODSCC at TSP Intersections, dated January,1995."
t 8.
February t 3,1995, letter from D. M. Saccomando to NRC transmitting Byron Station's request for a license amendment to implement a 3.0 voit Interim Plugging Criteria.
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t l
Repair Projections Byron Unit 1 currently has 1752 tubes removed from service. This equates to 9.6%
of the total number of tubes in the steam generators (SGs) having been plugged.
Byron's tube plugging limit is 15% for all four SGs and is in the process of being increased to 24%. Current projections of the number of tubes to be repaired during the mid-cycle outage is expected to be approximately 1200 for a 1.0 volt IPC and 275 t
for a 3.0 volt IPC. The 3.0 volt IPC for Byron Unit 1 is not approved for use at this time and is currently under NRC review.
An evaluation was performed to determine the impact of various repair scenarios on the SG plugging margins and associated economic costs from now to steam generator replacement (SGR) scheduled for the Spring of 1999. The total economic costs include repair costs and replacement power costs for lost capacity due to longer outages and power deratings. Table 2-1 summarizes the results of this evaluation. The table indicates that with a 1.0 volt IPC implemented in the upcoming mid-cycle outage (B1P02) and all repairs are by tube plugging, the total equivalent plugging percentage of all four SGs is over 16% with the highest plugged SG being 20.1% plugged and the lowest being 7.4%. Plugging at these levels presents several operational ar ' economic concerns. The large difference of plugging levels between SGs will negatively impact reactor coolant flow asymmetries which could result in power imbalances in the core. The 16% overall plugging level and the 20.1%
maximum plugging level after B1P02, will greatly reduce the plugging margin through the time of replacement in 1999. Depending on the repair scenarios that follow B1P02 (plugging, sleeving, 3.0 volt IPC,etc.), the 24% plugging limit could be exceeded. In addition, the 1.0 volt IPC and plugging of all repairable indications in B1P02 results in total costs significantly higher than the most economical option.
Sleeving is required to maintain and balance the plugging levels within acceptable limits given the 1.0 volt IPC option.
Table 2-1 clearly shows that in order to effectively manage SG operation 'and economic costs due to the large number of repairs, sleeving and/or 3.0 volt IPC would be required during the Byron mid-cycle outage. The only acceptable vendor to perform both the sleeving and 3.0 volt IPC implementation during B1P02 is Westinghouse, as further described. To implement a 3.0 volt IPC as described in Reference 8, selected tubes are required to be expanded into the tube support plates to prevent support plate displacement. The Westinghouse tube expansion process to support the 3.0 volt IPC is currently under NRC review. Comed has not submitted tube expansion processes from other vendors in order to minimize Staff work loads.
The Westinghouse expansion process utilizes the same equipment and personnel as tube sleeving. The only acceptable and approved sleeving process for use at Byron is the Westinghouse laser welded sleeve. The BWNT kinetic sleeve has been 2-1
i determined to be an unacceptable repair due to industry failures and subsequently is in the process of being removed from the Technical Specifications. Comed has recently submitted a request to the Staff to approve the Combustion Engineering TIG welded sleeve, but approval is not expected until the Spring of 1996.
The possibility of using multiple vendors during B1P02 to cover the different aspects of the work was explored and found not to be practical. For these reasons, Westinghouse was selected as the only acceptable vendor to perform SG inspection and repair activities during the Byron mid-cycle outage.
Following extensive discussions with Westinghouse, it was determined that the 3
earliest date that Westinghouse could provide personnel onsite to support a Byron mid-cycle inspection outage is October 22,1995. Further justification for this conclusion follows.
Schedular Considerations Westinghouse:
Figures 2-1 through 2-4 show Westinghouse scheduled (as of the date of this letter) steam generator outages by location and duration for the period from July 1,1995 to November 26,1995. These figures show critical Westinghouse resource loadings for the same time period (additional resources are required in support of a steam generator outage beyond those included on the graphs). Resources greater than 100% show demand for resources beyond those available at the time these charts were prepared (as indicated below, training of new personnel is required to meet the peak fall demand). Figures 2-1 and 2-2 show the Byron outage starting August 13, 1995 and Figures 2-3 and 2-4 show the Byron outage starting October 22,1995 (inprocessing begins with a plant shutdown on October 27). The best estimate of the sleeving material delivery date (week of September 3,1995) is shown on the key resource loading Figures 2-2 and 2-4.
4 Westinghouse resource dernand for the summer period (until August 31,1995) includes the following considerations:
11 Steam Generator outages (8 International,3 Domestic).
Maine Yankee Sleeving Campaign (17,000 sleeves).
Fall Resource Training Demand: To support the fall outage peak (mid-September to mid-October), an additional 70% Operations resources must be trained. This includes technicians, engineers, analysts, and support labor.
Fall equipment mobilization and preparation to support 10 domestic outages and 1 international outage.
Fall technical development support for 3 laser welded sleeve (LWS) outages and new technology introduction.
Planned vacations.
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Westinghouse resource demand for the fall period (September 1,1995 - October 22, 1995) includes the following considerations:
11 Steam Generator outages.
4 Major repair programs including 3 LWS outages and 1 chemical cleaning.
2 Major NDE outages with 6 or more channel heads of activity (excluding LWS outages and the chemical cleaning).
Resources (in percentage of currently available Westinghouse resources) required to support a Byron outage include:
10% Engineers 25% Technicians 15% ROSA-3s 33% LWS Trailers Additional support labor (not shown on graph)
Based on the information presented in the figures, a Byron Unit 1 outage in mid-August would have to be inspection and plugging only, since sleeving materials are not expected to be available. Such an outage would pull resources from the training tasks such that Westinghouse would not be in a position to support their scheduled fall peak. In addition, a Byron outage in the July to mid-October time period would result in Westinghouse resources being overallocated. Therefore, the only time period when Westinghouse can commit to providing resources in supp 1 of a Byron Unit 1 steam generator outage begins October 22,1995.
Cooling Tower Modification:
The Byron Station natural draft cooling towers (NDCTs) have sustained significant damage due to the effects of icing and wear. Unit 1 has been operating longer and, therefore, has the most extensive damage. The damage is related to the fill system which acts as the heat transfer media. As the fill is damaged or worn, portions collapse into the basin resulting in a loss of thermal efficiency. As efficiency is lost, the unit is derated.
The NDCT Fill Replacement Project is comprised of three phases of work, spread over three separate outages. The first phase was completed in B1R06 (Fall 1994).
When the requirement for a mid-cycle outage became known, plans were made to take advantage of the outage by accelerating the project and conducting Phase ll during the mid-cycle outage and Phase 111 during B1R07 (Spring 1996). This would result in completion of the project 18 months ahead of the original schedule with the associated cost savings of regained efficiency.
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The contractor performing the NDCT work for Byron cannot support a mid-cycle outage start date prior to September 15,1995 due to engineering and material resource constraints. Failure to perform Phase il during the mid-cycle outage as currently planned will result in a significant efficiency loss to Byron Station and require maintaining the current system for an additional 18 months.
Summer Peak Load consideration:
The summer months are traditionally the highest usage months experienced by utilities in the midwest. The September 15,1995 outage date, originally proposed by Comed in response to NRC's requirement of a mid-cycle outage, took into consideration the projected peak loading on the Comed system. The loss of Byron Unit 1 during the July to early September time period would result in possible i
shortage of available power in the Midwest.
Probability of Burst Assessment in the Fall of 1994, Byron Unit 1 implemented a 1.0 volt IPC during the Cycle 6 Refueling outage. Evaluations were performed to assess (Main Steam Line Break)
MSLB leakage and tube burst probabilities for the Beginning-of-Cycle 7 (BOC-7),
End-of-Cycle 7 (EOC-7), and at the projected Mid-Cycle Outage (B1P02) which was to begin on September 15,1995. The methodology for calculating the leakage and tube burst probability, including multiple tube bursts, was based on a Monte Carlo simulation which accounts for parameter uncertainty. The methodology was presented in detail to the Staff via a January 30,1995 Letter that transmitted the Byron Unit 1 Cycle 6 90 Day IPC Report (Reference 7). The calculated BOC-7, B1P02 (beginning on September 15,199f.', and EOC-7 leakage and burst probabilities were calculated for various probability of detection (POD) models, including a POD of 0.6 and an EPRI POD model. Table 2-2 shows the results of these Monte Carlo calculations.
The projected MSLB leakage for a POD of 0.6 was calculated to be 2.5 gpm and 5.1 gpm at September 15,1995 and at EOC-7, respectively. These are both significantly less than the site allowable limit of 12.8 gpm. From a MSLB leakage only perspective, full cycle operation could be justified. Therefore, a change in the mid-cycle outage date within the operating cycle would be bounded by 5.1 gpm and the onsite allowable leakage limit. The MSLB leakage estimated for October 27,1995 is 3.2 gpm. This estimate is based on interpolation between the three known Monte Carlo values, assuming a POD of 0.6. See Figure 2-5.
2-4 i
With a POD of 0.6, the total probability of tube burst exceeded the Technical Specification limit of 1.0x10 2 from beginning of cycle through the end of cycle 7. The burst probabilities ranged from 1.36x10-2 at the beginning of cycle to 3.29x102 at the l
end of cycle. A safety assessment was performed and submitted to the Staff via an October 17,1994 letter to support unit start-up (Reference 5). The justification for continued operation with a burst probability exceeding 1.0x10-2 consisted of 1)
Probabilistic Risk Assessment,2) commitment for a mid-cycle inspection outage, and
- 3) the burst probability remains below the NUREG-844 limit of 2.5x10 2 at the time of the mid cycle outage. A Monte Carlo calculation was performed for a September 15, 1995 unit shutdown and projected a total burst probability of 1.92x102 This includes the probability of multiple tube bursts (ie., one tube bursting, two tubes bursting, etc.).
A conservative estimate of the tube burst probability was made assuming the mid-cycle outage start date was moved from September 15,1995 to October 27,1995.
The estimate was derived through a straight line interpolation of the data points from the Monte Carlo calculated values at September 15 and FOC-7 as shown in Figure 2-6. Although, the actual tube burst probability is not lintaar over time, a straight line estimate through the three known Monte Carlo data points, BOC-7, September 15, 1995, and EOC-7, yields higher burst probabilities than the actual Monte Carlo curve due to the general concave shape of the curve. Extending the mid -cycle outage from September 15 to October 27 would increase the total probability of burst from 1.92x10 2 to 2.26x10 2 The NUREG-844 burst probability limit of 2.5x10 2 would still be satisfied for a October 27,1995 mid-cycle outage.
As shown on Table 2-2, when the EPRI POD is used, the total probability of burst is less than the NUREG-844 limit at all times during the full fuel cycle (Reference 5).
On October 27,1995, the probability of burst is estimated to be 9.61x10 which satisfies the Technical Specification limit.
The Spring 1995 Braidwood Cycle 5 Mid-Cycle Outage projected and actual probability of burst values were reviewed to determine trends pertaining to conservatisms in the Monte Carlo calculations using POD of 0.6. Table 2-3 shows a comparison of the projected and actual as-found burst probabilities assuming a POD of 0.6. The projected burst probability tends to over estimate the actual value by a factor of 5 to 28 for SGs A, B and D. The projected burst probability for the SG C is skewed low due to the plugging of 117 large voltage indications during the November 1993 Tube Leak Outage prior to the Cycle 4 inspection. Even considering this factor, the Monte Carlo calculation over estimated the burst probability. Since Braidwood and Byron have similar voltage and growth distributions, it can be expected that the projected tube burst probabilities for Byron would also over estimate the actual as found value during the mid-cycle outage.
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Risk Based Evaluation A risk assessment was performed to evaluate operation during several periods during the current feel cycle, consistent with the Staff's approach described in the August 18,1994, Sstety Evaluation Report (SER) (Reference 6) for 1.0 volt IPC. The approach used the total probability of burst value for combined single and multiple tube ruptures assuming a POD of 0.6. MSLB and Feedwater Line Break (FWLB) frequencies of 1.8x10' per reactor year are assumed in the assessment. These frequencies are based on the occurrence of 2 FWLB events in 1370 reactor years of Westinghouse pressurized water reactor (PWR) operation. An estimated probability of 1x10~8 was also used for failure to mitigate the combined effects of such events to prevent core damage. This assumption is consistent with NUREG-0844 and draft NUREG-1477. The general risk assessment approach to estimate the frequency of core damage per reactor year is as follows:
Core Damage,,,=(FWLB,,, + MSLB,,q) x (Failure to Mitigate,,q) x (Probability of Burst)
Core Damage,,, = (1.8x10-8 + 1.8x10~ ) x (1x10' ) x (Probability of Burst)
Using the above equation and the total probability of burst values from Table 2-3 for a POD of 0.6, the estimated frequency of core damage at BOC-7, September 15, 1995, October 27,1995, and at EOC-7 are listed in Table 2-4.
Based on these values, the estimated frequency of core damage due to induced 4
rupture of combined single and multiple tubes at Byron Unit i range from 4.90x10 4
to 1.18x10 during entire fuel Cycle 7.
The estimated incremental frequency of core damage can also be considered to be the incremental frequency for containment bypass release. Many probabilistic risk assessments for PWRs estimate the total 4
frequency of containment bypass releases on the order of 10 per reactor year, which the Staff has found to be acceptable. On that basis, the estimated increment for the Byron Unit 1 entire fuel cycle would also be acceptable. Changing the mid-cycle outage date from September 15 to October 27 would increase the core damage 4
4 4
frequency from 6.91x10 to 8.14x10. This is an increase of 1.23x10, which is considered an insignificant change in a risk assessment. Therefore, from a risk perspective, an October 27.1995 mid-cycle cutage start date is acceptable.
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Operational Considerations Significant Unit 1 plant operating experience since the Fall 1994 Refuel Outage:
One major chemistry excursion was experienced on December 3,1994, due to a condenser tube leak. Initial indication of a problem was received at 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />.
Following sampling and confirmation of elevated sodium and cation conductivity levels in the secondary side, a rampdown was begun at 2043, in accordance with EPRI secondary chemistry guidelines. The unit was brought to Hot Standby (Mode 3) conditions less than 31/2 hours following indication of an abnormal condition.
Location of the source of the leakage was made on December 6, at about 0300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br />. Following a thorough flushing and draining of the condenser and steam generators, Unit 1 was returned to service on December 16,1994.
Following the condenser tube leak, much less hideout return has been experienced on power ramps than was seen prior to the chemical cleaning in B1R06 (see for a discussion of chemical cleaning). This would indicate that the tube support plate crevices were not repacked by the contaminants from the condenser tube leak. Thus, the tube leak is expected to have minimal overall effect on continued SG operations.
Stable primary to secondary leakage in the range of 1-2 gpd has been experienced in the 1C steam generator since early in the operating cycle. Liquid sampling showed intermittent indication at the start of the cycle. Gas sampling has shown constant leakage since sampling was begun in February 1995.
Unit i fuel integrity has been good this cycle. Leakage from a fuel pin was identified several weeks into the cycle. lodine levels in the RCS remain below the threshold value (5.0 E-4 pCi/gm) for entry into the Failed Fuel Action Plan, however, the Plan has been conservatively entered due to the presence of a known leaking fuel pin.
The RCS iodine level has remained low with no marked increase over the course of the cycle. Current plans are to ultrasonically test (UT) and reconstitute the leaking assembly during B1R07.
As an added measure of conservatism, Byron will administratively reduce the RCS iodine limit from 1.0 pCi/gm to 0.35 Ci/gm for the time period between September 15 and the actual entry into the mid-cycle inspection outage. This will ensure that any offsite dose associated with SG tube leakage will be restricted to well below 10CFR100 limits (factor of 3 lower than dose associated with 1.0 Ci/gm).
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Operational Measures:
System operationa! measures, such as plant equipment, procedures, and training, are in place to provide for monitoring and the ability to respond to SG tube leakage as previously described in References 4 and 8. As a result of past industry leakage events, as described in SOER 93-01 and IEN 94-43, Byron has implemented a number of program enhancements to improve the ability to detect leakage and respond to situations where leakage is detected. Data from the Braidwood primary-to-secondary leak in October 1993 was also specifically reviewed for applicability due to the similarity in design between Byron and Braidwood. The programs and equipment at Byron are revised, as appropriate, whenever significant industry input becomes available.
The system operational measures available at Byron, including enhancements implemented and planned, were discussed in detail in the Byron submittals for 1.0 and 3.0 volt IPC (References 4 and 8). A recent enhancement to the Steam Jet Air Ejector (SJAE) radiation monitoring system has increased the sensitivity of the monitor and ensures capability for accurately trending primary-to-seconaary leakage.
With the improvement to the SJAE monitoring system, chemistry sampling of the off-gas effluent allows accurate measurement of primary-to-secondary leakage by evaluation of Xe-133. A backup to the off-gas method, is measurement of the tritium levels in the feedwater system. Due to increased awareness of primary-to-secondary leakage and in order to obtain data for small values of leakage, the off-gas system is currently being sampled daily.
f Iron transport is also being controlled to low levels by chemical addition. Alternate chemical additives are being explored to limit iron transport even further.
By minimizing the iron transported to the steam generators, tube surface fouling and deposit formations in the crevice regions are reduced. The deposit formations within the crevice due to iron transport can contribute to the degradation of the steam generator tubes at the tube support plate.
Other Considerations Circumferential Cracking:
During the Byron Unit 1 Cycle 6 refueling in the Fall of 1994, rotating pancake coil (RPC) inspections were performed on 100% of the hot leg roll transitions and circumferential cracking was identified in 132 roll transitions. This was the first time a 100% RPC inspection was performed at Byron and the first time circumferential indications were detected. The largest circumferential crack indication identified was removed from the steam generator for laboratory analysis. The calculated burst pressure based on the metallurgical crack depth was 4706 psi at room temperature (4362 psi at operating temperature). This indication was shown analytically to meet 2-8
~
)
+
the requirements of Reg Guide 1.121 limits of 1.43 x AP SLB (3660 psi) and 3 x AP NOP (3760 psi) at minimum material Lower Tolerance Level (LTL) values. Since the tube separated during the tube removal process, Electron Discharge Machining i
~ (EDM) simulations of the crack depth profile were burst tested to validate the analytical results. The tested burst pressures of all the simulations were in excess of the minimum Reg. Guide 1.121 burst pressure requirements with appropriate margins of safety. The testing also verified that the analytical burst pressure was valid.
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All circumferential indications were stabilized and removed from service thus eliminating the possibility 'of the tube severing and damaging other tubes.
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'I Due to the fact inat bobbin eddy current is not capable of reliably detecting circumferential indications, it is likely that the larger indications detected during the Byron ref al outage developed over a period longer than one cycle. This is supported by the ct that the recent Byron inspection detected a relatively small,60 degree arc length indication in a tube which had been MRPC inspected in the previous outage and showed no signs of cracking, indicating a relatively slow growth rate. Thus, extending the mid-cycle outage from September 15 to October 27 would not cause i
any potential circumferential indications from initiating or growing to sizes that would exceed Reg. Guide 1.121 structural limits. As previously discussed, Byron has implemented enhanced primary-to-secondary monitoring and trending programs to reliably detect and respond to any SG leakage. In addition, Byron will reduce the RCS dose equivalent lodine limit from 1 pCi/gm to 0.35 pCi/gm for the time period between September 15 and the actual entry into the mid-cycle inspection outage.
Chemical Cleaning:
Comed has evaluated the effects of the chemical cleaning performed during B1R06 on the Byron Unit 1 steam generators and inspection results as documented by a September 17,1994 transmittal to the Staff (Reference 3). An additional evaluation was performed following the chemical cleaning to determine the actual effects of the cleaning nad on the eddy current result. This evaluation will be submitted to the staff at a later date. The evaluation concludes that the chemical cleaning did not adversely affect the eddy current voltage and growth rate distributions and that negative growth rates experienced were due to normal eddy current variability, it is also concluded that future inspection results would not be impacted by the chemical cleaning process performed in B1R06. Therefore, chemical cleaning is not a factor when determining the mid-cycle outage start date.
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. Table 2-1: Byron Unit 1 Repair Options and' Costs Post Post Prior to j
B1P02 B1P02 SGR-l Option REPAIR OPTION
. Total.
Max Total (Note 1)
Equiv.
Equiv Equiv.
Pig %
Pig %
Pig %
i 1
1.0v IPC to SGR 16.1 %
20.1%
25.7 %
100% Pig at B1P02 f
Siv B1R07 to SGR 2
1.0v IPC to SGR 9.9%
12.7 %
21.7 %
Siv B1P02 to SGR 3
1.0v IPC B1P02 16.1 %
20.1 %
23.9 %
100% Pig at B1P02 3.0v IPC at B1R07 l
Siv at B1R07 4
4 3.0v IPC at B1P02 11.1 %
14.1 %
18.3%
~i 100% Pig at B1P02 Siv at B1R07 L
i Note 1: Repair Options are listed from the least economical to the most economical repair scenerio from now to SGR.
j Table 2-2: Byron Cycle 7 Probability of Burst MSLB Leakrate Total Prob. of Total Prob. of.
Burst (EPRI (gpm)
POD)
B0C-711/2/94 1.8 1.36 x 10 2 2.19 x 10" 9/15/95 2.5 1.92x 10 2 5.18x 10' 10/27/95*
3.2 2.26 x 10 2 9.61 x 10~
EOC-7 3/1/96 5.1 3.29 x 10-2 2.29 x 10 2 Monte Carlo Calculations were not performed to obtain values for this date.
The Probability of Burst and MSLB leakage values were 7nservatively interpolated between three known Monte Carlo obtained values.
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i Table 2-3: Braidwood Unit 1 Spring 1995 Mid-Cycle Outage Probability of Burst SG
' Projected Mid-Cycle
. Actual Mid-Cycle POD =0.6 POD =0.6
,A 1.52 x 10-2 2.02 x 10-B 1.69 x 10-'
3.26 x 104 C*
3.45 x 10-3.04 x 10-D 3.08 x 10-2 3.08 x 10-2 Voltage and growth distributions were affected by repairs made in this SG during the November 1993 Leaker Outage. Therefore, projected burst probability is skewed high.
Table 2-4: Estimated Frequency of Core Damage during Cycle 7 Total Estimated Freq.
Probability of of Core-Burst Damage / Reactor Year BOC-7 1.36x10-2 4.90 x 104 9/15/95 1.92x10-2 6.91 x 10-8 10/27/95 2.26x10 2 8.14 x 10-8 EOC-7 3.29x10-2 1.18 x 10-7
{
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9 FIGURE 2-1:
Westinghouso SG Fi Id Opsrations Byron Unit 1 Outage in August,1995 f~
Mar I
June i
July I
Aueust i
S.id *,
- octode, I
wovame l
oece i) l 7 l 14 l 21 l 28 l 4 l 11 l 18125 l 2 l 9 l 16 l 23 l 30 l 6 l 13 l 20 l 27 l 3 l 10 l 17 l 24 1 ! 8 l 15122 l 29 l 5112 l 19 l 26135 ID Tash Name 1
vacatens at 1 4
ATRC Tra@./~,.,-nt Support. - _
1 p-7 Maine Yankee (LWS)
, y 5/24 1U27 28 TM l
Sfts 5/2 i
~
31 'Fe's M 6112 713 34 Da*8 4 sits 7ae 38 Blayais 1 6/26 7/24 sn7 M; 42 Trkashn 7tte 5
83 Salem 1 7/15 8/23 70 SONGS 3 7G4 8/22 74 Bogey yf33 af3g 77 Cruas S/2 911 Se Byron afg3 gf3g 96 Tlhange 3 (LWS) gfg igng 164 Sequoyah 1 SIS l
10/23 111 Surry 1 gfgg gg!2 118 Farley 1 Sitt 14/22 126 Cook 1 (LWS) 9/30 18128 142 Diatdo Canyon i 1911 10/29
~'
13 Brak1wolod(LWS) 1914 144 Catawba 2 11/22 ggfgo
- ggf3, 1TE 52 1111 11/26 178 Seatwook g ggg3 incorporales personnel vacatens. summer trainrng to meet peak, A equipment turnaround between jobs (de =m V
2mM
..~-.--,.%
Key Resource Loading
~
Byron Starting 8/13
)
1 200
{
Sleeves 3
' Delivered N150 l
I
-x-O
! surt BF
+-
A-*
Engineers a.
7 g
g
-O-U 2:-
f
~*
i Technicians 3100
/
gf %
',A-A ij ROSA-3's E
o xx-
,_d 4
g
_m y
50 t'
r^
j p_'*g\\
LWS Trailers
,- ~
i i
e
=
{
i
~*-- 4 i
0 9t
-l-I-l 1 1-1-1-1-1-1-l-1-+-I-H-+
l 7/2 7/23 8/13 9/3 9/24 10/15 11/5 11/26 Week Of FIGURE 2-2
4 FIGURE 2-3:
Westinghouse SG Field Operations Byron Unit 1 Outage in October,1995 L
may l
June l
.ndy l
August I sepe.neer ocioim l-novmen I
oece 10 Test Name 30 l 7 l 14 l 21 l 281 4 l 11 l 18 l 251 2 l 9 l 16 l 23 l 30 l 6 l 13 l 20 l 27 l 3 l 10 l 17 l 24 1 l 8 l15 l 22 l 29 l 5]12 l 19 l 2613 @.
i vacations of,,
4 ATRC Travang/Developreent Support
{
{,
~
~ ~ ~
7 sE n (tws) sna 11/27 e +.
"'2 N "
"" V "
se esayai i sta 7a4
~
42 Tricastin sar rite T
.n9? m m.
a raa*.
sa s*a 1 ms sas
~~
~
~~~~
74 auger rat s/se
~
~~ ~~
n Crua.
.n wi
~
et Tihange 3 (LWS) ofg gng 39 segsoyah 1
- 8 14I23 M
Surry 1 wig gn 143 Farley 1 W20 14/22 116 Cook 1(t5Sh 9/30 10/28 127 D6ablo Canyon 1 ggfg
- gen, 134 Sraidwood 1 (LWS) 1914 1142
-~ ~
1st Catawba 2
, n, 1ee syron (twsl tw22 8
~~ ~
m s
roo.
1,,,, m
~
~
incorporasa personnet vacations sumrner tranno to rneet peak. a ewnent turrwound between jobs me =m vnspddagIe vardi mhp
-.. - - - =.. _,
. ~.
...-.4-.*.
.4.
Key Resource Loading Byron Starting 10/22 200 3 - - --
'5leeves Byron Delivered
- Start
.N150 i
-I-o
/
m A-*
Engineers i
/
i o
6-.
~
[2
/:
Technicians s
8100 y
g j
h
'b *
/
E ROSA-3's
,x
/
_ s,A-2 x
A\\
LWS Trailers y
50 t'
'r-x ' r I - r $j
-X x-g,
i 1
l l
0 tt I -I - l I i-I-t-1-1--1-1-l -- 1-1-1 I-7/2 7/23 8/13 9/3 9/24 10/15 11/5 11/26 i
Week Of FIGURE 2-4
FIGURE'2-5 Byron Cycle 7.MSLB Leakage (POD =0.6)
~
6, q
t
^
5.
5
--- 3 2
E 4
_..... _.4 E
E 3
x r
h k
3.15 gpm 2i
------------ - - - - - - - - - - - - - - - - - - - - - - - - - - o n, o / 27 / 9 5 " - - - - - - - -
a 9/15/95 g
p d
1 (;
^---- ---------
.:s t
!~
i l
I L
0
--- - l - --- i
/////////////////
Date f Straight Line Estimate
- Estimate on 10/27/95 Site Allowable Limit is 12.8 gpm
.,,,.r.
- .~.
m
'mc..
m M
w-
~
FIGURE 2-6
~
Byron Cycle 7 Probability of Burst (P0D=0.6) 0.04 7--
.g E
0.035 E-a e
9,93 l3
..=.y ca 0.025 fMREG-08%MIT2 0,025___________________________________.
o D
0.02 I-
- - -... 22s.on.
g b
10/27~/95 d
0.015 g
- - - - ----- ----------------- -- 8/15/85-- --------- "--- ---
--i L E H SPE M MJJ_..-
0.01____________
_ __________,_ __________~___
u 0.01
_a 2
0.005 p i
i i
i 1
0
/////////////4///
Date i : Straight Line Estimate
- Estimate on 10/27/95 m m..
+
_ e
.~r.
. -