ML033530321
| ML033530321 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 12/16/2003 |
| From: | Bezilla M FirstEnergy Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 3000, LAR 01-0019 | |
| Download: ML033530321 (102) | |
Text
{{#Wiki_filter:FENOC a "-.% 5501 North State Route 2 FrstEnergy Nuclear Operating Company Oak Harbor, Ohio 43449 Mark B. Bezila 419-321-7676 Vice President - Nuclear Fax: 419-321-7582 Docket Number 50-346 10 CFR 50.90 License Number NPF-3 Serial Number 3000 December 16, 2003 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001
Subject:
Davis-Besse Nuclear Power Station License Amendment Application to Revise Technical Specification 3/4.4.5, "Reactor Coolant System - Steam Generators," to Permit One-Time Extension of Steam Generator Tube Inservice Inspection Interval (License Amendment Request No. 03-0019) Ladies and Gentlemen: Pursuant to 10 CFR 50.90, the following amendment is requested for the Davis-Besse Nuclear Power Station, Unit I (DBNPS). The proposed amendment would revise Technical Specification (TS) 3/4.4.5, "Reactor Coolant System - Steam Generators," to allow a one-time extension of the steam generator tube inservice inspection interval. This one-time interval extension would apply only to the first inservice inspection following completion of the extended thirteenth refueling outage (13RFO). A comprehensive inservice inspection of the steam generators was performed during 13RFO and xvas completed on March 9, 2002. Since February 16, 2002, the DBNPS has been in an extended shutdown. During this extended shutdown, the steam generators were in a condition in which active degradation would not be expected. The proposed change will allow delaying steam generator inservice inspection until a mid-cycle outage commencing on or before March 31, 2005. Enclosure I to this letter contains the technical basis for the proposed extension and the proposed no significant hazards consideration. Approval of the proposed amendment is requested by February 8, 2004, to allow implementation of the amendment prior to the expiration of the TS surveillance interval on March 9, 2004. Once approved, the amendment shall be implemented within 30 days. 4D417
Docket Number 50-346 License Number NPF-3 Serial Number 3000 Page 2 The proposed changes have been reviewed by the DBNPS Station Review Board and Company Nuclear Review Board. Should you have any questions or require additional information, please contact Mr. Kevin L. Ostrowski, Manager - Regulatory Affairs, at (419) 321-8450. The statements contained in this submittal, including its associated enclosures and attachments, are tnle and correct to the best of my knowledge and belief. I declare under penalty of perjury that I am authorized by the FirstEnergy Nuclear Operating Company to make this request and the foregoing is true and correct. Executed on: /,Z/ & t03 By: Mark B. Bezilla, Vice President - N clear MAR Enclosures cc: Regional Administrator, NRC Region III J. B. Hopkins, NRC/NRR Senior Project Manager D. J. Shipley, Executive Director, Ohio Emergency Management Agency, State of Ohio (NRC Liaison) C. S. Thomas, NRC Region III, DB-1 Senior Resident Inspector Utility Radiological Safety Board
Docket Number 50-346 License Number NPF-3 Serial Number 3000 Enclosure I DAVIS-BESSE NUCLEAR POWER STATION EVALUATION FOR LICENSE AMENDMENT REQUEST NUMBER 03-0019 (98 pages follow)
LAR 03-0019 Page I DAVIS-BESSE NUCLEAR POWER STATION EVALUATION FOR LICENSE AMENDMENT REQUEST NUMBER 03-0019
Subject:
License Amendment Application to Revise Technical Specification 3/4.4.5, "Reactor Coolant System - Steam Generators," to Permit One-Time Extension of Steam Generator Tube Inservice Inspection Interval
1.0 DESCRIPTION
2.0 PROPOSED CHANGE
3.0 BACKGROUND
4.0 TECHNICAL ANALYSIS
5.0 REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration (NSHC) 5.2 Applicable Regulatory Requirements/Criteria
6.0 ENVIRONMENTAL CONSIDERATION
7.0 REFERENCES
8.0 ATTACHMENTS
LAR 03-0019 Page 2
1.0 DESCRIPTION
This letter is a request to amend the Davis-Besse Nuclear Power Station, Unit Number I (DBNPS) Facility Operating License Number NPF-3. The proposed change would revise the Operating License Technical Specification 3/4.4.5, "Reactor Coolant System - Steam Generators," to permit a one-time extension of the steam generator tube inservice inspection interval. The DBNPS thirteenth refueling outage (13RFO) commenced on February 16, 2002. Inservice inspection of the steam generators was performed during 13RFO and was completed on March 9, 2002 with the next inspection due March 9, 2004. Details of the inspection scope are provided in Section 3.0 of this application. Since February 16, 2002, the DBNPS has been in an extended shutdown. During this extended shutdown, no conditions existed that would require an assessment of active degradation mechanisms, crack growth rate progressions, or internal steam generator components. Additionally, no conditions were identified that would have an adverse effect on, or cause any type of known corrosion damage to the steam generators during the layup period. The proposed change will allow delaying steam generator inservice inspection until a mid-cycle outage commencing on or before March 31, 2005.
2.0 PROPOSED CHANGE
The proposed change affects TS 3/4.4.5 and is shown on the marked-up TS page in . The proposed change would add a note to TS Surveillance Requirement (SR) 4.4.5.3.a. SR 4.4.5.3.a currently states: Inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months after the previous inspection. If the results of two consecutive inspections for a given group of tubes following service under all volatile treatment (AVT) conditions fall into the C-I category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval for that group may be extended to a maximum of 40 months. The proposed change would add a double asterisked note to SR 4.4.5.3.a which states: An exception applies for the interval following the March 2002 inspection completed during the Thirteenth Refueling Outage. Under this exception, the next inservice inspection may be delayed until March 31, 2005. In summary, the proposed change revises Technical Specification 3/4.4.5, "Reactor Coolant System - Steam Generators," to permit a one-time extension of the steam generator tube inservice inspection interval until March 31, 2005. No associated change to the Technical Specification Bases is being made.
LAR 03-0019 Page 3
3.0 BACKGROUND
TS SR 4.4.5.3.a requires that inservice inspections of steam generator tubes be performed at intervals of not less than 12 nor more than 24 calendar months after the previous inspection. Per TS SR 4.4.5.3.d, the 25% surveillance interval extension provided in TS 4.0.2 does not apply to this requirement. Inservice inspection of the steam generators was performed during 13RFO, which commenced on February 16, 2002. A comprehensive inspection of the steam generators was completed on March 9, 2002. TS SR 4.4.5.3.a requires performance of the next inspection by March 9, 2004. Since February 16, 2002, the DBNPS has been in an extended shutdown. During this extended shutdown, the steam generators were in a condition in which active degradation of the steam generators would not be expected. The DBNPS reactor coolant system (RCS) contains two steam generators. The steam generators are discussed in DBNPS Updated Safety Analysis Report (USAR) Section 5.5.2, "Steam Generators." The steam generators are vertical, straight tube, once through, counterflow, shell and tube heat exchangers with shell side boiling. The steam generators perform the following safety functions:
- Provide a pressure boundary between the reactor coolant and the secondary side fluid to confine fission products and activation products within the reactor coolant system.
- Provide heat transfer capability to remove the reactor coolant heat produced during normal power operations.
- Provide normal and auxiliary feedwater flow paths and heat transfer capability for both normal and emergency cooldown, and supply steam for the auxiliary feed pump turbines for emergency cooling.
Steam generator inspection activities are performed in accordance with the DBNPS Steam Generator Management Program. The DBNPS Steam Generator Management Program implements the guidance of NEI 97-06, "Steam Generator Program Guidelines." The most recent steam generator inservice inspection was completed on March 9, 2002. This inspection included:
- 1. Inspection of new re-rolls.
- 2. Inspection of all in-service tubes and sleeves by a bobbin coil.
- 3. Inspection of 62 percent of the sleeve roll expansions by a plus point coil.
- 4. Inspection of 57 percent of the tube upper roll expansions by a plus point and pancake coil.
- 5. Inspection of all of the non-stress-relieved tube roll expansions-factory re-rolls by a plus point and pancake coil.
- 6. Inspection of 60 percent of the hot leg roll plugs by a plus point coil.
- 7. Inspection of the tubes bordering the sleeve region by a plus point and pancake coil.
S. Inspection of all of the flaw-like indications reported from bobbin by a plus point and pancake coil.
- 9. Inspection of the dent indications, including all those located above the 14th tube support plate and a 60 percent sample of the remaining population by a plus point and pancake coil.
LAR 03-0019 Page 4
- 10. Inspection of 500 tubes at the sludge pile region of the lower tubesheet in each steam generator by a plus point and pancake coil.
- 11. Inspection of plugged tubes per the Three Mile Island (TMI) severance tube event.
- 12. Inspection of all welded tube plugs by qualified VT-1.
Results of this inspection have been provided to the NRC in letters dated March 22, 2002 (Serial Number 2771), April 25, 2002 (Serial Number 2768), March 31, 2003 (Serial Number 2944), and November 3, 2003 (Serial Number 2989). Currently, the Davis-Besse steam generators have been in service for approximately 15.8 EFPY and have 562 (3.6%) plugged tubes in steam generator 2-A and 161 (1.0%) plugged tubes in steam generator 1-B leaving a total of 30191 tubes in service.
4.0 TECHNICAL ANALYSIS
The surveillance requirements for inspection of the steam generator tubes ensure that the structural integrity of this portion of the RCS will be maintained. Inservice inspection of steam generator tubing is essential in order to monitor the condition of the tubes for evidence of mechanical damage or progressive degradation due to design, manufacturing errors, or inservice conditions that lead to corrosion. Inservice inspection of steam generator tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken. Two assessments have been performed to assure the acceptable operation of the DBNPS steam generators for a period of up to 1.4 effective full power years (EFPY) following the end of the thirteenth refuieling outage. The first assessment is documented in Framatome-ANP Document 51-5033009-03, "DB-1 Steam Generator Shut Down/Lay Up Chemistry Assessment - 2003." This detailed assessment is included as Attachment 4 to this application. This assessment evaluated the layup and storage conditions of the steam generators during the extended shutdown from February 16, 2002 through December 1, 2003. This assessment concluded that no conditions existed that would require an assessment of active degradation mechanisms, crack growth rate progressions, or internal steam generator components. Additionally, no conditions were identified that would have an adverse effect on, or cause any type of known corrosion damage to the steam generators during the layup period. It is projected that there will be no degradation of the steam generator materials prior to plant restart provided current satisfactory storage and layup conditions are maintained. Prior to operation beyond the original surveillance interval (i.e., March 9, 2004), the DBNPS staff will assure that the steam generator layup and storage conditions subsequent to the time period assessed in Framatome-ANP Document 51 - 5033009-03 wvere consistent with the conclusions of that assessment. The second assessment is documented in Framatome-ANP Document 51-5034594-02, "A Steam Generator Tubing Operational Assessment for Davis Besse." This assessment is included as to this application. An operational assessment for a full cycle length (approximately 1.85 EFPY) had been completed following the inspections performed in 2002. Framatome-ANP Document 51-5034594-02 updated the full cycle operational assessment for a mid-cycle outage at approximately 1.4 EFPY. This assessment concluded that projected
LAR 03-0019 Page 5 structural margins are greater for 1.4 EFPY of operation than they are for a full cycle of operation. The projected number of indications remain the same for wear and decrease by about 20% for other degradation mechanisms for 1.4 EFPY of operation. In addition, projected accident leakage following a steam line break remains at nominal projected values. The proposed amendment would allow operation on the DBNPS steam generators until their next inspection during a mid-cycle outage commencing on or before March 31, 2005. This wvill include no more than 1.4 EFPY of operation. During a full cycle, approximately 1.85 EFPY of operation is expected. Since the layup and storage conditions of the steam generators during the extended outage have been evaluated and determined to not adversely affect the steam generators, and since the operational assessment for the mid-cycle outage has shown substantial margin for any unexpected degradation that may have occurred, the proposed one time exception to the steam generator inspection interval is acceptable. 5.0 REGULATORY SAFETY ANALYSIS 5.1 No Significant Hazards Consideration Technical Specification Surveillance Requirement 4.4.5.3 requires performance of steam generator tube inspections at an interval not more than 24 calendar months. The proposed amendment would provide for a one-time extension of the steam generator tube inservice inspection interval. The proposed change would allow the first steam generator inspection following the thirteenth refueling outage to be delayed until no later than March 31, 2005. An evaluation has been performed to determine wlhether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:
- 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No. The steam generator tubes perform both an accident prevention and an accident mitigation function. Steam generator tube integrity is necessary to prevent the loss of reactor coolant system inventory to the secondary system and to provide a barrier to fission product release to the environment. The layup and storage conditions of the steam generator during the extended outage have been assessed and determined to not adversely affect steam generator conditions. An operational assessment of the steam generators for approximately 1.4 effective full power year has been performed to assure acceptable structural integrity during the extended surveillance interval. The operational assessment for the steam
LAR 03-0019 Page 6 generators has determined that primary-to-secondary leakage following a steam line break, which is the limiting event (other than a tube rupture), would continue to be acceptable. Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
- 2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No. The proposed change does not introduce any new or different failure mechanism for the steam generators. Steam generator tube integrity will be maintained as previously analyzed following postulated events. Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
- 3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No. The layup and storage conditions of the steam generator during the extended outage have been assessed and determined to not adversely affect steam generator condition. The operational assessment for the mid-cycle outage has shown that structural margins are greater at approximately 1.4 EFPY then they would be at the end of a typical full cycle of operation. Accident induced leakage is projected to be the same for the surveillance interval extension period as it would be for a full cycle of operation. Therefore, the proposed change does not involve a significant reduction in a margin of safety. Based on the above, it is concluded that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of"no significant hazards consideration" is justified. 5.2 Applicable Regulatorv Requirements/Criteria Inspection requirements for the DBNPS steam generator are specified, in part, in USAR Section 3D.1.10, "Criterion 14 - Reactor Coolant Pressure Boundary." USAR Section 3D.1.10 states, in part: The reactor coolant pressure boundary has been designed, fabricated, erected, and tested to ensure an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture.
LAR 03-0019 Page 7 The steam generator tubes form part of the reactor coolant system pressure boundary. The proposed amendment does not affect any design, fabrication, or erection requirements. The technical analyses provided in Section 4.0 of this application and the referenced attachments demonstrate that the one-time surveillance interval extension will not adversely affect steam generator operation. The one-time modification to steam generator test (i.e, inservice inspection) requirements will not adversely affect the probability of abnormal leakage, of rapidly propagating failure, or of gross rupture. USAR Section 3D.1.26, "Criterion 30 - Quality of Reactor Coolant Pressure Boundary," states, in part: Components which are part of the reactor coolant pressure boundary are designed, fabricated, erected, and tested to the highest quality standards practical. Means are provided for detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage. The proposed change does not alter the quality standards to which the steam generators are tested. The test methods used during the thirteenth refueling outage and the test methods planned to be used during the mid-cycle outage will be consistent with the DBNPS Technical Specifications and industry guidance. USAR Section 3D.1.28, "Criterion 32 - Inspection of Reactor Coolant Pressure Boundary," states, in part: Components that are part of the reactor coolant pressure boundary are designed to permit (1) periodic inspection and testing of important areas and features to assess their structural and leaktight integrity, and (2) an appropriate material surveillance program for the reactor pressure vessel. The proposed change does not alter the design of the steam generators regarding the ability to perform periodic inspection and testing. The DBNPS Technical Specification requirements for inservice inspection of the steam generator tubes are based on a modification of Regulatory Guide (RG) 1.83, Revision 1, "Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes." The proposed change provides for a one-time extended inspection interval beyond the 24 calendar months specified in the RG. However, as addressed by the technical analysis provided in Section 4.0 of this application, the one-time exception to the RG inspection interval is acceptable. 10 CFR 50.55a, "Codes and Standards," requires the inservice examination of components in compliance with the requirements of the latest edition and addenda of the American Society of Mechanical Engineers Boiler and Pressure Vessel (ASME) Code incorporated by reference into 10 CFR 50.55a twelve months prior
LAR 03-0019 Page 8 to the start of the 120-month inspection interval. The current Third Ten Year Interval Inservice Inspection Program is based on ASME Code Section XI of the 1995 Edition with the 1996 Addenda, as modified by 10 CFR 50.55a. 10 CFR 50.55a(b)(2)(iii) states: Steam generator tubing (modifies Article IWB- 2000). If the technical specifications of a nuclear power plant include surveillance requirements for steam generators different than those in Article IWB- 2000, the inservice inspection program for steam generator tubing is governed by the requirements in the technical specifications. Accordingly, the steam generator tube inspections are governed by the DBNPS Technical Specifications, including the frequency of inspection, which is addressed by this proposed change. In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public. 6.0 ENV'IRONAMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.
7.0 REFERENCES
- 1. DBNPS Operating License NPF-3, Appendix A Technical Specifications through Amendment 260.
- 2. DBNPS Updated Safety Analysis Report through Revision 23.
- 3. Framatome Document 51-5033009-03, "DB-I Steam Generator Shut Down/Lay Up Chemistry Assessment - 2003," dated December 10, 2003.
LAR 03-0019 Page 9
- 4. Framatome Document 51-5034594-02, "A Steam Generator Tubing Operational Assessment for Davis Besse," dated December 9, 2003.
- 5. NEI 97-06, Steam GeneratorProgram Guidelines, Revision 1, dated January 2001.
- 6. Regulatory Guide (RG) 1.83, "Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes," Revision 1, dated July 1975.
- 7. Letter from FENOC to the NRC dated March 22, 2002, "Davis-Besse Nuclear Power Station Technical Specification 4.4.5.5a Report of Steam Generator Tube Plugging," DBNPS Serial Number 2771, ADAMS Accession No. ML020850568.
- 8. Letter from FENOC to the NRC dated April 25, 2002, "Davis-Besse Nuclear Power Station License Condition 2.C(7) Report for the Thirteenth Refueling Outage," DBNPS Serial Number 2768, ADAMS Accession No. ML021210583.
- 9. Letter from FENOC to the NRC dated March 31, 2003, "Technical Specifications 4.4.5.5.b and 6.9.1.5.b: Report of Steam Generator Tube Inservice Inspection Results," DBNPS Serial Number 2944, ADAMS Accession No. ML030930374.
- 10. Letter from FENOC to the NRC dated November 3, 2003, "Request for Additional Information Regarding the 2002 Steam Generator Tube Inspections (TAC No. MB9541)," DBNPS Serial Number 2989, ADAMS Accession No. ML033100370.
8.0 ATTACHMENTS
- 1. Proposed Mark-Up of Technical Specification Pages
- 2. Proposed Retyped Technical Specification Page
- 3. Technical Specification Bases Pages
- 4. Framatome Document 51-5033009-03
- 5. Framatome Document 51-5034594-02
LAR 03-0019 Attachment I PROPOSED MARK-UP OF TECHNICAL SPECIFICATION PAGES (11 pages follow)
INFORMATION ONLY REACTOR COOLANT SYSTEM STEAM GENERATORS LIMITING CONDITION FOR OPERATION 3.4.5 Each Steam Generator shall be OPERABLE with a minimum water level of 18 inches and the maximum specified below as applicable: MODES 1 and 2:
- a. The acceptable operating region of Figure 3.4-5.
MODE 3*:
- b. 50 inches Startup Range with the SFRCS Low Pressure Trip bypassed and one or both Main Feedwater Pump(s) capable of supplying Feedwater to any Steam Generator.
- c. 96 percent Operate Range with:
- 1. The SFRCS Low Pressure Trip active.
Or
- 2. The SFRCS Low Pressure Trip bypassed and both Main Feedwater Pumps incapable of supplying Feedwater to the Steam Generators.
MODE 4:
- d. 625 inches Full Range Level APPLICABILITY: MODES 1, 2, 3, and 4, as above.
ACTION:
- a. With one or more steam generators inoperable due to steam generator tube imperfections, restore the inoperable generator(s) to OPERABLE status prior to increasing T., above 200 0F.
- b. With one or more steam generators inoperable due to the water level being outside the limits, be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the next 30 hours.
- Establish adequate SHUTDOWN MARGIN to ensure the reactor will stay subcritical during a MODE 3 Main Steam Line Break.
DAVIS-BESSE, UNIT I 3/4 4-6 Amendment No. 2YY,7Y,192
INFORMATION ONLY jj_-S ten~~~~~~~iure [ Level Maximum Allowable Steam Generator in MODES 1 and 2 100- (43,96)
.g/
_e-
*p90-"/
E s0 Unacceptable Operating eJ 70-1 Region
'.70-cs60- ~~~~~~~~~~~Acceptable U ~~~~~~~~~~Operating a /
a S0- / ~~~~~~~~Region 50 (0.43) n0 - 50 60 0 Hain Steam Superheat (OF) 3/4 4-6a Amendment Ho;1'92 DAVIS-BESSE, UNIT I.
REACTOR COOLANT SYSTEM IN FORMATION ONLY STEAM GENERATORS SURVEILLANCE REOUIREMENTS 4.4.5.0 Each steam generator- shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5. 4.4.5.1 Steam Generator Sample Selection and Inspection - Each steam generator shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators specified in Table 4-4.1. 4.4.5.2 Steam Generator Tube Sample Select4on and-Inspection - The steam generator tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2. The inservice inspection of steam generator tubes shall be performed at the frequencies specified in Specification 4.4.5.3 and the inspected tubes shall be verified acceptable per the acceptance criteria of Specification 4.4.5.4. The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:
- a. The first sample inspection during each inservice inspection of each steam generator shall include:
- 1. All tubes or tube sleeves that previously had detectable wall penetrations (> 20%) that have not been plugged or repaired by repair roll or sleeving in the affected area.
(Tubes repaired by sleeving or repair roll remain available for random selection).
- 2. At least 50% of the tubes inspected shall be in those areas where experience has indicated potential problems.
DAVIS-BESSE - UNIT I 3/4 4-6b Amendment No.4-g2 220
UEACUOR COLKn-M &]9INFORMATION ONLY SURvETEL = Re (Continued)
- 3. A tube inspection (pursuant to Specification 4;4.5.4.aS8) shall be performed on each selected tube. If any selected tube does not permit the passage of the eddy current probe for a tube inspection, this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection.
- b. Tubes in the following groups may be excluded from the first random sample if all tubes in a group in both steam generators are inspected. go credit will be taken for these tubes in meeting minimum sample size requirements.
- 1. Group A-1: Tubes within one, two or three rows of the open inspection lane.
- 2. Group A-2: Tubes having a drilled opening in the 15th support plate.
- 3. Group A-3: Tubes included in the rectangle bounded by rows 62 and 90 and by tubes 58 and 76, excluding tubes included in Group A-1.*
- c. The tubes selected as the second and third samples (if required by Table 4.4-2) during each inservice inspection may be subjected to less than a full tube inspection provided:
- 1. The tubes selected for these samples include the tubes from those areas of the tube sheet array where tubes with Imperfections were previously found.
- 2. The inspections include those portions of the tubes where Imperfections were previously found.
The results of each sample inspection shall be classified into one of the following three categories: Category Inspection Results C-1 Less than SX of the total tubes inspected are degraded tubes and none of the inspected tubes are defective. C-2 One or more tubes, but not more than 1X of the total tubes inspected are defective, or between S and 107. of the total tubes inspected are degraded tubes. C-3 More than 107 of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective.
- Tubes in Group A-3 shall not be excluded after completion of the fifth refueling outage.,-
Amendment N-o.- Z7J 84 DAVIS-BESS, MM I 3/4 4-17
REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued!_ Notes: (1) In all inspections, previously degraded tubes must exhibit significant (> 10%4) further wall penetrations to be included in the above percentage calculations. (2) Where special inspections are performed pursuant to 4.4.5.2.b, defective or degraded tubes found as a result of the inspection shall be included in determining the Inspection Results Category for that special inspection but need not be included in determining the Inspection Results Category for the general steam generator inspection. 4.4.5.3 Inspection Frequencies - The above required inservice inspections of steam generator tubes shall be performed at the following frequencies:
- a. Inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months** after the previous inspection. If the results of two consecutive inspections for a given group of tubes following service under all volatile treatment (AVT) conditions fall into the C-1 category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval for that group may be extended to a maximum of 40 months.
- b. If the results of the inservice inspection of a steam generator performed in accordance with Table 4.4-2 at 40 month intervals for a given group* of tubes fall in Category C-3, subsequent inservice inspections shall be performed at intervals of not less than 10 nor more han 20 calendar months after the previous inspection. The increase in inspection frequency shall apply until a subsequent inspection meets the conditions specified in 4.4.5.3a and the interval can be extended to 40 months.
- c. Additional, unscheduled inservice inspections shall be performed on each steam generator in accordance with the first sample inspection specified in Table 4.4-2 during the shutdown subsequent to any of the following conditions:
- 1. Primary-to-secondary tube leaks (not including leaks originating from tube-to tube sheet welds) in excess of the limits of Specification 3A.6.2.
If the leak is determined to be from a repair roll joint, rather than selecting a random sample, inspect 100% of the repair roll joints in the affected steam generator. If the
-results of this inspection fall into the 0-3 category, perform additional inspections of the new roll areas in the unaffected steam generator.
- A group of tubes means:
(a) All tubes inspected pursuant to 4.4.5.2.b, or (b) All tubes in a steam generator less those inspected pursuant to 4.4.5.2.b.
- an xcntion apnime for the. interaml folaoing the March 2002 inspection comoleted durn the Tirtenth Refueling Outaie. Under his exception, the next inserzice inspection May be delayd until March 312005.
DAVIS-BESSE, UNIT 1 314 4-8 Amendment No. 21, 220
INFORMATION ONLY REACTOR COOLANT SYSTEM SURVEHllANCE R BUIUEMO M (Continued)
- 2. A seismic occurenc grater than the Operating Basis Badthuke
- 3. A loss-of-coolant accident requiring actuation of the engineered safeguards.
- 4. A main steam line or feedwater line break.
- d. The provisions of Specification 4.0.2 are not applicable.
4.4.5.4 AcMcptance Criteria
- a. As &isedin this Specification:
- 1. Tubing or Tube means that portion of the tube or tube sleeve which forms the primary system to secondary system boundary.
- 2. Imnperfectidn means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below.20% of the nominal tube wall thickness, if detectable, may be considered as imperfections.
- 3. Degradation means a service-induced cracking, wastage, wear or general corrosion occunting on either inside or outside of a tube.
- 4. Degraded Tube means a tube containing imperfections > 20% of the nominal wall thickness caused by degradation that has not been repaired by repair roll or sleeving in the affected area.
- 5. % Degradation means the percentage of the tube wall thickness affected or removed by degradation,
- 6. Defect means an imperfection of such severity that it exceeds the repair limit.
A defective tube is a tube containing a defect that has not been repaired by repair roll or sleeving in the affected area or a sleeved tube that has a defect in the sleeve.
- 7. Repair limit means the imperfection depth at or beyond which the tube shall be removed from service by plugging or repaired by repair roll or sleeving in the affected area because it may become unserviceable prior to the next inspection and is equal to 40% of the nominal tube wall thickness. The process described in Topical Report BAW-2120P will be used for sleeving.
DAVIS-BESSH, UNIT 1 314 4-9 Amendmnent No. 21;171, 220, 252
INFORMATION ONLY' REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) (Continued) 7. The repair rol process used is described in the Topical Report BAW-2303P Revision 4. lTe new roll area must be free of degradation in order for the repair to be considered acceptable.
- 8. Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 4.4.5.3.c, above.
- 9. Tube Inspection means an inspection of the steam generator tube from the point of entry corpletely to the point of exit. The previously existing tube and tube roll, outb d of the newv roll area in the tube sheet, can be excluded from futurem periodic inspection requirements bbecause it is no longer part of the pressure boundary once the repair roll is installed.
DAVIS-BiESSE, UINrIT 3/4 4-9a Amendment No. 21, 171, 220, 252
INFORMATION ONLY REACTOR COOLANT SYSTEM SURVEILLANCE REOUIREMENTS (Continued)
- 10. Preservice Inspection means an inspection of the full length of each tube in each steam generator performed by eddy current techniques prior to service to establish a baseline condition of the tubing. This inspection shall be performed prior to Initial POWER OPERATION using-the equipment and techniques expected to be used during subsequent inservice inspections.
- b. The steam generator shall be determined OPERABLE after completing the corresponding actions (plug or repair by repair roll or sleeving in the affected areas all tubes exceeding the repair limit and all tubes containing through-wall cracks) required by Table 4.4-2.
4.4.5.5 Renorts
- a. Following each inservice inspection of steam generator tubes, the number of tubes plugged in each steam generator shall be reported to the Commission within 15 days.
- b. The complete results of the steam generator tube inservice inspection shall be submitted on an annual basis in a report for the period in which this inspection was completed. This report shall include:
- 1. Number and extent of tubes inspected.
- 2. Location and percent of wall-thickness penetration for each indication of an imperfection.
- 3. Identification 6f tubes plugged, sleeved or repair rolled.
- c. Results of steam generator tube inspections which fall into Category C-3 and require notification of the Commission shall be reported prior to resumption of plant operation. This report shall provide a description of investigations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.
4.4.5.6 The steam generator shall be demonstrated OPERABLE by verifying steam generator level to be within limits at least once per 12 hours. 4.4.5.7 When steam generator tube inspection is performed as per Section 4.4.5.2, an additional but totally separate inspection shall be performed on special interest peripheral tubes in the vicinity of the secured internal auxiliary feedwater header. This testing shall only be required on the steam generator selected for inspection, and the test shall require inspection only between DAVIS-BESSE-, UNIT I 3/4 4-10 Amendment No. 6,a7,624?,j 4 84 r 220
INFORMATION ONLY REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) the upper tube sheet and the 15th tube support plate. The tubes selected for inspection shall represent the entire circumference of the steam generator and shall total at least 150 peripheral tubes. -4.4.5.8 Visual inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves shall be performed on each steam generator through the auxiliary feedwater injection penetrations. These inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves- shall be performed during the third period of each ten-year Inservice Inspection Interval (ISI). 4.4.5.9 When steam generator tube inspection is performed as per Section 4.4.5.2, an additional but totally separate inspection shall be performed on special interest tubes that have been repaired by the repair roll process. This inspection shall be performed on 100% of the tubes that have been repaired by the repair roll process. The inspection shall be limited to the repair roll joint and the roll transitions of the repair roll. Defective or degraded tubes found in the repair roll region as a result of the inspection need not be included in determining the Inspection Results Category for the general steam generator inspection. DAVIS-BESSE, UNIT I Amendment No. Q, 22Gir 226 3/4 4-10a
an r ~~~~~~~~~MNMM TABLE 4.4-t OB -A INSPECTED DURING INSERVICE INSPECTION promwic Inte .No Yet No. of sit" Generators per Ut' To Three [Fon Two Three Fout n Irnpei Flet I service AO One Two Two -a Inwivko Inspections sOne' oneJ Oo One 3
-wi Table Notation 0
- 1. The steam geaof on atotatig fchedule ettewtopasthmn 2 N % of the lubes rvki Inspection may be limited to oneam
(*ters Isthe ntmbrw of steam generatots In she plant) I the results of the fist or wevilous Invections Indicate that al* sitm generbiots ae performing In a lie manner. Note that under sam. cfrcumstances. the operelmg conditions #n one or more steam generstors may be found to be more $eee than thoet In other steant fzeuetots Under such ircumn stances he samptl sequenes ihall be modified to Impect the mot vern conditions.
- 2. The other steam enator not Inspectel dinhg the tWit Inwv Inspectlon shall be inspected. Tle tiird and subsetuent inpelon sthoukI follow the Instrucntmns desribed in t above. ;I
- 3. Eah of the other two steam geneators not nsPected thtring the first Ineice ispecmnit sha he n"spected dwring the second and third Inspections. The lourh ni subteItiet Inspectiloni shal Follow Ihe nttiuctitns descoibed In I above.
~z
TABLE 4.4-2 STEAM GENERATOR TUBE INSPECTION en ac w0 cn IST SAMP2 3NPECTION 2ND S MPI SCION 3RDf SAMP OISPECTtON en m Sample Siz Result Action Requfred Resuft Aetlon Requi Result Action ReuW a z A minimum _.1 No_ N)A NIA NIA NIA
-4 ofS Tubes perS.O.(t) -
C-2 ' I orepufrbyreprfrtomgr C-i None N/A NWA
. eefntddebete tubes and inspect adittonal 2S tubes In this S.O. -1 C-2 Platorrepft bytep? rorImg °r C1 None sleevIn deeivetubeslnd 7- Inspect addional 4S tubes thIs S.G.
C-2 Phgotreputbreputrolritor C-3 Pafbrm tedonrfrC.3 temuttof w ____ ____ mi
~~~~~~~~~~~~~~~~~~~~first
.C3 Pedbwnaction forC-3 emuttof WA N/A 532 0
¢.3 nspect n tubes In thb . tphug r Ahl otherS OJs repi by tepu rolling or seciIng ne C4 None NWA NIA I delecte tubes vn Inspect 2S tubes In each other 0. Report to the Im NRC pior to resumption of pant It operation. __
SomeS.Oa C- Perlbn ctlon brC-2 rtsh of 0. I, 2 but no second sample N/A N/A C> addttionsl S.O. _4M _, = M Add tonal s.a. tinspect an tubes Ineach S.O. and I-0 IsC-3 plug et repar byrp"trollmg or leving derectie tubes. Report to the NRC prio to Meumtion of NIA N/A O 1-f plant operation. to 00 (1) S-34% (Where N Is the number of steam generators In the unit, and n Is the number of steam generators Inspected during an Inspection. E:E
LAR 03-0019 PROPOSED RETYPED TECHNICAL SPECIFICATION PAGE (1 page follows)
REACTOR COOLANT SYSTEM SURVEILLANCE REOUTREMENTS (Continued) Notes: (1) In all inspections, previously degraded tubes must exhibit significant (> 10%) further wall penetrations to be included in the above percentage calculations. (2) Where special inspections are performed pursuant to 4.4.5.2.b, defective or degraded tubes found as a result of the inspection shall be included in determining the Inspection Results Category for that special inspection but need not be included in determining the Inspection Results Category for the general steam generator inspection. 4.4.5.3 Inspection Frequencies - The above required inservice inspections of steam generator tubes shall be performed at the following frequencies:
- a. Inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months** after the previous inspection. If the results of two consecutive inspections for a given group* of tubes following service under all volatile treatment (AVT) conditions fall into the C-1 category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval for that group may be extended to a maximum of 40 months.
- b. If the results of the inservice inspection of a steam generator performed in accordance with Table 4.4-2 at 40 month intervals for a given group* of tubes fall in Category C-3, subsequent inservice inspections shall be performed at intervals of not less than 10 nor more than 20 calendar months after the previous inspection. The increase in inspection frequency shall apply until a subsequent inspection meets the conditions specified in 4.4.5.3a and the interval can be extended to 40 months.
- c. Additional, unscheduled inservice inspections shall be performed on each steam generator in accordance with the first sample inspection specified in Table 4.4-2 during the shutdown subsequent to any of the following conditions:
- 1. Primary-to-secondary tube leaks (not including leaks originating from tube-to tube sheet welds) in excess of the limits of Specification 3.4.6.2.
If the leak is determined to be from a repair roll joint, rather than selecting a random sample, inspect 100% of the repair roll joints in the affected steam generator. If the results of this inspection fall into the C-3 category, perform additional inspections of the new roll areas in the unaffected steam generator.
- A group of tubes means:
(a) All tubes inspected pursuant to 4.4.5.2.b, or (b) All tubes in a steam generator less those inspected pursuant to 4.4.5.2.b.
- An exception applies for the interval following the March 2002 inspection completed during the Thirteenth Refueling Outage. Under this exception, the next inservice inspection may be delayed until March 31, 2005.
DAVIS-BESSE, UNIT I 3/4 4-8 Amendment No. 21, 220
LAR 03-0019 TECHNICAL SPECIFICATION BASES PAGES (3 pages follow) Note: Tle Bases pages are providledfor inzfornationi orals.
REACTOR COOLANT SYSTEM INFORMATION ONLY BASES 3/4.4.4 PRESSURIZER A steam bubble in the pressurizer ensures that the RCS is not a hydraulically solid system and is capable of accommodating pressure surges during operation. The steam bubble also protects the pressurizer code safety valves and pilot operated relief valve against water relief. The low level limit is based on providing enough water volume to prevent the low level interlock from de-energizing the pressurizer heaters during steady state operations. The high level limit is based on providing enough steam volume to prevent water relief through the pressurizer relief valves during the most challenging anticipated pressurizer insurge transient, which is a loss of feedwater. Since prevention of water relief is a goal for abnormal transient operation, rather than a Safety Limit, the value for high pressurizer level is nominal and is not adjusted for instrument error. The ACIION statement provides 1 hour to restore pressurizer level prior to requiring shutdown. The I-hour completion time is considered to be a reasonable time for restoring pressurizer level to within limits. The pilot operated relief valve and steam bubble function to relieve RCS pressure during all design transients. Operation of the pilot operated relief valve minimizes the undesirable opening of the spring-loaded pressurizer code safety valves. 3/4,4.5 STEAM GENERATORS The Surveillance Requirements for inspection of the steam generator tubes ensure that the structural integrity of this portion of the RCS will be maintained. The program for inservice
- inspectionof steam generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1. Inservice inspection of steam generator tubing is essential in order to maintain surveillance of the conditions of the tubes in the event that there is evidence of mechanical damage or progressive degradation due to design, manufacturing errors, or inservice conditions that lead to corrosion. Inservice inspection of steam generator tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken. A process equivalent to the inspection method described in Topical Repoit BAW-2120P will be used for inservice inspection of steam generator tube sleeves. This inspection will provide ensurance of RCS integrity.
The plant is expected to be operated in a manner such that the secondary coolant will be maintained within thlise chemistry limits found to result in negligible corrosion of the steam. generator tubes. If the secondary coolant chemistry is not maintained within these chemistry limits, localized corrosion may likely result in stress corrosion cracking. The extent of cracking during plant operation would be limited by the limitation of steam generator tube leakage between the primary coolant system and the secondary coolant system (primary-to-secondary leakage = 150 GPD through any one steam generator). Cracks having a primary-to-secondary leakage less than this limit during operation will have an adequate margin of safety to withstand the loads imposed during normal DAVIS-BESSE, UNIT I B 3/4 4-2 Amendment No. 135,171,220 LAR No. 01-0012
REACTOR COOLANT SYSTEM INFORMATION ONLY BASES (Continued) operation and by postulated accidents. Operating plants have demonstrated that primary-to-secondary leakage of 150 GPD can be detected by monitoring the secondary coolant. Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and plugged or repaired by repair rolling or sleeving in the affected areas. Wastage-type defects are unlikely with proper chemistry treatment of the secondary coolant. However, even if a defect should develop in service, it will be found during scheduled inservice steam generator tube examinations. As described in Topical Report BAW-2120P, degradation as small as 20% through wall can be detected in all areas of a tube sleeve except for the roll expanded areas and the sleeve end, where the limit of detectability is 40% through wall. Tubes with imperfections exceeding the repair limit of 40% of the nominal wall thickness will be plugged or repaired by repair rolling or sleeving the affected areas. Davis-Besse will evaluate, and as appropriate implement, better testing methods which are developed and validated for commercial use so as to enable detection of degradation as small as 20* through wall without exception. Until such time as 20% penetration can be detected in the roll expanded areas and the sleeve end, inspection results will be compared to those obtained during the baseline sleeved tube inspection. An additional repair method for degraded steam generator tubes consists of rerolling the tubes in the tubesheet to create a new roll area and pressure boundary for the tube. The repair roll process will ensure that the area of degradation will not serve as.a pressure boundary, thus permitting the tube to remain in service. The degraded area of the tube can be excluded from fiture periodic inspection requirements because it is no longer part of the pressure boundary once the repair roll is installed in the tubesheet. All tubes which have been repaired using the repair roll process will have the new roll area inspected during the inservice inspection. Defective or degraded tube indications found in the new roll area as a result of the inspection of the repair roll and any indications found in the originally rolled region of the rerolled tube need not be included in determining the Inspection Results Category for the general steam generator inspection. The repair roll process will be performed as described in the Topical Report BAW-2303P, Revision
- 4. The new roll area must be free of degradation in order for the repair to be considered acceptable.
After the new roll area is initially deemed acceptable, future degradation in the new roll area will be analyzed to determine if the tube is defective and needs to be removed from service. Leakage from repair rolls will be accounted for to ensure post-accident primary-to-secondary leakage -willnot exceed that assumed in the safety analyses. DAVIS-BESSE, UNIT I B 314 4-3 Amendment No. 171, 184, 192,220,252
INFORMATION ONLY REACTOR COOLANT SYSTEM BASES (Continued) Whenever the results of any steam generator tubing inservice inspection fall into Category C-3, these results shall be reported to the Commission prior to resumption of plant operation. Such cases will be considered by the Commission on a case-by-case basis and may result in a requirement for analysis, laboratory examinations, tests, additional eddy-current inspection, and revision of the Technical Specifications, if necessary. The steam generator water level limits are consistent with the initial assumptions in the USAR. While in MODE 3, examples of Main Feedwater Pumps that are incapable of supplying feedwater to the Steam Generators are tripped pumps or a manual valve closed in the discharge flowpath. The reactivity requirements to ensure adequate SHUTDOWN MARGIN are provided in plant operating procedures. The steam generator minimum water level requirement is met by verifying the indicated steam generator level is greater than or equal to the value that corresponds to the required actual minimum level above the tubesheet. : DAVIS-BESSEL UNIT I B 3/4 4-3a Amendment No. 171, 184, 192, 220, LAR No. 00-0001
LAR 03-0019 FRAMATOME DOCUMENT 51-5033009-03 DB-I Steam Generator Shut Down/Lay Up Chemistry Assessment - 2003 (50 pages follow)
2044u-9 (rz2UUZ) A FRAMATOME ANP ENGINEERING INFORMATION RECORD Document Identifier 51 - 5033009-03 03 l 212 05 Title DB-1 Steam Generator Shut Down/Lay Up Chemistry Assessment-2003 PREPARED BY: REVIEWED BY: Name M.J.Bell Name B. H. Cyrus Signature Date 12/10/03 &Lj~ a, Date 12/10/03 Technical Manag r Statement: Initials Reviewer is Independent. L . LegLS a Remarks: Framatome ANP, Inc. initiated the Shutdown/Layup Chemistry Assessment Task (Task 3 of the Steam Generator Startup Review Project) to evaluate the layup and storage conditions in the OTSGs during the current plant shutdown. The shutdown period began on 2/16/02 @ 0255 with a turbine trip, and continued until plant heat-up in September 2003. The evaluation period was from 2/16/02 until 12/01/03, and included the Normal Operating Pressure Test (NOPT) period in addition to the periods when the plant was at ambient temperature. The objectives of Task 3 are to ensure that appropriate controls were in place during the extended outage to preclude any adverse effects on the OTSGs and to provide a technical basis to support a one time license change request to allow OTSG operation beyond the 24 month inspection interval. No conditions were identified that would have an adverse effect on, or cause any type of known corrosion damage to, the steam generators during the layup period including the NOPT. Further, no conditions were identified that would require an assessment of active degradation mechanisms, crack growth rate progressions, or internal steam generator components.
.lNGMECRINO DOCUMET VEW
'. W~K MAYPROCEM 2.~ rp'nSE AND RESUSMMEWOR INCRPOAT P aNgES LND:CATEDL 3=REVISE AND0RESUBMITE WORK MAYNOT PROCEED.
WORK MAY PROCEED. pERNIjsSIONTO PROCEED ON THIS DOCUMEFNT DOrS NOT BELIEVE SUPPLIER FROM FULLCMLAC WITH P.O./CONTRACT SPECIFICATION REU TS a.1ia Page I of 413
51-5033009-03 Page 2 of 50 Record of Revision Date Revision Section Description 09/15/03 00 All Original Release 11/06/03 01 4.0 Add customer comments 11/14/03 02 4.4 Add customer comment 12/10/03 03 All Update to 12/01/03
51-5033009-03 Page 3 of 50 TABLE OF CONTENTS PAGE
1.0 INTRODUCTION
.................................................. 6 2.0 METHODOLOGY .................................................. 6 3.0 STEAM GENERATOR EVTENT TIME-LINE .................................................. 6 4.0 PLANT CHEMISTRY DATA .................................................. 6 4.1 PRIMARY CHEMISTRY .................................................. 6 4.2 OTSG CHEMISTRY .................................................. 7 4.3 OTSG FILL WATER .................................................. 7 4.4 NITROGEN BLANKETING .................................................. 8 4.5 CONDENSATE/STEAM AND FEED WATER STORAGE ............................................ 8 5.0 DISCUSSION AND CONCLUSIONS .................................................. 9
6.0 REFERENCES
................................................. 10 APPENDIX A: OUTAGE OTSG EXVENT TIMELINE ................................................. 41
51-5033009-03 Page 4 of 50 LIST OF TABLES TABLE NUMBER TITLE PAGE I OTSG LAYUP WATER CONTROL PARAMETERS 12 2 OTSG LAYUP WATER CONTROL PARAMETERS 12 3 DEMINERALIZED WATER SPECIFICATIONS 12 4 OTSG LAYUP WATER CHEMISTRY CONTROL 13 5 FEEDWATER CHEMISTRY DATA DURING SHUTDOWN 13 6 CONDENSATE/FEEDWATER SYSTEMS 13 SHUTDOWN CONDITION 7 RCS STARTUP CONTROL PARAMETERS 14 8 OTSG STARTUP/HOT STANDBY CONTROL 14 PARAMETERS 9 FEED WATER STARTUP/HOT STANDBY CONTROL 14 PARAMETERS
51-5033009-03 Page 5 of 50 LIST OF FIGURES NUMBER TITLE PAGE I RCS SULFATES 15 IA NOPT RCS CHEMISTRY 16 2 OTSG I CHLORIDE 17 OTSG I OXYGEN 18 4 OTSG I FLUORIDE 19 5 OTSG I HYDRAZINE 20 6 OTSG I SODIUM 21 7 OTSG I SULFATE 22 8 OTSG I SOLUTION pH 23 9 OTSG I SILICA 24 10 OTSG 2 CHLORIDE 25 I1 OTSG 2 OXYGEN 26 12 OTSG 2 FLUORIDE 27 13 OTSG 2 HYDRAZINE 28 14 OTSG 2 SILICA 29 15 OTSG 2 SODIUM 30 16 OTSG 2 SULFATE 31 17 OTSG 2 SOLUTION pH 32 18 DEMINERALIZED WATER 33 19 DEMINERALIZED WATER 34 20 NOPT FEEDWATER DISSOLVED OXYGEN 35 21 RCS TEMPERATURE 36 22 NOPT FEEDWATER SODIUM 37 23 NOPT FEEDWATER CATION CONDUCTIVITY 38 24 NOPT FEEDWATER HYDRAZINE 39 25 NOPT FEEDWATER SUSPENDED SOLIDS 40 26 NOPT OTSG I CHEMISTRY 41 27 NOPT OTSG 2 CHEMISTRY 42
51-5033009-03 Page 6 of 50
1.0 INTRODUCTION
Framatome ANP, Inc. (FANP) initiated the Shutdown/Layup Chemistry Assessment Task (Task 3 of the Steam Generator Startup Review Project) to evaluate the layup and storage conditions in the OTSGs during the current plant shutdown. The shutdown period began on 2/16/02 @ 0255 with a turbine trip, and continued until plant heat-up in September 2003. The evaluation period was from 2/16/02 until 12/01/03, and included the Normal Operating Pressure Test (NOPT) period in addition to the periods when the plant was at ambient temperature. The objectives of Task 3 are to ensure that appropriate controls were in place during the extended outage to preclude any adverse effects on the OTSGs, and to provide a technical basis to support a one time license change request to allow OTSG operation beyond the 24 month inspection interval. 2.0 METHODOLOGY Task 3 was implemented by working on-site with site chemistry personnel to compile the OTSG lay-up chemistry environment data during the time period of the extended outage. Data was obtained in the following areas:
- OTSG Water Sample Analyses Data
- RCS Chemistry and Conditions (OTSG 1° levels)
- Fill and Makeup Water Source Chemistry Data (DWST, HEN')
- Record of OTSG opening to air/nitrogen blanket during openings
- OTSG Nitrogen Blanket Data
- Condensate/Steam and Feedwater storage data (startup chemistry effects)
- Procedures including Chemistry Layup Control, Shutdown Operations, Fill, Drain, and Layup, and Operational Chemistry Control Limits.
The data compiled was subsequently reviewed in Lynchburg by FANP to ensure appropriate controls were in place to preclude any adverse affects on SG tubing and internals. 3.0 STEAM GENERATOR EVENT TIME-LINE The plant OPS logs were reviewed, and a steam generator event time-line was prepared. The main incidents of interest were the steam generator events associated with establishing appropriate layup conditions. The events time-line is presented in tabular form in Appendix A. 4.0 PLANT CHEMISTRY DATA Plant chemistry data was obtained for the primary, secondary, and OTSG makeup water system for the shutdown period and reviewed.
51-5033009-03 Page 7 of 50 4.1 PRIMARY CHEMISTRY Corrosion experience with sensitized Alloy 600 OTSG tubing has identified reduced sulfur forms as contaminants of concern at storage and layup conditions. The analysis of sulfate in the RCS provides a good indication of the presence of sulfur forms. The RCS sulfate data for the shutdown period are shown in Figure 1. Note that after the typical sulfate spike associated with the shutdown (turbine trip), the sulfates were kept in control for the shutdown period. The normal RCS sulfate limits are <150 ppb when the temperature is below 2500Ff11. The sulfate during the shutdown period only slightly exceeded 100 ppb oil two occasions. The RCS was drained, and nozzle dams were installed in the primary heads on 2/20/02 and removed on 3/14/02; installed again on 7/5/02, and removed oil 3/13/03. During those time periods, the primary side of the steam generator would be completely drained and not subject to a corrosive environment. Between 3/14/02 and 7/5/02 and after 3/13/03, the primary side steam generators levels fluctuated from completely full when the RCS wvas pressurized to various levels as the refueling canal level changed. During these times, when a partial primary side level resulted, sulfate levels were low. No other RCS chemistry parameters or conditions are considered to be potentially detrimental to the OTSG tubing during the shutdown period. 4.1.1 NOPT The plant operated above 250'F temperature during the period from September 13, 2003 to October 4, 2003 (Figure 21). The RCS chemistry requirements during these plant conditions are given in Table 7111. The plant chemistry data for this period are shown in Figure IA. None of the control parameters were exceeded while the RCS temperature was above 250'F. 4.2 OTSG CHEMISTRY Chemistry data was obtained for both OTSGs during the shutdown period (2/16/02 to 12/1/03 including the NOPT period) for the parameters listed below. The data for these parameters are shown in the indicated figures for OTSG I and 2, respectively.
- Chloride - Figures 2, 10
- Oxygen - Figures 3, 11
- Fluoride -Figures 4, 12
- Hydrazine - Figures 5, 13
- Sodium - Figures 6, 15
- Sulfate - Figures 7, 16
- Solution pH - Figures 8, 17
- Silica - Figures 9, 14 These data were compared to the plant operating limits for the shutdown period given in Table 1121, and the EPRI guidelines given in Table 2131. Throughout the shutdown period, the chemistry was found to be within the limits of both the plant
51-5033009-03 Page 8 of 50 specifications12 ] as well as the EPRI Guidelines13]. A summary of the plant chemistry control for the layup wvater in the two steam generators during the shutdown period is given in Table 4, where it wvill be noted that the observed data is well within the limits defined in both the plant and EPRI control specifications. However, two spikes up to about I ppm were observed in the silica concentration in both OTSGs (Figures 9 and 14). The observed spikes occurred in January and in June-August, 2003. The cause of the spikes is unknown, but analytical error is one possibility. No materials degradation would result from these relatively low concentrations. Silica is not a control or diagnostic parameter in the EPRI Guidelines1 31 . 4.2.1 NOPT The plant operated above 250'F temperature during the period from September 13, 2003 to October 4, 2003 (Figure 21). The secondary system chemistry control requirements during the NOPT are given in Tables 8 and 9121, and are the same as for startup/hot standby. The OTSG and feedwater control parameters were all within the required limits (OTSG Chloride - Figures 2, 10, Sodium - Figures 6, 15, Sulfate - Figures 7, 16, and Feedwater (Figures 22 through 25). 4.3 OTSG FILL WATER The source of the OTSG fill water is the demineralized water storage tank. The chemistry data for the demineralized water during the shutdown period is shown in Figures 18 and 19. The plant specifications for the demineralized water are given in Table 3121. It is noted that on several occasions, the fluoride, sodium, dissolved oxygen, and chloride exceeded the specifications in Table 3. As indicated in the OTSG Events Timeline (Appendix A), demineralized water was added on several occasions during the shutdown period. Additions occurred during the initial shutdown period of 2/16/02 - 2/20/02 for soaks and flushes; during refill following maintenance on 4/4/02 - 4/5/02; on 11/20/02 for level adjustment; and during the period 3/5/03-3/10/03 for filling after draining for maintenance. In all cases except on 11/20/02, the demineralized water was within the required quality specifications. Demineralized water %vasadded on 11/20/02 during a small dissolved oxygen excursion %vilenthe dissolved oxygen concentration reached 200 ppb. Since this was a level adjustment addition, dilution of the fill water with the low oxygen water in the OTSGs would maintain the OTSG water at <100 ppb. Thus, no adverse effects of this addition would be expected. 4.4 NITROGEN BLANKETING A nitrogen blanket is initiated and maintained on the steam generators to exclude air (oxygen) from entering and promoting corrosion reactions, and to facilitate draining of the OTSGs when necessary. Nitrogen may be added to produce a blanket pressure, or as a trickle feed when maintenance activities prevent a positive pressure blanket.1 4] Appropriate safety precautions are taken to prevent accidents associated with nitrogen
51-5033009-03 Page 9 of 50 applications. As noted in the OTSG Events Timeline (Appendix A), nitrogen was added on numerous occasions. Based on these data, it is concluded that nitrogen was used appropriately to protect the OTSGs. However, it is apparent that not all the nitrogen addition events were recorded. For example, it is known from discussion with plant personnel that nitrogen was used during the fill, soak, and drains that occurred during the initial shutdown period. However, there wvere no nitrogen addition events during the fill, soak and drain evolutions recorded in the plant operator's logs, which provided the information for the generation of the Event Timeline (Appendix A). On 9/1/03, while the assessment team was on site, the steam generators were drained to the condenser in preparation for an AFW pump test. At that time, nitrogen was not available to blanket the generators while draining, so it must be assumed that air was introduced. Subsequently, a nitrogen blanket was established on 9/5/03 until the OTSGs were placed under vacuum for Mode 3 entry on 9/11/03. This short exposure to air is not considered to have caused any corrosive damage. The OTSGs were placed back in full wet layup recirculation following the NOPT on 10/07/03. 4.5 CONDENSATE/STEAM AND FEED WATER STORAGE Storage of the condensate and feedwvater system will have no effect on the layup conditions in the steam generators. However, in the interest of minimizing the ingress of contaminants, such as corrosion product iron oxide into the steam generators on startup, the control of storage conditions in the condensate and feedwater systems can have a significant contribution. Chemicals were reportedly added to the condensate on 2/17/2002 at 0330 at 0% power with the plant in Mode 3. Reported chemistry data is given in Table 5 show that the fluoride, chloride, sulfate and sodium were very low and that hydrazine was being added. Table 6 shows the condensate and feedwater conditions and activities during the shutdown. 5.0 DISCUSSION AND CONCLUSIONS Working on-site with site chemistry personnel, the OTSG lay-up chemistry environment data was compiled for the tine period of the extended outage beginning in February, 2002. One addition of demineralized water was made to maintain level when the makeup water dissolved oxygen was greater than 100 ppb. Since at that time high hydrazine 'vas present and low oxygen water was already in the OTSGs, oxygen control was not lost due to this addition. The plant OPS logs provided a good method of determining the steam generator events time-line (Appendix A). However, better record keeping concerning the steam generator conditions would provide better documentation in support of adequate shutdown/layup control. For example, on several occasions layup recirculation was either stopped or started in consecutive steps without the opposite step recorded in sequence. The Steam
51-5033009-03 Page IOof50 Generator lay-up status record keeping concern was captured in the DBNPS corrective action program. Layup recirculation is an important part of maintaining a uniform layup chemical treatment. On two occasions, valve misalignments following steam generator filling resulted in some period of time without recirculation wvben it wvas thought to be operating. Fortunately, chemical addition occurred along with the demineralized water fill and provided adequate distribution of chemicals in the steam generators. Subsequent sampling and analyses confirmed layup chemical control. Based on the review of steam generator layup chemistry control described and discussed above, it is concluded that no conditions existed that would require an assessment of active degradation mechanisms, crack growth rate progressions, or internal steam generator components. No conditions were identified that would have an adverse effect on, or cause any type of known corrosion damage to the steam generators during the layup period. It is projected that there wvill be no degradation of the steam generator materials prior to plant restart provided current satisfactory storage and layup conditions are maintained. These assumed storage conditions will be confirmed following plant startup and any deviations and/or discrepancies will be evaluated as to their effect on steam generator materials.
51-5033009-03 Page 11 ofS0
6.0 REFERENCES
- 1. EPRI TR-105714-R5, PWR Primary Chemistry Guidelines, September 2003.
- 2. DB-CH-06900, Operational Chemistry Control Limits, R08, March 31, 2003.
- 3. EPRI TR-102134-R5, PWR Secondary Chemistry Guidelines, March, 2000.
- 4. DB-OP-06230, Steam Generator Secondary Side Fill, Drain and Layup, R04, April, 2003.
- 5. DB-OP-06903, Plant Shutdown and Cooldown, R08, August, 2003
- 6. DB-OP-06904, Shutdown Operations, R15, August, 2003.
- 7. E-mail, R. Edwards to M. Bell, 11/11/03, OTSG Nitrogen Blanket
51-5033009-03 Page 12 of 50 TABLE 1: OTSG LAYUP WNATER CONTROL PARAMETERS"' PARAM ETER SPECIFICATION Hydrazine >75 ppm, <500 ppm pH 29.8 Sodium <1.0 ppm Chloride <1.0 ppm Dissolved Oxygen <100 ppb Sulfate <1.0 ppm TABLE 2: OTSG LAYUP WATER CONTROL PARAMETERS13 1 PARAMETER SPECIFICATION Hydrazine, ppm 75-500 pH 29.8 Sodium, ppb <1000 Chloride, ppb <1000 Dissolved Oxygen, ppb <100 Sulfate, ppb <1000 TABLE 3: DEMINERALIZED WN'ATER SPECIFICATIONS1 PARAMETER (CONTROL) SPECIFICATION Specific Conductivity, ,LS/cm <0.3 Silica, ppb <20 Sodium, ppb <3 Chloride, ppb <5 Fluoride, ppb <5 Dissolved Oxygen, ppb <100 Sulfate, ppb <5 Total Organic Carbon, ppb <100 Iron (Membrane), ppb <10 PARAMETER (DIAGNOSTIC) TYPICAL VALUE Calcium, ppb <40 Aluminum, ppb <40 Magnesium, ppb <40
51-5033009-03 Page 13 of 50 TABLE 4: OTSG LAYUP WATER CHEMISTRY CONTROL PARAMETER SPECIFICATION VALUE OTSGMI OTSG# 2 Max., Average Max., Averagc Miin. or MmIin. or Range Range Hlydrazine, ppm 75-500 67-176 116 68-136 97 pli >9.8 9.78 9.97 9.80 10.01 Sodium, ppb <1000 312 159 445 229 Chloride. ppb <1 000 69 37 77 40 Dissolved Oxygen. ppb <100 80 17 60 19 Sulfate, ppb <1000 333 154 361 241 TABLE 5: FEEDWVATER CHEMISTRY DATA DURING SHUTDOWN I)ATE TIME IIYDRAZINE, HOWER/MOI)E FLUORII)E, CIHILORII)E, SUlFATE, SOIDIUM. _phpb__ _ _ _ _ _ _ _ pibb - 2/10/02 00:15 100/1 <1 <1 2/11/02 08:00 0/3 35 2/13/02 00:40 0/3 <1 1.98 1.58 08:15 0/3 <1 2.50 1.53 2/16/02 00:00 0/3 91 20:00 0/3 1008 20:45 0/3 540 2.47 22:05 0/3 606 29 2/17/02 00:05 0/3 946 45 01:40 0/3 842 25 03:35 0/3 16300 TABLE 6: CONDENSATE/FEEDNNWATER SYSTEMS SHUTDOWN CONDITION DATE CONDITION 3/12/02 Refilling condensate maintaining pH>9.6 4/14/02 Condensate pump s/d and condensate on mini-recirc 4/20/02 Condensate pump on 5/12/02 FW cleanup/DO removal 5/23/02 Condensate shutdown 6/1/02 - 6/5/03 Condensate drained 6/5/03 Fill condensate 6/7/03 Drain condensate to remove iron 6/9/03 Refill condensate 6/10/03 Condensate on recirculation 6/17/03 Condensate on mini recirculation 6/28/03 Condensate off mini recirculation 6/30/03 Drain deareartors for maintenance 7/5/03 Restart condensate pump and refill deareartors 7/15/03 FW cleanup and DO removal 7/20/03 Condensate layup with mini-recirculation
51-5033009-03 Page 14 of 50 TABLE 7: RCS STARTUP/HOT STANDBY CONTROL PARAMETERSM'] [ PARAMETER I Prior to >2501F and Criticality I Chloride, ppb <150 Sulfate, ppb <150 Fluoride, ppb <150 Oxygen, ppb <100 TABLE 8: OTSG STARTUP/HOT STANDBY CONTROL PARAMETERS 12 PARAMETER INITIATE ACTION Sodium, ppb >100 Chloride, ppb >100 Sulfate, ppb >100 Cation Conductivity, ,uS/cm >2 TABLE 9: FEEDWATER STARTUP/HOT STANDBY CONTROL PARAMETERSL J PARAMETER INITIATE ACTION SU Dissolved 02, ppb >100 Hydrazine, ppb <8x 0 2 . <50 SU Suspended Solids, ppb >100 Hot SB Suspended Solids, ppb >10
51-5033009-03 Page 15 of 50 FIGURE 1: RCS SULFATE 300 250 200 m a- 150 100 50 0 i,\ z3!\oa
\ 4r>,
# e f9ha>b 5\A IeS /,, R&,` e So0 ,e\ e f ,N\° e e\ "N ',r\° ,° DATE
51-5033009-03 Page 16 of 50 FIGURE IA: NOPT RCS CHEMISTRY 70 60 50 40 -- O- Chloride 0. .0 -*O- Fluoride 0. 6 Dissolved Oxygen 30 I Sulfate 20 10 0
~ ~~~
cb\ ~ ~ ~ ~ ~ ~ ~ ~ ()()~~ ~ ~ rb ()(1(1(~ DATE
51-5033009-03 Page 17 of 50 FIGURE 2: OTSG I CHLORIDE 90 80--oI _ ____ _ 60 50 40 30 -
- 20. -----
1-- 1A1 10 0 DATE
51-5033009-03 Page 18 of 5O FIGURE 3: OTSG 1 DISSOLVED OXYGEN 90 80 - - ------ _ _ _ _ _ _ _ _ _ 70-60 - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 30 - - - - -_ _ _ _ _ _ 20 10 -- _ _ _ _ __ _ DATE
51-5033009-03 Page 19 of 50 FIGURE 4: OTSG I FLUORIDE 35 30 25 20 m .0 0. i5 10 5 0 4%4% 4% ~ 4% d\\'\ ~ ~ ~ ~ ~ ~ ~ ) -p ~ - ' ' DATE
51-5033009-03 Page 20 of 50 FIGURE 5: OTSG 1 HYDRAZINE 160 140 _ _ _ 120 -__ ____ __ ________ 0 100 60 ____XI__ 40'-______ ___________________ _ _ - 20 - - i- . . __ ;_ i____ . _ _ .__._._._. 0. DATE
51-5033009-03 Page 21 of 50 FIGURE 6: OTSG I SODIUM 600 500 400 0.
- a. 300 200 100 0
\ \ 4& \& \& \IZPI 1411", 14RPI 144"ll 14"ll "4& P P 4 4P ,Ib\Z$b Nlb\c' N4P Nb\Z Nb\cz \'§) N\;§) ,, e 0 e s "$%,, Z CP 4' , N\ 4 b\, 4 )\ A\ b\ Cb\ Q\ "'S C DATE
51-5033009-03 Page 22 of 50 FIGURE 7: OTSG I SULFATE 700 600 500 400 .0 0. 0. 300 200 100 0 Nit tN ssozDAe I\N \N e lb\is \\ 3\
\ l\ \ \N \\\
DATE
51-5033009-03 Page 23 of 50 FIGURE 8: OTSG I pH 10.4 10.2 10 ci, I-- z 9.8 =L 9.6 9.4 9.2
,\& soegos & & %e ch\o Iot Iotsotsot sot sotsot sot DATE
51-5033009-03 Page 24 of 50 FIGURE 9: OTSG 1 SILICA 1200 1000 800 m
- 0. 600 0.
400 200 0
,,N ,9 q\9 0 & ! sz5 , lz5 0 51 4 5) o 59) \59, Xp !5
,\
Pt' O\ N'
-0 N\
' 'I\, 4 N
\0 , s 4 , \ e 4, IS, :3 lzl b59) 51 SP b,\
'OX0 \
Z v \ \, ,
" Q,
'Z
\
',b ',b -) ',b 'b ,b xjz)
-"\,p 0
DATE
51-5033009-03 Page 25 of 50 FIGURE 10: OTSG 2 CHLORIDE 250 200 150 0 100 50 0
\6Zll° 6\°`15 st\°51 e 14 "A \°
,t2 I' lbP° I\ ""o,\Z
.t°Z\Z e e \< e\ e\ e\ lb\6 DATE
51-5033009-03 Page 26 of 50 FIGURE 11: OTSG 2 DISSOLVED OXYGEN 70 60 50 40 .0 0. 0. 30 20 10 0 I I It, Ir, IC IV CI 'V IV CV CI IC lrz ~ll~ lz lZ (Z ~ (Z ~ lZ Z Q
'b
( (Y (~% (Y a% Y a% Y a% (),lZ Cb l. l Z l e DATE
51-5033009-03 Page 27 of50 FIGURE 12: OTSG 2 FLUORIDE 40 35____ _ 30 25 25150 - __-__ _i = _ ___ _ ] 10*-- -- _ DATE
51-5033009-03 Page 28 of 50 FIGURE 13: OTSG 2 HYDRAZINE 140 120 100 80 E 0. 0. 60 40 20 0 TN3\& A5 b b\ NNN to\° lb\°3'\O l°5z,5b\ b \ NO N DATE
51-5033009-03 Page 29 of 50 FIGURE 14: OTSG 2 SILICA 1200 1000 800 m a.
- a. 600 400 200 0.! x . . . 5p NS\~~~~~~~~~1,§,\S 4Z ~ 1,0§~ ~ \~
DATE
51-5033009-03 Page 30 of 50 FIGURE 15: OTSG 2 SODIUM 1200 1000 800
- 0. 600 400 200 0
,P NbP A dP stPNbP P P P P DATE
51-5033009-03 Page 31 of S0 FIGURE 16: OTSG 2 SULFATE 700 600 500 400 Q0 0. 300 - 200 - 100 0. 4\& N\ \ 4% 4%&s 4&\ %& &H & \ 5 \4445 I5 4444 o 4 4 DATE
51-5033009-03 Page 32 of 50 FIGURE17: OTSG 2 pH 10.4 10.2 - A 4 10* A LA 111*1i 9
- 0. 9.8 ~~~~~~~CNI-GETS rvr
-{
9.6 -l 9.4 9.2 666\"I$ 66\Fl e e6\ 6 <6\5 .,bfl 66°6\ b\° 66 b\P e\ 66\ 6\ Nz°06°\6° N\ N\ N\ < DATE
51-5033009-03 Page 33 of 50 FIGURE 18: DEMINERALIZED WATER 18 16 i I I 14 - 12 - 10 I - I _______ FLUORIDE m C0
- 0. --- SILICA 8 I -_____________________________ _____________________________________________________ -- SODIUM 6-p EJ ir~~~~~~~1 4
2-A L 4\ n . . DATE
51-5033009-03 Page 34 of 50 FIGURE 19: DEMINERALIZED WATER 900 - 800 _ _ 700 ___ 600 500- SULFATE -CL
- n. DISSOLVED OXYGEN 400 A CHLORIDE 300 l___
200 -___ 100 3 0 DATE
51-5033009-03 Page 35 of 50 FIGURE 20: NOPT FEEDWATER DISSOLVED OXYGEN 3 2.5 2-m CL 0L 1.5 1 0.5 -. 4 0 lb lb lb lb n, C. Z n, lb lb lb
"'p race lb rh p-n.
C3-n p-C161 CT-,
'p- z-n, Z)- p lb sjz lb n, (Zs-n.
(Zs- "\(§)
,4Ili 4:11 43 tP 4Q, '14, RO R; CP 41 (p ql cb 0101 01\r CP C,\rp Cb\Tl CP ,,\rl DATE
51-5033009-03 Page 36 of 50 FIGURE 21: NOPT RCS TEMPERATURE 600.00 500.00 400.00 U. CI, Lu a: 300.00 CD Lu 200.00 100.00 0.00 1) 5Z5 XIO 01 0
!p p
(:bxql p all", p CO, COO 4sp Oex 5) O' lp 4 p p, 't - 5g) e e "S p p, (p K", I I',' x e .1"ZP 0\0\ p'b a, DATE
51-5033009-03 Page 37 of 50 FIGURE 22: NOPT FEEDWATER SODIUM 3 2.5 .1-I 2 __
- 0. 1.5 0.
.1- i 1
0.5 1-0 DATE
51-5033009-03 Page 38 of 50 FIGURE 23: NOPT FEEDWATER CATION CONDUCTIVITY 3 2.5 2 E U 0 1.5 E 1 0.5 0 0'e, ot ao eot , eotsot
, sot c o o Rote ot q Rot \ ot Ro toATo DATE
51-5033009-03 Page 39 of 50 FIGURE 24: NOPT FEEDWATER HYDRAZINE 900 800 -_ _ _ 700 600 _ _ __ _ _ _ 500 400 300. 200-100 - __ .. _. . 0i 9/23/03 9/24/03 9/25/03 9/26/03 9/27/03 9/28/03 9/29/03 9/30/03 10/1/03 10/2/03 10/3/03 DATE
51-5033009-03 Page 40 of 50 FIGURE 25: NOPT FEEDWATER SUSPENDED SOLIDS 12 10 1-° 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0-- 8 1 ~ - - _ _ - _ _ _ _ _ __ _ _ _ _ m C. 6 a. 4 2 _ A DATE
51-5033009-03 Page 41 of 50 FIGURE 26: NOPT OTSG I CHEMISTRY 200 180 _ _ _ l ~~~~~~~~~~~~~~~~~~-O 180 Sodiuml 160 Chloride 8 ~~~~~~~~~~~~~~~~~~~~~~~~~~~Sulfate 140 - ___ 120- __ _ 160 m 0. 0. 40 . 20 . 9 _9 DATE
51-5033009-03 Page 42 of 50 FIGURE 27: NOPT OTSG 2 CHEMISTRY 200 - 180 _ _ __- __ Chloride 160 -DSodium
. ~~~~~~~~~~~~~~~~~~~-a
- S ulfate -
120- -_ - CL 100 ___- 40 60 20 =A 0-DATE
51-5033009-03 Page 43 of 50 APPENDIX A: OUTAGE OTSG EVENT TIMELINE Date l Tlme l OTSG#1 Secondary I Primary Nitrogenl OTSG#2 Level l Level- Nitrogen I General Level In. FR Level ft. [t. In. FR Primary I Comments 2/16102 10:30 Start Filling 10:40 Start Filling 12:24 Draining 14:51 90% OR 19:04 90% OR 19:11 90% OR 22:38 Complete filling 23:41 Start Draining Start Filling _ _ 2/17/02 0:35 Start Draining _ __ 1:53 Start Draining 2/19102 23:09 On WLU Recirc.? 23:40 Start Filling 530 2/20102 0:05 WLU chem add WLU chem add 1:00 __X 5:41 _ Start Filling 5:52 On WLU Recirc.? On WLU Recirc.? 2/26/02 11:39 22.5 22.5 15:52 23.5 23.5 3/1/02 0:09 Stop Recirc. 0:17 Stop Recirc. 3/5/02 2:00 Start Draining 650 2:30 Stop Drain 600 l 4:39 5 psi 5 psi 17:16 Start Draining . 22:05 Complete Draining 370 22:07 Complete Draining 0 1:32 Strart Drain Start Drain 3/15/02 5:15 20.5 20.5 18:00 0 0 3/16/02 5:02 18.8 18.8 3/17/02 2:10 2.7 psi 5:10 1 psi 20:00 Add 3/18102 4:00 Add 3/22102 9:28 Add 15:14 Add 22:54 Add
51-5033009-03 Page 44 of 50 Date Time OTSG#11 Secondary Primary Nitrogen OTSG#2 I Level Level- Nitrogen General Level Level In. FR Primary Comments In. FR ft. ft. 3/23/02 5:51 5 Add _ 8:55 __ _ _ _ _ _ Add__ _ _ _ __ _ _ _ _ _ 14:50 Add _ __ _ __ _ _ _ _ _ 21:10 __ _ _ _ _ _ A dd _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ 3/24102 3:22° Add 9:30 Add 16:20 Add . 20:37 Add 3/25/02 2:50 Add 8:30 Add . 13:40 Add 17:56 Add 23:01 Add 3/26/02 2:43 Add . 7:45 Add 13:00 Add 16:51 __ _ _ _ _ _ A dd _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ 21:36 Add_ 3/27/02 2:06 Add 4:50 _ Add 9:20 Add 16:17 Add 20:55 Add 3/28/02 0:18 Add 3:57 Add 10:00 Add 21:46 Add 3/29/02 2:09 Add Add 5:00 Add Add 11:06 . Add Add 7 ~~~~~16:10 Add Add 21:12 3/30/02 3:01 9:36 15:56 Add Add 3/31/02 4:40 10:03 Add Add 15:53 Add Add 22:04 Add . Add 4/2/02 8:40 Add . Add 15:33 Add . Add
51-5033009-03 Page 45 of 50 Date Time OTSG#1 Secondary l Primary Nitrogen OTSG#2 Level Level-* l Nitrogen General Level l Level In. FR Primary [ l Comments In. FR ft. ft. [ l 4/3/02 1:52 Add Add 9:19 Add Add 13:02 Off Add 16:50 Add Add 17:09 Add Add 4/4/02 10:30 Start Filling 0 0 10:43 Add 21:55 Start Filling 280 4/5/02 0:17 WLU Chem. Added WLU Chem. Added 14:07 Complete Filling 623 16:29 Complete Filling 650 4/6/02 3:37 On WLU Recirc.? 4:40 On WLU Recirc.? 4/7/02 19:30 0 0 No Both Drained 4/9/02 11:08 Stop Recirc. 11:35 Stop Recirc. 4/11/02 13:04 On WLU Recirc.? 5/12/02 18:18 On WLU Recirc.? On WLU Recirc.? MSVs found closed, no recirc. path. __________ opened. 5/15102 20:44 On WLU Recirc. 6/10/02 5:30 Stop Recirc. 23:46 0 0 6/11/02 0:46 3.6 3.6 2:51 13.6 13.6 4:34 23.5 23.5 11:25 _ _ _ _ _ _ _ _ _ 23.5 6/12102 8:13 On WLU Recirc.? _ 23:30 Stop Recirc. 6/13/02 12:56 On WLU Recirc. 13:13 On WLU Recirc. 6/27/02 13:15 On WLU Recirc. 6/28/02 10:09 Stop Recirc. 13:18 On WLU Recirc. 13:29 On WLU Recirc. 16:58 0.4 0.4 6/30/02 8:43 Start draining RCS cold legs 9:50 Completed draining RCS cold legs
51-5033009-03 Page 46 of 50 Date Time OTSG#1 Secondary Primary Nitrogen OTSG#2 Level Level* Nitrogen General Level Level In. FR Primary Comments In. FR ft. ft. 715/02 Nozzle dams _____________ __________ ~~~~~~~~~~~~~~~~~ 7/221/02 11:49 18.1 18.1 7/22/02 4:28 23.3 23.3 7/28/02 18:21 On WLU Recirc. 7/29/02 18:11 On WLU Recirc. __X__ 7/30/02 2:20 0 0 7/31/02 Stop Recirc. 8/3/02 11:25 On WLU Recirc. 8/18/02 7:04 On WLU Recirc. CR-02-4431: WLU OTSG#1 valves _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _____ ________ _____ _____ misalig nneed d.alig 11/20/02 6:51 Added water Out vents Added water Out vents 1/26/03 13:15 X 11 L 11 1/27/03 18:38 0.3 0.3 2/1/03 14:20 6.1 6.1 _ 17:17 22.2 22.2 2/28/03 4:34 14 14 3/1/03 5:28 20 20 3/2/03 14:40 Start Draining 20:30 5 psi 22:09 5 psi 3/3/03 0:35 5 psi 4:53 Complete Draining 0 SG#1 vented 16:58 _.SG#1 vented for maintenance 3/4/03 1:10 23.5 23.5 3/5/03 16:26 Stop Recirc. Preparation for draining 18:00 Start Filling 19:45 WLU Chem. Added 3/6/03 0:49 5 psi 1:04 Start Draining 6:04 0 7:01 Complete Filling _ _ _ __ 12:05 On WLU Recirc. 17:35 Complete Draining 370 3/10/03 13:08 ______________________ __________ ____________ __________ StartrtFFilling lln __________ ____________ __________ ____St 3/12/03 22:57 Start Filling 594
51-5033009-03 Page 47 of 50 Date Time OTSG#1 Secondary Primary Nitrogen OTSG#2 Level Level" Nitrogen General Level Level In. FR Primary Comments In. FR ft. _ ft. 3/13/03 WLU Chem. Added Nozzle dams ______________________ ~~~ ~~~rem oved 0:26 Complete Filling 3/15/03 14:54 On WLU Recirc. On WLU Recirc. 11:30 Start Depress. 12:10 Complete Depress. _ 13:20 2-3 psi . ____________ 16:18 22 psi 16:32 On WLU Recirc. Stop Recirc. 3/23/03 14:00 On WLU Recirc. 4/7/03 4:07 Stop Recirc. 4:11 Stop Recirc. 4/10/03 14:40 On WLU Recrc. On WLU Recirc. 4/16/03 22:12 On WLU Recirc. On WLU Recirc. 22:39 _ Off recirc. 5/28/03 22:09 Stop Recirc. _ MSV repair 5/30/03 7:48 _ _ _ On WLU Recdrc. 6/9/03 18:04 On WLU Recirc. 7/2/03 15:54 On WLU Recirc. 7/25/03 14:25 Stop Redrc. . 8/15/03 0:00 615 621 8/15/03 5:40 On WLU Recirc. 5:45 On WLU Recirc. _ _ _ 8/21/03 12:00 616 _ _ 8/22103 7:00 615 _ _ _ _ 8/27/03 9:00 614 9/1/03 0:35 note note note: Both removed per DB-OP-06230 3:23 Start Draining 614 Start Draining _ 4:00 _ 615 8:00 403 10:00 397 23:00 404 9/3/03 7:09 BEGIN PLANT HEATUP 9/4/03 15:00 410 1 1 1 403 9/5/03 2:05 1 _ 1 Add, 4 psi I I _ I Add, 2 psi
51-5033009-03 Page 48 of 50 Date Time OTSG#1 Seconda Prima Nitrogen OTSG#2 Level Level- Nitrogen General Level Level In. FR Primary Comments In. FR ft. ft. 9/7/03 16:00 426 _ _ _ _ 11:00 446 443 18:30 RCS at 100-110 F 9/10/03 14:42 Add, 4 psi Add, 4 psi 15:15 _ 20 psi _v__ 23 psi_ 17:00 Start Draining 425 _ Start Draining 440 18:15 Stop Draining 370 19:51 Stop Draining 390 9/12/03 2:00 390 3:00 440 14:48 Start Filling _ _ _ 15:00 367 _ BOX _ 15:28 Stopped Filling 375-405 i 19:00 414 9/13/03 7:12 RCS at 179 F 10:00 381 382 16:00 472 17:00 449 9/14/03 16:00 300 23:00 280 9/15/03 3:00 319 10:45 Start FS&D Start FS&D 10:55 Start 2 hr soak _ 11:18 _ Start 2 hr soak 12:55 Ended 2 hr soak, _ X _ _ _ _ Drain to Condenser _ 13:19 Ended 2 hr soak, Drain to Condenser 22:00 57 9/16/03 1:00 58 334 2:09 Filled and Start 2 hr soak 3:26 Filled and Start 2 hr soak l 4:13 _ __Ended 2 hr soak, _ Start Draining 5:35 Ended 2 hr soak, _ Start Draining 6:00 303 9:00 65
51-5033009-03 Page 49 of 50 Date Time OTSG#1 Secondary Primary Nitrogen OTSG#2 Level Level.. Nitrogen General Level Level In. FR Primary Comments In. FR ft. ft. 9/16/03 11:00 60 _ _ _ _ _ X 14:00 _ 329 16:00 324 21:00 . 67 . 9/17/03 0:00 61 . - 3:00 321 4:00 324 4:18 Ended 2 hr soak, Start Draining 4:33 Ended 2 hr soak, _ Start Draining . 11:00 44 _ 14:00 _ _ _ 46 __ 9/22/03 6:00 53 23:00 55 10/2/03 21:00 50 . . _ . - 10/3/03 0:00 314 5:00 . 46 19:00 42 21:00 60 . 22.00 257 10/4/03 0:00 Start Filling 393 From Condensate 22:00 Start Filling . From Condensate . 22:49 Stop Filling 575 _ 23:20 _ _ Stopped Filling 575 _ X 10/5/03 0:00 . 563 4:00 484 _ 15:00 650 17:00 635 18:00 616 19:00 615 20:03 Condensate ShutdownMWL U 10/7/03 0:00 650 1:00 650 10/8/03 15:00 619 10/14/03 16:48 619 10/22103 21:12 Stop WLU Recirc. 0:00 X _ 608 E_ _ 10/23/03 5:00 612
51-5033009-03 Page 50 of 50 Date Time OTSG#1 Secondary Primary Nitrogen OTSG#2 Level Level** Nitrogen General Level Level In. FR Primary Comments In. FR ft. ft. 10/24103 0:05 Start WLU Redrc. 0:08 Stop WLU Recirc. 21:18 Start WLU Recirc. 11/1/03 0:40 Add 1:24 Start Draining 565 14:23 stop draining 300 16:30 Isolated 11/2/03 1:00 297 2:00 650 11/5/03 17:00 319 _ 11/6/03 2:20 Complete Filling 3:00 650 3:55 Start WLU Recirc. 14:00 595 14:10 Start Filling 588 16:00 650 11/7/03 9:37 WLU Recirc. WLU Recirc. 16:00 620 . 11/8/03 10:35 Started Chem. Add. 11:15 Stopped Chem. Add. 12/1/03 11:54 Stop WLU Recirc. 12/2/03 0:00 _ 613 _ 12/3/03 0:00 _ 609 12/4/03 14:23 Start WLU Recirc.
LAR 03-0019 FRAMATOMIE DOCUMENT 51-5034594-02 A Steam Generator Tubing Operational Assessment for Davis Besse (19 pages follow)
20440.9 (2/2002) 'A ENGINEERING INFORMATION RECORD FRAMATOME ANP Document Identifier 51 - 5034594 - 02 03 - 1204 Title A Steam Generator Tubing Operational Assessment for Davis Besse PREPARED BY: REVIEWED BY: Name J. A. Begley Name S.L. Fleck Signature Date 1219103 Signature
/-
A Iof
"" o Date 12/9103 Technical Manager Statement: Initials Reviewer is Independent.
Remarks: This report describes the results of an operational assessment for steam generator tubing at Davis Besse mid cycle 14. ENIERNFENOC ENOINEERINO DOCUMENT REVIEW 1.W-WORK ItAY PROCCEM 2.= REVISE ANDRxSndTWORK MAY PROCEED SUBJECTTO PNOORPORATION OF CNAMM S.= REVISE AND RICUIt WORK MAY NOT PRCE 4.0 REVIEW NOT REMMI WORK MAY PROCEED PERMISSION TO PROCEED ON ThIS DOCUMENT DOES NOT FEIEVE SUPPLIER FROM FULL COMPPUANCIE WITHE OJCONTRACT SPECIFICATWON
~~~~~AE Page I of _19_
51-5034594-02 Page 2 of 19 Table of Contents Section Title 1.0 Introduction 3 2.0 Operational Assessment for Mid Cycle 14 4 3.0 Signal Amplitude Approach to CMOA 11 4.0 Conclusions 17 5.0 References 18 Record of Revisions Section Revision Description All 00 Original Release All 01 Updated to Include Lower TEC All 02 Updated to Include a Discussion of Projected Numbers of Indications
51-5034594-02 Page 3 of 19 1.0 Introduction An operational assessment for the first mid cycle of operation after 13RFO at Davis Besse was performed. The previous operational assessment' for a full cycle length of 1.85 EFPY was reviewed and updated as needed. Recent degradation growth rate information2 for OTSG plants was compared to parameters used for the full cycle length analysis. No updates were required. The previous analysis remains valid and Is bounding for mid cycle operation. Projections for the number of indications expected at a mid cycle inspection were developed to provide a basis for evaluation of degradation progression rates. The limiting form of tubing degradation at Davis Besse is considered to be freespan axial ODSCC/ IGA (groove IGA). A recently developed eddy current signal amplitude approach 3 to CMOA analyses Is provided for this mechanism. It provides a check of conventional physical sizing methodologies and Is more directly related to noise effects on detection sensitivity requirements.
51-5034594-02 Page 4 of 19 2.0 Operational Assessment for Mid Cycle 14 Table 2.1 lists previous operational assessment results' for full cycle operation In Cycle 14. A bounding approach was used with all input at worst case 9 5 th percentile values. Upon review of latest information 2. degradation growth rate parameters remain either appropriate or conservative. Since margins exist for a bounding approach to full cycle operation, structural requirements are met for mid cycle operation. As was the case for full cycle operation, projected mid cycle SLB leakage is zero other than that nominally associated with preexisting degradation in rolled tube ends In the upper tubesheet as well as leakage from mechanical sleeves and plugs. A conservative projection for mid cycle SLB leakage is the same as for full cycle, 0.11 gpm in the limiting steam generator, S/G A. However, since this projection was developed tube end cracking was found In a sister OTSG in the lower tubesheet4 . Based on this information, the limiting projected full cycle SLB leak rate at Davis Besse should be Increased by 7% to account for undiscovered lower tube end cracks. This leads to a revised value of 0.12 gpm. The Ume for degradation growth at mid cycle, estimated as 1.4 EFPY. Is less than full cycle, 1.85 EFPY, structural margins at mid cycle will increase by about 15% compared to those for full cycle operation. Structural integrity for freespan axial ODSCC was determined via a multi-cycle Monte Carlo approach' 5. Updated results for mid cycle operation are shown in Figure 2.1. This plot shows the distribution of worst case burst pressures. The 95th percentile worst case burst pressure is about 5370 psi, well above a nominal 3AP of 4050 psi. Similar results for full cycle operation are shown in Figure 2.2. Here, the 9 5 th percentile worst case burst pressure is about 4300 psi. Figure 2.3 shows the distribution of projected number of detected indications at mid cycle. This is to be compared to the distribution of projected number of detected indications of freespan axial ODSCC/IGA for full cycle operation shown in Figure 2.4. For mid cycle the best: estimate is 8 compared to about 10 for full cycle. Table 2.2 provides a summary of projected number of degradation sites for full and mid cycle operation for the active degradation mechanisms at Davis Besse. Wear Indications are left in service if NDE maximum depths are less than 40% TW. The rate of appearance of new wear indications is very small. Hence, cycle length has little effect on the estimated total number of wear Indications. All other degradation mechanisms follow a plug on detection repair scenario, thus cycle length will affect the expected number of new indications. Overall the projected number of indications at mid cycle with a plug/repair on detection repair scenario Is about 60% of the number expected for full cycle operation. In terms of a comparison of projected numbers of indications for 13RFO versus observed numbers of indications at 13RFO, the following points are noted:
- Freespan axial ODSCC was first observed at 13RFO. Projections for the initial onset of a degradation mechanism are highly variable. Accordingly, 8 were observed while 2 were projected.
- For roll transition PWSCC, a projection of 2 versus an observation of 2 is excellent.
51-5034594-02 Page 5 of 19
- Projections for axial PWSCC at tube ends were intentionally conservative. Inspection results at 1 RFO and 12RFO led to a Weibull slope of 14 compared to a more realistic maximum slope of 6. The observed number of Indications at 13RFO reflects a more realistic Weibull slope. It takes about 3 inspections to develop a reliable Weibull slope.
- The difference between projected and observed numbers of upper bundle volumetric IGA indications for 13RFO is due to improved detection sensitivity as a result of chemical cleaning performed at 12RFO.
- Use of a new eddy current technique at 13RFO combined with chemical cleaning at 12RFO led to a low projection compared to the observed number of Indications, 220 versus 288. The eddy current technique for 14RFO mid cycle will be the same as for 13RFO.
For mid cycle operation of about 1.4 EFPY, projected structural margins are about 15% greater than full cycle operational, projected numbers of indications remain the same for wear and decrease by about 20% for other degradation mechanisms and projected SLB leakage remains at nominal projected values due to mechanical plugs and sleeves and preexisting PWSCC In rolled lengths at upper tubesheet expansion transitions. As noted In another reporte degradation growth is not expected over the extended length of downtime prior to startup for Cycle 14. A substantial margin exists for any unexpected degradation growth that may have occurred.
51-5034594-02 Page 6 of 19 Table 2.1 Bounding Operational Assessment Results for Full Cycle Operation Degradation BOC Worst 95th EOC EOC Projected EOC Structural Mechanism Case Percentile Bounding Bounding Degradation Allowable Margin Degradation Degradation Axial Circ Severity Degradation Growth for Length Length Severity 1.85 EFPY Wear 47.7 %1W 5.4°1hW 0.4- NA 53.1ioTW 69.7%/oTW 16.6%lW Avg. Depth Avg. Depth Avg. Depth Avg. Depth Volumetric IGA 46.0 %YTW 15.5 %1TW 0.32' 0.32' 0.20D 0.37" 0.1 (Axial Force Avg. Depth Avg. Depth Eff. 100%/aTW Eff. Eff. Loading) Length 1 00%lW 100%TW Length Length Volumetric IGA 46.0 %YTW 15.5 YoTW 0.32" 0.32 61.8%TW 72.3%/oTW 11.5%/47W (Pressure Avg. Depth Avg. Depth Avg. Depth Avg. Depth Avg. Depth Loading) Circurnferential 35.9 %ToTW 22.5 %/oTW NA 0.38" 0.23' 0.37" 0.14" SCC at Top Avg. Depth Avg. Depth (750) Eff. 100%1aTW Eff. Eff. Span Dents Length 100%TW 100%TW Length Length
51-5034594-02 Page 7 of 19 Table 2.2 Both Found and Projected Numbers of Indications for Limiting Steam Generator Normalized to 100% Inspection Scope Projected Degradation Found Projected Found 14RFO Projected Mechanism 12RFO 13RFO 13RFO without Mid Cycle Mid Cycle Freespan Axial 0 2 8 10 8 ODSCC___ __ Roll Transition 0 2 2 5 4 PWSCC Tube End Axial 30 140 69 63 new 54 new PW SCC__ _ _ _ ___ _ _ _ _ Upper Bundle Volumetric IGA 15 15 66 66 51 Wear 177 220 288 288 288 Tube End Circumferential 0 na 5 5 4 Circumferential Cracking at Upper 0 na 2 2 1 Bundle D en ts_ _ _ _ _ _ _ __ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Notes:
- Freespan axial ODSCC was first observed at 13RFO. Projections for the initial onset of a degradation mechanism are highly variable. Accordingly, 8 were observed while 2 were projected.
- For roll transition PWSCC, a projection of 2 versus an observation of 2 Is excellent.
- Projections for axial PWSCC at tube ends were intentionally conservative. Inspection results at 11RFO and 12RFO led to a Weibull slope of 14 compared to a more realistic maximum slope of 6.
The observed number of indications at 13RFO reflects a more realistic Weibull slope. It takes about 3 inspections to develop a reliable Welbull slope.
- The difference between projected and observed numbers of upper bundle volumetric IGA indications for 13RFO is due to improved detection sensitivity as a result of chemical cleaning performed at 12RFO.
- Use of a new eddy current technique at 13RFO combined with chemical cleaning at 12RFO led to a low projection compared to the observed number of indications, 220 versus 288. The eddy current technique for 14RFO mid cycle will be the same as for 13RFO.
51-5034594-02 Page 8 of 19 Distribution of Projected Worst Case Degraded Tube Burst Pressures, Freespan Axial ODSCC at Mid Cycle Histogram CDF 250- _-*-°--O - 1.0
-0.9 200 - -0.8
-0.7 150 -0.6
+/-0.5 4-100 -0.4 0.3 50 0.2 0.1 0o---
1 2 3 4 5 6 7 8 9 10 ksi Figure 2.1 Distribution of Projected Worst Case Burst Pressures for Axial ODSCCIIGA at Mid Cycle.
51-5034594-02 Page 9 of 19 Projected Distribution of Minimum Degraded Tube Burst Pressures at 14RFO Due to Freespan Axial ODSCC/IGA Histogram CDF 180 ,1.0 160 0.9 140 -0.8 i 0.7 120+ 0.6 100l
.0.5 801
-0.4 60
-0.3 40t 20
- 0. ).0 2 3 4 5 6 7 8 9 ksi Figure 2.2 Distribution of Projected Worst Case Burst Pressures for Axial ODSCC/IGA after Full Cycle Operation, 14RFO.
51-5034594-02 Page 10 of 19 Distribution of Expected Numberof Freespan ODSCC Indications at Mid Cycle Histogram CDF 3001 ~~~1~~ 1.0
< 1~~~~~~~~0.9
/~~~~~~~~~~~~~ 0.8 0.7 200--
/ 0.6
-0.5 0.4 loot / 10.3
. 0.2
/
n i 0 123467 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Number (persimulation) Figure 2.3 Distribution of Projected Number of Detected Freespan Axial ODSCC/IGA Sites at Mid Cycle 14 Inspection.
51-5034594-02 Page 11 of 19 Projected Freespan Axial ODSCC/IGA Sites at 14RFO Histogram CDF 2507 T1.0 0.9 200- 0.8
-0.7 150
/ 0.6 f0.5 0.4
/
1001 0.3
- 50. 0.2
-0.1 0i _- _- .1. l I I I11 v .W 0 10 20 30 Number (per simulation)
Figure 2.4 Distribution ofProjected Number of Detected Freespan Axial ODSCC/lGA Sites For Full Cycle Operation.
51-5034594-02 Page 12 of 19 3.0 Signal Amplitude Approach to CMOA NDE measurements of physical crack dimensions provide an Indirect route to CMOA analyses and the evaluation of the effect of eddy current noise on the probability of detection of degradation as a function of degradation severity. A more direct route is provided by correlating burst pressure with eddy current signal amplitude. The burst pressure of tubing with axial ODSCC/IGA degradation can be related to the signal amplitude of the Plus Point probe and the length of degradation as measured via the Plus Point probe3 . Figure 3.1 shows a plot of measured burst pressure versus a calculated burst pressure using peak to peak Plus Point voltage and Plus Point length as input. This relationship was specifically developed for OTSG tubing. Similar formulations are available for other tubing sizes as well as for axial PWSCC. Measured burst pressures are for tubing with actual service induced axial ODSCC/IGA. The burst pressure equation Is given by: P8S(S~+S~).~i-
=05 P* (0.79 + 0.184
- in(VP))J l ( r )~~R; [ A +2t 1.29 ]
where, t is the wall thickness, R, is the mean radius, S. is the yield strength, S, is the ultimate strength, Lop Is the Plus Point length and V,,p Is the peak to peak Plus Point voltage. If Sy + S, are taken as the average value at temperature of 136,590 psi, actual burst pressures are normally distributed about the calculated burst pressure with a standard deviation of 646 psi. Hence, uncertainties in the burst pressure due to relationship uncertainty and material property variation are easily considered. If a degradation site is undetected, growth over the next cycle of operation must be considered. Degradation growth leads to a decrease in burst pressure. Thus, in order to meet the 3AP minimum burst strength requirement at EOC, undetected degradation must exhibit a burst strength considerably higher than 3AP at BOC. A degradation growth allowance can be accommodated using the growth rate distributions of conventional CMOA analysis. Monte Carlo calculations combined the uncertainties in material tensile properties, burst equation uncertainties and growth allowances leading to the results of Figure 3.2. The limiting combinations of Plus Point voltages and lengths that must be detected in order to meet a 3AP after 1.85 EFPY and 1.4 EFPY of operation are illustrated the probability of interest, 0.95. This Is more conservative than the probability of 0.90 specified by the EPRI Tube Integrity Assessment Guidelines4 . If degradation sites are present in the steam generator with a degradation severity above the must detect curve, then detection is required to meet the minimum required EOC burst pressure. Since axial ODSCC/IGA is detected with the bobbin probe In OTSG's, the correspondence of Plus Point voltage for SAIIMAI indications to the bobbin probe voltage of NQI indications needs to be considered. Limited data suggests a minimum I to I correspondence. A further evaluation is in progress. Early results Indicate that increased emphasis on the absolute bobbin probe signal is worthwhile.
51-5034594-02 Page 13 of 19 One check of the reasonableness of the must detect curves is provided by consideration of the Plus Point voltage-length correlation with burst pressure as applied to years of results of In situ pressure testing. Figure 3.3 plots condition monitoring acceptance curves for meeting a temperature compensated minimum burst pressure of 4050 psi at probabilities of 0.95, 0.90 and 0.50. Plus Point voltages and lengths for indications which passed In situ testing at a 4050 psi target pressure are also shown In Figure 3.3. Large amplitude signals that passed in situ testing are found to be confounded with dent and ding signals leading to a large peak to peak signal. Only one burst pressure in situ failure has been observed after a very large number of in situ tests InOTSG plants. It is plotted as a large diamond symbol and lies very close to the 50/50 burst line. The correlation of burst pressure with Plus Point voltage and length is in excellent agreement with years of in situ testing results. For completeness, Figure 3.4 shows some historical in situ data and the empirical CM curve which has been used in the past. The historical empirical curve and present Monte Carlo calculations agree remarkably we!l.
51-5034594-02 Page 14 of 19 OTSG Tubing, Axial ODSCCIIGA 12000 11000 10000 9000 en CL 8000 m-a! 7000 I-ci C.) 6000 M 5000 Z10 4000 3000-2000-1000-0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 Normalized Measured Burst Pressure, psi Figure 3.1 Burst Pressure Calculated from Plus Point Voltage and Plus Point Length Versus Normalized Measured Burst Pressure.
51-5034594-02 Page 15 of 19 2 1.8 1.6 1.4 > 1.2 ~Ii 1 L' 0.8 0.6 0.4 0.2 0 0 0.5 1 1.5 2 2.5 3 Plus Point Crack Length, Inchos Figure 3.2 Plus Point Voltage and Length Condition Monitoring and Operational Assessment (rMust Detect) Curves for Freespan Axial ODSCC/IGA at 4050 psi at 0.95 Probability
51-5034594-02 Page 16 of 19 4 3.5 3 \ 0
> 2.5 - Lone In Situ Failure 0, > 2
- 0
.5 Xo 1.5 \ \ __ 1 9 50150 0.5 95150 0 0.5 1 1.5 2 2.5 3 3.5 4 Plus Point Crack Length, Inches Figure 3.3 Combinations of Plus Point Voltages and Lengths AMecting Condition Monitoring via Analysis Compared to In Situ Tcst Results for a Temperaturc Compensated Target Pressure of 4050 psi.
51-5034594-02 Page 17 of 19 OTSG In Situ Results, Axial ODSCC/IGA 5 4 0 -W 3 0 U) w 2 3: 1 0 0 1 2 3 4 5 6 7 8 Plus Point Crack Length, inches Figure 3.4 Historical In Situ Data and Previous Empirical CMN Acceptance Boundary
51-5034594-02 Page 18 of 19 4.0 Conclusions An operational assessment for the first mid cycle of operation after 13RFO at Davis Besse was performed. The previous operational assessment' for a full cycle length of 1.85 EFPY was reviewed and updated as needed. Recent degradation growth rate Information2 for OTSG plants was compared to parameters used for the full cycle length analysis. No updates were required. The previous analysis remains valid and is bounding for mid cycle operation. Projections for the number of indications expected at a mid cycle inspection were developed to provide a basis for evaluation of degradation progression rates. For mid cycle operation of about 1.4 EFPY, projected structural margins are about 15% greater than full cycle operational, projected numbers of indications remain the same for wear and decrease by about 20% for other degradation mechanisms and projected SLB leakage remains at nominal projected values due to plugs, sleeves and preexisting PWSCC In rolled lengths at upper tubesheet expansion transitions. As noted in another report¶ degradation growth is not expected over the extended length of downtime prior to startup for Cycle 14. A substantial margin exists for any unexpected degradation growth that may have occurred. The burst pressure of OTSG tubing with axial ODSCC/IGA degradation can be related to the signal amplitude of the Plus Point probe and the length of degradation as measured via the Plus Point probe3 . A CMOA approach using Plus Point signal amplitude is described. This approach provides a check and verification of conventional NDE sizing and analysis methodologies.
51-5034594-02 Page 19 of 19 5.0 References
- 1. Begley, J. A. and Begley, T. F., "A CMOA Evaluation of Steam Generator Tubing at Davis Besse, FA-DB-011-0. ForeLine Associates LLC, April, 2002.
- 2. Begley, J. A., "Degradation Growth Rates in OTSG Tubing", Framatome-ANP Document 51-5022969-00, Framatome ANP, September, 2003.
- 3. Begley, J. A. and Colgan, K. A., "Correlation of Burst Pressure with +Pnt Voltage and Length for OTSG Axial ODSCCIIGA, 32-5030334-00, Framatome ANP, July, 2003.
- 4. Begley, J. A. and Martin, C., "A CMOA Evaluation of Steam Generator Tubing, 13RFO at CR3", 51-5035818-01, October, 2003.
- 5. "Steam Generator Integrity Assessment Guidelines", EPRI Report, TR-107621, Rev. 1, March 2000.
- 6. Bell, M. J., 'DB-1 Steam Generator Shutdown/Lay Up Chemistry Assessment", Framatome ANP Document 51-5033009-02, November, 2003.
Docket Number 50-346 License Number NPF-3 Serial Number 3000 COMMITMENT LIST The following list identifies those actions committed to by the Davis-Besse Nuclear Power Station (DBNPS) in this document. Any other actions discussed in the submittal represent intended or planned actions by the DBNPS. They are described only for information and are not regulatory commitments. Please notify the Manager- Regulatory Affairs (419-321-8450) at the DBNPS of any questions regarding this document or any associated regulatory commitments. COMMITMENTS DUE DATE The DBNPS staff will assure that the steam generator March 9, 2004 layup and storage conditions subsequent to the time period assessed in Framatome-ANP Document 51 - 5033009-03 were consistent with the conclusions of that assessment.}}