ML20197D224
| ML20197D224 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 12/17/1997 |
| From: | Cruse C BALTIMORE GAS & ELECTRIC CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9712290007 | |
| Download: ML20197D224 (122) | |
Text
Cll Altl t:W ll. Cetl'thl:
llallirnorr Csas arulllectric Comj'uny Vice President Cah ert Cliffs Nuclea ther Plant Nuclear Energy 1650 Culvert Cliffs Parkway t,usby. Klar> tand 20657 410 495-4455 December 17,1997 U. S. Nuclear Regulatory Commission Washington,DC 20555 A'ITENTION:
Document Control Desk SUBJi T:
Calvert Cliffs Nucicar Power Plant Unit Nos.1 & 2; Docket Nos. 50 317 & 50 318 lkquest for Review and Anproval of SystemRcpottdor License Renewal
REFERENCES:
(a)
Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated August 18,1995, Integrated Plant Assessment Methodology (b)
Letter from Mr. D. M. Crutchfleid (NRC) to Mr. C.11. Cruse (DGE),
dated, April 4,1996, Final Salety Evaluation (FSE) Concerning The Baltimore Ges and Electric Company Report entitled, " Integrated Plant Assessment Methodology" (c)
Letter from Mr. S 7. Flanders (NRC), dated March 4,1997,"St.mmary of Meeting with Baltimore Gas and Electric Company (BGE) on BGE License Renewal Activities" e
This letter forwards the attached Integrated Plant Assessment (IPA) System Repons for review and approval in accordance with 10 CFR Part 54, the license renewal rule. Should we apply for License Renewal, we will reference IPA System Reports as meeting the requirements of 10 CFR 54.21(a),
" Contents of application-technical Information," and the demon =tration required by 10 CFR 54.29(a)(1),
" Standards for issuance of a tenewed license."
The information in this report is accurate as of the dates of the referenas listed therein. Per 10 CFR 54.21(b), an amendment or amendments will be submitted that identify any changes to the current licensing basis that materially affect the content of the license renewal application.
In Reference (a), Baltimore Gas and Electric Company submitted the IPA Methodology for review and approval, in Reference (b), the Nuclear Regulatory Commission (NRC) concluded that the IPA
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Document Control Desk
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i Methodology :is acceptable 1 for;- meeting - 10 CFR 54.21(aX2) of t!.c license renewal rule, and if implemented,'provides reasonable assurance that all structures and components subject to an aging 1
manegement review pursuant to 10 CFR 54.21(aXI) will be identified. Additionally, the NRC concluded i
that the metho6 ology provides processes for demonstrating that the effects of aging will be adequately
- saanaged pursuant to 10 CFR $4.21(aX3) that are conceptually sound and consistent with the intent'of the license renewal nale, l
' n Reference (c), the NRC stated that if the format and content of these reports met t% requirements of-i Lthe template developed by BGE, the NRC could begin the technical review. Th s report has been -
. prodt.ced and formatted in accordance with these guidance documents..We look torward to your-comments on the reports as they are submitted and your continued cooperation with our license renewal i
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Document Control Desk December 17,1997,
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- Should you have questions regarding this matter, we will be pleased to discuss them with you.
Very truly yours,
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STATE OF MARYLAND
- TO WIT:
I
- COUNTY OF CALVERT 1.- Charles 11.- Cruse, being duly sworn, state that I am Vice President, Nuclear Energy Division,
- Baltimore' Gas and Electric Company (DGE), and that I am duly authorized to execute and file this response on behalf of BGE. To the best of my knowledge and belief, the statements contained in this
, document are true and correct. To the extent that these statements are not based on my personal l
' knowledge, they are based upon information provided by other BGE employees and/or consultants. Such information has been reviewed in accordance with company prac ce and I believe i
- reliable, w W/Y A m W
/
Sul; peri'tzef anq;swom before m/e a NotarysPublic in and for the State of Maryland and C c#, New a
.this /' day of I)/2*M_,1997, c
g Wm8ESS _ my 11and and Notarial Seal:
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Notary Public
= My Commission Expires:
h M /98'l Date LAURA A. MARTIN CliC/DLSidim NOTARY PUBLIC STATE OF MARYLAND --
My Commeslan Expiros JJy 1,1999
-Attachments: (1)' 4.1 Reactor Coolant System
. (2) 5.11 A. Auxiliary Building 11 eating and Ventilation System
_(3)_ 5.16 Saltwater System -
cc:
R.' S. Fleishman, Esquire' H. J. Miller, NRC J. E. Silberg, Esquire Resident inspector,NRC -
=
Director,' Project Directorate 1 1, NRC -
. R. I. McLean, DNR 7
A. W. Dromerick, NRC.
J.11. Walter, PSC
- D. L. Sobrio, NRC :
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't e-ATTACHMENT (1) i 4
1 4
a i
b APPENDIX A - TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM 4
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L i-Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant December 17,1997
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w-AIIACHMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM 4.1 Reactor Coolant System His is a section of the-Baltimore Gas and Electric Company (BGE) License Renewal Application (LRA), addressing the Reactor Coolant System (RCS). - The RCS was evaluated in accordance with the Calvert Cliffs Nuclear Power Plant (CCNPP) Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections are prepared independently and will, collectively, comprise the entire BGE LRA.
4.1.1. Scoping System level scoping describes conceptual boundaries for plant systems and structures, develops screening tools that capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify systems and structures within the scope of license renewal. Component level scoping describes the components within the boundaries of those systems and structures that contribute to the intended functions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended functions and then dispositions the component types as either only associated with active functions, subject to replacement, or subject to AMR either in this report or another report.
Section 4.1.1.1 presents the results of the system level scoping,4.1.1.2 the results cf the component level scoping, and 4.1,1.3 the results of scoping to determine components subject to AMR.
Representative historical operating experience pertinent to aging is included in appropriate areas, to provide insight supporting the aging management demonstrations. This operating experience was obtained through key. word searches of BGE's electronic database ofinformation on the CCNPP dockets and through documented discussions with currently assigned etgnizant CCNPP personnel.
4.1.1.1 System Level Scoping His section begins with a description of the system that includes the boundaries of the system as it was scoped. The intended functions of the system are listed and are used to define what portions of the system are within scope for license renewal.
System Descriotion/Concentual Boundaries The function of the RCS is to remove heat from the reactor core and internals and transfer it to the secondary (steam generating) system. The RCS of each Unit, which is entirely located within the Containment Building, consists of two heat transfer loops connected in parallel across the reactor pressure vessel (RPV). Each loop contains one steam generator (SG), two reactor coolant pumps (RCPs), connecting piping, and. flow and temperature instrumentation. Other major RCS components include the pressurizer and quench tank. Coolant system pressure is maintained by the pressurizer, which is connected to one of the RCS loop hot legs. [ Reference 1, Section 4.1.2] Because the RPV is such a significant component of the RCS and because several aging' mechanisms are unique to it, the-RPV has a separate aging management evaluation in Section 4.2 of the BGE LRA.
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Application for License Renewal 4.1-1 Calvert Clifts Nuclear Power Plant L
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ATTACHMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM The basic RCS functional requirements are: [ Reference 2, Section 1.13]
To remove heat from the reactor core and reactor internals and transfer it to the secondary (SGs) system; To contain fission products released by fuel element defects and prevent the release of these fission products to the environment; To provide remote monitoring capability for the RCS parameters; To permit remote control of RCS parameters; and To provide required inputs to the Reactor Protective System, the Reactor Regulating System, and e
the Engineered Safety Features Actuation System for protection of the reactor core and RCS components.
- The primary function of the RCPs is to provide forced coolant flow through the core. There are four RCPs in the RCS of each Unit, which are located in the SG (return lines) " cold legs." [ Reference 1, Section 4.1J]
During operation, the four RCPs in each Unit c rculate water through the RPV where the water serves as both coolant and neutron moderator for the core. He heated water enters the two SGs in each Unit, transferring heat to the secondary (steam) system, and then returns to the RCPs to repeat the cycle. Refer to Figure 41 (Unit 1) and Figure 417 (Unit 2) of the Updated Final Safety Analysis Report (UFSAR) for a flow diagram of the RCS. [ Reference 1, Section 4.1.2]
The RCS pressure is maintained by regulating the water temperature in the pressurizer where steam and water are held in thermal equilibrium. Steam is either formed by the pressurizer heaters or condensed by the pressurizer spray to limit the pressure variations caused by contraction or expansion of the reactor coolant. The pressurizer is located with its base at a higher elevation than the RCS loop piping.
[ Reference 1, Section 4.1.2] A number of pressurizer heaters are operated contir.uously to offset the heat losses and the continuous minimum spray, thereby maintaining the steam and water in thermal equilibrium at the saturation temperature corresponding to the desired system pressure. [ Reference 1, Section 4.1JJ l
Overpressure protection is provided by two power-operated relief valves (PORVs) and two spring-loaded safety valves connected to the top of the pressurizer. Steam discharged from the valves is cooled and condensed by water in the quench tank. The RCS vent lines from the RPV and the pressurizer also discharge to the quench tank. In the unlikely event that the discharge exceeds the capacity of the quench tank, the tank is relieved to the containment via the quench tank rupture disc. The quench tank is located at a level lower than the pressurizer. This ensures that any PORV or pressurizer safety valve leakage from the pressurizer, or any discharge from these valves, drains to the qv:nch tank. [ Reference 1, Section 4.1.2]
The Nuclear Steam Supply System (NSSS) utilizes two SGs to transfer the heat generated in the RCS to the secondary system. He SG shell is constructed of carbon steel. Manways and handholes are
_ provided for easy access to the SG internals. [ Reference 1, Section 4.13]
Application for License Renewal 4.1 2 Calvert Cliffs Nuclear Power Plant
[
ATTACHMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM The SG is a vertical U tube heat exchanger. The SG operates with the reactor coolant in the tube side and the secondary fluid in the shell side. Reactor coolant enters the SG through the inlet nozzle, Dows through 3/4" outside diameter U tubes, and leaves through two outlet nozzles. Vertical partition plates in the lower head separate the inlet and outlet plenums. The plenums are stainless steel clad, while the primary side of the tube sheet is nickel chromium-iron (Ni Cr Fe) clad. The vertical U-tubes are Ni-Cr-Fe alloy. The tube-to-tube sheet joint is welded on the primary side. Tubes that have degraded may be repaired using tube sleeves or removed from service by either a welded or a mechanical-type tube plug.
[ Reference 1, Section 4.1.3]
Feedwater enters the SG through the feedwater nozzle where it is distributed via a feedwater distribution ring. Water exits the ring through apertures in the top fitted with J tubes, then Dows into the downcomer. The downcomer is an anmdar passage formed by the inner surface of the SG shell and the cylindrical shell wrapper that encloses the vertical U tubes. At the bottom of the downcomer, the secondary water is directed upward past the vertical U tubes where heat transfer from the primary side produces a water-steam mixture. [ Reference 1, Section 4.1.3.2]
Constant RCS makeup and letdown is handled by the Chemical and Volume Control System (CVCS).
l An inlet nozzle on each of the four RPV inlet pipes allows injection of borated water into the RPV from the CVCS and from Safety injection System in the event emergency core cooling is needed. During a normal plant shutdown, these nozzles are also used to supply shutdown cooling How from the low pressure safety injection pumps. An outlet nozzle on one RPV outlet pipe is used to remove shutdown cooling Dow. [ Reference 1, Section 4.1.2]
Drains from the RCS piping to the Radioactive Waste Processing System are provided for draining the RCS for maintenance operations. A connection is also provided oa the quench tank for draining it to the Radioactive Waste Processing System following a relief valve or efety valve discharge. [ Reference 1, Section 4.1.2]
The RCS piping censists of two loops that connect the SGs to the reactor vessel. Each loop consists of 42 inch inside diameter " hot leg" piping connecting the reactor vessel outlets to the SG inlets, and 30-inch inside diameter piping connecting the SG outlets to the RCPs and the coolant pumps to the reactor vessel inlet nozzles. A surge line connects one loop hot leg to the pressurizer. [ Reference 1, Section 4.1.2]
Vents were added to the RPV head and to the pressurizer head in response to the Three Mile Island lessons learned report, "Clarincation of TMI Action Plan Requirements," NUREG 0737, item II.B.l.
These vents are intended to provide a means of releasing non-condensable gases from the RCS during natural circulation. The pressurizer vent line valves are used as a backup to main at.d auxiliary spray to depressurire the RCS during a SG tube rupture. The original design of CCNPP allowed venting of the RCS only during cold shutdown. The vent modifications provide electrically-operated solenoid valves, powered from emergency electrical busses, that are operated f6om the Control Room. The RPV and the pressurizer each have two of these valves in series, which fail closed (power-to-open). The reactor vessel vent line valves are installed in previously existing lines; the pressurizer vent line valves are installed in a line that was added as an additional branch off the pressurizer vapor sample line. The two vent lines join to a common line that leads to the quench tank. The common line contains a temperature l
Application for License Renewal 4.1-3 Calvert Clifts Nuclear Power Plant i
- o, ATTACHMFNT 11)
APPENDIX A-TECIINICAL INFORMATION 4.1-REACTOR COOLANT SYSTEM clement and alarm that is used for valve seat leak detection and flow indication. [ Reference 1, Section 4.1.3]-
ne components covered by this evaluation include the RCPs and their motors, RCS piping, pressurizer, pressurizer heaters, PORVs and safety valves, SGs, quench tank, and associated instruments and controls. The SG boundaries are set at the ends of the nozzles' safe-ends connecting the SG to other components or systems. The nozzles include ma:n feedwater, auxiliary feedwater, main steam, RCS inlet and outlet, instrumentation, and any integral attachments.. (Reference 2, Section 1.1.2]
He boundary between the RPV and RCS main coolant piping excludes the RPV nozzles, which are evaluated with the RPV and Control Element Drive Mechanisms (CEDMs)/ Electrical System in Section 4.2 of the BGE LRA. [ Reference 2, Section 1.1.2]
In addition, the following piping, supports, instrumentation and controls, and valves are covered or excluded in this evaluation: (Reference 2, Section 1.1.2]
Piping:
Small tubing and piping that is Geld run (i.e., instrumentation tubing) and does not have component designators is not evaluated in this report; PORV and safety valve discharge piping is included up to but not including the connecting e
non.lcs on the quench tank; Vents, drains, and other similar attached lines are included out to the second valve from the RCS; e
and Safety injection and similar lines from the interconnecting systems are included out to the first valve from the RCS.
Supports and hangers for piping and components that are not reviewed in this evaluation are evaluated in the Component Supports Commodity Evaluation in Section 3.1 of the BGE LRA.
Instrumentation and Controls covered by this evaluation are: [ Reference 2, Section 1.1.2]
All remote and local instrumentation associated with the RCS loops, the pressurizer, and the RCPs. Steam generator secondary side instrumentation is not covered in this evaluation; Incore neutron detectors and incore (core exit) temperature monitors; Instrumentation scope includes transmitters, signal processing, equipment, Control Room displays, and other applicable readouts, but does not include cabling. Cabling is evaluated in the Cables Commodity Evaluation in Section 6.1 of the BGE LRA; Automatic and manual controls for pressurizer heaters, pressurizer spray, RCPs, and the PORV and its isolation valves are evaluated; and Power supply components for the RCPs and heaters are included up to the power supply breaker.
Application for License Renewal 4.1-4 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM The valves covered by this review include: [ Reference 2, Section 1.1.2)
Valves associated with the pressurizer spray (including Instrument Air System supply valves to e
the pressurizer spray control valves);
Pressurizer Code safety valves; PORV and associated motor operated block valves; e
All normally closed RCS pressure boundary valves in vent and drain lines (this extends to the second valve from the RCS in each line); aad Instrument valves for the RCS instrumentation (e.g., pressurizer level transmitter instrument root e
valves),
in addition, a few valves in associated systems are included; these are: [ Reference 2, Section 1.1.2]
Two manual valves in the CVCS letdown line; Check valves in the CVCS RCP seal bleedofilines; e
Two check valves in the relief piping from the RCS drain tank heat exchanger; The air system valves noted above; and RCP lube oil r:servoir level transmitter root valves.
The RCP and motors and their oil lift system are included in this evaluation. The RCP and motor cooling subcomponents are included in this evaluation out to the connection with the Component Cooling (CC) System. [ Reference 2, Section 1.1.2] Included in this evaluation are the SG and pressurizer supports. Component supports, cables, instrument lines, and instruments not identified as RCS components in the RCS scoping results are generically included in the Component Supports Commodity, Cables Commodity, Instrument Lines Commodity and Fire Protection AMRs.
[ Reference 2, Section 3.2)
System Oncrating Exnerience The following are RCS operating experiences related to aging mechanisms with the potential for affecting the intended functions of'he system components.
RCP Events RCP Suction Deflector Failures In 1988 and 1996, faihires of RCP suction deflector bolting at CCNPP occurred and bolt fragments were assumed to be lodged in the RPV on the vessel cladding and near the downcomer. Refer to the RPV/CEDMs and Electrical System evaluation in Section 4.2 of the BGE LRA for further discussion of this event. [ References 3 and 4]
Application for License Renev>al 4.15 Calvert Cliffs Nuslear Power Plant
ATTACHMENT fn APPENDIX A-TECIINICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM RCP Leakage On several occasions, CCNPP has shut down due to RCS leakage nsalated with the RCPs. These occurred primarily between 1978 and 1985, and resulted from minor leakage in RCP sensing, instrument, and controlled leakoff lines. These small RCP lines were leaking at weld locations as the result of vibratory fatigue. Corrective actions have included weld repair and replacement of weded pipe with new continuous sections of pipe for leakofT lines. In some instances the pipe supports were modified to reduce the efTects of vibration. Braided hose jumpers were used with sensing and instrument lines. For piping usociated with the RCP seal leakoff lines, CCNPP has implemented a vibration monitoring and reduction program, minimized vibration through continued RCP balancing, and replaced / relocated existing pipe flanges. [ References 5 through 11]
The original Byron Jackson seals have been replaced with improved seals. The new seals are designed in accordance with American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Ill,1983 Edition with Summer 1983 Addenda, and manufactured by Sulzer Bingham Pumps.
[ Reference 1, Section 4.1]
RCP Thermal Barrier llousing Cracks Baltimore Gas and Electric Company has determined that NRC Information Notice 97 31," Failures of Reactor Caolant Pump Thermal Barriers and Check Valves in Foreign Plants," is applicable to CCNPP, since there has been evidence of cracking in the RCP thermal barrier housings. Calvert Cliffs found shallow surface cracking on the 22B RCP thermal barrier housing in 1987. A safety analysis addressed the consequences of this cracking and the potential for overpressurizing the Component Cooling (CC)
System. The analysis found that the CC System would not be subjected to overpressuri7ation since there are six CC relief valves with adequate capacity inside the Containment Building. Another analysis by the pump vendor found that any cracks would be self arresting and would go no deeper. This analys s was partially val; dated by CCNPP when No, llB RCP cover was tested in the fall of 1996. The inspection found shallow surface cracks within a small area of oxide that were not evident after the oxide area was cleaned. The cover of No. 21 A RCP was also inspected in June 1997, with no cracking found.
The potential for thermal stress cracking in the RCPs has also been addressed by adding inspection requirements to the RCP overhaul procedures. Baltimore Gas and Electric Company has concluded that these analyses, tests, and inspection requirements adeqrately address the concerns of Information Notice 97-31.
Erggutizer Events Calvert Cliffs has experienced RCS pressure boundary leakage of Alloy 600 components. During the 1989 Unit 2 refueling outage, CCNPP personnel discovered evidence of RCS leakage from approximately 20 of 120 pressurizer heater steens. Unit I was shut down from 100% power ta allow inspection of the pressurizer. No signs or evidence of leakage was found on the Unit I pressurizer heater penetrations or pressure / level instrumentation penetrations. Both units remained shut down until the cause was understood.
The cracks were of an axial nature and eventually determined to be not safety significant. [ Reference 12]
- Upon further evaluation it was determined that the cause of the leakage was primary water stress corrosion cracking (PWSCC). Primary water SCC is stress corrosion cracking (SCC) that occurs in susceptible materials exposed to the primary water environment of the RCS. [ Reference 13] Calvert Application for License Renewal 4.1-6 Calvert Cliffs Nuclear Power Plant i
ATTACilMEprT (1)
APPENDIX A-TECllNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM Cliffs has a total of 244 Alloy 600 penetrations in the Unit 1 RCS, and 126 remaining in Unit 2 (120 pressurizer heater sleeves were replaced with Alloy 690 in 19891990), in addition, a pressurizer vapor spae9 instrument nozzle was found leaking in May 1989, which led to the replacement of all four of the Unit 2 pressurizer vapor space nozzles with Alloy 690, During the Unit i 1994 refueling outage, two other heater sleeves were found leaking and were plugged. The remaining 188 henter sleeves were nickel-plated, as a preventive method to halt PWSCC. These events contributed to the development and evaluation of the CCNPP Alloy 600 Program Plan, which manages PWSCC in the RCS. [ Reference 14, Sections I,2,3,18,19]
SG Events The CCNPP SGs have been repeatedly and extensively examined with different non-destructive examinations techniques. These non-destructive examination techniques include eddy current tetting (bobbin coil examinations, and the Motorized Rotating Panake Coil and Plus Point system). These examinations found some SG tubes that have degraded due to intergranular stress corrosion craving (IGSCC), which is the result of material stress, environment, and age. The results of these SG inspection reports are submitted to the NRC, [ References 15 and 16] Another degradation mechanism includes denting of the SG tubes. Denting has occurred on numerous tubes and may cause them to eventually crack. Currently, all tubes with cracks are repaired upon detection of the crack. [ Reference 17]
To minimize denting, Calvert Cliffs has removed major copper sources from the feedwater and condensate systems and maintained a low oxygen level with secondary chemistry control.
[ Reference 17] There has also been circumferential cracking of the SG tubes at the hot leg tube sheet expansion transition. All tubes with circumferential cracking are removed from service. The aging mechanism was determined to be IGSCC originating on the secondary side (outer diameter) of the tubes.
Calvert Cliffs maintains elevated pil chemistry on the SG secondary side to limit iron transport to the SGs and, therefore, the deposits in the SG. Steam generator deposits create local chemistry conditions conducive to intergranular attack (IGA)/lGSCC. [ References 15 and 16]
He primary degradation mechanism of both Unit I and 2 SGs is outside diameter initiated IGA /lGSCC.
Unit I degradation is primarily located in the hot leg upper tube bundle freespan and the hot leg tubesheet transition zone. Unit 2 degradation is primarily located at the hot leg tubesheet transition zone.
Baltimore Gas and Electric has pulled several tubes containing stress corrosion cracks from these zones and burst tested them to near virgin tube pressures to show significant margin to structural integrity limits. Baltimore Gas and E!cetric has also performed in situ pressure tests on degraded tubes to demonstrate adequate structural integrity consistent with the requirements of Regulatory Guide 1.121.
Baltimore Gas and Electric Company is aware of SG flow-assisted corrosion at the San Onofre Nuclear Generating Station and will monitor industry activity related to this aging mechanism. Calvert Cliffs will respond to any NRC generic communications on this matter as part of the CLB. An evaluation of flow assisted corrosion for CCNPP SGs will be incorporated into annual updates of the BGE LRA.
Qther RCS Events RCS Resin Intrusion Calvert Cliffs Unit I had a resin intrusion in March 1989, and Unit 2 suffered a resin intrusion in Jame y 1983, due to a failed outlet retention element of the ion exchanger in the purification system.
Application for License Renewal 4.1-7 Calvert Cliffs Nuclear Power Plant
o, ATTACHMENT m APPENDIX A TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM The effect on the RPVs was evaluated at the time of the intrusions, as discussed in Section 4.2 cf the BGE LRA, and found to be acceptable. Resin intrusions are a potential issue since resin decomposition products (sulfates) ma) contribute to cracking of sensitized Alloy 600, and the Unit I resin intrusion event caused elevated sulfate levels in the RCS. The Unit was shut down to restore chemistry, He sulfate concentration in the RCS was evaluated by Combustion Engineering (CE) and BGE, and the potential increase for PWSCC or IGSCC was determined to be insignificant. [ References 18 and 19]
Boric Acid Corrosion There have been several instances of external corrosion on RCS components due to boric acid leakage.
in 1981. CCNPP Unit 2 experienced boric acid wastage on the RCS cold leg near the suction pipe to an RCP. This wastage (determined to be general corrosion) penetrated to a maximum depth of 1/8 inch (nominal pipe wall thickness 3.6 inches) and extended about 20 percent around the circumference of the pipe, inservice examination also revealed corrosion damage on the closure studs of two of the four RCPs. [ Reference 20] A modification was made to install a stainless steel skirt en the RCPs to prevent any potential borated water leakage from dripping onto the RCS cold leg piping.
RCS Chemistry An incident related to RCS plant chemistry occurred in October 1979 when an abnormally high ingress of oxygen occurred. %is oxygen ingress resulted in an increase of corrosion products in the RCS and eventually to buildup of corrosion nroducts on core surfaces. This corrosion product buildup resulted in axial power imbalance (the corrosion products were a neutrun absorber) and a slight increase in the differential pressure drop across the core. This power imbalance led to a 50% power reduction. The source of the oxygen ingress was found and terminated. Calvert Cliffs treated the RCS with hydrogen peroxide during a cold shutdown of the Unit and significant corrosion product releases were observed.
Upon return to power, core differential pressure and axial power distribution returned to normal. No fuel failures were observed because of this event. [ Reference 21)
RPV Head Closure Seal Leakage Detection Line Stress corrosion cracking was discovered in 1994 during a metallurgical examination of the Unit 2 RPV head closure seal leakage detector instrument line. Leakage from the line was noted during a routine post-trip containment inspection. The pipe was replaced and an examination confinned that the failure mechanism was transgranular SCC (TGSCC) of stainless steel. Baltimore Gas and Electric Company concluded that the most likely initiator of the TGSCC was an ever increasing concentration of contaminants in the vicinity of the crackmg due to repeated boil off of the liquid left in the line at the end of each refueling, eventually reaching levels high enough to cause TGSCC [ Reference 22] Even though the flawed portion of the line on Unit 2 was replaced during the January 1994 shutdown, BGE replaced the entire pipe during the 1994 refueling outage. Baltimore Gas and Electric Company also conducted non-destructive examination of the Unit 1 RPV head closure seal leakage detector instrument line and discovered flaw indications. As a result, the entire line was replaced and rerouted to an alternate flange tap. To prevent recurrence of TGSCC in the RPV head closure seal leakage monitor lines, BGE currently intends to drain the line after each refueling outage to eliminate liquid / vapor interface in high temperature sections of the line, and remove contaminants that create an environment conducive to TGSCC. [ References 22 and 23)
Application for License Renewal 4.1-8 Calvert Cliffs Nuclear Power Plant
ATI'ACIIMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1 - REACTOR COOLAFT SYSTEM in summary, these RCS events demonstrate that CCNPP has and will continue to address and perform corrective actions as required so that the RCS components are capable of performing their intended function under all current licensing basis (CLB) design loading conditions during the period of extended operation.
System Interfaces The niajor RCS interfaces are with the CVCS, Safety injection System, Reactor Protective System, Reactor Regulating System, Engineered Sr.fety Features Actuation System, NSSS sampling, and_ the RPVs/CEDMs. Other interfaces include CC, Main Steam, Feedwater, and Auxiliary Feedwater Systems.
A simplified flow diagram of the RCS and ;ts interfacing systems and components is provided in Figure 4.1 1 [ Reference 1, Figures 4 1,4 17, Reference 2, Section 1.1.2, Reference 24]
Those systems or systems' components interfacing with the RCS that are within the scope of license renewal are noted with an asterisk (*) in Figure 4.1 1. Where a system, component, commodity, or structure interface is in scope for license renewal, it will be addressed by the respective section of this application for that system, component, commcdity, or structure.
Application for License Renewal 4.1-9 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (D 4
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FIG. 4.1-1 UNIT No.1 REACTOR COOLANT SYSTEM SIMPLIFIED DIAGRAM (INFORMATION ONLY)
Application for License Renewal 4.1-10 Calvert Cli1Ts Nuclear Power Plant
ATTACHMENT Q)
APPENDIX A-TECliNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM System Scoping Results The RCS components ne within scope for license renewal based on 10 CFR 54,4(a). In accordance with Section 4.1.1 of the CCNPP IPA Methodology, a detailed list of system intended functions was determined based on the requirements of 10 CFR 54.4(a)(1) and (2): [ Reference 25, Table 1)
To provide manual control of RC5 pressure and pressurizer level via charging pumps during design bases events; To control RCS pressure by regulating water temperature in the pressurizer; To provide indication of degrees of subcooling during design basis events; To provide wide range loop temperature signals via resistance temperature detector circuits; e'. To provide thermal margin / low pressure signals to the Reactor Protective System for thermal margin / low pressure trip; To provide coastdown flow on interruption'of power to the RCPs; To vent the RCS when natural circulation How has been disrupted or blocked by accumulation of non-condensable gases; To provide differential pressure signals to the Reactor Protective System for low flow trip; To provide valve operation logic signals to support Safety Injection System functions; To maintain electrical continuity and/or provide protection of the electrical system; To maintain the pressure boundary of the system (liquid and/or gas for five process Huids, RCS primary side, Feedwater/ Main Steam secondary side, CC System, and RCP lube oil);
To provide containment isolation of the RCS during a loss-of-coolant accident; To provide reactor core decay heat removal via natural circulation. Note: This function also applies to station blackout (10 CFR 50.63) based on 654.4(a)(3);
To provide indication of natural circulation Gow via core exit thermocouples, Note: This function also applies to station blackout (10 CFR 50,63) based on Q54,4(a)(3);
To provide reactor vessel coolant inventory level indication. Note: This function also applies to station blackout (10 CFR 50.63) based on 654.4(a)(3);
To provide protection from overpressure in the RCS. Note: This function also applies to station blackout (10 CFR 50.63) based on Q54,4(a)(3);
The following RCS intended functions were determined based on the requirements of 10 CFR SU(a)(3):
[ Reference 25, Table 1. TPR Section]
For station blackout (650.63)- To detect leakage from the primary system following loss of AC power; For station blackout ($50.63) and fire protection (Q50.48)- To provide RCS isolation to maintain e
inventory following loss of AC power; Application for License Renewal 4.1 Calvert Cliffs Nuclear Power Plant
j ATTACllMENT (1) l APPENDIX A-TECliNICAL INFORMATION
)
4.1 - REACTOR COOLANT SYSTEM For post accident monitoring - To provide information used to assess the environs and plant j
conditions durirg and following an accident; For environmental qualification (650.49) - To maintain functionality of electrical components as addressed by the Envhonmental Qualification Program; For fire protection (650.48) - To provide lube oil collection for RCP motors sized to accommodate the largest potential oil leak; For fire protection (650.48) - To provide monitoring of essential parameters for ensuring safe shutdown in the event of a postulated severe fire; For fire protection (650.48) To provide RCS heat removal by realignment and operation of the shutdown cooling flowpath; For fire protection (650.48) - To control RCS pressure by regulating pressurizer water temperature during shutdown in the event of a postulated severe fire.
The design parameters for each of the major RCS components are given in Section 4.1.3 of the CCNPP UFSAR. The RCS is designated as a Category I system for seismic design and a Class I system for the criteria ofload combinations and stress that are presented in Tables 4 6,4 7, and 4 8 of CCNPP UFSAR Section 4.1.3. The regulations listed in 10 CFR 54.4(a)(3) do not necessarily require nuclear safety grade components in order to respond to the requirements of the regulations liowever, the components of the RCS that have intended functlans listed above associated with these regulations are safety related, Seismic Class 1, and are subject to the applicable loading conditions identified in UFSAR Section 4.1.3, Table 4-8.
4.1.1.2 Component Level Scoping Based on the intended functions listed above, the portion of the RCS that is within the scope of license renewal includes piping, components (e.g., heat exchangers, pressure vessels, pumps, valves, tanks, etc.),
and instrumentation that are relied on for mitigation of design basis events, station blackout, post-accident monitoring, environmental qualification, and fire protection.
A total of 63 device types within the RCS equipment types were designated as within the scope of license renewal based on these intended functions. These device types are listed in Table 4.1-1.
[ Reference 25]
Several components are common to many plant systems and perform the same passive functions regardless of system. These components include th; following:
Structural supports for piping, cables and components; Electrical cabling; and Process and instrument tubing, instrument tubing manual valves, and tubing supports.
Application for License Renewal 4.1-12 Calvert Cliffs Nuclear Power Plant
ATTACHMENT f1)
APPF.NDIX A-TECilNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM TABLE 4.1 1-RCS DEYlCE TYPES WITHIN THE SCOPE OF LICENSE RENEWAL 4
Device Code Device Description -
Device Code Device Description -
CC Pipe Line with Piping Code of"CC" PC Pressure Controller
-GC Pipe Line with Piping Code of"GC" PD1 Ditlerential Pressure T ransmitter lill Pepe Line with Piping Code of"1111" P1 Pressure Indicator
.IIC Pipe Line with Piping Code of"IIC" PIA Pressure Indicator, Alarm
^
AE Analyzer Element PIC Pressure indicator Controller Al Analyict Indicator PNL Panet ilKR Circuit lireaker PR Pressure Recorder CKV Check Valve Pl Pressure 1 ransmitter COIL Electric Coil PUMP Pump CV Control Valve PY Pressure Relay El Voltage /Cunent Device PZV Pressure Vessel ERV Electronically Operated Relief Valve R1 Radiation Indicator 1:U 1:use RV Relief Valve ils lland Switch RY Relay llV lland Valve SV Solenoid Valve ilX licat Exchanger TE lemperature Element 1/1 Current / Current Device Tl lemperature Indicator 11 Ammeter -
1K lank JL Power I amp indicator TP Temperature Test Point LC Level Controller iR Temperature Recorder LG Level Gauge TT lemperature 1ransmitter Li Level Indicator TY Temperature Relay LIC Level Indicatmg Controller U
llenter LR Level Relay VE Vibration Element LT Les el Iransmitter VI Vibration Indicator LY Level Relay VIA Vibration Indicating Alarm M/P Microprocessor VT Vibration Transmitter MD 125/250 VDC Motor XL Miscellaneous Mil 13kV Motot/ Machine YX Power Supply MOV Motoroperated Valve ZL Position Indicating Lamp Nil 480 V Local Control Station ZS Position Switch PA Preisure Alarm 4.1.1.3 Components Sublect to AMR This section describes the components of the RCS that are subject to an AMR It begins with a listing of passive intended fimetions and then dispositions the device types as either only associated with active functions, subject to replacement, evaluated in other reports, evaluated in commodity reports, or evaluated for aging management in this section Passive Intended Functions In accordance with CCNPP IPA Methodology Section 5.1, the following RCS functions were determined to be passive. [ Reference 25, Attachments 1]
To maintain the pressure boundary of the system (liquid and/or gas for five process fluids, RCS o
. primary side, Feedwater/ Main Steam secondary side, CC System, and RCP lube oil);
Application for License Renewal 4.1-13 Calvert Cliffs Nuclear Power Plant
0 ATTACHMENT {1)
APPENDIX A-TECHNICAL INFORMATION 4.1-REACTOR COOLANT SYSTEM To maintain electrical continuity and/or provide protection of the electrical system; and e
To provide contair. ment isolation of the RCS during a loss of-coolant accident.
e Device Tynes Subject to AMR The components of the RCS and their supports were reviewed and those that have the passive intended functions. were identified. Of the 63 device types identified within scope for license renewal:
[ Reference 2, Table 3 2]
The RPVs and their supports are evaluated for the efTects of aging in the RPVs and e
CEDMs/ Electrical System Evaluation in Section 4.2 of BGE's LRA. [The device type PZV evaluated is the pressurizer,]
One device type, the TB pressure wells, were considered to be part of the pipe and were evaluated with the piping.
One device type, TPs, or Reactor Vessel Level Monitoring System probes, are evaluated for the effects of aging in the RPV and CEDMs/ Electrical System Evaluation in Section 4.2 of BGE's LRA.
Five device types, LT, PT, P1, PIA, and PDT, are evaluated in the Instrument Lines Commodity Evaluation in Section 6.4 of BGE's LRA.
One device type, PNL, is evaluated in the Electrical Commodities Evaluation in Section 6.2 of BGE's LRA.
Some of the LT and PT device types are subject to replacement (environmental qualification).
Thirty-nine device types; AE, AI, BKR, COIL, El, FU ! % 1/l, II, JL, LC, L1, LIC, LR, LY, M/P, s
MD, Mll, NB, PA, PC, PIC, PR, PY, RI, RY, TI, TR, i X U, VE, VI, VIA, VT, XL, YX, ZL, and ZS are only associated with active functions.
The 16 remaining device types have passive intended functions and are long-lived. The device types are listed in Table 4.12. They are subject to AMR (RCS), and are the subject of the remainder of this report.
Several components in the RCS are common to many plant systems and have been included in separate sections of the BGE LRA that address those components as commodities for the entire plant. These components include the following: [ Reference 2, Section 1.l.3]
= ' Those structural supports for piping, cables, components in the RCS that are subjected to AMR are esaluated for the effects of aging in the Component Supports Commodity Evaluation in Section 3.1 of the BGE LRA, except for the SG supports and pressurizer support skiits that are evaluated in this section.
Electrical cabling for components in the RCS that are subject to AMR are evaluated for the e
effects of aging in the Electrical Cables Commodity Evaluation in Section 6.1 of the BGE LRA.
This commodity evaluation completely addresses the RCS passive intended ftmetion, "To maintain electrical continuity and/or provide protection of the electrical system."
Application for License Renewal 4.1-14 Calvert Cliffs Nuclear Power Plant
ATTACllMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Instrument tubing and piping, and the associated supports, instrument valves, and fittings for e
components in the RCS that are subject to AMR, and the pressure boundaries of the instrument themselves, are all evaluated for the effects of aging in the Instrument-Lines Commodity Evaluation in Section 6.4 of the DGE LRA.
As a result of the evaluations described above, the only passive intended function associated with the RCS is the following:
To maintain the pressure boendary of the system (liquid and/or gas for five process fluids, RCS primary side, Feedwater/ Main Steam secondary side, CC System, and RCP lube oil); and To provide containment isolation of the RCS during a loss-of coolant accident.
He containment isclatian function requires maintaining pressure boundary of components that are not contiguous with the RCS safety related pressure boundary. The two pressure boundary hand valves for sampling the pressurizer quench tank form a portion of the containment isolation function. The remaining sampling components are located in the NSSS Sampling Evaluation in Section 5.13 of the BGE LRA [ Reference 25, Attachments l}
TAHLE 4.12 RCS DEVICE TYPES REOUIRING. AMR Piping ( CC)
Piping (-GC)
Piping ( 11B)
Piping ( lIC)
Check Valve (CKV)
Control Valve (CVf Electronically-Operated Relief Valve (ERV) lland Valve (llV) lleat Exchanger (ilX)
Level Gauge (LG)
Motor Operated Vaive (MOV)
Pump (PUMP)
Pressure Vessel (PZV)
Relief Valve (RV)
Tank (TK)
Daltimore Gas and Electric Company may elect to replace components for which the AMR identifies further analysis or examination is needed in accordance with the License Renewal Rule, components subject to replacement based on qualified life or specified time period are not subject to AMR.
Application for License Renewal 4.1-15 Calvert Cliffs Nuclear Power Plant
.f ATTACIIMENT (1)
APPENDIX A TECHNICAL INFORMATION 4.1-REACTOR COOLANT SYSTEM 4.1.2 Aging Maragement ne potential ARDMs for the RCS components are listed in Table 4.1-3. - ne plausible ARDMs are identified in the table by a check mark (/) in the appropriate column. He device types listed in Table 4.13 are those previously identified in Table 4.12 as passive and long live t ne device types not included in Table 4.1 3 were previously dispositioned with the CC NPP IPA Methodology as performing an active function, are replaced and/or addressed in commodity evaluations. For efriciency in presenting the results of these evaluations in this report, the components are grouped together based on similar ARDMs.
[ Reference 2. Section 4.4)
He following discussions present information on plausible ARDMs. The discussions are grouped by ARDMs and address the materials and environment pertinent to the ARDM, the aging efTects for each
. plausible ARDM, the device types that are affected by each, the methods to manage aging, the aging management pro;; ram (s), and the aging management demonstration. The groups addressed are:
Group 1 Denting Group 5 - Galvanic / General Corrosion and Pitting Group 2 Wear Group 6 - IGA Group 3 - Erosion / Erosion Corrosion Group 7 - SCC /lGSCC/PWSCC Group 4 - Fatigue Group 8 - Thermal Embrittlement Application for License Renewal 4.1-16 Calvert Cliffs Nuclear Power Plant
^
ATTACHMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1-REACTOR COOLAhT SYSTEM TABLE 4.1-3 POTENTIAL AND PLAUSIBLE ARDMs FOR THE RCS Device Type -
Posestial ARDM Name.
-0C 4f13 4E CAV.
CV ERY llV ELA -
.1%
50 Cavnaten Erosion
=
Con:ammation Sedimentanon iouf mg Corrosion 1augue C@hrmkage Crevice Cormsson Denung
<(I)
Dynamsc leadmg IJectncal Stressors Erosen
<(3)
Ltosson Corrosion
/(3)
Fangue
/(4)
/(4)
/(4)
/(4)
/(4)
/(4)
<(4)
/(4)
<(4)
<(4) balvanic Corrosson
<(5)
/(5)
Oca val Corrosion
- (5)
<(5)
<(5)
/(5)
<(5)
<(5)
<(5)
<(5)
<(5) ilydmgen image IGA
/(6)
Intergimular Corrosion irradiaton Eod
&.mm Macrobiologically-influenced Corrosma Neutron Embrettlement Oxidauon Particulate Wear Esosion Penmg
/(5)
Radiaten Damage Salene Water Attack Selecuve teachmg SCC
/(7)
/U)
/0) vp)
- p)
/(7)
<(7)
<p) vp) vp)
IGSCC vp)
/p)
<p)
P% SCC
<p) vp)
Stress Relaxauon 1hermal Damage 1hermal Emtnt:lement
/(s)
<(g)
<(g)
W ear
/G)
- 2)
/g2)
/(2)
- G)
/(2)
- G)
- G)
/(2)
<(2)
/(2)
/
indicates plau,ible ARDM determination
(#)
Indicates the group in which this ARDM is evaluated Apnlication for License Renewal 4.1-17 Calvert Cliffs Nuclear Power Plant
I ATTACHMEN"1 (1)
APPENDIX A.TECIINICAL INFORMATION 4.1 -REACTOR COOLANT SYSTEM Group 1 (denting)- Materials and ELvironment Table 4.14 shows that denting is plausible for the SG llX tubes, which are fabricated from Alicy 600.
(Reference 2 Attachments 5,6, ilX Ol] Denting only occurs on the secondary side (on the SG IIX tube exterior surfaces). The seco.dary side of these llX tubes are exposed to the internal environment of Jie SGs.
Ti. internal SG sec,adary side environment during power generation is saturated steam and water at a design pressure / temperature of 1000 psig/580'F and normal operating parameters of approximately 850 psig/520*F. The SGs also contain chemically treated, demineralized, high pressure water with high flow rates and fbid velocities at full power conditions. [ Reference 1, Chapters 10.I,10.2, Reference 26]
During plant shutdown conditions, the SGs may be drained.
Group I (denting)- Aging Mechanism t'ffects Denting refers to mechanical deformation of the SG tubes at support plates due to accelerated corrosion of the support plate structures. The corrosion products have a lower density than the 1 ate metal and tend to fill the space between the supports and the tubes. When the spaces are filled, additional corrosion causes the tubes to deform. Tub. denting has been observed in CE SGs [ Reference 2, Attachments 7, liX - SG]
Therefore, denting was de termined to be plausible for the SG llX tubes for which aging effects must be managed during the peri-d of extended operation.
Group 1 (denting)- Methods to Manage Aging Mitigntion: Design features, such as the proper design and material selection of the RCS device types susceptible to this ARDM, can mitigate the effects of denting. Maintaining proper chemistry control on the secondary side of the SG could aid in mitigating the effects of denting.
Discoverv: Denting of the SG llX tubes can be discovered by remote examination during plant refueling outages. Indications of denting identified during examinations of RCS components during refueling autages cars be recorded and evaluated for potential damage.
Group 1 (denting)- A **g Management Program (s)
Mitigation: There are no programs to mitigate the effects of denting other than the proper design and material selection for the intended application. No credit is taken for secondary chemistry control in the mitigation of denting.
Ascoverv: The CCNPP Surveillance Test Procedures STP-M-574-1/2," Eddy Current Examination of CCNPP I/2 SGs," are credited for discovering denting in SG IlX tubes. The procedure directs the user as to the sample size for tube inspection, inspection process, evaluation, and determination of tube status.
The evaluation of SG llX tubes is accomplished with this procedure, Electric Power Research Institute (EPRI)/ industry guidelines, and CCNPP Technical Specifications. The SG llX tubes are ranked in categories of degradation' according to the CCNPP Technical Specifications.
The Technical Application for License Renewal 4.1-18 Calvert Cliffs Nuclear Power Plant t
ATTACHMENT (1)
APPENDIX A-TECliNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Specifications have three categories for inspection results based on the percentage of tubes that are classi6ed as degraded and defective. The eddy current acceptance criteria for SG llX tubes are:
Imperfection - means an exception to the dimensions, Gnish, or contour of a tube from that e
required by fabrication drawings or speci6 cations. Eddy-current testing indications below 20%
of the nominal wall thickness, if detectable, may be considered as imperfections.
Degraded tube - means a tube containing imperfections 2: 20% of the nominal wall thickness caused by degradation.
Defe:t - means an imperfection of such severity that it exceeds the plugging or repair limit. A e
tube containing a defect is defective. Any tube that does not permit the passage of the eddy-current inspection probe shall be deemed a defective tube.
Hugging or repa!r limit - means the imperfection depth at or beyond which the tube shall be removed from service by plugging, or repaired by sleeving in the affected area because it may become unserviceable prior to the next inspection. The plugging or repair limit imperfection depths are speciGed as 40% of originsi nominal tube wall thickness or 40% of Westinghouse laser welded sleeve wall thickness.
An issue Report (IR) is submitted to plug or sleeve SG llX tubes that are cor.ddered susceptible to failure before the next inspection. The inspection frequency for SG liX tubes is determined by the CCNPP Techilcal Speci0 cations. [ References 27 and 28] For purposes of SG tubing, " susceptible to failure" means active degradation has been identined through inspection and the tube is susceptible to not satisfying structural integrity limits prior to the next refueling outage (or next inspection).
The Unit I and 2 SG tubes are inspected during each unit's refueling outage. Inspections are based on EPRI guidance, applicable industry experience, Technical Speci6 cations and site specinc SG degradation characteristics. Consistent with this, BGE is currently en active participant on committees sponsored by EPRI, CE Owners Group, and the Neclear Energy Institute focusing on preservation of SG structural integrity.
Group 1 (denting)- Demonstration of Aging Management Bascd on the factors presented above, the following conclusions can be reached with respect to the SG llX tubes that are susceptible to denting:
The SG llX tubes are a pressure-retaining bcun(ary for the RCS, so their integrity n ust be maintained under CLB design conditions.
Denting is plausible for the SG llX tubes and could reruit in the deformation of component material, leading to the loss of the pressure-retaining boundary function.
The CCNPP Technical Procedures STP-M 574-l/2 are credited for discovering denting of the SG llX tubes. An IR is submitted to plug or sleeve SG llX tubes that are considered susceptible to failure.
Therefore, there is reasonable assurance that the effects of denting will be managed in order to maintain the pressure boundary integrity fer the Group I components listed above under all design conditions required by the CLB during the period of extended operation.
App;ication for License Renewal 4.1-19 Calvert Clifts Nuclear Power Plant
ATTACHMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Group 2 (wear) Materials and Envircament Table 4.13 shows that wear is plausible for some of the RCS components. These susceptible RCS components and their material characteristics are: (Reference 2, Attachments 4,5,6, -CC-02/03/04, -
GC 01/02/d3/04/05/06, CV-01, ERV-01,-IIC-01, ilV-01/03/04, llX 01/02, PUMP-01, PZV-01, MOV-01/0']
i
-CC pipe Danges (stainless steel);
-GC - pipe flanges (stainless steel);
CV - bonnet / internals and bolting (stainless steel);
ERV - body / internals (stainless steel);
-llc - pipe Danges (stainless steel);
IIV - body and bonnet (forged or cast austenitic stainless steel (CASS]), stem (stainless steel);
SG llX primary manway, manway cover (carbon steel), sauds and nuts (alloy steel); secondary manway and manway cover plate (carbon steel), studs (alloy steel) and nuts (carbon steel),
secondary handhole and handhole cover plate (carbon steel), studs (alloy steel) and nuts (cerbon steel);
SG llX tubes (Alloy 600);
RCP seal water IIX tubes (stainless steel);
a PUMP (RCP) case and pump cover (CASS), clasure studs and nuts (carbon steel);
Pressurizer manway forging and cover plate (carbon steel or alloy steel); and MOV - body / bonnets (austenitic stainless steel), for some MOVs with stainless steel discs and stems, and some MOV seats (stellite).
The internal RCS environment (p:imary side) is that of chemically treated borated water at an operating pressure of approximately 2250 psia. The RCS operating temperatures are not greater than 548 F in the cold leg and a maximum of approximately 600'F in the hot leg. He RCS maintains a now rate of approximately 134x10' lbm/hr.
(Reference 1, Section 4.1.1, Table 4-1].
The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control.
The internal SG environment (secondary side) during power generation is saturated steam and water at a design pressure / temperature of 1000 psig/580 F and normal operating parameters of approxime.tely 850 psig/520*F. The SGs also contain chemically-treated, demineralized, high pressure water with high flow rates and Guld velocities at full power conditions. [ Reference 1, Chapters 10.1,10.2, Reference 26]
During plant shutdown conditions, the SGs may be drained.
As the interface between the primary and secondary Guids, the SG liX tubes are subjected to both the
- internal RCS environment and the internal SG environment.
Application for License Renewal 4.1-20 Calvert Cliffs Nuclear Power Plant
^
l ATTACllMENT m APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM 1
- The external RCS environment is ambient atmospheric air inside the Containment Building that is j
climate controlled.- This environment in the Containment Building during normal operations has maximum humidity of 70% and maximum temperature of 120*F.
[ Reference 1, Table 9-18, Reference 29, Attachments 1, Table I page 13]
Group 2 (wear)- Aging Mechanism Effects Wear results from relative motion between two surfaces (adhesive wear) from the inHuence of hard abrasive particles (abrasive wear), or Duid stream (crosion), and from small, vibratory or sliding motions under the in0uence of a corrosive environment (fretting). In addition to material loss from the above wear mechanisms, impeded relative motion between two surfaces held in intimate contact for extended periods may result in galling /self welding. Wear most typically occurs in components that experience considerable relative motion such as valves and pumps, in components that are held under high loads with no motion for long periods (i.e., valves, Hanges), or in clamped joints where relative motion is not intended but occurs due to loss of clamping force (e.g., tubes in supports, valve stems in seats, springs against tubes). [ Reference 2, Attachments 7 HX]
Wear can also occur between closurcs/ closure cover plates and by flow induced vibrations causing a rubbing action between components.
[P.crerence 2, Attachments 6, HX]
Therefore, wear was detennined to be plausible for the Group 2 components for which aging effects must be managed during the period of extended operation.
Group 2 (wear). Methods to Manage Aging Mitigation: Design features such as the proper design and material selection of the RCS device types susceptible to this ARDM can mitigate the effects of wear. Mechanical wear on those components that are manipulated during refueling operations can occur, but they usually are not subject to mechanical wear during normal operation. Minimizing the amount of component manipulation can mitigate wear.
Discoverv: With proper design, mechanical wear occurs slowly over long periods of time and is revealed as material loss of the components themselves. This wear can be discovered and monitored by visual inspection of the affected areas. Visual inspections of components can find mechanical wear on the components.
Indications of wear identiGed during visual examinations of RCS components during refueling outages can be recorded and evaluated for potential damage. Evidence of this mechanical wear could then lead to corrective actions being taken to restore the design function of the affected components.
Group 2 (wcar)- Aging Management Program (s)
Mitigntion: There are no programs to mitigate the effects of wear other than the proper design and material selection for the intended application.
Discoverv: He CCNPP Administrative Procedure MN-3-110,"lSI of ASME Section XI Components," is one of the existing programs designed to detect and manage the aging effects of wear for the RCS components susceptible to wear. [ Reference 2, Attachments 8] The Inservice Inspection (ISI) Program Application for License Renewal 4.1-21 Calvert Cliffs Nuclear Power Plant
ATTACHMENT m APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Plan responds to the requirements of Section XI of the ASME Code,1983 Edition ti rough Sammer 1983 Addenda, and is subject to periodic update per 10 C.'R 50.55a. [ Reference 30, Section 1.2.l]
' He scope of the existing ISI Program for the RCS includes examinatiot and inspection of components identiGed in ASME Section XI (e.g., Subsection IWB, etc.). [ Reference 31, Section 1.2A] H e ISI Program is perfonned to meet the requirements of references identified in Section 1.2A of Reference 3i.
An extensive list of the developmental ar.d performance references for the existing ISI program is provided in Section 2.0 of Reference 31.
Inservice inspection requirements in ASME Section XI, as implemented by the existing ISI Program, provide for visual examination of accessible surfaces of RCS components.
[ Reference 32, Table IWB 2500-1] The ASME Section XI ISI visual examination of the RCS components requires determining the general mechanical and structural conditions of the components from the effects of wear.
Examinations may require, as applicable, determination of structural integrity, measurement of clearances, detection of physical displacements, structural adequacy of supporting elements, connections between load-carrying structural members, and tightness of bolting. [ Reference 32, IWA 2213 Visual Examination VT 3]
If any abnormal condition is identified, the ASME Code provides requirements for th( %ely correction of the condition. [ Reference 32, IW A-4130 Repair Program] Visual inspections can reaue identify damage to the RCS components from wear. He corrective actions taken will ensure that the RCS components remain capable of performing their intended function under all CLB conditions.
The ISI Program is subject to internal and independent assessments and is recognized through these assessments as performing highly effective examinations and aggressively pursuing continuous improvements. Baltimore Gas and Electric Company monitors indu 'y initiatives and trends in the area of ISI and non-destructive examination and plays a leadership de in developing, analyzing, and cdvancing non destructive examination and ISI methods. He program is also subject to frequent external assessments by the Institute for Nuclear Power Operation, NRC, and others.
Operating experience relative to the ISI Program at CCNPP has been such that no site specific problems or events have required changes or adjustments. The program has been effective in its function of performing examinations required by ASME Section XI with respect to wear.
The CCNPP Boric Acid Corrosion inspection (BACl) Program, MN-3-301, is credited with the discovery of wear of RCS components. The discovery of boric acid residue could indicate RCS leakage as the result of component wear. The ISI Program required the establishment of the Boric Acid Corrosion Monitoring Program to systematically ensure that boric acid corrosion does not degrade the primary system boundary. [ Reference 31, page 23, Section 5.8.A.I.] The program controls examination and test methods and actions to minimize the loss of structural and pressure retaining integrity of RCS pressure boundary components due to boric acid corrosion. [ Reference 31, Section 3.0.C] The basis for the establishment of the program is Generic Letter 88-05, Boric Acid Corrosion c f Carbon Steel Reactor Pressure Boundary Components in pressurized water reactor (PWR) plants. [ Reference 33, Section 1.1]
. The scope of the progmm is threefold: (1) It provides examination locations where leakage may cause degradation of the primary pressure boundary by boric acid corrosion; (2) It provides examination
' Application for License Renewal 4.1-22 Calvert Cliffs Nuclear Power Plant
i i
ATTACHMENT m i
AVPENDIX A. TECHNICAL INFORMATION 4.1 - REACTO.R. COOLANT SYSTEM requiremeats and methods for the detection of leaks; and (3) It provides the responsibilities for initiating engineerb g evaluations and the subsequent proposed corrective actions. [ Reference 33, Section 1.2)
Under the SACI Program the VT 2 (a type of visual examination described in ASME XI, IWA 2212) walkdown examinations must be performed in accordance with ASME XI, IWA 2212, and the VT-1 examinations must be performed in accordance with ASME XI, IWA 2211. The VT 2 walkdown examinations must include the accessible external exposed surfaces of pressure-retaining, nomnsulated components; floor areas or equipment surfaces located underneath noninsulated components; vertical surfaces of insulation at the lowest elevation where leakage may be detected and horizontal surfaces at each insulation joint for insulated components; flocr areas and equipment surfaces beneath components and other areas where water may be channeled for insulated components whose external insulation surfaces are inaccessible for direct examination; and for discoloration or residue on any surface for evidence of boric acid accumulation. Any leakage detected must be reported on an IR for cor.osion degradation assessment. [ Reference 33, Section 5.2)
Upon reaching reactor shutdown, ISI personnel are required to perform a containment walkdown visual ir, sction (VT-2) as soon as poasible after attaining hot standby condition to identify and quantify any leakage found in specific areas of the Containment Building. A second ISI walkdown is performed prior to plant startup (at normal operating pressure and temperature) if leakage was identified and corrective actions taken. He ISI must ensure that all components that are subject ofIRs where boric acid leakage
- has been found are examined in accordance with the requirements of this program. [ Reference 33, Sections 5,1 and 5.2] Calvert Cliffs Administrative Procedure QL-2-100, " Issue Reporting and Assessment," defines requirements for initiating, reviewing, and processing irs, and resolution ofissues, ne irs are generated to document and resolve process and equipment deficiencies and nonconformances. [ Reference 34, Sections 1,1 and 1.2)
Additionally, the progrrm has evolved with regard to boric acid leaks discovered during other types of walkdowns and inspections. The program dictates a minimum qualification level of Level 11 Inspectors for the evaluation of boric acid leaks. Apparent leaks that are discovered d. iring these other walkdowns/ inspections are documented in irs by the individual discovering the leak. These irs are then routed to the ISI organization for closer inspection and evaloation by a Level 11 Inspectar for disposition.
This approach provides for more boric acid leakage inspection coverage and ensures boric acid leakage and its effects are properly evaluated.
Issue Reports that have been written in accordance with this program are required to address: (1) the removal of the boric acid residue; and (2) the inspection of the affected components for general corrosion. If general corrosion is found on a component, the IR is to provide an evaluation of the component for continued service and corrective actions to prevent recurrence.
[ Reference 33, Section 5.3]
Calvet Cliffs Technical Procedure RCS-10, " Pressurizer Manway Cover Removal and Installation," is also credited with the discovery of wear on the pressurizer components. He procedure contains steps
' hat direct the user to inspect the studs (if they were not removed) for the presence of boric acid. The procedare also directs the user to contact the ISI organization to perform visual inspections of the pressurizer manway studs and nuts to ensure that they are acceptable for reuse. If boric acid is present, RCS-10 directs the cleaning and !ubrication of the pressurizer manway studs and nuts. [ Reference 35]
Application for l>wnse Renewal 4.1-23 Calvert Cliffs Nuclear Power Plant
H ATTACIIMENT (1)
APPENDIX A.TECliNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Technical Procedure RCS-10 is performed during refueling outages. This program has been observed to be historically effective in managing the applicable aging.
Calvert Cliffs Technical Procedures SG 1,' Steam Generator Secondary Manway Cover Removal," and SG 2, " Steam Generator Secondary Manway Cover installation," are both credited with discovery of wear on the SG manway closure surfaces. Procedures SG 1 and SG-2 both direct the user to inspect the seating surfaces for defects, and if defects are found, to notify the job supervisor. The procedures also require the studs to be inspected prior to installation of the manway covers. [ References 36 and 37]
Both SG 1 and SG 2 are performed during refueling outages, This program has been observed to be historically effective in managing the applicable aging.
Calvert ?liffs Technical Procedures SG 5," Steam Generator Secondary llandhole Cover Removal," and SG 6, ' 6 team Generator Secondary External llandhole Cover Installation," are both credited with discovery of wear on the SG secondary handhole closure surfaces. Procedures SG-5 and SG-6 both direct the Wser to inspect the seating surfaces for defects or smoothness, and if defects are found, to notify the job supervisor. [ References 27 and 28] Both SG 1 and SG 2 are performed during refueling outages.
Calvert Cliffs Surveillance Test Procedures STP-M 574 l/2 are credited for discovering of wear on SG llX tubes. The procedure directs the user as to the sample size for tube inspection, inspection process, evaluation, and determination of tube status. Refer to Group 1 (denting) for a discussion of this surveillance program. [ Reference 38 and 39]
Calvert Cliffs Surveillance Test Procedures STP-0-27-1/2, " Reactor Coolant System Leakage Evaluation," are credited for discovering wear on the RCS valve discs and seating surfaces. The procedure wHI di5 cover wear on RCS valves by determining if any of them are leaking RCS coolant.
Calvert Cliffs procedures STP 0-27-l/2 directs the user to perform calculations to determine the amount and potential source of RCS leakage. Any abnormal RCS leakage would be detected and actions taken to conect the leakage prior to a loss of the valve intended function. The basis for the acceptance criteria of leakage rates are provided by the CCNPP Technical Specifications. The CCNPP Surveillance Test Procedures STP O 27-l/2 are performed in conjunction with CCNPP Technical Procedure CP-224,
" Primary to Secondary Leak Rate." [ Reference 401 This program has been observed to be historically effective in managing the applicable aging mechanism (s).
Calvert Cliffs Technical Procedure SG 20, " Steam Generator Primary Manway Cover Removal and installation," is credited with the discovery of wear on the SG primary maaway flange.; eating surfaces.
De procedure directs the user to inspect the SG primary manway flange sealing surfaces for flaws and to clean tne gasket surface areas. In addition, SG 20 requires the user to ensure that all studs and nuts have been inspected by BGE's Materials Engineering and Inspection Unit prior to installation. [ Reference 41]
This procedure is performed during plant refueling outages. This program has been observed to be historically effective in managing the applicable aging.
Calvert Cliffs will continually review industry activity and experience with respect to wear of tube in tube RCP seal water heat exchangers with CCNPP Administrative Procedure NS-1-100, "Use of Operating Experience and the Nuclear llotline." Calvert Cliffs will take appropriate actions if any wear-Application for 1.icense Renewal 4.1-24 Calvert Cliffs Nuclear Power Plant
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. ATTACHMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM induced pressure boundary leakage occurs in RCP seal water heat exchangers.
[ Reference 2,
. Attachments 8,10]
Group 2 (wear)- Demonstration of Aging Managernent Dased on the factors presented above, the following conclusions can be reached with respect to the components listed under the Materials and Environment section that are susceptible to wear:
The Group 2 components listed above provide the RCS pressure retaining boundary and containment isolation function, so their integrity must be maintained under CLB design conditions.
Wear is plausible for the Group 2 components mentioned above. Wear could result in the loss of component sp-*erial and lead to the loss of the passive intended functions.
_ The CCNPP Administrative Procedure MN 3-110 provides for the inspection of Group 2 components per the requirements of ASME Section XI. Though wear cannot be completely prevented, the status of pressure-retaining components can be evaluated on a basis that allows for corrective actions to be taken as conditions indicate component wear.
The CCNPP BACI Program provides for examination of potential corrosion of the Group 2 components described above and subsequent cleanup of any boric acid residue present on them.
The CC?TP Technical Procedure RCS 10 provides for the insrection of the pressurizer ir away seating surfaces for wear and manway studs / nuts for the presence of boric acid.
The CCNPP Technical Procedures SG-1 and SG 2 provide for the discovery of wear on the SG manway closure surfaces.
The CCNPP Technical Procedures SG-5 and SG-6 provide for the discovery of wear on the SG handhole closure surfaces.
The CCNPP Technical Procedures STP M-574-1/2 are credited for discovering wear on the SG IIX tubes. An IR is submitted to plug or sleeve SG IIX tubes that are considered susceptible to failure.
The CCNPP Surveillance Test Procedures STP-O-27-l/2 are credited for discovering wear on the RCS valve discs and seating surfaces that perform a pressure boundary function by performing RCS leak rate calculations. The RCS is subject to Technical Specifications for addressing any abnormal leakage.
The CCNPP Technical Procedure SG-20 requires inspection for wear / flaws on the SG primary manway cover flange seating surfaces.
Calvert Cliffs will continually review industry experience for RCP seal ws.a. IIX tube wear in accordance with CCNPP Administrative Procedure NS-1-100.
Calvert Cliffs will take appropriate action if the industry experiences degradation of these llXs resulting from tube wear.
Therefore, there is reasonable assurance that the effects of wear will be managed in order to maintain the pressure boundary integrity fbr the Group 2 components listed above under all design conditions required by the CLB during the period of extended operation.
. Application for License Renewal 4.1 25 Calvert Cliffs Nuclear Power Plant
t NffACilhENT (D APPENDIX A.TErilNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM Group 3 (erosion / erosion corrosion). Materials and Environment Table 4.13 shows that crosion is plausible for home RCP components and crosion corrosion is plausible for some SO llX components. These susceptible RCS components and their material characteristics are:
l
[ Reference 2, SG llX, PUMP 01, Attachments 4,5,6) t S0 IlX + main steam outlet nor.zles forging (alloy steel), secondary manway and manway cover e
plate (alloy steel), secondary handhole (carbon stect), and handhole cover plate (alloy steel); and RCP. case and pump cover (CASS).
e 1hc internal RCS environment (primary side) is that of cl.emically treated borated water at an operating pressure of approximately 2250 psia. The RCS operating temperatures are not greater than 548'F in the cold leg and a maximum of approximately 600'F in the hot leg. The RCS maintains a Dow rate of npproximately 134x10' lbm/hr.
[ Reference l, Section 4.1.1. Table 4.lt The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control.
The internal 50 environment (sr.condary side) during power generation is saturated steam and water at a design pressure / temperature of 1000 prlg/580'F and normal operating parameters of approximately 850 psig/$20'F. The SGs also contain chemleally treated, demineralized, high pressure water with high How rates and Guld velocities at full power conditions. [ Reference 1, Chapter 10.I,10.2, Reference 26]
During plant shutdown wnditions, the SGs may be drained.
Group 3 (ernelon/ erosion corrosion). Aging Mechanism E& cts Erosion is camed by the high velocity steam, water, or two-phase mixture (which may include particles) impinging on materials or leaking from joints. This mechanical wear or abrasion can be characterized by grooves, gullies, waves, holes, or valleys on a metal surface. Erosion corrosion is the acceleration of a carrosive ne eess because of the croelon of the protective oxide film, which results in chemical attack or v
dinclutic ~f the underlying metal. Ero; ion corrosion also occurs in environments with h!gh velocity water (sihsic on two phase) havirt How disturbances, low oxygen content, and Guld pil < 9.3. Erosion corrosion is also increased by component geometries that cause disturbances in the now stream.
[ Reference 2, Attachments 7. Valve]
The *occilled SG llX components are subjected to environments that are conducive to crosion corrosion, whiie the specified RCP co npon,nts are subjected to environmem conducive to erosion.111erefore,-
esosion ard emsion corrosion were determined to be plausible ARDMs for the Group 3 components for which aging effects must be managed. [ Reference 1. Attachments 6s, l{X, PUMP]
Eroup 3 (ero.lon/crosion corrosion). Methods to Manage Aging Mjtigation; Desigt, features, such as the proper material select.on (and proper installation) of the RCS device types susceptible to tl.ese ARDMs, can mitigate the effects of crosion/ erosion corrosion.
Dhcomy:- Erosion and crosion corrosion can occur over time and are revaaled as material loss of the components themselves. - These effects can be discovered and monitored by visual inspection of the potentially affected areas.
Visual inspections of these components could find any potential Application for License Renewal 4.1 26 Calvert Cliffs Nuclear Power Plant
ATTACHMrNT f1)
APPENDIX A.TECilNICAL INFORMATION dl-REACTOR COOLANT SYSTEM I
crosion/crosion corrosion on the components. Programs that monitor crosion corresion could be utilized as a means of tracking and discovering the onset of these aging mechanisms before the RCS components fall to perform their intended function.
Programs / procedures that look for RCS leakage also augment the management of crosion/ erosion corrosion by discovering leakage and performing subsequ'nt ourrective actions that would alleviate conditions leading to these ARDMs.
Group 3 (erosion / erosion corrosion) At et Management Program (s) l Mitigation: There are no CCNPP programs credited with the mitigation of crosion/ erosion corrosion.
1hc following discovery programs can limit the effects of these ARDMs by taking corrective actions when they are discovered.
Discau:ty: 1he CCNPP Administrative Procedure MN 3110 is one of the existing programs designed to detect and manage the aging effects of crosion corrosion of the SG main s'eam outlet nonles.
(Reference 2, Attachments 8 TPR) The ISI Program refers to an ultrasonic procedure that examines the SG main steam outlet noule inner radius area.1his procedure directs the user to refer to the ASME Boller and Pressure Vessel Code Section XI. Table IWB 35121 for evaluation criteria of the ultrasonic examination results. [ Reference 42] Refer to the previous discussion of the ISI Program under Group 2 (wcar) under Aging Managemerit Programs.
Calveit Cliffs DACI Program is credited with the discovery of crosion of the joint before the RCP cast.
and pump cover.1hc protedure requires investigation of any boric acid leakage that is found on these components during walkdowns. Refer to the previous discussion of the DACI Program under Group 2 (wear). Aging Management Programs.
Group 3 (erosion / erosion corrosion) Demonstrelon of Aging Management
- Dased on the factors presented above, the following conclusions can be reached with respect to the Group 3 components:
The Group 3 components provide a pressure retaining bounJary for the RCS, so their integrity must be maintained under CLB design loading conditions.
Erosion is plausible for RCP components listed above. This could resub in the loss of component material and lead to the loss of the pressure retaining boundary function.
Erosion corrosion is plausible for the SG main steam outlet nonles. This could result in the loss of component material and lead to the loss of the pressurectaining boundary function.
Calvert Cliffs' ISI Program is credited with the discovery of crosion corrosion on the SG main outlet nonles tising ultrasonic examinations. The program requires the performance of corrective actions before a pipe /nonic wall thins to below the minimum required wall thickness necessary for the pipch.oule to perform its intended function.
Calvert Cliffs B ACI Program is credited with the discovery of erosion on the joint before the RCS case and pump cover. This program also provides for examination of potential corrosion of the Application for License Renewal 4.1 27
- Calvert Cliffs Nuclear Power Plant
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AHACEMINI LU APPENDIX A TECHNICAls INFORMATION 4.1.HEACTOR COOLANT SYSTEM RCS device types described above and subsequent cleanup of any boric acid residue present on them.
Herefore, 'here is reasonable assurance that the effects of erosion and crosion corrosion will be managed in order to maintain the pressure boundary integrity for the RCS device types listed above under all design conditions required by the CLB during the period of extended operation i
Group 4 (fatigne). Materials and Environment I
Table 4.13 shows that fatigue is plausible for some of the RCS device types. Dese susceptible RCS device types and their material characteristics are:
(Reference 2, CC 01/02/03/04/05/06, GC.
01/02/03/04/05/06, CKV 01, CV 01, ERV-01, ilX 01, MOV 01/02, PUMP-01, PZV 01, RV 01 Attachments 4,5,6)
CC includes all piping subcomponents such as nonles, forgings, welds, safe ends, and thermal sleeves (piping is stainlesc steel, safe ends are CASS);
i GC. pipe (stainless steel), Danges (stainless steel), bolting studs (alloy steel), bolting hex nuts e
(carbon steel), welds (stainless steel);
CKV body / bonnet (stainless or carbon steel) and bolting (carbon steel);
e CV body / bonnet (CASS) and bonnet / internals (stainless steel);
e ERV cage (CASS)and body / internals (stainless steel);
SG llX lower shell segments, upper shell segment, upper cone segment, top head peel segments e
(carbon steel), top head dome segment, steam outlet nonic forging, steam outlet safe end, feedwater nonic forging, feedwater nonle safe end (alloy steel), and secondary welds (alloy steel);
MOV - body / bonnet (austenitic stainless steel, stainless steel), disc and stem (CASS and stainless e
steel), and seat (stellite on CASS);
PUMP - (RCP) case and pump cover (CASS), closure studs and nuts (carbon steel);
PZV all pressurizer subcomponents are susceptible to fatigue (main shell, head and bottom e
plates are alloy steel with stainless steel or Alloy 600 cladding); and RV base (austenitic stainless steel), noule (alloy steel), disc (CASS).
e
%c internal RCS environment (primary side) is that of chemically treated borated water at an operating pressure of approximately 2250 psia. He RCS operating temperatures are not greater than 548'F in the cold leg and a maximum of approximately 600'F in the hot leg. The RCS maintains a Dow rate of 6
appr3ximately 134x10 lbm/hr.
[ Reference 1, Section 4.1.1, Table 4 l]. De RCS also contains chemicalm for controlling reactor po ur (boric acid) and corrosion control.
' Be internal SG environment (secondary side) during power generation is saturated steam and water at a
' design pressure / temperature of 1000 psig/580*F and normal operating parameters of approximately 850 psig/520'F. The SGs also contain chemically treated, demineralized, high pressure o ater with high Dow rates and Guld velocities at full power conditions. [ Reference 1 Chapter 10.1,10.2, Reference 26]
During plant shutdown conditions, the SGs may be drained. %c RCS components listed are subject to Application for License Renewal 4.1 28 Calvert Cliffs Nuclear Power Plant
1 A*ITACllMENT f1)
APPENDIX A TECHNICAL INFORMATION 4.1 MEACTOR COOLANT SYSTEM t
thermal and mechanical cyclic loading during RCS heat.up and cool-down and other plant opera:lonal events.
Group 4 (fatigue). Aging Mechanism Effects Low cycle fatigue is a mechanism that initiates and propagates Daws under the influence of Ductuating or cyclic applied stress. Fatigue is in0uenced by variables that include: mean stress, stress range, environmental conditions, surface roughness, and temperature. Thermal stresses develop when a material is heated or cooled. Generally, fatigue failures occur at stresses having a maximum value less than the yield strength of the material if a component is repeatedly subjected to loads of sufficient magnitude, a fatigue crack or cracks will eventually be formed in some highly stressed region and may gradually progress through the metal until complete fracture occurs. [ Reference 43, page 4 7) ne cracks may then propagate under continuing cyclic stresses.
The fatigue life of a component is a limetion of several variables such as str6 evel, stress state, cyclic wave form, fatigue environment, and the metallurgical condition of the matei. Failure occurs when the endurance limit number of cycles (for a given load amplitude) is exceeded.
[ Reference 2, Attachments 7s)
The RCS device types listed above are subject to a wide variety of varying mechanical and thermal loads. [ Reference 2, Attachments 7s] Plant transients apply cyclical thermal loading and pressurization that contribute to fatigue accumulation on the RCS device types above. The limiting locations for low-cycle fatigue in the RCS and their controlling transients are: [ Reference 44, Table 51]
Pressurlier Spray System cycle of the pressurizer spray; e
Safety injection nozzle plant cooldown (initiation of shutdown cooling);
Charging inlet nonle loss of charging How and recovery, loss of letdown How and recovery, e
regenerative heat exchanger isolation; Pressurizer surge nonle - pressurizer heatup and plant cooldown; SO secondary shell initiation of main feedwater, initiation of auxiliary feedwater; SO feedwater nonle initiation of main feedwater; Pressuriter bottom head and support skirt plant cooldown, reactor trip; Shutdown cooling outlet nonle plant cooldown; and e
SG tube-to-tubesheet weld primary leak test RCS heatup.
American Society of Mechanical En, ects Section til requires the design analysis for Class I components to address fatigue and estabbshes limits such that initiation of fatigue cracks is precluded.
Section 111 defines the fatigue threshnid in terms of a cumulative fatigue usage factor (CUF). The low.
cycle fatigue " damage" from a particular transient depends on the magnitude of the stresses applied. The summation of ratigue usage over all transients of all types is the CUF. Crack initiation is conservatively assumed to have occurred at a CUF equal to one.
Application for License Renewal 4.1 29 Calvert Cliffs Nuclear Power Plant
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y--w-,,--n-,
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AIIAcitMENT (1)
APPENDIX A.TI'CHNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM 1he CUF can be determined from the actual or predicted transient history for the compos ent and limits established on the number of transients.
Group 4 (fatigwe). Mettiods to Manage Aglag r
hiltintion: The effects of low cycle fatigue can be mitigated by operational practices that reduce the
[
number and severity of thermal transients on the RCS components and by proper design and material i
selection.1herefore, the effects of fatigue can be mitigated by operational practices that reduce the number and severity of pressure and thermal transients, by fuel management practices that minimite the number oflefuelings, and by proper design and material selection.
Dh n ety: Fatigue cracks can be discovered by inspecting components, and the scope and frequency of inspations can be established based on the likelihood that fatigue cracks have initiated. As discussed above, low-cycle fatigue is accounted for in the original design in accordance with ASME Code Section 111. Monitoring the number of design basis transients and/or the accumulated fatigue usage can be used to predict the end of fatigue life.
American Society of Mechanical Enginects Code Section111 also provides accepted practices for
. analyzing Class I components for thermal fatigue combined with all other loads that must be considered l
under the Cl.II. An inspection program designed to identify crack initiation can be effective in discovering the effects of this aging mechanism prior to loss of the RCS pressure boundary function.
'ihe RCS components listed above can be inspected during plant refueling outages.
Group 4 (fatistue). Aging Manag, uent Program (s) hiltigatin: As part of general operating practice, plant operators minimize the duration and severity of tralisitory operational cycles. Further modification of plant operating practices to reduce the magnitude and/or frequency of thermal transients would place additional unnecessary restrictions on plant operations.1his is because the detection and monitoring activities discussed below are deemed adequate for effectively managing fatigue in the RCS. No credit has been given to the 24 month fuel cycle since plant transients other than refueling could cause plant heat ups and cool downs.
Dhcarry: The CCNPP Fatigue Monitoring Program (FMP) records and tracks the number of critical thermal and pressure test transients. Cycle counting is performed as part of this program. The data for thermal transients is collected, recorded, and analyzed using a safety related sonware package. The sonware is used to analyre data that represents real transients and to predict the number of transients for 40 and 60 years of plant operation based on the historical records. This information is used to verify that the RCS critical locations will not experience more than the allowable numbcr of cycles for those locations.
. [ Reference 44. Tables 41,4 7, Reference 45)
The improved Standard Technical Specifications for CCNPP, which will be implemented in 1997, will contain a requiremen, for tracking cyclic wd transient occurrences to ensure that components are maintained within the design limits.
The current FMP monitors and tracks low cycle fatigue usage for the limiting components of the NSSS and the SG safe-ends to-reducer welds. Eleven locations in these systems have been selected for monitoring for low-cycle fatigue usage; they represent the most bounding locations for critical thermal and pressure transients and ope:ating cycles. [ References 44 and 45] The RCS critical (or bounding)
Application for License Renewal 4.1 30 Calvert ClitTs Nuclear Power Plant
ATTACllMINT (1)
APPENDIX A.TECilNICAL INFORMATION t
4.1 - MEACTOR COOLANT SYSTEM i
locations and their controlling transients for fatigue are listed above in the Aging Management Effects section. [ Reference 44, Sections 4.1,4.8) A one time fatigue analysis will be performed for the RCPs, MOVs, and pressurizer RVs to determine if thisc components are bounded by components and transients currently included in thn FMP. If these components are not bounded they will be added to the FMP.
[ Reference 2 Attachments 10]
He original design fatigue analysis of the RCS components (which was incorporated into the FMP) determined the critical locations and corresponding transients. All transients that contribute to low cycle fatigue usage are accounted for as part of the original design fatigue analysis. The FMP only tracks certain critical transients (see list of trans!cnts and components under Methods to Manage Aging). The contribution to fatigue usage for all other design transients is accounted for by an " initial" fatigue usage.
The software package adds subsequent fatigue usage resulting from RCS pressure and temperature.
transients to "initid" fatigue usage to obtain the current CUF.
[ Reference 44 Sections 4.1,4.8, Reference 46)
The current FMP tracks low cycle fatigue usage using both cycle counting and stressed-based analysis.
In accordance with ASME Code Section 111, the fatigue life of a component is based on a calculated CUF ofless than or equal to one. The CUF and vml number of transients for limiting locations in the NSSS and sos are determined using plant thersi sr@vure data. The CUF for several locations, including the pressurlier surge line, is also calculatM > Ar3 wiss based analysis techniques. [ References 45,46, and 47]
Plant parameter data is collected on a periodic basis and revieweu to ensure that the data represents actual transients. Valid data are entered into the software, which counts the critical transient cycles and calculates the CUFs. Based on ASME Code Section 111, a CUF less than or equal to one, and/or the number of cycles remaining below the design allowable number, are acceptable conditions for any given component since no crack initiation would be predicted.
The number of cycles and CUF are calculated on a semi. annual basis, which provides a readily predictable approach to the alert value. [ Reference 47, Section 1.1] In order to stay within the design basis, corrective action is initiated well in advance of the CUF approaching one or the number of cycles approaching the design allowable, so that appropriate corrective actions can be taken in a timely and coordinated manner. [P.eference 47]
Modifications have been made to the FMP recognizing lessons learned. For example, analysis techniques, such as stress based analysis, have been implemented for locations that have unique thermal transients or involve unique geometry. Other modifications have been made to reflect changes or proposed changes to plant operating practices, and to reflect plant operating conditions more accurately, The plant design change process requires the FMP to consider any proposed changes that affect the fatigue design basis or transient definitions. [ References 45 and 48)
The CCNPP FMP has been inspected by the NRC, which noted that this monitoring system can be used to identify components where low-cycle fatigue usage mty challenge the remaining and extended life of the components and can provide a basis for corrective action where necessary. The program is controlled in accordance with EN 1300," Implementation of Fatigue Mocitoring." [ Reference 49] Since the FMP Application for 1,icense Renewal 4.1-31 Calvert Cliffs Nuclear Power Plant
+,,,,
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,.n
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A*ITACHMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM has been initiated, no locations have reached their design allowable number of cycles or a CUF of greater than or equal to one. He CUFs through 1996 for the RCS components listed above are: [ Reference 45]
Unit 1 IJnitl Pressurizer Spray System 0.33877 0.32699 e
Safety injection Nonle 0.00992 0.00925 Charging Inlet Noule 1 0.1 ISIS 0.11615 e
Charging inlet Nor21e 2 0.11515 0.11616 e
Pressurizer Surge Nozzle 0.13137 0.09635 50 Secondary Shell 1 0.08957 0.09110 e
SO Secondary Shell 2 0.08951
- 0.09133 Pressurizer Bottom IIcad and Support Skirt 0.26150 0.23734 Shutdown Cooling Outlet Nozzle 0.15917 0.12896 SO Tube-to Tubesheet Weld 1 0.02653 0.02653 e
- SO Tube to Tubesheet Weld 2 0.02653 0.02653 To further address fatigue for license renewal, CCNPP participated in an EPRl sponsored task to demonstrate the industry fatigue position. He task applied industry-developed methodologies to identify fatigue sensitive component locations that may require further evaluation or inspection for license renewal and evaluate environmental clTects as necessary, The program objective included the development and justincation of aging management practices for fatigue at various component locations for the renewal period. He demonstratbn systems were the Feedwater System, the pressurizer surge line, and the Charging / Letdown System. [ Reference 4, Page 3]
Gractic Safety Issuc_lli6 Generic Safety issue 166, Adequacy of Fatigue Life of Metal Components, presents concerns identined by the NRC that must be evaluated as part of the lleense renewal process. The NRC staff concerns about fatigue for license renewal fall into five categories: The Orst is adequacy of the fatigue design basis when environmental effects are considered. This concern does not apply to the RCS because of stringent RCS water chemistry controls, exceptionally low oxygen concentrations (less than 5 parts per billion),
and because the RCS carbon steel interior surfaces are clad with stainless steel. The second category concerns the adequacy of both the number arid severity of design basis transients. Since these have already been analyzed for the CCNPP RCS, this concern does not apply. A third category, adequacy of ISI requirements and procedures to detect fatigue indications, does not apply because CCNPP does not rely on ISI as the sole means for detection of fatigue. Category four, adequacy of the fatigue design basis for Class I piping components designed in accordance with American Nuclear Standards Institute B31.1, does not apply because the RCS does not have piping components designed in accordance with H31.1. The Of1h and last category, adequacy of actions to be taken when the fatigue design basis is potentially compromised, are adequately addressed by the CCNPP FMP. [ Reference 50, 110 Application for License Renewal 4.1 32 Calvert Cliffs Nuclear Power Plant b
9
, TTACllMENT_II)
APPENI)IX A TECHNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM Group 4 (fatigue) Desmonstration of Aging Management
{
Hased on the factors presented above, the following conclusions can be reached with respect to the RCS components subject to low cycle fatigue:
The 0,oup 4 components provide a pressure retaining boundary for the RCS, so their integrity e
must be maintained under CLB design conditions.
j low cycle fatigue is plausible for the Group 4 device types listed above.
e if left unmanaged, low cycle fatigue could result in crack initiation and growth, which could e
impair the pressure retaining function.
'Ihe Group 4 device types are the bounding fatigue sensitive components for the RCS and are e
expected to bound the other RCS components for the effects of fatigue, The CCNPP FMP tracks all applicable plant transients and monitors the cycles and fatigue usage e
for the bounding RCS components.
The FMP is controlled so that effective and timely corrective acticns can be taken prior to a loss of RCS pressure boundary integrity resulting from fatigue damage.
A one time fatigue analysis will be performed for the RCPs, MOVs and pressurlier RVs to determine if these components are bounded by components and transients currently included in the FMP. If these components are not bounded they will be added to the FMP.
Tracking the cycle and fatigue usage for the bounding RCS components will ensure that they and e
all other RCS components will not exceed their fatigue design basis.
Therefore, there is reasonable assurance that the efTects of fatigue in RCS components will be managed in order to maintain the components' intended function under all design loading requirements of the CLB during the period of extended operation.
Group 5 (galvanic / general corrosion and pitting)-Materials and Environment Table 4.13 shows that galvanic, general corrosion, and pitting are plausible for some of the RCS components. The RCS subcomponents listed below are susceptible to one or more of these ARDMs,
'these susceptible RCS components and their material characteristics are:
[ Reference 2, CC.
01/02/03/04, GC 01/02/03/04/0$/06, CKV 01, ERV 01, ilV 04, llX-01, MOV-02, PUMP-01, PZV-01, RV 01, Attachments 4,5,6)
General CorIpsion ihternal -
e ' CC pipe, cibows, and noule forging (carbon steel), bolting studs (alloy steel), bolting hex nuts (carbon steel);
GC - botting studs and botting hex nuts (carbon steel);
e-CKV - some of the CKVs bolting (carbon steel);
e
-
Application for License Renewal _
4.1 33 Calvert Clifts Nuclear Power Plant
{
ATTACliMENT (1)
APPENDIX A. TECHNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM SG llX primary manway (alloy sted, clad. Alloy 600), manway cover plate (carbon or alloy steel), primary head torus (carbon steel with stainless steel clad), spherical head (carbon steel);
secondary manway studs (alloy steel) and hex nuts (carbon steel), secondary manway yoke (carbon steel), handhole studs and nuts (alloy steel); primary manway studs and nuts (alloy steel);
lower support sliding base and cap plate (carbon steel), lower support flange bolts (alloy steel),
and flange nuts (carbon steel);
MOV. bonnet stud and nai(carbon steel);
PUMP. closure studs and nuts (carbon stect);
Pressurizer. alloy steel shell, top head and bottom head (alloy steel); safety / relief valves, spray and surge nozzle forgings (forged alloy steel); manway forging (alloy steel), manway cover plate (carbon stect), manway bolting studs and bolts (alloy steel); carbon steel welds; support ring assembly and base ring assembly (carbon steel), support skirt forging (alloy steel), and lifling lugs (carbon steel); and RV bonnet / spring / bonnet studs (carbon or alloy steel).
Osnual Corrosion. Intemd SG llX tube support structures (carbon steel components of various Grades and Classes)
Galvanic Corrosion. INtcrnal llV. stem, disk and seat (sf sinless steel).
e
$tinn. Internd i
SG llX. tubes (Alloy 600) exposed to the SG internal (secondary side) environment.
He internal RCS environment (primary side) is that of chemically treated borated water at an operating pressure of approximately 2250 psia. He RCS operating temperatures are not greater than 548'F in the cold leg and a maximum of approximately (00'F in the hot leg. De RCS maintains a flow rate of approximately 134x10' lbm/hr.
[ Reference 1, Section 4.1.1 Table 4-l].
The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control.
He internal SG environment (secondary side) during power generation is saturated steam and water ai a design pressure / temperature of 1000 psig/580*F and normal operating parameters of approximately 850 psig/520'F, The SGs also contain chemically treated, demineralized, high pressure water with high flow rates, and fluid velocities at full power conditions. [ Reference 1, Chapter 10.1,10.2, Reference 26]
During plant shutdown conditions, the SGs may be drained.
As the interface between the primary and secondary fluids, the SG llX tubes are subjected to both the internal RCS environment and the intemal SG environment.
The external RCS environment is ambient atmospheric sir inside the Containment Building that is elimate controlled. His environment in the Containment Dullding during normal operations has maximum humidity of 70% and maximum temperature of 120'F.
[ Reference 1, Table 918, Reference 29, Attachments 1. Table 1 page 13]
Application for License Renewal 4.1 34 Calvert ClitTs Nuclear Power Plant -
AITAcitMrNT (1)
APPENDIX A TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM for RCS carbon steel components clad on the interior surfaces with stainless steel, only exterior surfaces 4
could be susceptible to the ARDMs in this group. The RCS contains boric acid that could leak onto the
{
exterior of these carbon steel components. [ Reference 2. Attachments 6s and 7s]
Group 5 (galvanic / general corrosion and pitting) Asing Mechanism Effects i
General corrosion is degradation that results in wall thinning (wastage) due to chemical attack (dissolution) by an aggressive environment to rnaterials susceptible to thr.t environment. An important concern is the leakage of boric acid on carbon steel components. Doric acid attacks and damages the components clad internally with stainless steel from the their exterior (carbon steel) surfaces. The consequences of the damage are a loss of load carrying cross sectional area. General corrosion could lead to excessive wall thinning and failure of the RCS pressure boundary function for the RCS components. [ Reference 2. Attachments 7s]
i Galvanic corrosion is accelerated corrosion caused by dissimilar metals in contact in a corrosive or conductive solution. Galvanic corrosion requires two dissimilar metals in physical or electrical contact, developed electrical potential (material dependent), conducting solution, and a corrosive environment (i.e., oxygen or chlorides for example). [ Reference 2, Attachments 7s)
Pitting is a form of locallied general corrosion that results in holes in a metal. Pitting can lead to penetrations of the pressure boundary with a small amount of metal loss. Carbon steels, stainless steels, and Alloy 600 are susceptible to pitting in various degrees. Severe pitting of CE SG tubes has occurred at other power plants. [ Reference 2,ilX01, Attachments 7]
ifleft unmitigated in the long term, galvanic / general corrosion could eventually result in failure of the Group 5 components pressure retaining capability under CLU design loading conditions.
Group 5 (galvanic / general corrosion and pitting) Methods to Manage Aging Mitigation: The effects of these ARDMs cannot be completely prevented, but they can be mitigated by minimizing the exposure of the carbon steel surfaces of the RCS metal components to an aggressive chemical environment. Stainless steel cladding on the interior of some RCS components helps to reducc the effects of galvanic / general corrosion on the interior surfaces exposed to reactor coolant, liowever, mitigation of corrosion on the exterior surfaces of the Group S components requires minimization of RCS leakage frons the RCS pressure boundary, and the removal of any boric acid residue from exterior RCS surfaces.
Discovem 'the effects of galvanic / general corrosion on the RCS components can be discovered through a program of visual inspections on the RCS areas susceptible to these ARDMs. Inspection of the areas around the RCS components would identify leakage occurring and result in corrective octions being taken before corrosion could degrade the RCS intended function. Those Group S components that are not accessible to visual inspection (i.e., SG llX tubes - pitting) can be examined using remote sensing techniques.
Application for License Renewal 4.1 35 Calvert Cliffs Nuclear Power Plant
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1 i
1 AUACHMENT_II)
APPENDIX A. TECHNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM t
Gronp 5 (galvanic / general corrosion and pitting)- Aging Manage:nent Prograni(s) l Mitinatinn:
Ihternah The CCNPP BACI Program will mitigate the effects of boric acid corrosion on external carbon steel surfaces through discovery of minor leakage of RCS components and removal of any boric acid residue that is found during walkdown inspections. Removal of any boric acid leakage from component surfaces mitigates the effects of this substance on these surfaces. This program was previously described in Group 2 (wear) under Aging Management Programs.
Dhcacty:
INiernah Discovery of galvanic / general corrosion for RCS components is performed by the CCNPP llACI Program and Technical Procedure SG 20. These programs and procedures require the visual inspection of RCS components for boric acid leakage and corrosion. The CCNPP llACI Program is credited with discovery of galvanic / general corrosion for those RCS components listed as susceptible to these ARDMs. This program requires investigation of any boric acid leakage that is discovered. The BACI Program was previously discussed in Group 2 (wcar) under Aging Management Programs.
(Reference 2. Attachments 8)
'the CCNPP MN.3110, ISI of ASME Section XI Components, is credited with discovering galvanic / general corrosion on the RCP components and discovering general corrosion on RCS piping (pipe code.CC). Visual examination (VT 2) of external surfaces are performed for these RCS components in accordance with ASME Section XI IWA.2212. [ Reference 2, Attachments 8]
'Ihe CCNPP Technical Procedure SG 20 is credited with the discovery of general corrosion on the SG primary manway bolting materials. The procedure directs the user to inspect the SG primary manway Dange sealing surfaces for Daws and to clean the gasket surface areas, in addition, SG 20 requires the user to ensure that all studs and nuts have been inspected prior to installation. [ Reference 41) This procedure is performed during plant tefueling outages.
Internah The CCNPP Technical Procedures STP.M 5741/2 are credited for discovering pitting on SG llX tubes.
'the procedure implements the inspection requirements of the CCNPP Technical Speci0 cations and defines the sample size for tube inspection, inspection process, evaluation, and determination of tube status. 'this procedure was previously described in Group 2 (wear) under Agh.g Management Programs. [ References 38 and 39]
For internal corrosion of SG HX tube support structures, BGE is aware of SG How assisted corrosion at the San Onofre Nuclear Generating Station and will monitor industry activity related to this aging mechanism. Calvert Cliffs will respond to any NRC generic communications on this matter as part of the CLD An evaluation of Dow. assisted corrosion for CCNPP SGs will be incorporated into annual updates of the BGE LRA.
The corrective actions taken as a result these programs will ensure that the RCS components remain capable of performing their intended function under all CLB conditions during the period of extended.
operation.
Application for License Renewal 4.1 36 Calvert Clifts Nuclear Power Plant
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4 AITACllMENT f1)
APPENDIX A. TECHNICAL INFORMATION 4.1. REACTOR COOI ANT SYSTEM iiroup 5 (galvan!c/ general corrosion and pitting). Demonstration of Aging Management Based on the material presented above, the following conclusions can be reached with respect to the galvaulc/ general corrosion and pitting of the Group 5 components:
The Group 5 components provide a pressure retaining boundary, and their integrity must be maintained under CLU design loading conditions.
General corrosion is plausible for the Group 5 components listed as susceptible, which could lead to loss of pressure retaining boundary integrity.
Galvanic corrosion is plausible for the Group 5 hand valves, which could lead to loss of pressure-retaining boundary integrity.
Pitting is plausible for the SG llX tubes, which could lead to loss of pressure retaining boundary integrity.
%e CCNPP BACI Program provides for examination of potential galvanic and general corrosion of the RCS c' ternal surfaces and subsequent clea >up of any boric acid residue.
x
%e CCNPP ISI Program provides for the inspection of RCS pipe and RCPs, per the requirements of ASME Section XI, for galvanic / general corro.; ion. nough galvanic / general corrosion cannot be completely prevented, the status of these components can be evaluated on a regular basis and corrective actions can be taken as conditions indicate general corrosion.
Calven Cliffs Technical Procedure SG 20 will provide for the discovery of general corrosion or flaws on the SG primary manway cover flange seating surfaces and primary manway studs / nuts.
Calven Clilh Technical Proceduies STP M 5741/2 are credited for discovering pitting of the SG llX tubes. An IR is submitted to plug or sleeve SG llX tubes that are considered susceptible to
- failure, Examinations will be performed and appropriate corrective actions will be taken if e
galvanic / general corrosion or pitting are discovered.
%crefore, there is reasonable assurance that the effects of galvanic / general corrosion and pitting on RCS components will be managed in order to maintain the components pressure boundary integrity under all design conditions required by the CLB during the period of extended operation.
Group 6 (IG A). Materials and Environment Table 4.13 shows that IGA is plausible fo* the RCP seal water ilXs, which are subjected to both the RCS and CC System environment. The RCP seal water 'riXS are fabricated faom stainless steel.
[ Reference 2,llX 02, Attachments 4,5,6)
- The internal RCS environment (primary side) is that of chemically-treated borated water at an operating pressure of approximately 2250 psia. The RCS operating temperatures are not gnater than 548T in the cold leg and a maximum of approximately 600T in the hot leg. He RCS maintains a flow rate of approximately 134x10' lbm/hr.
(Reference 1, Section 4.1.1, Table 4-1].
The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control. The intemal environment of Application for License Renewal 4.1 37 Calvert Cliffs Nuclear Power Plant
~.
ATTACllMENT W APPENDIX A.TECIINICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM the CC System is chemically treated water at a design pressure of 150 psig and a maximum design temperature of 180'F. [ Reference 1, Section 9.5.2.1, Table 917]
Group 6 (IGA). Aging Management Effects 1
Intergranular attack is similar to IGSCC, except that stress is not required for IGA. Intergranular attack is locallred corrosion at or adjacent to grain boundaries, with relatively little corrosion of the material grains, it is caused by impurities in the grain boundaries, or the enrichment or depletion of alloying elements at grain boundaries, such as the depletion of chromium at austenitic stainless steel grain boundaries. Nickel alloys, such as Alloy 600. experience IGA in the presence of certain sulfur environments at high temperatures or when austenitic stainless steel weld filler material is inahertently used on Ni Cr Fe alloys. The susceptibility of IGA can ollen be corrected by redistributing alloying elements more uniformly through solution heat treatment, by modifying the alloy to increase resistance to segregation, or by using a completely different alloy. [ Reference 2,ilX 02, Attachments 7s]
Group 6 (IGA)- Methods for Managing Aging hildgaden: The effects ofIGA can be mitigated on RCP se61 water llXs y minimizing the exposure of the internal surfaces of the components to an aggressive environment. Maintaining system chemistry conditions to minimize impurities can limit the rate and effects of degradation due to these ARDMs.
Discovery: 1here are no feasible methods to discover IGA on the RCP seal water ilXs other than indications of RCS leakage into the CC System. This RCS leakage is detected by radiation monitors in the CC System.
Group 6 (IGA). Aging Management Program (s) hiitigation: The etTects of IGA will be mitigated for the RCP seal water HX by CCNPP Chemistry Procedure CP.204," Specification and Surveillance Primary Systems," and CP.206," Specifications and Surveillance for Component Cooling / Service Water Systems." Maintaining an RCS and CC System chemistry with minimal impurities will aid in the preventing IGA. [ Reference 2, Attachments 1]
CP-204 Calvert ClitTs Technical Procedure CP.204 is credited with mitigating the effects ofIGA on the RCP seal water ilX (RCS side) by monitoring and maintaining the RCS chemistry. The chemistry controls provided by CP 204 have been established to: minimize impurity ingress to plant systems; reduce corrosion product generation, transport, and deposition; reduce collective radiation exposure through chemistry; improve integrity and availability of plant systns; and extend component and plant life.
Maintaining system chemistry conditions to minimize impurN. limits the rate and effects of component degradation. CP.204 in based on the Technical Specifications, DGE's interpretation of industry standards, and recommendations made by CE.
[ Reference 51, Sections 1.0,2.0; Reference 52, Section 6.1.A]
The scope of CP 204 includes the following systemvcomponents: [ Reference 11, Section 2.0]
Reactor Coolant (Modes 1 through 6);
Application Per License Renewal 4.1 38 Lalvert Cliffs Nuclear Power Plant
ATTACHMENT fu APPENDIX A-TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM Spent Fuel Pool (Modes 1.arough 6);
e Refueling Water Storage Tank (Modes I through 6);
e Refueling Pool (Mode 6);
e Safety injection Tanks (Modes 1 through 6);
e liigh Pressure Safety injection Pump Discharge (Modes 1 through 6);
)
e lloric Acid Storage Tank (Modes 1 through 6);
e Reactor Coolant Waste Receiver Tank (Modes 1 through 6);
e Reactor Coolant Waste Evaporator Bottoms (Modes 1 through 6);
e e.
Iloric Acid Batching Tank (Modes 1 through 6);
Chemical and Volume Control lon Exchangers (Modes 1 through 6); and e
Spent Fuel Pool lon Exchangers.
Calvert Cliffs Technical Procedure CP 204 lists the parameters to monitor (e.g., chloride, fluoride, sulfate, oxygen, pil), the frequency of monitoring these parameters, and the acceptable value or range of values for each parameter. The primary chemistry parameters are measured at procedurally specified frequencies (e.g., daily, weekly, monthly) and are compared against " target values," which represent a goal or predetermined warning limit. If a target value is approached or violated, corrective actions are taken as prescribed by the procedure, thereby ensuring timely response to chemical excursions.
[ Reference 50, Sections 3.0.C.4,6.0)
The chemistry program at CCNPP (which includes CP 204) is subject to internal assessment activity both within the Chemistry Department and through the site performance assest. ment group. The program is also subject to external assessments by Institute for Nuclear Power Operations, NRC, and others.
Operating experience relative to the chemistry program at CCNPP has shown it has been effective in its function of minimizing corrosion and corrosion-related failures and problems.
Calvert Cliffs Technical Procedure CP-204 provides for a prompt review of primary system chemistry 4
parameters so that steps can be taken to return chemistry parameters to acceptable levels (within Technical Specification limits), and thus minimizing impurities and limiting the rate and effects of degradation due to corrosion mechanisms. [ Reference 2, Attachments 8; Reference 50, Section 2.0]
CP-206 Calvert Cliffs Technical Procedure CP 206 is credited with mitigating IGA on the RCP seal water ilX (CC System side) by monitoring and maintaining CC chemistry to control the concentrations of oxygen, chlorides, other chemicals, and contaminants. The water is treated with hydrazine to minimize the amount of oxygen in the water that aids in the prevention and control of most corrosive mechanisms.
Continued maintenance of system water quality will ensure minimal piping or e mponent degradation.
[ Reference 53, Attachments 8]
Calvert Cliffs Technical Procedure CP 206 describes the surveillance and specifications for uonitoring the CC System fluid. The procedure lists the paramet a to monitor, the frequency of monitoring these
~
Application for License Renewal.
4.1-39 Calvert Clifts Nuclear Power Plant
ATIACHMENI,.LO 1
APPENDIX A. TECHNICAL INFORMATION 4.1 -HEACTOR COOLANT SYSTEM parameters, and the target and action levels for the CC System fluid parameters. The parameters monitored by CP 206 are pil, hydrazine, chloride, dissolved oxygen, dissolved copper, dissolved iroa, suspended solids, gamma activity, and tritium activity (normally not a radioactive system).
[ Reference 54, Attachments 1]
nese chemistry parameters are :urrently monitored on a frequency ranging from three times per week to once a month. All of the parameters listed in CP 206 currently have target values that give an acceptable range or limit for the associated parameter. Two of the prameters, pil and hydrazine, have action levels associated with them. For pli, the current action level is less than 9.0 or greater than 9.8; for hydrazine the current action level is less than 5 or greater than 25 parts per million (ppm). Refer to Attachments 1 in CP 206 for the specific monitoring frequency and target values for each chemistry pararacter.
iReference $4, Attachments 1)
Operational experience related to CP 206 has shown no problems related to use of this proer June with respect to the CC System, in 1996, CP 206 was revised to include dissolved iron as a chemis,ry parameter, Dissolved iron was added as a parameter to CP 206 to discover any unusual corrosion of the CC carbon steel components.
An internal BGE chemistry summary report for 1996 described the CCNPP Units 1 and 2 CC/ Service Water Systems' chemistry as excellent. Action levels for all four systems were only exceeded on eight occasions, or approximately 0.7% of the time during the year. Over 70% of the action levels exceeded were due to ma,jor system changes c'uring the 1996 refueling outage. Ilecommendations to correct this condition have been made to determine outage evolutions that can afTect the CC/ Service Water System chemistry and take action to prevent chemistry targets being exceeded.
The CC System usually operates within normal parameters, except when the system is restarted aller an outage lay up. During an outage lay up, the affected CC components may experience some minor corrosion when the internal component surfaces are exposed to air. After the CC System is returned to service and flow is once again established, some of this minor corrosion is removed from the pipe inner surface and released into the system where it is detected. An increase in suspended solids (due to this efTect) was seen on Unit I at the start of the 1996 outage, and was correlated to flow ir.itiation through the shutdown cooling IlXs. The level of suspended solids slowly decreased over the course of the year back to levels obtained before the outage. The Unit 2 suspended solids showed a fairly steady baseline with a few minw spikes occurring during the year.
Procedure CP 206 provides for a prompt review of CC chemistry parameters so that steps can be taken to return chemistry parameters to normal levels, and thus minimizes the efTects of crevice corrosion / pitting.
Discoverv: Procedure CP 206 is credited with the discovery of wear in the RCP seal water llX If the llXs were to corrode through, radiation monitors on the CC System would detect this leakage from the RCS. Refer to the discussion above for details on CP 206.
Application for License Renewal 4.140 Calvert Clifts Nuclear Power Plant
_ _ ~
ATTACitMrNTJ1)
APPENDIX A. TECHNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM i
Group 6 (IGA). Iknoonstration of Aging Management t
Based on the material presented above, the following conclusions can be reached with respect to the IGA
[
of the Group 6 components:
lhe RCP seal water llXs provide a presrire retaining boundary, and their integrity must be e
maintained under CLB design loading conditions, Intergranular attack is plausible for the RCP seal water llXs, which could lead to loss of pressure-e retaining boundary integrity, Calvert Cliffs Technical Procedure CP 204 will mitigate the effects oflOA on the RCP seal water e
llX IRCS side)by maintainleg primary system chemistry conditions such that impurities will be minimized, and contains acceptance cri eria that ensures prompt corrective actions will be taken when adverse chemistry parameters are detected.
i Calvert Cliffs Technical Procedure CP 206 will mitigate the effects ofIGA on the RCP seal water e
ilX (CC ",3.n side) by controlling the range of specific chemical parameters, and provide action levels that ensure timely correction of adverse chemistry parameters.1hc procedure will also provide for the discovery of RCS leakage into the CC System by monitoring for elevated radiation levels in the CC System.
Examinations will be performed and appropriate corrective actions will be taken if IGA is discovered.
'Iherefore, there is reasonable assurance that the effects of LOA on the RCP seal water ilXs will be managed in order to maintain the components pressure boundary integrity under all design conditions required by the CLil during the period of extended operation.
Group 7 (SCC /lGSCC/PWSCC)- Materials and Environment Table 4.13 shows that SCC, IGSCC, and PWSCC are plausible for some of the RCS device types, it should be noted that the ARDMs IGSCC and 1 WSCC are variations of SCC that can affect different material types, that can occur in difTerent environm nts, and that can be managed by similar and/or different aging management programs. The RCS components listed below are susceptible to one or more of these ARDMs. These susceptible RCS device types, applicable ARDM(s), and their material characteristics are:
[ Reference 2 CC-Ol/02/03/04/06, GC 01/02/03/04/05/06, CKV 01, CV 01, ERV 01,llV-04,ilX 01, MOV 01/02, PZV 01, RV-01, Attachments 4,5,6, Table 4.2]
' SCC /lGSCC/PWSCC PZY - pressurizer. pressure, level, and temperature noule forgings (except Unit 2 upper pressure o
and level forgings. Alloy 600), pressure, level, temperature, safety / relief valve and spray nozzle safe ends (stainless steel), surge nozzle safe end (stainless steel cast), spray and surge noule thermal sleeve (Alloy 600), Unit I heater sleeve (Nickel plated Alloy 600), manway Siting (alloy steel), welds (Alloy 600); and
-CC charging noule thermal sleeve, resistance temperature detector noule, pressureisample e
nonle neck, safety injection thermal sleeve, surge noule thermal sleeve (all are Alloy 600).
Application for License Renewal 4.1-41 Calvert Cliffs Nuclear Power Plant
ATTACHMENT i1)
APFENIHX A. TECHNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM SG llX instrument nozzles (Alloy 600), ilX tubes (Alloy 600) exposed to the internal (primary e
side) environment of the RCS and secondary side of the SGs, primary manway studs (alloy steel).
]
scc /lGScC CC bolting studs and hex nuts (carbon steel); RPV head closure seal leakage detection piping (stainless steel), uttings (stainless steel), and welds (stainless steel); and GC. bolting studs (alloy steel) and hex nuts (carbon steel).
e S.CC CKV. bolting (carbon steel);
f e
e - CV. bolting (carbon steel);
ERV. bracket studs (alloy steel) and nuts (caiton steel);
e llV. some bodies and bonnets (CASS or forged sustenitic stainless steel);
e MOV bonnet studs and nuts (carbon steel); and e
RV bonnet / spring / bonnet studs (carbon or alloy steel).
e Alloy 600 RCS components exposed only to the RCS primary water (l.c., not SG tubes) are only susceptible to PWSCC.
The internal RCS environment (primary side) is that of chemically treated borated water at an operating pressure of approximately 2250 psia. The RCS operating temperatures are not greater than 548'F in the cold leg and a maximum of approximately 6'J0*F in the hot leg. The RCS maintains a Dow rate of approximately 134x10' lbm/hr.
(Reference l, Section 4.1.1. Table 41). The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control.
'the internal SG environment (secondary side) during power generation is saturated steam and water at a design pressure / temperature of 1000 psig/$80'F and normal operating parameters of approximately 850 psig/520'F. The SGs also contain chemically treated, demineralized, high pressure water with high Dow rates and Guld velocities at full power conditions. [ Reference I, Chapter 10.1,10.2, Reference 26]
During plant shutdown conditions, the SGs may be drained.
As the interface between the primary and secondary Duids, the SG llX tubes are subjected to both the internal RCS environment and the internal SG environment.
The external RCS environment is ambient atmospheric air inside the Containment Building that is climate controlled. 'lhis environment in the Containment Building during normal operations has maximum humidity of 70% and maximum 'craperature of 120'F.
[ Reference 1, Table 918, Reference 29, Attachments 1, T3ble 1 page 13)
As a result of the actions taken due to the experience in 1989 and 1994 with minor Pressurizer lleater Sleeve leakage, BGB has replaced or scheduled near term replacement of high susceptibility Alloy 600
- pressure boundary components.' [ Reference 14, Section 2] The remaining CCNPP Alloy 600 pressure Application for License Renewal-4,1-42 Calvert Cliffs Nuclear Power Plant
-g y,wp--
r+=-
- -t
=
e--e
,9-.i ye e e
a-,-
+e---
- + rum--
---rn-
'*re m-
%9-y yu-
'pr--im-'t
ATTACHMENT (1) i APPENI)IX A TECHNICAL INFORMATION i
4.1 REACTOR COOLANT SYSTIT boundary components are among the least susceptible to PWSCC when compared to other U.S. reactors that have performed inspections of these noules, (Reference 14, Section 16.1.7, Figure 6 6]
I Group 7 (SCC 4GSCC/PWSCC) Aging Mechanlsm Efkts Stress corrosion cracking results from the combined and synergistic interaction of a chemically.
aggressive environment, susceptible material, and tensile stress (can be the result of cold working). Over long periods of time SCC occurs as the material falls by slow, environmentally induced crack initiation and growth that may lead to eventual kicalized, non ductile failure. He RCS materials susceptible to SCC are austenitic stainless steel, low alloy steels, and nickel based Alloy 600.
Several RCS components, such as the pressuriter surge line safe ends, spray noule safe ends, pressurizer instrument nozzles, and pressurizer heater sleeves, are particularly susceptible to SCC, [ Reference 2, PZV. Valve, Attachments 7s) Understanding of the variables that cause these efTects and their interdependencies continues to improve and is the subject of ongoing research by industry worldwide and by NRC, Intergranular SCC is the prefereritial dissolution of grain boundary regions tvith only a slight attack of the grain matrix. He IGSCC aging mechanism requires the presence of high tensile stress, material that is sensitive to attack, and the presence of corrosive anions such as oxygen, chlorides, fluorides, sulfates, and other sulfur ions.
Primary water SCC (in particular, IGSCC)is SCC that occurs in the presence of the RCS (primary side coolant) environment. The PWSCC aging mechanism has been observed in the tube roll transition region of SGs and is a problem for pressurizer instrument nozzles and heater sleeves fabricated from Alloy 600. [ Reference 2, SG llX, PZV, Attachments 7s)
Experience to date indicates that cracks for PWSCC of RCS penetrations initiate Erst in the vicinity of penetrations and then grow axially from the penetration. The resulting cracks are short, grow slowly, grow at comparable rates axially and radially (through wall), and result in very minimal leakage when through wall penetration Gnally occurs. Herefore, safety concerns are minimal. [ Reference 55]
The RCS components described above are considered susceptible to SCC, IGSCC, and PWSCC are exposed to an aggressive environment, and are placed under high tensile stresses. [ Reference 2 Attachments 6s,7s] The combined etTect of these factors could result in reduction of the ability of the components to maintain the RCS pressure boundary under CLB design loading conditions. Therefore SCC, IGSCC, and PWSCC are plausible ARDMs for this group of components, Group 7 (SCC /lGSCC/PWSCC) Methmis to Manage Aging
- Mitigation: The effects of S
, IGSCC, and PWSCC on susceptible materials in the RCS cannot be climinated, but the efTects of these ARDMs can be monitored and actions taken to mitigate the effects.
Reactor coolant chemistry controls that minimize dissolved oxygen and halides and sulfur species are also believed to mitigate. SCC and IGSCC susceptibility on RCS piping. Sleeving, plating, weld overlays, thermal treatment, and replacement with material less susceptible to SCC can also be used to mitigate or remedy the effects these APDMs have on RCS components.
- Application for License Renewal 4.1 43:
Calvert Cliffs Nuclear Power Plant
AIIACHMENT 111 i
APPFNDIX A. TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM i
DIEmsty: Stress corrosion cracking (of all kinds) of RCS components can be discovered and monitored by inspection programs. Inspection methods and frequencies can be defined based on susceptibility of the components, and Inspection results from other facilities can be used to adjust the predicted susceptibility, inspection methods, and frequency of inspection.
Given the expected axial nature of cracks, the slow growth rates, the minimal leakage that occurs once through wall penetration does occur, and the low safety concern, periodic inspections of low-susceptibility pressure boundary penetrations for evidence ofleakage is sufficient. Dedicated inspection of high susceptibility pressure boundary and non pressure boundary components should be considered and be timed based on expected initiation of cracks and expected propagation rates.
Detection of cracks shortly aller they have initiated would permit timely repair, long before the intended function lajeopardized, and might minimize the cost and complexity of repair. Ranking models could be used to estimate SCC susceptibility and to schedule inspections based on Ne potential for crack initiation.
Group 7 (SCC /lGSCC/PWSCC). Aging Management Program (s) 1he CCNPP Alloy 600 Program Plan is credited with both mitigation and discovery of SCC /lGSCC for susceptible RCS piping components (cuept for the RPV head seal leakage detection line),
SCC /lGSCC/PWSCC for susceptible pressurizer components, and 50 llX instrument nozzles.
Calvert Clllis' Alloy 600 Program Plan was developed in response to primary pressure boundary leakage at CCNPP and other plants caused by PWSCC. The CCNPP Alloy 600 Program Plan builds on CCNPP and industry experience and provides for systematic evaluation of Alloy 600 pressure boundary components in the RCS it addresses nuclear safety concerns and identifies actions to minimize the 4
safety and economic impact of SCC of Alloy 600 components. The program defines mitigation and discovery alternatives, as discussed below, and provides the process for considering susceptibility, safety, and eccenomics in selecting from these alternatives. It also includes measures for monitoring industry experience and making appropriate adjustments based on this experience.
The susceptibility to SCC was evaluated for each CCNPP Alloy 600 nozzle based on ranking models developed by both Westinghouse and CE. A susceptibility index calculated from the Westinghouse model is a function of microstructure, efTective stress factor, and temperaturn factor. The susceptibility index is used to develop a Relative Susceptibility Index, which is the susceptibility index of the component under analysis as compared to the susceptibility index of the reference / benchmark component. The reference component in this case is the CCNPP Unit 2 Pressurizer heater sleeves that developed minor leakage in 1989. The Relative Susetptibility Index is then multiplied by the actual or effectis e full power hours to obtain a time dependent Relative Cumulative Susceptibility Index.
The CE model was used for the RCS Alloy 600 nozzles with inputs that were generic to all welded-tube type Alloy 600 nozzles; temperature, time in effective full power hours, and applied stress, which is based on the geometry of penetration and material yield strength. The CE model was used to calculate crack initiation probabilities as a function of effective full power hours. (Referei.cc 14, Section 7].
Application for License Renewal 4.1 44.
Calvert Cliffs Nuclear Power Plant y
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KLTACHMfWT f1) i APPENDIX A. TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM ne calculated susceptibility and crack initiation probability results were used to rank the nonles and to i
develop recommendations for inspection, mitigation, repair and/or replacement of the nonle(s).
[Refarence 14, Section 8) ne susceptibility and economic analyses are used to select from the following options available for nonles: [ Reference 14, Section 9)
Repair /replaec nonles based on susceptibility assessment; Perform mitigating techniques based on susceptibility assessment; Continue visually inspecting each nonle am required by the HACI Program; e
Be prepared to repair nonles on an as failed basis, nis option requires BGB to have i
replacement noules, repair plans, and design packages ready prior to the discovery of leakage; and Perform augmented inspection to find non throughwall SCC and perform repair / replacement, as e
necessary.
Nuclear safety, radiation exposure, and economics are considered when selecting mitigating steps or repair / replacement for nonles susceptible to SCC. Nuclear safety considerations include whether a complete severance of the nonle due to circumferential cracking could lead to an unisolable small break loss-of coolant accident, whether stresses would exist tha' could lead it.. ach circumferential cracking, and whether a nonle would exhibit minor leakage before crack growth would cause rapidly increasing leakage. [ Reference 14, Section 14),
ne focus of this program to date has been on pressure boundary components, nis is appropriate given their greater stresses and greater potential to initiate design basis events. This program plan will be modified to include RCS coules thermal sleeves in addition to those that form the pressure boundary.
[ Reference 2, Attachment 10] He SG llX tubes are specifically excluded from the scope of the Alloy 600 Program Plan. [ Reference 14, Section 1.1)
Mitigation: ne effects of SCC /lGSCC will be mitigated for the RCS piping (device code CC) by CCNPP Technical Procedure CP-204. Laintaining the RCS chemistry with a minimum of impurities will aid in the prevention of these ARDMs. [ Reference 2, Attachment 1) For funher discussion of CP 204, refer to the Group 5 (IGA) Aging Management Programs.
The CCNPP Alloy 600 Program Plan lists possible additional mitigation alternatives that include the following techniques: [ Reference 14, Section ll)
Shot peening This induces compressive residual stress, slowing PWSCC initiation; Sleeving - A sleeve of Alloy 690 is rolled nnd/or wcued in existing Alloy 600 sleeves; Weld overlay - A thin layer of welded metal with a composition equivalent to Alloy 690 is e
deposited over the high stress area of the Alloy 600; Nickel plating His technique provides a barrier to the primary water; e
Thermal treatment Conducted in situ to reduce residual stress; RCS temperature reduction Reduces the thermodynamic driving force for PWSCC; e
Application for License Renewal 4.1-45 Calvert Cliffs Nuclear Power Plant -
ATTACHMIXr (1)
APPENilIX A. TECHNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM Zine injection - Zine added to the primary water may slow initiation and growth of PWSCC cracks; and Mechanical stress improvement. Controlled plastic deformation of the nonle(s) in a manner that e
. creates compressive residual stresses at locations susceptible to SCC (the technique has been used i
extensively in iloiling ' Vater Reactor plan s on stainless steel pipe fittings, weldments, and i
nonles).
If mitigation techniques are not sufficient or are unfeasible, then corrective actior.s are provided for nonle(s) repair or replacement. The Alloy 600 Program Plan includes the following options to repair or replace nonles: [ Reference 14, Section 12) local weld repair of defects; e
Replacement with Alloy 690 sleeves; e
Removal from service / plugging of a nonle; or e
Encapsulate the existing nonle in an outer noule bolted to the vessel to convert the nonle into a i
e bolted gasketedjoint.
1 Calvert Cliffs Technical Procedure RV.78, " Reactor Vessel Flange Protection Ring Removal and Closure licad Installation," is credited with the mitigation of SCC on the RPV head seal leakage detection line. The procedure directs the user to blow the RPV head seal leakage detection line (also known as the 0-ring seal leak off line) clear of fluid with compressed air. [ Reference 23 Section 6.3)
Clearing the line of fluid will greatly reduce the potential for this ARDM. [ Reference 2, CC06, Attachments 6) This procedure will be performed after each refueling outage, nis program has been considerably upgraded through operating experience, to the point of requiring close inspection for nicks, j
scratches, and pitting, with documented acceptance criteria for any indications found. These upgrades have been very effective, Calvert Cliffs' reactor vessels are currently operating leak free.
Discoverv: Because PWSCC of RCS penetrations is not presently a significant safety concern at CCNPP, the Alloy 600 Program Plan presently focuses its analysis on economic considerations, it assesses the relative susceptibility to PWSCC for each group of RCS noules and determines which are at greatest risk of crack initiation.
All RCS Alloy 600 noules are inspected each refueling outage for indications of leakage by the DACI Program. [ Reference 33] Leakage that develops between refueling outages will be detected before significant through wall leakage develops as a result of the Technical Specification limits on leakage.
The Alloy 600 Program Plan also includes provisions for augmented inspection based on susceptibility.
Reactor Coolant System nonles are evaluated under the Alloy 600 Program Plan based on primary and
. secondary factors. The primary evaluation factors for PWSCC susceptibility include: [ Reference 14, Section 8]
Operating temperature; f
Material peak stress level-e Material heat treatment, if known; i
e i
Application for License Renewal 4.1 -d'.5 Calvert Cliffs Nuclear Power Plant
ATTACHMENT f1)
APPENDIX A TECilNICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM Number of effective full power hours; and e
Previous industry failures of same material heat.
e 1hc secondary PWSCC susceptibility factors include: (Reference 14, Section 8]
Industry susceptibility rankings; Amount and type of machining / rework on a component during fabrication; Product fonn (i.e., har, tubing, pipe);
Whether a crevice environment exists; Potential for trapping contaminants due to isolation from flow circulation (stagnation);
llistory of chemical excursiona; and General susceptibility of nonle type.
Susceptibility rankings based on predictive models cannot be used to predict the exact timing of crack initiation or progression thmugh wall. Primary water SCC initiation times for identical materials vary over a wide band, and predictive models take into account a limited number of parameters. Detailed study of material properties, fabrication, and service history is required to assess susceptibility of individual nonles, llowever, the susceptibility models are used to allow susceptibility comparison.1hc CB model is used in the economic analysis to determine the optimal time for augmented inspections, but not as the basis for safety evaluations. [ Reference 14, Section 7)
'Ihe susceptibility model results are used for analyzing nonics to determine when to perform augmented inspections for crack initiation. Alternatives for augmented nonle inspections melude eddy current, dye penetrant, and ultrasonic examination. [ Reference 14, Section 10]
Relevant operating experience applicable to PWSCC includes failure of purification system resin retention screens. 'this resulted in a resin intrusion of the Unit 1 RCS in March 1989. Resin decomposition products may contribute to cracking of sensitized Alloy 600 and the evaluation of the 1989 cient concluded that prompt actions were taken to minimize the deviation and RCS temperature and to remove the resin and its decomposition products, [ Reference 18]
Alloy 600 PWSCC has occurred at CCNPP and at other domestic and foreign PWRs and BGE has been a leader in industry efforts to understand and manage PWSCC. [ Reference 14, Section 3] 'the Alloy 600 Program Plan is a relatively new program, having been initiated in 1992. Since this program achieved its present form in 1995, no pressure boundary leakage has occurred as a result of PWSCC. Some RCS components have been replaced and some have been nickel plated as a result of the program.
The Alloy 600 Program Plan includes specific provisions for monitoring industry expWence anci adjusting the plan accordingly. Calvert Cliffs MN 3-304, Control of the Alloy 600 % gram Plan establishes adrainistrative controls for this program under the site procedures hierarchy, he Allcr N Program Plan will continue to examine pressure-boundary components susceptible to PWSCC to e. tea that these components maintain their intended function required by the CLB during the period ot Application for License ikrewal 4.147 Calvert Cliffs Nuclear Power Plant I
ATIACHMENT (1)
APPENDIX A TECHNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM
- extended operation. The program will be modified to include RCS nozzle thermal sleeves. (Reference 2, Attachments 10)
Calvert Cliffs' BACI Program is credited with the discovery of SCC /lGSCC on the external surfaces of RCS piping (pipe code GC) studs / nuts, and SCC on RCS valve bolting. This procedure requires investigation of any boric acid leakage that is found. [ Reference 2, Attachment 1) Refer to the discussion of the BACI Program in Group 2 (wear). Aging Management Programs.
1echnical Procedures STP M 574 l/2 are credited for discovering of SCC /PWSCC on SG llX tubes.
He procedure directs the user as to the sample size for tube inspection, inspection process, evaluation, and determination of tube status. Refer to the discussion of the SG Eddy Current examination program in Group 2 (wear) under Aging Management Programs.
Calvert Cliffs Administrative Procedure MN 3110 is credited with discovering SCC on the external surfaces of RCS piping components (pipe code -CC). Visual examination (VT 2) of external surfaces are performed for the RCS components in accordance with ASME Section XI IWA 2212. The ISI Program was previously discussed in Group 2 (wear) under Aging Management Programs.
Technical Procedure FASTENER 01," Torquing and Fastener Applications,"is credited with discovering SCC on SG llX bolting studs. The procedure is used whenever studs are detensioned and retensioned on the SGs during plant refueling outages. This procedure directs the user to perform a visual inspection of the fasteners for damage and corrosion, if fasteners are acceptable they are reused, otherwise they are replaced. [ Reference 56, Sections 6.2,6.3)
Group 7 (SCC /IGSCC/PWSCC)- Demonstration of Aging Management Based on the factors presented above, the following conclusions ca.. be reached with respect to SCC, IOSCC, and PWSCC of the Gioup 7 components:
ne pressurizer components are susceptible to SCC /lGSCC/pWSCC and provide the RCS e
pressure retalning boundary. Rese components must maintain their integrity under CLB design loading conditions.
He piping co aponents listed are susceptible to SCC /lGSCC and provide the RCS pressure-retaining boundary, nese components must maintain snelt integrity under CLB design loading conditions.
ne SG components listed are susceptible to SCC /PWSCC/lGSCC and provide the RCS pressure-retaining boundary, These components must maintain their integrity under CLB design loading conditions.
ne valve components listed are susceptible to SCC and provide the RCS pressure retaining e
boundary and containment isolation function. These components must maintain their integrity under CLB design loading conditions.
Although susceptibility to PWSCC is low relative to most other plants, PWSCC is plausible for some of the Group 7 components mentioned above, and could impair their ability to perform their intended function.
~ Application for License Renewal 4.1 Calvert Cliffs Nuclear Power Plant t
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l A1TACitMENT f1)
[
APPENDIX A. TECHNICAL INFORMATION 4.1 REACTOR COOLANT SYSTEM The NRC, industry, and DGE have concluded that PWSCC axial cracking is not a safety concern e
and that circumferential cracking that would not be detected bebre it is a safety concern is not likely.
Calvert Cliffs' Alloy 600 Program Plan provides for actions to assess SCC /PWSCC/lGSCC susceptibility and take action to mitigate, inspect, repair, or replace only Alloy 600 components based on the results. It schedules augmented inspections when crack initiation is likely.
l Calvert Cliffs' Alloy 600 Program Plan also includes provisions for monitoring and incorporating industry experience. He Alloy 600 Program Plan will be modified to include thermal sleeves in.<talled in the RCS noules.
Calvert Cliffs Technical f rocedure CP.204 will mitigate the effects of SCC and IGSCC for the RCS piping components (except the RPV head seal leakage detection line) by maintaining primary system chemistry conditions such that it.'puritles will be minimited, and contains acceptance criteria that ensures corrective actions will be taken to ensure timely correction of
+
adverse chemistry parameters.
Calvert uiffs' DACI Program provides for examination of the RCS external surfaces and discovery of any SCC /lGSCC on RCS piping components and SCC on RCS valve components.
The program also provides for subsequent cleanup for any boric acid leakage that is found.
Calvert Cliffs Technical Procedure RW78 is credited with the mitigation of SCC of the RPV head seal leakage detection line by clearing the line of stagnant fluid with compressed air.
Calver1 Cliffs Technical Procedures STP.M.574 1/2 are credited for discovering outside diameter initiated lOSCC and PWSCC on the SO IlX tube,. An IR is submitted to plug or sleeve SO IlX tubes that are considered susceptible to failure.
Calvert Cliffs' ISI Program, per the requirements of ASME Section XI, is credited with the discovery of SCC and IGSCC on the external surfaces of RCS piping components. Though SCC /lGSCC cannot be completely prevented, the status of the components can be evaluated on a regular basis and corrective actions can be taken as conditions indicate SCC.
Calvert Cliffs Technical Procedure FASTENER 01 is credited for discovering SCC on 50 llX primary rnanway bolting studs.
Therefore, there is reasonable assurance that the effects of SCC, IGSCC, and PWSCC will be managed i
in order to maintain the RCS intended functions under all conditions required by the CLD during the period of extended operation.
E Group 8 (thermal embrittlement). Materials and Environment Table 4.13 shows that thermal embrittlement is plausible for some of the RCS device types. These susceptible RCS device types and their material characteristics are: [ Reference 2, CC.01/05, PUMP-01, PZW01, Attachments 4,5,6)
CC surge pipe, surge elbows; surge nonle safe end, shutdown cooling nonle safe end, safety Irdection nonle safe end (CASS);
PUMP. (RCP) case and pump eover (CASS); and I
Application for License Renewal 4.1 49 Calvert Cliffs Nuclear Power Plant w
ATTACllMENT (1)
APPENDIX A.TECilNICAL INFORMATION 4.1 MEACTOR COOLANT SYSTEM PZV. surge nonle safe end (CASS).
The RCS internal environment (primary side) is that of chemically treated borated water at an operating pressure of approximately 2250 psia, ne RCS operating temperstures are not greater than 548'F in the cold leg and a maximum of approximately 600'F in the hot leg. The RCS maintains a Dow rete of approximately 134x10'lbm/hr, [ Reference 1, Section 4.1.1 Table 41] The RCS also contains chemicals for controlling reactor power (boric acid) and corrosion control. He RCS components listed are subject to thennal and mechanical cyclic loading during RCS heat up and pressurization.
Group 8 (thermal embrittlemeny - Aging Mechanism Effects Cast austenitic stainless steel material is susceptible to thermal embrittlement mechanisms in a high temperature environment. Thennal embrittlement is the loss of fracture toughness caused by the thermally induerd changes in the fo tnation and distribution of alloying constituents. Ferrite-containing stainless stecir are susceptible, w are materials with giain boundary segregation of impurities.
[ Reference 2, Valve, Attachments 7]
Fracture toughness is a measure of a material's resistance to fracture in the presence of a previously existing crack. Generally, a material is considered to have adequate fracture. toughness if it can withstand loading to its design limit in the presence of detectable flaws under stated conditions of stress and temperature, ne CASS thermal embrittlement mechanisms are both time and temperature dependent. He maximum rate of embrittlement for CASS occurs at 885'F i 45'F. At lower temperatures the embrittlement rate is less, but the effects of thermal embrittlement have been observed at temperatures as low as 500'F to 650'F. [ Reference 57, Section 4.2; Reference 58, Enclosure 2, item 10)
In addition to temperature, thennal embrittlement is dependent on the CASS material alloy composition.
liigh molybendum and carbon content contribute to thennal embrittlement susceptibility. Equally important is the casting process used to fabricate the component. Centrifugally cast components are more resistant to thermal embrittlement than statically-cast components. [ Reference 2, Attachments 7, Valve, Reference 57 Section 4.2]
For centrifugally cast component parts with delta ferrite content below 20%, mechanical propenies are not degraded significantly by the thermal embrittlement process, For statically-cast component parts with molybendum content such that it meets casting grade CF3 or CF8 limits, the 20% delta ferrite threshold also applies. Ilowever, for statically-cast component pans with molybendum content above that meeting CF3 or CF8 limits,14% della ferrite is the threshold below which no significant degradation due to thermal embrittlement is observed. Herefore, thermal embrittlement is potentially significant for:
[ Reference 57, Section 4.2]
Centrifugal ly cast component pans, with a delta ferrite content above 20%;
Statically-cast component parts, with molybendum content meeting CF3 and CF8 limits and with a deha ferrite content above 20%; and Statically-cast corrponent parts, with molybendum content exceeding CF3 and CF8 limits and with a delta ferrite content above 14%.
Application for License Renewal 4.1 50 Calvert Cliffs Nuclear Power Plant
^
ATTACliMENT (1)
APPENDIX A-TECHNICAL INFORMATION
(
4.1 - REACTOR COOLANT SYSTEM nis aging mechanism, if unmanaged, could eventually result in a loss of material fracture toughness such inat the Group 8 components may not be able to perform their intended function under CLB -
conditions. Herefore, thennal embrittlement was determined to be a plausible ARDM for which the aging effects must be managed for the Group 8 components.
Group 8 (thermal embrittlement)- Metbods to Manage Aging i
Mitigation: Here are currently no methods of mitigating the effects of thermal embrittlement other than proper material r, election and by replacing susceptible components with components constructed of non.
susceptible materials. Use of non CASS components (e.g., forged stainless steel), or use of CASS i
components with delta ferrite content below the threshold values shown above, would make this ARDM l
non-plausible.
Discoverv: A program that would analyre those RCS components that are susceptible to thermal embrittlement could determine if those components are able to maintain their intended function during i
the license renewal period. As noted in the Material and Environment section above, some of the Group 8 hand valves may have forged (i.e., not cast) stainless steel bodies / bonnets. Walkdowns can be performed to visually exam the components or gather specific manufacturer and model number information in order to determine whether the components are of forged or cast construction. For components that arc determined to be of cast construction, analysis can be perfonned (e.g., detennination I
of delta ferrite content) to determine if valves have adcquate fracture toughness based on their material properties.
i Group 8 (thermal embrittlement)- Aging Management Program (s)
Mit@ation: There are no methods to prevent thermal embrittlement; therefore, there are no programs for the mitigation of this ARDM.
Discoveg: A new program will be eveloped to manage the clacts of thermal embrittlement by identifying those components that may not be able to perform their intended function due to the effects of thermal embrittlement. He CASS Evaluation Program will be based on two alternatives. The first alternative will be a delta ferrite and flaw tolerance analysis. This analysis will be ocrfonned on a case-
- by-case basis using actual material data and the procedure outlined in NUREG/CR 6177, Assessment of Thennal Embrittlement of Cast Stainless Steels," and NUREG/CR-4513, Revision I, " Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR / Light Water Reactor)
Systems." The flaw tolerance analysis will use the procedures from ASME Nuclear Code Case N 481.
i ne intent of the analysis will be to detennine if the respective valve has adequate fracture toughness, based on its material properties, in order to be capable of perfonning its pressure boundary function under CLB conditions. [ Reference 2, Attachments 10]
. De second alternative will be to replace the components with those that contain no~CALS. He second alternative will be used if a component cannot be qualified for the license renewal term under the first alternative, or'ifit is more Cost effective to replace rather than perform an analysis. Replacement of the component will make the ARDM as-non plausible for ue respective component.
[ Reference 2, Attachments 10]
Application for License Renewal 4.1 51 Calvert Clifts Nuclear Power Plant
.o A*ITACliMENT (1)
APPENDIX A-TECHNICAL INFORMATION 4.1.HEACTOR COOLANT SYSTEM The corrective actions taken as part of the CASS Evaluation Program will ensure that the Group 8 -
components remain capable of performing their pressure boundary function under all CLB conditions.
Group 8 (thermal embrittlement)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect o the Group 8 components subject to thermal embrittlement:
The Group 8 components have the passive intended functions to maintain the RCS pressure boundary and containment isolation under CLH design loading conditions.
Thermal embrittlement is plausible the Group 8 components which, if unmanaged, could eventually result in a loss of fracture toughness such that the Group 8 components may not be able to perform their pressure boundary function under CLU conditions.
Calvert Cliffs' CASS Evaluation Program will perform analysis to determine if the RCS components in question have adequate fracture toughness in order to perform their pressure boundary function under CLU design loading conditionc. Alternatively, the CASS Evaluation Program will replace susceptible components with components that contain no CASS, thus making the ARDM non plausible.
Therefore, there is reasonable assurance that the effects of thermal embrittlement will be managed in order to maintain the RCS intended functions under all conditions required by the CLB during the period of extended operation.
4.lJ Conclusion The programs discussed for the RCS components are listed on the following table. These programs are administratively controlled by a formal review and approval process, As demonstrated above, these programs will manage the aging mechanisms and their effects such that the intended functions of the RCS components will be maintained, consistent with the CLD d aring periods of extended operation.
The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with Ql 2, " Corrective Actions Program." QL-2 is purr.uant to 10 CFR Par 150, Appendix 11, and covers all structures and components subject '.o.AMR.
Application for License Renewal 4.1 52 lalvert Cliffs Nuclear Power Plant
e A*ITACitMFNT (1)
APPENDIX A.TECilNICAl, INFORMATION 4.1. REACTOR COOLANT SYSTEM TAHLE 4.14 LIST OF AGING MANAGEMENT PROGRAMS FOR Tile RCS
- Preg m a -
> Credhed As -
lixisting CCNPP " Eddy Current Discovery of the effects of denting (Group !), wear Exam of CCNPP Unit 1 (Group 2), pitting on SG tubes (Group 5), and SCC SG," and,"Pxidy Current (Group 7).
Exam of CCNPP Unit 2 SG,"(STP M 574 l/2)
Existing CCNPP *Pressuriter Discovery of the effects of wear (Group 2) on pressurizer Manway Cover Removal studs, nuts, and seating surfaces.
and Installation,"(RCS 10)
ExisUg CCNPP "SG Secondary Discovery of the effects of wear (Group 2) on SG closure Manway Cover Removal surfaces.
and installation"(SG 1/2);
" Steam Generator Secondary llandhole Cover Remosal"(S0 5); and
" Steam Generator Secondary External llandhole Cover installation"(SG 6) lixisting CCNPP "RCS Leakage Discovery of the efrects of wear (Group 2).
Evaluation" (STP 0-27 l/2)
Existing CCNPP "Use of Operating Discovery of the effects of wear (Group 2) on RCP tube-in.
Experience and the Nuclear tube seal water ilX through a continuing review of industry llotline"(NS 1 100) experience.
Existing CCNPP "SG Primary Discovery of the effects of wear (Group 2) and general Manway Cover Removal corrosion (Group 5) on the primary side of the SG manway and installation"(SG 20) and seating surfaces.
Existing CCNPP " Inservice Discovery, per ASME XI, of the effects of wear (Group 2),
inspection of ASME crosica corrosion (Group 3), generat and galvanic corrosion Section XI Components" (Group 5), SCC and IGSCC (Group 7) on those RCS (MN 3-110) components susceptible to these ARDMs.
Existing CCNPP BACI Program Discovery and mitigation of the effects of wear (Group 2),
(MN 3 301) crosion (Group 3) galvanic / general corrosion (Group 5),
and SCCilGSCC (Group 7).
Application for License Renewal 4.1 53 Calvert Cliffs Nuclear Power Plant
e ATTACHMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1. REACTOR COOLANT SYSTEM
- . Program?
NCredited'Asl
~
Existing CCNPP " Specifications and Mitigation of the effects ofIGA (Group 6) on the RCP scal Surveillance for Component water IIXs.
Cooling / Service Water.-
System"(CP 206)
~
Existing CCNPP " Specification and Mitigation of the effects of IGA (Group 6) and SCC, Surveillance Primary IGSCC, and PWSCC (Group 7) on RCS components.
Systems"(CP 204)
Existing CCNPP Torquing and Discovery of the effects of SCC (Group 7) on RCS Fastener Applications fasteners. Those fasteners that are non acceptable are (FASTENER 01) replaced.
Existing CCNPP RV-78," Reactor Mitigation of the efTects of SCC (Group 7) on the RPV Vessel Flange Protection head closure seal leakage detection line.
Ring Removal and Closure llead Installation" Modified CCNPP FMP Discovery of the efTects of low-cycle fatigue (Group 4).
The FMP will be modified to perform an engineering evaluation for the RCPs, MOVs, and pressurizer RVs to ensure that the components are bounded by existing critical locations and controlling transients.
If they are not bounded they will be added to the FMP.
Modified CCNPP Alloy 600 Program Discovery and mitigation of the effects of SCC, IGSCC, and PWSCC (Group 7), anJ will be modified to include the RCS nozzle tiarmal sleeves.
New CASS Evaluation Program Discovery and management of the effects of thermal embrittlement (Group 8).
Application for License Renewal -
4.1 54 -
Calvert Cliffs Nuclear Power Plant
- 0 ATTACHMENT (1)
APPENDIX A TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM -
4.1.4 HEFERMCE" 1.
Calvert Cliffs Nuclear Pov'er Plant, Updated Final Safety Analysis Report, Revision 20 2.
" Reactor Coolant System Aging Management Review Report," Revision 3, July 28,1997 3.
Letter from Mr. J. T. Wiggins (NRC) to Mr. G. C. Creel (BGE), dated August 28,1989, "NRC Region I Combined Inspection Report Nos. 50 317/8914 and 50-318/8914" 4.
Combustion Engineering Report CENC-1849, " Evaluation of Calven Cliffs Vessel Potential Wear of Bottom llead Clad Due to Loose Pump Bolt," December 16,1%18 5.
Letter from Mr. R. M. Douglass (13GE) to Mr. B. l{. Grier (NRC), dated Ma." i < 178, CCNPP 30-Day Report for Licensea Event Report 317 78 22/3L 6.
Letter from Mr. L. B. Russell (BGE) to Mr. B.11. Grier (NRC), dated January 24,,979, CCNPP 30-Day Report for Licensee Event Report 318 79-01/3L 7.
Letter from Mr. L. B. Russell (BGE) to Mr. B. II. Grier (NRC), dated February 1,1979, CCNPP 14-Day Report for Licensee Event Report 318 79-03/IT 8.
Letter from Mr. L. B. Russell (BGE) to Mr. B.11. Grier (NRC), dated May 30,1980, CCNPP 30-Day Report for Licensee Event Report 317 80-24/3L 9.
Letter from Mr. L. B. Russell (13GE) to Mr. J. A. Allan (NRC), dated May 19,1983, CCNPP 30-Day Report for Licensee Event Report 317 83 20/3L 10.
Letter from Mr, L. B. Russell (BGE) to NRC Document Control Desk, dated August 6,1984, CCNPP Licensee Event Report 318 84 06,"RCP Seal Bleedoff Line Weld Failure" 11.
Letter from Mr.
L.
B. Russell (BGE) to NRC Document Control Desk, dated November 5,1985, CCNPP Licensee Event Report 317 85-013,"RCP Shaft Seal Bleedoff Line Weld Failure" 12.
Letter from Mr. L. B. Russell to NRC Document Control Desk, dated November 3,1989, CCNPP Licensee Event Report 318 89-07, Revi ion,1, " Evidence of Leakage from Unit 2 Pressurizer lleater Penetrations Due to Intergratular Stress Corrosion Cracking by Residual Fabrication Stress" 13.
Letter from Mr. G. C. Creel (BGE) to NRC Document Control Desk, dated March 1,1991, CCNPP Unit Nos.1 & 2, "Repon of Changes, Tests, and Experiments," Ar FCR 89-089 Supplement 5,6,7.-
14.
CCNPP Alloy 600 Program Plan, Revision 1, November 1996 15.
Letter from Mr. P. E. Katz (BGE) to NRC Document Control Desk, dated August 30,1996, "CCNPP Unit i Steam Generator Tube Inspection Results" 16.
Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated June 27,1995,
" Response to NRC Generic Letter 95-03. Circumferential Cracking of Steam Generator Tubes"
?.
Letter from Mr. T. T. Martin (NRC) to Mr. J... Tieman (BGE) dated January 6,1988, "NRC Region I Combined Inspection Reports Nos. 50-31/87-25; 50-318/87-26" 18.
Letter from Mr. J. T. Wiggins (NRC) to Mr. G. C. Creel (BGE), dated July 21,1989, "NRC Region I Combined Inspection Report Nos. 50-317/89-06 and 50-318/89-06" Application for License Renewal
_4.1 55 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (1)
APPENDIX A-TECIINICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM
- 19.. Letter from Mr. G. C.
Creel (BGE) to NRC Document Control Oesk, dated September 20,1989, CCNPP Submittal of Basis for Determination 20.
Letter from Mr. R. R.- Keimig (NRC) to Mr. A. E. Lundvall, Jr. (BGE), dated March 12,1981, "NRC Region i Combined Inspection Reports Nos. 50-317/81-02; 50-318/81 02" 21.
Letter from Mr. A. E. Lundvall, Jr. (BGE) to Mr. R. A. Clark (NRC), dated August 5,1980, "CCNPP Unit I Docket No. 50-317 Power Distribution Episode" 22.
Letter from Mr. C. J. Cowgill (NRC) to Mr. R. E. Denton (BGE), dated April 1,1994, "NRC P.egion i Resident inspection Report Nos. 50-317/94-09 and 50 318/94-09, (February 6,1994 to March 12,1994)"
23.
CCNPP Technical Procedure RV 78, " Reactor Vessel Flange Protection Ring Removal and Closure llead installation (Unit I and 2)," Revision 5, November 22,1996 24.
CCNPP Drawing 60729S110001,"RCS," Revision 61 25 "CCNPP Component Level ITLR Screening Results, RCS System 64," Revision 4, October 17,1996 26.
CCNPP Drawing 92767Sii EB 1,"M 601 Piping Class Sheets," Revision 21, October 19,1994 27.
CCNPP Technical Procedure STP M 5741, " Eddy Current Exam of CCNPP Unit 1 SG,"
Revision 6, March 12,1993 28.
CCNPP Technical Procedure SG 5, "SG Secondary External llandhole Cover Installation,"
Revision 7, December 23,1996 29, CCNPP Engineering Standard ES-014, " Summary of Ambient Environmental Service Conditions," Revision 0, November 8,1995 30.
" Inservice inspection Program Plan for the Second Inspection Interval for Calvert Cliffs Nuclear Power Plant Units 1 &
2,"
Southwest Research Institute Project 17-1168, November 1987, Revision 0, Change 6, November 11,1996 31.
CCNPP Administrative Procedure MN-3110 " Inservice Inspwion of ASME Section XI Components," Revision 2, July 2,1996 32.
ASME Boiler and Pressure Vessel Code,Section XI, " Rules for in-Service inspection of Nuclear Power Plant Components," 1983 edition with Addenda through Summer 33.
CCNPP Administrative Procedure MN 3 301, " Boric Acid Corrosion Inspection Program,"
Revision I, December 15,1994 34.
CCNPP Procedure QL-2-100," Issue Repor*.ing and Assessment," Revision 4, January 2,1996 35.
CCNPP Procedure RCS-10, " Pressurizer Manway Cover Removal and installation,"
Revision 3, August 12,1991 36.
CCNPP Technical Procedure SG-1, " Steam Generator Secondary Manway Cover Removal,"
Revision 5, March 25,1992 37.
CCNPP Technical Procedure SG-2," Steam Generator Secondary Manway Cover Installation,"
Revision 5, March 25,1992 38.
CCNPP Technical Procedure SG 6, "SG Secondary Handhole Cover Removal," Revision 6, October 7,1991 Application for License Renewal 4.1-56 Calvert Cliffs Nuclear Power Plant
A'ITACIIMENT (1)
APPENDIX A. TECHNICAL INFORMATION 4.1 - REACTOR COOLANT SYSTEM 39.
CCNPP Technical Procedure STP-M 574 2, " Eddy Current Exam of CCNPP Unit 2 SG,"
Revision 4, March 12,1993 40.
CCNPP Surveillance Test Procedures STP O-271/2, "RCS Leakage Evaluation," Revision 16, December 4,1991 41.
CCNPP Technical Procedt s SG 20,"SG Primary Manway Cover Removal and Installation,"
Revision 8, October 10,1996 4 2.-
Vendor Procedure 83A6045, Ultrasonic Examination of Nozzle Inner Radiu; Atcas for CCNPP," NES, Inc., Revision 1, March 13,1996 43.
Electric Power Research Institute Report TR 104509, "CCNPP Life Cycle Management / License Renewal Program RPV Evaluation," April 1995 44.
CCNPP Fatigue Monitoring Program, Volumes 1 and 2, CE-NPSD-634 P, April 1992 45.
Structural Integrity Associates, Inc., SIR 96-006, " Cycle Counting and Cycle-Dased Fatigue Report for CCNPP Units 1 and 2," February 21,1996 46.
Structural Integrity Associates, Inc., SIR 96-006, " Cycle Counting and Cycle Based Fatigue Report for CCNPP Units I and 2," February 21,1996 47.
CCNPP Administrative Procedure EN l 300, " Implementation of Fatigue Monitoring,"
Revision 0, February 28,1996 48.
CCNPP Engineering Standard ES-020," Specialty input Screens for the Engineering Service Process," Revision 1, May 1,1996
/.9.
Letter from Mr. J. P. Durr (NRC) to Mr. C. Stoiber [sicJ (BGE), dated February 11,1993,
" Inspection Report Nos. 50-317/92-32 and 50-318/92-32" 50.
CCNPP Procurement Specification No. 6422284S, " Technical Services to Evaluate Thermal Fatigue Effects on CCNPP Systeus Requiring AMR for License Renewal," Revision 1, September 3,1996 51.
CCNPP Technical Procedure CP-204, " Specification and Surveillance Primary Systems,"
Revision 7, March 11,1997 52.
CCNPP Nuclear Program Directive, Cil-1,
" Chemistry Program,"
Revision 1, December 13,1995 53.
CCNPP " Component Cooling System Aging Management Review," Revision I, November 7,1996 54, CCNPP Tecnnical Procedure CP 206, " Specifications and Surveillance Component Cooling / Service Water System," Revision 3, November 4,1996 55.
NRC Generic Letter 97 01," Degradation of Control Rod Drive Mechanism Nozzle and other Vessel Closure llead Penetrations," April 1,1997 56.
CCNPP -Technical Procedure, " FASTENER 01, Torquing and Fastener Applications,"
Revision 0, July 1,1993 57.
Electric Power Research Institute Report TR 103844,"PWR RCS License Renewal Isdustry Report," Revision 1 July 1994 58.
NRC Generic Letter 89-21," Request for Information Concerning the Status ofImplementation of Unresolved Safety issue Requirements," October 19,1989 Application for License Renewal 4.1-57 Calvert Cliffs Nuclear Power Plant
'I.-
ATTACIIMENT (2)
APPENDIX A - TECIINICAL INFORMATION 5.11A - AUXILIARY IlUILDING HEATING AND VENTILATION SYSTEM Balti.. ' e Gas and Electric Company Calven Cliffs Nuclear Power Plant Desember 17,1997
(_
Mi ATTACHMrNT W APPENDIX A -TECHNICAL INFORMATION 5.llA AUXILIARY HUILDING }{ EATING AND VENTILATION SMTEM 5.ll A Auxiliary PViding l{cating and Ver.tilation System
- His is a section of the Baltimore Gas and Electric Company (DGE) Lic.:nre Renewal Application (LRA)
Wressing the Auxiliary Building Heating r.nd Ventilation (ll&V) System. The Auxiliary Building tiAV System was evaluated in accordance with the Calvert Cliffs Nuclear Power Piart (CCNPP)
Integrated Plant Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections cre prepared independently and will, collectively, comprise the entire BGE LRA.
- 5. IIA.1 Scoping System level scoping describes conceptual boundaries for plant systems and structures, develops screening tools which capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify systems and structures within the scope of license renewal. Component level scoping describes the components within the boundaries of those systems and structures that contribute to the intended functions. Scoping to determine components subject to aging management review (AMR) begins with a listing of passive intended functions and then dispositions the device types as eitner only associated with active functions, subject to replacement, or subject to AMR either in inis report or another report.
Representative historical operating experience pertinent to aging is included in appropnate areas. to provide insight supporting the aging management demonstrations. This operating experience was obtained through key-word searches of BGE's electronic database ofinformation on the CCNPP dockets and through documented discussions with currently assigned cognizant CCNPP personnel.
Section 5.ll A.l.1 presents the results of the system level scoping, 5.ll A.I.2 the results of the component level scoping, and 5.llA.I.3 the results of svping to determine components subject to an AMR.
5.ll A.I.1 System Level Scoping This section begins with a description of the system, which includes the boundaries of the system as it was scoped. The intended functions of the system are listed and are used to define what portions of the system are within the scope oflicense renewal.
Systrin3ssniption/Concentual Boundaries The Auxiliary Building Il&V System is comprised of fans, air handling units, dampers, filters, coolers, controls, and ductwork, which provide air, in some cases filtered and tempered, to various rooms in the auxiliary and radwaste buildings. A negative pressure, with respect to ambient and surrounding areas of the building, is normally maintained in the Auxiliary Building to ensure that clean areas do not become contaminated through the ventilation system. Areas serviced by the system include the Switchgear Rooms (each unit), Diesel Generator Rooms (three total), Auxiliary Feedwater (AFW) Pump Room (each unit), Service Water (SRW) lleat Exchanger Room (each unit), main steam line penetration area (each unit), waste processing area (each unit), Emergency Core Cooling System (ECCS) Pump Rooms (each unit), the fuel handling areas (shared between units), and general areas of the Auxiliary Building.
- Exhaust air from the waste processing areas, ECCS Pump Rooms, and the fuel handling areas is passed through a roughing filter and a high efficiency particulate (IIEPA) filter to remove potentially radioactive particulate contamination prior to discharge through the plant vent. Exhaust air from the ECCS Pump Room and the fuel handling area can also be routed through separate charcoal filters to Application for License Renewal 5.1 l A-1 Calvert Cliffs Nuclear Power Plant
t*
ATTACHMENT (2)
APPENDIX A. TECHNICAL INFORMATION -
5.11A - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM remove radioactive iodine in the event of a loss-of-coolant accident or fuel handling incident, respectively. [ References 1 through 5]
He Switchgear Rooms are cooled the year round by redundant heating, ventilating, and air conditioning (llVAC) units and refrigeration systems. The air conditioning system provides conditioned air for cooling and ventilation. A set of mixing dampers automatically proportion the amount of fresh air and recirculated air as needed to maintain room temperature within design limits. The HVAC units and refrigeration components are redundant, but the supply and retum ducts to the Switchgear Room are not.
[ References I,4, and $]
The Fairbanks Morse diesel generators are housed in three separate rooms in the Auxiliary Building.
Ileat output from each generator is sufficiently high that cooling must be provided for both summer and winter, The ventilation system for this area is designed to limit room temperature to a maximum of 120 F in summer and a minhnum of 60*F in winter. Outside air is used as the cooling medium. An air-handling unit and mixing box damper arrangement proportion the flow of outside air and recirculated air according to room temperature. When the emergency diesel generator (EDG) is running, its room is pressurized and the excess air is forced out through a weatherproof exhaust opening over the outside door, llot water unit heaters maintain a minimum temperature of 60 F when the diesel is shut down.
[ References I and 4] licating and ventilation for the additional EDGs, which are located in a separate building outside, are discussed in the Control Room HVAC System Evaluation in Section 5. llc of this application.
There are " normal" and " emergency" air cooling systems for the AFW Pump Room. During normal plant operation, one self contained HVAC unit maintains the temperature in this room at 90*F or below.
During the emergency mode of operation, which would exist if the normal HVAC unit fails for any reason, redundant fans circulate air baween these two rooms through a system of connecting ductwork.
The heat sink effect v the equipment room supplies all of the cooling required to prevent the room air temperature from rising above 130*F, provided administrative operational restrictions tre followed, te
- prevent failure of the air-cooled bearings of the pumps while they are operating. [ References 1,4, and 5)
The SRW lleat Exchanger Room is provided with forced air ventilation by separate supply and exhaust fans and dampers. The ventilation is required to remove equipment heat and maintain the room temperature low enough for equipment operability in post-accident situations. Relatively cool air is drawn from the Turbine Buildhg and the warmer exhaust air is returned there, as well. The dampers automatically shut upon high pressure to isolate the room from temperature rises due to a high energy line break inside of the Turbine Building. [ References 6 and 7]
. Heat released by the main steam and feedwater pipes requMs that cooling be provided in the main steam line penetration area all year round. This system uses cutside air as the cooling medium. - Fresh air is mixed with recirculated air as required and supplied through ducting from an air-handling unit. The main steam line penetration area is pressurized and the excess air flows out through the open safety vent to the roof. A room thermostat controls the position of the mixing dampers, which are located upstream of dust-stop filters. [ References 1,4, and 5)
A negative pressure with respect to ambient and surrounding areas of tA building is normally maintained in the waste processing area. A common air supply system consisting of three 50% capacity Application for License Renewal 5.11 A 2 Calvert Clifts Nuclear Power Plant
't '
A'ITACliMENT m APPENDIX A -TECHNICAL INFORMATION 5.llA - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM air handling units supplies outdoor air for ventilation of the common waste processing area and geteral areas in the Auxiliary Building. A system of ductwork ensures a uniform distribution throughout this area. He exhaust system draws air from the waste processing areas by means of ductwork and forces it through IIEPA filters, after which it is discharged into the main exhaust plenums. From here, the main plant exhaust fans force the air past the radioactivity monitors and out through the exhaust stacks. These exhaust fans are 100% redundant, but the filters are not. [ References I and 3]
The ECCS Pump Rooms require ventilation to limit room temperature and provide proper cooling of the safety _ injection and containment spray pumps. He subsystem consists of one cooling unit for each ECCS Pump Room, cooling unit fans, and an ECCS Pump Room exhaust system that includes a roughing filter, a llEPA filter, charcoal filter, and dampers. The Saltwater System p-ovides cooling to the cooling unit. [ References 1 and 3]
Two 50% capacity air handling units provide filtered air to the fuel handling area, which includes the spent fuel pool area, New Fuel Storage Room, and the Miscellaneous Waste Evaporator Room. A separate exhaust system draws air through a manifold and ilEPA filters and feeds it into the main plant vent of Unit 1. During load handling evolutions over the spent fuel pool that includes moving fuel, this air is diverted through ;..arcoal filters after it leaves the llEPA filters for removal of radioactive iodines prior to discharge to minimize radioactive material release in the event of a fuel handling accident. The exhaust fans are capable of maintaining a negative pressure with respect to ambient and surrounding areas of the building. Unit heaters are provided to maintain a minimum temperature of 60'F in the winter. [ Refer,nces I and 3]
System Interfaces
%c Auxiliary Building II&V System has an interface with the following systems and components:
[ References 2 through 5; Reference 8]
System /Comnonent Within the scone of License Renewal at the Interface?
Main Plant Vent No Control Room IIVAC System Yes, See Section 5.1IC of the BGE LRA Radiation Monitoring System No Saltwater Cooling System Yes, See Section 5.16 of the BGE LRA Service Water System No System Sconing Results The Auxiliary Building II&V System is within the scope of license renewal based on 10 CFR 54.4(a).
The following intended functions of the Auxiliary Building fl&V System were determined based on the requirements of $54.4(a)(1) and (2), in accordance with the CCNPP IPA Methodology, Section 4.1.1:
[ Reference 9, Table 1]
To supply air to the battery ventilation system in response to a Design Basis Event (DBE);
To initiate letdown line isolation to provide radiological release control during a loss-of-coolant accident; To provide vent!!ation for, and remove potentially radioactive contamination from, the ECCS Pump Room in response to a DBE; Application for License Renewal 5.ll A-3 Calvert Cliffs Nuclear Power Plant i
_g.
t' ATTACHMENT (M APPENDIX A -TECHNICAL INFORMATION 5.11A AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM To provide ilVAC for, and remove potentially radioactive contamination from, the Fuel llandling
- area in response to a DBE; To provide IIVAC to the Electrical Switchgear Room in response to a DBE; To provide ventilation to the Diesel Generator Rooms in response to a DBE; To provide ventilation to the AFW Pump Room in response to a DBE;
- ' To provide ventilation to the SRW Heat Exchanger Room in response to a DBE; To maintain electrical continuity and/or provide protection of the electrical system; To maintain the pressure boundary of the system (liquid and/or gas); and To maintain structural ir.tegrity to support proper operation of other Auxiliary Building H&V System components.
The following Auxiliary Building II&V System intended functions were determined based on the j
requirements ofiS4.4(a)(3): [ Reference 9, Table 1]
For fire protection (l50.48)- To provide alternate ventilation to the AFW Pump Room during a fire; and For environmental qualification (650.49). To maintain functionality of electrical equipment as addressed by the Environmental Quali0 cation Program and to provide information used to assess the plant and environs condition during and following an accident.
All components of the Auxiliary Building H&V System that meet the fire protection or environmental qualification criteria of 54.4(a)(3) are also safety related. No components were scoped that only meet a 34.4(a)(3) criteria.
Components of the Auxiliary Building II&V System that support the above functions are safety-related and Seismic Category I and are subject to the applicable loading conditions identified in the Updated Final Safety Analysis Report Section 5/1.2 for Seismic Category 1 systems and equipment design.
[ References 3 through 6; Reference 10] The ductwork was constructed of galvanized copper bearmg sheet steel, which conformed to the latest Cuide from the American Society of Heating, Refrigeration, and Air Conditioning Engineers. It was installed in accorda:.ce with high velocity and low velocity duct construction standards from the Sheet Metal and A/C Contractors National Association. (Reference 11]
Ooerating Ihnerienes Over 20 years of operating experience has shown the H&V systems at CCNPP to be highly reliable in maintaining their passive functions. Some cracking has been discovered in HVAC ducting due to vibration induced fatigue. However, these isolated failures were due to a combination of design and instal 4 tion deficiencies. In one case, additional supports were added to the ducting to pevent recurrence. In another case, the fans were balanced to minimize the vibration. - Some loosening of fasteners has been experienced due to dynamic loading. Vibration-related aging concerns are minimized through system design and existing maintenance practices, which are further described below in the discussion for Group 3. Vibration isolators, i.e., flexible collars or cloth boots, are installed around the fans to minimize the vibration being transferred to other equipment. [ Reference 2, Attaci ments 6)
Furthermore, fans are monitored for vibration whenever the fan belts are retensioned or replaced.
~ Application for License Renewal 5.1 l A-4 Calvert ClitTs Nuclear Power Plant
l' ATTACHMENT (2)
APPENDIX A -TECilNICAL INFORMATION 5.llA - AUXILIARY HUILDING HEATING AND VENTILATION SYSTEM in 1980, a Control Room air conditioning unit was placed out-of service to repair broken damper linkages. This failure was caused by excessive wear due to inadequate lubrication of the damper linkage.
The existing preventive maintenance (PM) procedure was modified to include lubrication along with the
_ periodic visual inspection. (Reference 12] During performance of these periodic inspections, elastomer deyadation of the seals has also been identified. If the seals on jambs or blade edging lose their resiliency or are deteriorated, corrective actions are taken to have the seals replaced. (Reference 13]
Corrosion has been disec-ed in the housing below the cooling coils in some of the HVAC units. These areas have been inst
. to assess the corrosion rates and adequacy of the system pressure boundary.
Other than the limiteo nt of degradation experienced due to vibration, wear, and corrosion, no other signi0 cant aging conces. iiave been identified that could affect the ability of the Auxiliary Building Il&V System components to perform their passive in: ended functions.
5.II A.1.2 Component Level Scoping Based on the intended system functions listed above, the portions of the Auxiliary Building II&V System that are within the scope of license renewal include all safety-related components in the system (electrical, mechanical, and instrumentation), and their supports. Safety-related portions of the Auxiliary Building H&V System include the following: (References 3 through 5; Reference 10]
Plant Area Portion Within Scone Switchgear Room Entire subsystem including IIVAC units, refrigeration system, and supply and return duct and dampers Diesel Generator Rooms Entire subsystem including supply duct, dampers and fans, and the exhaust dampers AFW Pump Rooms Supply duct and dampers and exhaust fans, duct and dampers (the normal A/C unit, and associated duct and damper is not)
SRW lleat Exchanger Rooms Entire subsystem including supply fan, dampers and duct, and exhaust fan and dampers Main steam line penetration None area Waste processing area None ECCS Pump Room Exhaust path including fans, HEPA filters, charcoal filters, duct, and dampers (exhaust duct from the downstream side of the exhaust fan discharge damper to the plant vent is not)
Fuel handling area Exhaust fans, HEPA filters, ch'rcoal filters, duct, and dampers (all supply fans, HVAC units, filters, duct, and dampers are not, exhaust duct from the wall of the fuel handling area Exhaust Fan Equipment Room to the plant vent is also not)
Application for License Renewal 5.1 I A-5 Calvert Cliffs Nuclear Power Plant
a s
1 ATTACHMENT W APPENDIX A -TECHNICAL INFORMATION 5,llA - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM The following 46 device type. in the Auxiliary Building II&V System were designated as within the scope oflicense renewal because they have at least one intended function [ Reference 2, Section 3.2 and Table 3 2):
Device Tvoc Device Descriotion Device Tyne
. Device Descriotion
-ACC Accumulator MD 125/250VDC Motor CKV Check Valve MO Motor Operator COIL Coil PD1 Pressure DiffIndicator
-COMP Compressor PDIS Pressure Diffindicator Switch -
CV Control Valve PI Pressure Indicator DAMP-Damper PNL Panel DISC Disconnect Switch / Link PO Piston Operator DRY Air Dryer PS Pressure Switch DUCT llVAC Duct PT Pressure Transmitter FAN Fan PY Pressure Converter (Relay)
FL Filter RV ReliefValve FU Fuse RY Relay GD Gravity Damper.
SV Solenoid Valve llD Manual Damper -
TC Temperature Controller ilS Ilandswitch TCV Temperature Control Valve ilV iland Valve TE Temperature Element ilX lleat Exchanger
. TIC Temperature Indicating Controller IIY Converter / Relay TS Temperature Switch JD Tubing with Piping Code of"JD" TT Temperature Transmitter JL Power Lamp indicator TY Temperature Device (Relay)
LY Level Device (Relay)
ZC Position Controller M
480V Motor (Feed from MCC)
ZL Position Indicating Lamp MB 480V Motor ZS Position Switch Some components in the Auxiliary Building Il&V System are common to many other plant systems and have been included in separate sections of the BGE LRA that address those components as commodities for the entire plant. These components include the following: [ Reference 2, Section 3.2]
Structural supports for ducting, piping, cables, and components are evaluated for the effects of aging in the Component Supports Commodity Evaluation in Section 3.1 of this application.
Electrical control and power cabling are evaluated for the effects of aging in the Electrical Cables Commodity Evaluation in Section 6.1 of this application. This commodity evaluation completely addresses the passive intended function entitled " maintain electrical continuity and/or provide protection of the electrical system" for the Auxiliary Building H&V System.
Instrument tubing arid piping and the associated supports, instrument valves, and fittings (generally everything from the outlet of the final root valve up to and inc_luding the instrument),
and the pressure boundaries of the instruments themselves, are all evaluated for the effects of aging in the Instrument Lines Commodity Evaluation in Section 6.4 of the BGE LRA.
Application for License Renewal.
5.11A-6 Calvert Cliffs Nuclear Power Plant
I ATrACllMENT d)
APPENDIX A -TECliNICAL INFORMATION 5.11A - AUXILIARY HUILDING HEATING AND VENTILATION SYSTEM 5.11A.I.3 Components Subject to AMR This section describes the components within the Auxiliary Building il&V System that are subject to AMR. It begins with a listing of passive intended functions and then dispositions the device types as either only associated with active functions, subject to replacement, evaluated in other reports, evaluated in commodity reports, or remaining to be evaluated for aging management in this section.
Passive Intendulfunctions in accordance with CCNPP IPA Methodology Section 5.1, the following Auxiliary Building H&V System functions were determined to be passive: (Reference 2, Table 3 1]
Maintain the pressure boundary of the system (liquid and/or gas);
e Maintain electrical continuity and/or provide protection of the electrical system; and Maintain structural integrity to suppon proper operation of other Auxiliary Building H&V e
System components.
Device Tyoes Subject to AMR Of the 46 device types within the scope of license renewal; [ Reference 2, Table 3 2 and Appendix B; Reference 14]
Twenty five device types have only active functic:a and do not require AMR; coil, control valve, disconnect switch / link, fuse, hand switch, converter / relay, power lamp indicator, level device (relay),
480V motor (feed from MCC),480V motor, 125/250VDC motor, motor operator, piston operator, pressure transmitter, pressure converter (relay), relay, temperature controller, temperature element, temperature indicating controller, temperature switch, temperature transmitter, temperature device (relay), position controller, position indicating lamp, and position switch.
Ten device types do not require a detailed evaluation of specific aging mechanisms because they are e
considered part of a complex assembly whose only passive function is closely linked to active performance as discussed below; accumuhtor, air dryer, compressor, tubing with piping Code of "JD," pressure indicator, pressure switch, check valve, relief valve, solenoid valve, and temperature control valve.
In accordance with the provisions of Section 6.1.1 of the CCNPP IPA Methodology, components that comprise the refrigeration units do not require a si.ccific evaluation of ARDMs because the detrimental effects of aging mechanism: can Se observed by detrimental changes in the performance characteristics or condition of refrigeration unit components if they are properly monitored.
Therefore, by adequately monitoring these performance or condition characteristics, the effects of aging on the passive intended function are also adequately managed. The active functions are monitored by: (1) operational requirements that must be satisfied for continued plant operation; (2) Maintenance Rule system performance monitoring; and (3) component-specific condition monitoring addressed under the CCNPP Maintenance Program. [ Reference 2, Appendix B]
The ten device types listed above are entirely included in these complex assemblies. Three other device types, i.e., hand valves, heat exchangers, and fans, include some components that are part of these complex assemblies and some that are included in the AMR presented herein.
Application for License Renewal 5.1 l A-7 Calvert Cliffs Nuclear Power Plant
=g 3."
ATTACHMENT m APPENDIX A -TECIINICAL INFORMATION
- 5. IIA - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM Two devices types are evrituated in another section of this application;
> ' Panel' is evaluated for the effects of aging in the Electrical Commodities Evaluation in Section 6.2 of this application. This commodity evaluation completely addresses the pass!ve intended function entitled " maintain structural integrity to support proper operation of other Auxiliary Building fl&V System components"
> 'Pressare differential indicator switch' is evaluated for the effects of aging in the Instiu.~nt Line Commodity Evaluation in Section 6.4 of this application.
The remaining nine device types listed in Table 5.II A 1 are subject to a detailed evaluation of aging mechanisms as part of the AMR and are included in this section. For AMR, some device types have a number of groups associated with them because of the diversity of materials used in their fabrication or -
differences in the environments to which they are subjected.
Maintenance of the pressure boundary of the system is the only passive intended function associated with the Auxiliary Building fl&V System not addressed by one of the.ommodity evaluations referred to above. Therefore, only the pressure-retaining function for the nine device types listed in Table 5.ll A-1 is considered in the AMR for the Auxiliary Building H&V System. Unless otherwise annotated, all components of each listed device _ type are subject to AMR.
TABLE 5.ll A-I AUXILIARY BUILDING H&V SYSTEM DEVICE TYPES REQUIRING AMR Damper HVAC Duct Fan (1)
Filter Gravity Damper Manual Damper Hand Valve (1,2)
Heat Exchanger (1)
Pressure Differential Indicator (2)
(1) The fans (condenser fans), heat exchangers (condenser and cooling coils of the HVAC unit), and hand valves that are part of the Switchgear Room refrigeration unit are not evaluated herein because they are part of a complex assembly whose only passive function is closely linked to active per# rmance as permitted in Section 6.1.1 of the CCNPP IPA Methodology.
(2) The e galization valve (hand valve) and pressure differential indicator switch for the ECCS Pump Room exhaust ilEPA filters are evaluated in the Instrument Line Commodity Evaluation in Section 6.4 of this application. [ Reference 9, Attachment 4A) i Application for License Renewal 5.11 A-8 Calvert Cliffs Nuclear Power Plant l
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APPENDIX A -TECHNICAL INFORMATION 5.11A - AUXILIARY BUILDING HEATING AND VENTILATION-SYSTEM 5.11A.2 Aging Management
' A list of potential age-related degradat on mechanisms (ARDMs) identified for the Auxiliary Building i
H&V System components is given in Table 5.ll A 2.- The plausible ARDMs are identified in the Table by a check mark (/) in the appropriate device type column. A check mark indicates that the ARDM applies to at least one group for the device type listed. For efficiency in presenting the results of the evaluations in this section, ARDM/ device type combinations are grouped together where there are similar characteristics, and the discussion is applicable to all components within that group. Exceptions are noted where appropriate. Ta..le 5. IIA 2 identifies the group in which each ARDM/ device type combination belongs.
The following groups have been selected for the Auxiliary Building II&V System:
Group 1 - Includes crevice corrosion, general corrosion, and pitting for duct and heat exchangers.
Group 2 - Includes elastomer degradation and wear for non metallic duct and dunper parts.
Group 3 - includes dynamic loading for fans.
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APPENDIX A -TECHNICAL INFORMATION
- 5. IIA - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM TABLE 5.11 A-2 POTENTIAL AND PLAUSIBLE ARDMs FOR TIIE AUXILIARY BUILDING II&V SYSTEM Auxiliary Bellilag H&V System Device Types -
N Peteestal ARDMs e DAMP DUCT FAN FL GD lid liv HX PD1 Cavitation Erosion Corrosion Fatigue Crevice Corrosion V(1)
V(1)
Dynamic Loading V(3)
Erosion Corrosion Fatigue Fouling Galvanic Corrosion General Corrosion V(1)
V(1)
Ilydrogen Damage Intergranular Attack Microbiologically-Induced Corrosion Particulate Wear Erosion Pitting V(1)
V(1)
Radiatior. Damage Elastomer degradation V(2) 4(2)
V(2)
Selective Leaching Stress Corrosion Cracking Stress Relaxation Thermal Embrittlement Wear V (2)
V(2)
V(2) 3 - indicates that the ARDM is plausible for component (s) within the device type
(#) - Indicates the Group in which this device type /ARDM combination is evaluated Note: Not every component within the device types listed here may be susceptible to a given ARDM.
This is because components within a device type are not always fabricated from the same materials or subjected to the same environments. Exceptions for each device type will be indicated in the ag*ng management section for each ARDM discussed in this report.
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APPENDIX A -TECIINICAL INFORMATION 5.11 A - AUXILIARY BUILDING IIEATING AND VENTILATION SYSTEM The following is a discussion of the aging management demonstration process for each group identified above. It is presented by group and includes a discussion on materials and environment, aging mechanism effects, methods to manage aging, aging management program (s), and aging management derr.anstration.
Group 1 (crevice corrosion, general corrosion, and pitting for duct and heat exchangers) -
Materials and Environment Group i is comprised of components that are potentially exposed to moist air and condensation.- These include the ducting where the steel materials are exposed to the potentially moist air. The duct, fittings, doors, and door hinges / latches are constructed of galvanized carbon steel. The joint angles are constructed of carbon steel, and the bolts and rivets are plated carbon steel. The supply and exhaust registers are constructed of either enameled carbon steel or aluminum. Group 1 ducting includes all of the Auxiliary Building fl&V System duct that is within the scope of license renewal. Some of the components' surfaces are painted or galvanized. [ Reference 2, Attachments 4 and 6)
Also included in Group 1 is the galvanized carbon steel housing for the Switchgear Room cooling coils that may be exposed to moist air and condensate from the coils. If the drains become plugged, there may also be standing water in the drain pan that could spill over onto other sections of the equipment base.
The coils themselves have the system pressure boundary intended function; however, they do not require AMR because they are part of the refrigeration units and considered a complex assembly, as discussed in Section 5.11 A.I.2. [ Reference 2, Attachments 4 and 6)
The Auxiliary Building H&V System is designed to maintain the temperatures inside each of the ventilated areas, assuming the outdoor air temperature is 95'F, below the design temperature as follows:
(Reference 1, Table 9-18]
Subsystem Desien Temocrature ('F)
Switchgear Room 104 EDG Rooms 120 AFW Pump Room 90 Main steam penetration area 160 Waste processing i10 Fuel handling area 110 ECCS Pump Room i10
'Ihe internal environment for the Auxiliary Building H&V System consists of outside air or of air drawn from ventilated areas. No design requirements exist for maintaining humidity below a specified value in the Auxiliary Building. However, the maximum normal relative humidity inside the Auxiliary Building areas is 70%. (Reference 15] Outdoor air could reach a relative humidity of up to 100%. All of these components are located in ventilated areas indoors and, therefore, not exposed :s the outside weather or sun.
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ATTACHMENT m APPENDIX A -TECliNICAL INFORMATION 5.11A - AUXILIARY HUILDING llEATING AND VENTILATION SYSTEM Group 1 (crevice corrosion, general corrosion, and pitting for duct and heat exchangers) - Aging Mechanism Effects Crevice corrosion is intense, localized corrosion within crevices or shielded areas, it is associated with a small volume of stagnant solution caused by holes, gasket surfaces, lapjoints, crevices under bolt heads, surface deposits, designed crevices for attaching thermal sleeves to safe-ends, and integral weld backing -
rings or back-up bars. The crevice must be wide enough to permit liquid entry and narrow enough to malmain stagnant conditions, typically a few thousandths of an inch or less. Crevice corrosion is closely related to pitting corrosion and can initiate pits in many cases, as well as leading to stress corrosion cracking. [ Reference 2, Attachments 6 and 7]
General corrosion is the thinning (wastage) of a metal by chemical attack (dissolution) at the surface of the metal by an aggressive environment. General corrosion requires an aggressive environment and materials susceptible to that environment. The consequences of the damage are loss of load carrying cross-sectional area. [ Reference 2, Attachments 6 and 7]
Pitting is another form ofloca!! zed attack with greater corrosion rates at some locations than at others.
Pitting can be very insidious and destructive, with sudden failures in high pressure rplications (especially in tubes) occurring by perforation. This form of corrosion essentially produces holes of varying depth to diameter ratios in the steel. Deep pitting is more common with passive metals, such as austenitic stainless steels, than with non passive metals. Pits are generally elongated in the direction of gravity. In many cases, erosion corrosion, fretting corrosion, and crevice corrosion can also lead 'c pitting. [ Reference 2, Attachments 6 and 7]
For Group 1 components, there are two possible effects from long-term exposure to the moist environment; a uniform corrosion of the exposed steel surfaces causing material thinning, and localized attack resulting in pits and cracks. Those items that are painted or galvanized are protected from the effects of corrosion; however, where the coating is damaged, the corrosion may take place. The most
. likely locations for corrosion is in crevices at duct joints and between support angles and sheet metal.
These corrosion ARDMs are not plausible for the registers constructed of alurr.inum because that material is resistant to corrosion in this mild environment. If corrosion were left unmanaged, it could eventually result in loss of the pressure-retaining capability under CLB design loading conditions.
- [ Reference t Attachment 6]
Group 1 (crevice corrosion, general corrosion, and pitting for duct and heat exchangers)- Methods to Manage Aging Mitigation: Since there are no design features for control of humidity, the only feasible method of preventing exposure of these components to a corrosive environment is to apply a protective coating to them. Those subcomponents without a protective coating, or where the coating has degraded, will potentially be exposed to moisture from condensation. The subcomponents constructed of carbon steel materials could be replaced with subcomponents constructed of more corrosion resistant materials.
[ Reference 2, Attachment 8]
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Y ATTACIIMENT m APPENDIX A -TECilNICAL INFORMATION 5.llA - AUXILIARY HUILDING llEATING AND VENTILATION SYSTEM 4
Discoverv: '!he effects of corrosion (crevice corrosion, general corrosion, and pitting) on Group I components can be discovered and monitored through non-destructive examination techniques, such as visual inspections or pressure tests. [ Reference 2, Attachment 8] Representative samples of susceptible locations can be used to assess the need for additional inspections at less susceptible locations.
Group 1 (crevice corrosion, general corrosion, and pitting for duct and heat exchangers) - Aging Management Program (s)
Mitigation: Maintaining the protective coatings, as discuased below in Discovery, will help to mitigate corrosion of these components. No other mitigation techniques are deemed necessary at this time, so there are no rnitigation programs credited for managing corrosion of Group I components.
Dissmuy: For Group I components, crevice corrosion, general corrosion, and pitting can be readily detected through visual examination. Additionally, degraded protective coatings, which help mitigate corrosion, can also be visually detected so that corrective actions can be taken to restore the coatings. As such, an inspection program can provide the assurance needed to conclude that the effects of plausible aging an. being effectively managed for the period of extended operation. Routine system walkdowns would discover corrosion of the external surfaces of the Group I components. To assure that corrosion is discovered ifit exists on the internal surfaces of these components, they will be included in a new ARDI Program to accomplish the necessary inspections. [ Reference 2, Attachment 8]
System Walkdowns Calvert Cliffs Administrative Procedure MN l.319, " Structure and System Walkdowns," provides for discovery of general corrosion, and conditions that could allow corrosion to occur (e.g. degraded paint),
of the Auxiliary Building IIAV System by performance of visual inspections during plant walkdowns.
The purpose of the procedure is to provide direction for the performance of structure and system walkdowns and for the documentation of the walkdown results. (Reference 16, Sections 1.1 and 1.2]
In accordance with MN-l-319, personnel with assigned responsibility for specific structures and systems perform periodic walkdowns. Walkdowns may also be performed as required for reasons such as material condition assessments; system reviews before, during, and after outages; start-up reviews (i.e.,when a system is re-energized or placed in service); and as required for plant modifications.
[ Reference 16, Section 5.l]
One of the objectives of the walkdowns is to assess the condition of the CCNPP structures, systems, and components 'such that any degraded condition will be identified, documented, and corrective actions taken before the degradation proceeds to failure of the structures, systems, and components to perform their intended functions. [ Reference 16, Sections 5.1.C, 5.2.A.1, and 5.2.A.5] Conditions adverse to quality are documented and resolved by the Calvert Cliffs Corrective Actions Program. The existing
_ procedure will be modified to include specific inspection items with respect to discovery of these ARDMs to help ensure they are being adequately managed.
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APPENDIX A -TECHNICAL INFORMATION 5.11 A'- AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM -
The procedure provides guidance for specine types of degradation or conditions to inspect for when performing the walkdowns. Inspection items related to aging management include the following:
[ Reference 16, Section 5.2 and Attachments 1 through 13]
_ ltems related to specific ARDMs such as corrosion or vibration; Effects that may have been caused by ARDMs such as damaged supports; concrete degradation, e
anchor bolt degradation, or leakage of fluids; and Conditions that could allow progression of ARDMs such as degraded protective coatings, leakage e
of Hulds, presence of standing water or accumulated moisture, or, inadequate support of components (e.g., missing, detached, or loose fasteners and clamps).
The walkdowns promote familiarity of the systems by the responsible personnel and provides extended attention to plant material condition beyond that afforded by Operations and Maintenance alone. The procedure has been improved over time, based on past experience, to provide guidance on specific activities to be included in the scope of the walkdowns.
The corrective actions taken as a result of system walkdowns will ensure that the Group 1 duct and heat exchangers remain capable of performing their passive intended function under all CLB conditions.
Age-Related Degradation Insnection Pronram To moaitor the effects of corrosion for internal surfaces of Group I components, they will be included within a new plant program to accomplish the needed inspections. This program is considered an Age-Related Degradation Inspection (ARDI) Program as deGned in the CCNPP IPA Methodology presented in Section 2.0 of the BGE LRA.
The elements of the ARDI program will include:
Determination of the examination sample size based on plausible aging effects; identification of inspection locations in the system / component based on plausible aging effects e
and consequences ofloss of component intended function; Determination of examination techniques (including acceptance criteria) that would be effective, e
considering the aging effects for which the component is examined; Methods for interpretation of examination results; e
Methods for resolution of unacceptable examination findings, including consideration of all e
design loadings required by the current licensing basis (CLB), and specification of required corrective actions; and Evaluation of the need for follow-up examinations to monitor the progression of any age related degradatiora Corrective actions will be taken, as necessary, in accordance with the CCNPP Corrective Actions Program and will ensure that the components will temain capable of performing the system pressure boundary integrity function under all CLB conditions.
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l.. - 1; ATTACHMrNT Q) l; APPENDIX A -TECHNICAL INFORMATION 5.11 A'. AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM Group 1 (crevice corrosion, general corrosion, and pitting for duet and heat exchangers) -
Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to crevice corrosion, general corrosion, and pitting of duct and heat exchangers:
The Group 1 components provide system pressure-retaining boundary and their integrity must be maintained under all CLB conditions.
Crevice corrosion, general corrosion, and pitting are plausible for the components, and result in material loss which, if left unmanaged, can lead to loss of pressure retaining boundary integrity.
Existing visual inspections will continue to be performed in accordance with modified Administrative Procedure Md l-319 to help ensure that these ARDMs are being adequately managed. Signs of degraded paint or galvanized surfaces, of external corrosion, or of internal corrosion that resulted in holes in the duct or cooler housing would be detected during these walkdowns, if unsatisfactory conditions are detected, corrective actions are taken in accordance with the CCNPP Corrective Actions program.
To provide the needed inspection for the internal mtfaces of Group I components, they will be included in the scope of an ARDI Program, inspections will be performed, and appropriate corrective action will be taken if significant corrosion is discovered.
Therefore, there is reasonable assurance that the effects of crev'.ce corrosien, general corrosion, and pitting on Group I components will be managed in such a way as to maintain the components' pressure boundary integrity, consistent with the CLB, during the period of extended operation.
Group 2 (elastomer degradation and wear for non-metallic duet and damper parts)- Materials and Environment The Auxiliary Building Il&V System galvanized carbon steel ducting was installed with flexible collars in connections between fans and ducts or casings to prevent excessive movements oflong ducts. These dexible collars are constructed of elastomers and are installed with sufficient slack to prevent transmission of vibration. Collars are secured to fans and ducts with galvanized steel bars fastened with bolts for an air-tight construction. Some of the Auxiliary Building 11&V System dampers are required to maintain system pressure boundary while in the closed position, and they are provided with compressible seals for leak tightness. These seals are constructed of neoprene material, which is an elastomer.
[ Reference 2, Attachment 4s; Reference 11]
The internal and external environments for the Auxiliary Building Il&V System components are discussed above in the Materials and Environment Section for Group 1.
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APPENDIX A -TECIINICAL INFORMATION 5.llA - AUXILIARY HUILDING IIEATING AND VENTILATION SYSTEM Group 2 (elastomer degradation and wear for non metallic duct and damper parts) - Aging Mechanism Effects An elastomer is a material that can be stretched to significantly greater than original length and, upon release of the stress, will return with force to approximately its original length. When an elastomer ages, there are three mechTnism primarily involved:
Scission - ne process of breaking molecular bonds, typically due to ozone attack, UV light, or radiation; Crosslinking 'De process of creating molecular bonds between adjacent long chain molecules, typically due to oxygen attack, heat, or curing; and Compoun ' ingredient evaporation, leaching, mutation, etc.
Natural aging tests indicate that where there is a significant property change in a elastomer, it appears to occurs within the first five to ten years after initial formulation / curing. Measurable properties that change include hardness, modulus, elongation, tensile strength, and compression strength. Elastomers generally harden as they age making sealing more difficult. (Reference 2, Attachment 7s]
Wear results from relative motion between two surfaces (adhesive wear), from the influence of hard, abrasive particles (abrasive wear) or fluid stream (erosion), and frorr small, vibratory or sliding motions under the influence of a corrosive environment (fretting). Motions may be linear, circular, or vibratory in inert or corrosive environments. Fretting is a wear phenomenon that occurs between tight fitting surfaces subjected to a cyclic, relative motion of extremely small amplitude. Common sites for fretting are in joints that are bolted, keyed, pinned, press fit or riveted, in oscillating Searings, couplings, spindles, and seals; in press fits on shafts; and in universaljoints. (Reference 2, Attachment 7s]
Elastomer degradation and wear are plausible for the flexible collars since the clastomers will degrade at the joints in the llVAC equipment due to relative motion between vibrating equipment, pressure variations and turbulence, and exposure to temperature changes and oxygen. These stressors will result in eventual tearing of the boot. Elastomer degradation and wear are plausible for damper seals because the neoprene will degrade due to relative motion between the blade and sleeve during damper operation and exposure to temperature changes and oxygen. Rese stressors will result in eventual breakdown of the seal. [ Reference 2, Attachment 6s] If left unmanaged, elastomer degradation and wear could eventually result in the loss of pressure boundary integrity of the duct flexible collars and damper seals under CLB design loading conditions.
Group 2 (clastomer degradation and wear for non-metallic duct and damper parts) - Methods to Manage Aging Mitigation: Elastomer degradation can be mitigated by utilizing materials that are less susceptible to heat and oxygen. Wear can be mitigated by minimizing operation of the dampers to slow degradation of the seating surfaces, which leads to a loss ofleak tightness. [ Reference 2, Attachment 7s]
Discoverv: Periodic visual inspections can be performed for the Group 2 equipment to detect the efTects of clastomer degradation and wear. Degradation of the flexible collars can be detected through periodic system walkdowns because the collars are readily accessible. Degradation of damper seals can be
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APPENDIX A -TECilNICAL INFORMATION
- 5. IIA - AUXILIARY BUILDING llEATING AND VENTILATION SYSTEM detected through continued inspections and walkdowns, if signincant degradation is discovered, the Hexible collars or damper seals can be repaired or replaced as appropriate. [ Reference 2, Attachment 8]
Group 2 (elastomer degradation and wear for non-metallic duct and damper parts) - Aging Management Program (s)
Mitigation: The system was designed to minimize vibration by using equipment support isolators and equipment-to-duct isolators such as the Dexible collars. Changes to materials or to system operating practices are not deemed necessary to mitigate the efTects of these ARDMs. Implementing the discovery methods discussed below are adequate methods to manage these ARDMs. Since there are no additional methods beyond these design features for mitigating elastomer degradation and wear, there are no programs credited with mitigating the aging effects due to these ARDMs. [ Reference 2, Attachment 6s and 8]
Discovery; Routine system walkdowns would discover elastomer degradation and wear of the duct Oexible collars and possibly of the damper seals. To assure that degradation of the damper seats is not threatening the capability of the dampers to provide the pressure boundary function they will be included in a new ARDI Program.
System Walkdous Procedure MN 1-319 provides for discovery of the effects of clastomer degradation and wear by providing for system walkdowns that include visual inspections, reporting the walkdown results, and initiating corrective action. Under this program, inspection items typically related to aging management include identifying poor housekeeping conditions (such as degraded paint), and id ntifying system and equipment stress or abuse (such as excessive vibrations, bent or broken component supports, etc.). Signs of cracking or tearing of duct flexible collars would be detected during these walkdowns, in some cases, these walkdowns can detect degradation in the dampers, such as if a non-operating fan is rotating backward due to a leaking damper. All the accessible external surfaces of the subject equipment are monitored and conditions identi0ed as adverse to quality are corrected in accordance with the CCNPP Corrective Actions Program. [ Reference 16] The existing procedure will be modified to include speciGe inspection items with respect to discovery of these ARDMs to help ensure they are being adequately managed. Refer to the discussion on Aging Management Programs for Group I for a detailed description of procedure MN 1319.
ARDI Program The system walkdowns can identify degradation evident externally from the components, which is adequate for the duct flexible collars and, in some cases, the damper seals. An inspection of the internals of the dampers would provide additional assurance that the effects of elastomer degradation and wear are being adequately managed. This inspection will be accomplished as part of an ARDI Program as denned in the CCNPP IPA Methodology presented in Section 2.0. Refer to the Group I discussion on aging management programs for a detailed discussion of the ARDI Program.
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5.11 A-17 Calvert Cliffs Nuclear Power PIU
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APPENDIX A -TECliNICAL INFORMATION 5.llA - AUXILIARY HUILDING liFATING AND VENTILATION SYSTEM Corrective actions will be taken in accordance with the CCNPP Corrective Actions Program and will ensure that the components will remain capable of performing their pressure boundary integrity ftmetion under all CLB conditions.
Group 2 (elantomer degradation and wear for non-metallie duet and damper parts)
Demonstration of Aging Management Based on the factors presented above, the following conclusions can be reached with respect to clastomer degradation and wear for duct flexible collars and damper seals:
Auxiliary Building Il&V System ducts and dampers provide system pressure-retaining boundary and their integrity must be maintained under CLB design conditions.
Elastomer degradation and wear are plausible for the ficxible collars due to the relative motion between vibrating equipment, pressure variations, and turbulence, and exposure to temperature changes and oxygen. Elastomer degradation and wear are plausible for the damper seals du to relative motion between the blade and sleeve during damper operation and exposure to temperature changes and oxygen.
if left unmanaged, elastomer degradation and wear can result in material loss, tearing, or e
cracking, which could lead to loss of pressure-retaining boundary integrity.
Existing visual inspections will continue to be performed in accordance with modified Adml.nstrative Procedure MN 1319 to help e, a that these ARDMs are being adequately managed. Signs of cracking or tearing of duct collars would be detected during these walkdowns, as well as such conditions as identifying unusual noises, leaks, or vibration. If unsatisfactory conditions are detected, corrective actions are taken in accordance with the CCNPP Corrective Actions Program.
To provide the needed internal inspection for the dampers, they will be included in the scope of an ARDI Program. Inspections will be performed, and appropriate corrective action will be taken if significant degradation of the damper seals is discovered.
Therefore, there is reasonable assurance that the effects of elastomer degradation and wear for duct flexible collars and damper seals will be managed in such a way as to maintain the components' pressure boundary integrity, consistent with the CLB, during the period of extended operation.
Group 3 (dynamic loading for fans)- Materials and Environment Group 3 is comprised of fans because the rotating equipment can cause vibration that causes dynamic loading of the fasteners. Normal bearing wear and dirt buildup cause imbalances in the rotating parts of the fans, thereby creating vibrations. Flexible collars are installed on the fans to provide dynamic isolation for adjacent components, which minimizes the dynamic loading for those components. The fans have air for their intemal and external environments. [ Reference 2, Attachment 7]
Fan housings and fasteners for the ECCS Pump Room exhaust fans, AFW Pump Room supply fans, EDG Room supply fans, Switchgear Room supply fans, and fuel handling area exhaust fans are constructed of carbon steel. The SRW lleat Exchanger Room supply and exhaust fan housings and supports are Application for License Renewal 5.11 A-18 Calvert Cliffs Nuclear Power Plant
KITACllhiENT (2)
APPENDIX A -TECHNICAL INFORMATION 5.11A - AUXILIARY BUILDING llEATING AND VENTILATION SYSTEM constructed of aluminum and the fasteners of carbon steel. The fan blades and motors do not perform a passive intended function. Therefore, they are not subject to AMR. [ Reference 2, Attachment 4s]
Group 3 (dynamic loading for fans). Aging Mechanism Effects Dynamic loadings (vibrations) are created at blowers by rotating parts with imbalances due to dirt buildup and normal bearing wear. Dere is a history of loosened mechanical fasteners due to vibration in fans at CCNPP. uls mechanism is plausible for the fans, but is not considered plausible for adjacent IIVAC equipment dee to the dynamic isolation provided by flexible collars, if dynamic loading was left unmanaged, it could eventually result in the loss of pressure boundary integrity of the Auxiliary Building II&V fans under CLB design loading conditions. [ Reference 2, Attachments 5 and 6]
Group 3 (dynamle loading for fans)- Methods to Manage Aging hiitigntion: Dynamic loading can be mitigated by minimizing the mechani:al loading due to vibration.
The system is designed to minimize vibration by using equipment support isolators and equipment-to-duct isolators, such as flexible collars. Visual inspections during system walkdowns would provide for j
detection of vibration so that corrective actions could be taken to minimize vibration and, thereby, mitigate the effects of dynamic loading. (Reference 2, Attachment 8]
Discoverv : The effects of dynamic loading, e.g., loosened fasteners, can be detected through visual inspections. Periodic visual inspections during system walkdowns would provide for detection of the effects of dynamic loading, as well as vibration problems that can cause this ARDM to occur.
[ Reference 2, Attachment 8]
Group 3 (dynamle loading for fans)- Aging Management Program (s)
Mitigation: System walkdowns provide for periodic visual inspections of the external surfaces of Auxiliary Building Il&V System components. During these walkdowns any vibration problems would be detected so that corrective actions can be taken to minimize the vibration.
[ Reference 2, ] Refer to the discussions below in Discovery for a description of the system walkdowns.
1 Discoverv: Routine inspections are performed on system components in accordance with Administrative Procedure MN 1319. System walkdowns are credited for discovery of the effects of dynamic loading, as well as abnormal or excessive vibration, which can cause dynamic loading to occur. Procedure MN-1-319 requires routine system walkdowns that include visual inspections, reporting the walkdown sesults, and initiating corrective action. Under this procedure, inspection items typically related to aging management include identifying unusual noises and identifying system and equipment stress or abuse, such as excessive vibrations, bent or broken component supports, etc. Conditions identified as adverse to quality are corrected in accordance with the CCNPP Corrective Actions Program. [ Reference 16] The xisting procedure will be modified to include specific inspection items with respect to discovery of inese ARDMs to help ensure they are being adequately managed. Refer to the discussion above in Group i under Aging Management Programs for a detailed discussion of procedure MN-1-319.
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ATTACHMENT (2)
APPENDIX A -TECliNICAL INFORMATION 5.llA - AUXILIAF f HUILDING HEATING AND VENTILATION SYSTEM Group 3 (dynamle loading for fans)- Demonstration of Aging Management Dased on the factoa presented above, the following conclusions can be reached with respect to dynamic loading for all Auxiliary Building Il&V fans:
Auxiliary Building Il&V System fans provide the system pressure retainin<, boundary and their integrity must be maintained under CLB design conditions.
Dynamic loading is a plausible ARDM for the fans due to excessive vibration resulting from fan operation.
if left unmanaged, dynamic loading can result in loosened fasteners, which could lead to loss of e
pressure retaining boundary integrity.
Existing visual inspections will continue to be performed in accordance with modified CCNPP Administrative Procedure MN 1319 to help ensure that these ARDMs are being adequately managed. Signs ofloosened fasteners would be detected during these walkdowns, as well as such conditions as identifying unusual noises or vibration, so that corrective actions can be taken to mitigate this ARDM.
Therefore, there is reasonable assurance that the efTects of dynamic loading for fans will be managed in such a way as to maintain the components' pressure boundary integrity, consistent with the CLD, during the period of extended operation.
5.ll A.3 Conclusion
'Ihe programs discussed for the Auxiliary Building Il&V System are listed in Table 5.ll A 3. These programs are (and will be for new programs) administratively controlled by a formal review and approval process. As has been demonstrated in the above section, these programs will manage the aging mechanisms and their effects such that the intended functions of the components of the Auxiliary Building II&V System will be maintained, consistent with the Cl.D, during the period of extended operation.
The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-2, " Corrective Actions Program." QL-2 is pursuant to 10 CFR Part 50, Appendix D, and covers all structures and components subject to AMR.
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i ATTACIIMENT (2)
APPENDIX A -TECHNICAL INFORMATION 5,llA - AUXILIARY BUILDING HEATING AND VENTILATION SYSTEM Table 5.llA-3 LIST OF AGING MANAGEMENT PROGRAMS FOR THE AUXILIARY BUILDING II&V SYSTEM I Agrass:
Cmdited As '-
yy; 4
31odified CCNPP System Walkdowns Discovery and management of the effects of crevice a
e rr si n, general c rr si n, and pitting for the Administrative Procedure external surfaces of duct and heat exchangers MN-1-319," Structure and (Group 1)
System Walkdowns" Discovery and management of the effects of elastomer Existing procedure will be degradation and wear for the duct flexible collars modified to include specific (Group 2) items with respect to discovery Mitigation of vibration and discovery and management of these ARDMs to help ensure each plausible ARDM is being of the effects of dynamic loading for the fans adequately managed.
(Group 3)
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Discovery and management of the effects of crevice New ARDI Program corrosion, general corrosion, and pitting for the internal surfa.es of duct and heat exchangers (Group 1)
Discovery and management of the effects of elastomer degradation and wear for the surfaces of damper seals (Group 2)
Application for License Renewal 5.11A-21 Calvert Cliffs Nuclear Power Plant
ATTACHMFNT (2)
APPENDIX-A -TECIINICAL INFORMATION 5.llA - AUXILIARY HUILDING HEATING AND VENTILATION SYSTEM
- 5. IIA.3 References 1.
"CCNPP Updated Final Safety Analysis Report," Revision 20 2.
"CCNPP Auxiliary Building and Radwaste H&V System Aging Management Review Report,"
Revision 1, March 21,1997 3.
CCNPP Drawlig No,60722SH0001, " Auxiliary Building Ventilation Systems," Revision 40, January 16,1997 4.
CCNPP Drawing No. 60722SH0002, " Auxiliary Building Ventilation Systems," Revision 36, December 2,1996 5.
CCNPP Drawing No. 60722SH0003, " Auxiliary Building Ventilation Systems," Revision 3, August 29,1996 6.
CCNPP Drawing No. 60723S11000, " Ventilation Systems: Containment, Turbine, and Penetration Rooms," Revision 38, July 12,1996 7.
CCNPP Drawing No. 60625S110015, Service Water lleat Exchanger Room Ventilation,"
Revision 2, November 21,1990 8.
CCNPP Drawing No. 60708SH0002, " Circulating Saltwater Cooling System," Revision 78 November 28,1996 9.
CCNPP Report," Component Level Screening Results for the Auxiliary Building and Radwar.c Il&V System, System No. 032," Revision 2, July 10,1996 10.
CCNPP Engineering Standard ES Oll," System, Structure, and Component (SSC) Evaluation,"
Revision 4, August 27,1996 11.
CCNPP Specification No. 6750-M 196, " Specification for Heating, Ventilating, and Air Conditioning Ducts," Revision 4, June 14,1974 12.
Letter from Mr. L. B. Russell (BGE) to Mr. B. H. Grier (HRC), dated July 18,1980, " Thirty-day Report for Licensee Event Report 80-29/3L" 13.
CCNPP Preventive Maintenance Checklist MPM09021, " Auxiliary Building H&V Damper inspection" 14.
CCNPP Report," Component Pre-Evaluation for the Auxiliary Building and Radwaste H&V System (032)," Revision 1. February 14,1997 15.
CCNPP Engineering Standard ES-014 " Summary of Ambient Environmental Service Conditions", Revision 0, November 8,1995 16.
CCNPP Administrative Procedure MN-1-319," Structure and System Walkdowns," Revision 0, September 16,1997 Application for License Renewal 5.11 A-22 Calvert Clifts Nuclear Power Plant
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j s ATTACHMENT (3) d 4
APPENDIX A - TECIINICAL INFORMATION 5.16 - SALTWATER SYSTEM Baltimore Gas and Electric Company Calvert Cliffs Nuclear Power Plant December 17,1997 -
,s ATTACitMENT 0)
APPENDlX A TECHNICAL INFON.MATION 5.16. SAL 1TATEli SYSTEM f,16 Saltwater System This is a section of the Bahimore Gas and Electric Company GGE) License Renewal Application (LRA), addressing the Saltwater (SW) System. The SW System was esaluated in accordance with the Calvert Cliffs Nuclear Power Pla.,t (CCNPF) Integrated Platt Assessment (IPA) Methodology described in Section 2.0 of the BGE LRA. These sections are prepared independently and will, collectively, comprise the entire LRA.
5.16.1 Scoplug 1
System lesel scoping describes conceptual boundaria for plant systems and structures, develops I
screening tools which capture the 10 CFR 54.4(a) scoping criteria, and then applies the tools to identify synems and st.uctures within the scope of license renewal Component level scopink escribes the d
components within the boundaries of those systems and structures that contribute to the intended ftmetions. Scoping to determine components subject to Aging Management Review (AMR) begins with a listing of passive intended functions and then dispositions the device types as eitner only asseclated with active functions, subject to replacement, or subject to AMR either in this report or another report Section 5.16.l.' presents the results of the system level scoping. 5.16.1.2 the results of the component levtI scoping, and 5.16.l.3 the results of scoping to determine components subject to an AMR.
5.16.1.1 System Level Scoplag 1his section begins with a description of the system that includes the tmundaries of the system as it was scoped. The intended functions of the system are listed and are used to denne what ponlons of the system are within the scope oflicense renewal.
SysicmDsicLpilon!fontsptual floundaries lhe SW System is a safety related system. Each CCNPP unit has three SW pumps that provide the driving head' 9ve SW from the intake structure, through the system, and back to the circulating water discharge coi
. A simplined diagram of the system is provided in Figure 5.161. The system b designed such each pump has suGiclent head and capacity to provide cooling water for the Service Water (SRW) System, Component Cooling (CC) System, and Emergency Core Cooling System (ECCS) pump room air coolers, as required by 10 CFR Part 50, Appendix A.
[ Reference 1. Section 1.1.1; Reference 2]
The SW System in each unit consists of two subsystems. Each subsystem provides SW to a SRW heat exchanger, a CC heat exchanger, and an ECCS pump room air cooler in order to transfer heat from these heat exchangers and coolers to the Chesapeake Bay. Seal water for the circulating water pumps (which supply water to the main condensers) is supplied by both subsystems. [ Reference 1, Section 1.1.1]
During normal operation, both subsystems in each unit are in operation with one pump running on each header and a third pump in standby. If needed, the standby pumps can be lined up to either supply header in their respective units. The SW Oow through the SRW and CC heat e changers is throttled to provide su0icient coo *ing to the heat exchangers, while maintaining total subsystem now below a maximum value. [ Reference 1, Section 1.1.1]
i Application for License Renewal 5.16 1 Calvert Cliffs Nuclear Powsr Plant
ATTACHMENT (3)
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APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM INTAKE STRUCIURE Note-Annemions a e prtmded at
- Circu! sting wa:er Sys:em LA between the SW Sptem end (WSLR-Refer to aber se'stmetures to 'hif BGE LRA Section 33)
- Pump Seals (Not WSLR) the wher systems'stmetures are within the scope oflicense renewal (%3LR) at the interface point only.
Saltwater 11 Pump (21)
SRW SRW IIEAT HEAT EXOIANGER EXOIANGER 12(22) 11(21) 7 4
7 4
sRwse sRwsys
@sLR-Refer as (wstA. Refer 3, BGELRA BGELRA y
1 5"'"" ' ' D Saltwater 12 Pump (22)
CC Cc HEAT HEAT EXOIANGER EXOIANGER 12(22)
II(21)
T 4
7 4
cc sys:e.,
cc sys==
(wsta. Rerer s.
msta-Re*r t.
BGE LRA BGELAA Saltww 13 Pump (23)
ECCS ECCS PUMP ROOM l' UMP ROOM AIR COOLER AIR COOLER I? 22) 1I(21)
I Aet Bkig A I I Aus Bidg. E I Hestmg & Vent. Sysica IMeg & Veit system (WsLR-Referto (R3LR -Refer to BGE1RA BGEIM o
Sertum i'I A) section 5 II A) pg ggj Discharge FIGURE S.161 Normal DM-p CCNPP SALTWATER SYSTEM Circulatmg hater Sptem DM-g Conduits (SIMPLIFIED DIAGRAM - FOR INFORMATION ONLY)
(Nct WSLR)
Application for License Renewal 5.16-2 Calvert Gifts Nuclear Power Plant
5 4
AITAC11AILhT_D)
APPENDIX A TECilNICAL INFORMATION 5.16. SALTWATER SYSTEM Operation following a loss-of-coolant accident has two phases: before the Recirculation Actuation Signal (RAS) and after the RAS. One subsystem can satisfy the cooling requirements of both phases.
[ Reference 1 Section 1.1.1]
After a loss-of-coolant accident but before a RAS, each subsystem will cool an SRW heat exchanger and an ECCS pump room air cooler. Flow to the ECCS pump room air cooler is initiated only if required due to high room temperature. The minimum required SW Oow is 16,830 gpm to each SRW heat exchanger, and 400 gpm to each ECCS pump room air cooler. There is no now to the CC heat exchangers. System now is not throttled. [ Reference 1, Section 1.1.1; Reference 3]
When a RAS occurs, the minimum required How to each SRW heat exchanger is reduced to 9,500 gpm, and each ECCS pump room air cooler remains at 400 gpm. Flow is restored to the CC heat exchangers at a minimum required amount of 5,500 gpm each. System now is throttled for this phase. [ Reference 1 Section 1.1.1]
In denning the scope of the SW System evaluation, an exception was made to the boundary convention.
The SRW and CC heat exchangers are included in the scope of this evaluation even though heat exchangers are nnrmally considered part of the systems they cool. This exception was made because age related degradation is much more severe on the SW side of the heat exchangers. [ Reference 1, Section 1.1.2]
t Optrating Exnedentc; Representative historical operating experience pertinent to aging is provided in this section and other appropriate sections to provide insight supporting the aging management demonstrations. This operating experience was obtained through key word searches of BGE's electronic database of information on the CCNPP dockets, and through documented discussions with currently assigned cognir. ant CCNPP personnel.
During the 1984 CCNPP Unit 2 refueling outage, two through wall holes occurred during work on the SW side of one CC heat exchanger channel head in preparation for coal tar epoxy application. The CC heat exchanger through wall attack w.s attributed to graphitic corrosion. A visual examination was subsequently conducted on the operating Unit I CC and SRW heat exchanger channel heads. Two of the CC heat exchangers had three areas with apparent through wall weepage. Unit I was then shut down and all CC and SRW heat exchangers were examined. Due to the size, location, and numb.r of areas found below minimum wall on the channel heads, several repairs or channel head replacements were made. All CC and SRW heat exchanger channel heads were coated with coal tar epoxy to prevent future corrosion.
These graphitic corrosion problems were the subject of NRC Information Notice No. 84 71. As shown in Table 5.16-4, the current design for Gese heat exchangers uses neoprene rubber linings in the channel heads rather than the coal tar epoxy coating used previously. [ References 4 and $]
1he SW System has experienced through wall pressure boundary failures of carbon steel aboveground piping lined with concrete, including occurrences in 1984 and 1991. The cause of the failures was due to failure of the concrete lining and subsequent corrosion of the bare metal exposed to SW. A modification has-been performed to replace the aboveground concrete-!'-4 niping with rubber lined piping.
[ References 6 and 7]
Application for License Renewal 5.16-3 Calvert Cliffs Nuclear Power Plant
ATTACHMFNT d) i APPENDIX A TECHNICAL INFORMATION 5.16. SAllrWATER SYSTEM In 1990, a pin hole leak was observed in the discharge piping of one of the Unit i SW pumps. The cause I
of the leak was localized corrosion of an inner weld connecting a slip-on flange to the pipe and localized i
corrosion of the pipe between welds.1he corrosion occurred because of the failure of the grout lining l
that was applied during construction to protect Geld welds Corrective actions included inspection of other Danges in the SW System. Grout fining dc0ciencies were found on other flanges and, in each case, t
the grout was removed and replaced with an epoxy. type lining. [ References 8 and 9) 1he SW side of the SRW heat cul' angers has experienced crosion corrosion in the past. During the
[
spring 1994 Unit I re% ling nage,140 plugged tubes were replaced in the No.11 SRW heat exchanger. These tubes ad previously been plugged due to leakage. During the replacement, it was n
discovered that there was severe tube wall thinning in the utst three to four inches of the inlet end of the
~
tubes. Tube damage was apparently caused by crosion corrosion on the tube side. Further inspection indicated that similar damage was widespread in both the No.11 and 21 SRW heat exchangers. This problem was temporarily addressed by installing sleeves in the inlet end of the tubes. The existing heat exchangers also have experienced degraded thennal performance due to fouling. These problems have required frequent cleaning of the heat exchangers, which restricts operational Ocxibility. Due to the crosion corrosion and thermal perfonnance problerns, BGE plans to replace the existing tube and shell SRW heat exchangers with new plate and frame heat exchangers having increased thermal performance i
capability. The materials thosen for the new heat exchangers (litanium for the plates and EPDM
/ Ethylene Propylcnc Dienc Monomer) for the gaskets) and the method by which they will be assembled will provide deterrence to the crosion corrosion problem that damaged the existing heat exchange.s.
[ Reference 3]
Nuclear Regulatory Commission Generic 1 etter 8913 outlined concerns regarding the safe operation and maintenance of open-cycle cooling water systems. For CCNPp Units I and 2, the open cycle cooling water system in the scope of Generic Letter 8913 is the SW System, in response to Generic Letter 8913. HGE committed to establishing a routine inspection and maintenance program for the SW piping and components to ensure that corrosion, erosion, protective coating failure, sitting, and biofouling cam.ot degrade system performance. Specine actions completed by DGE are as follows:
[ Reference 10]
DilTerential prescure across cach SRW heat exchanger is monitored twice per shifl. The SRW e
heat exchangers and the CC heat exchangers ere bulleted periodically, lhe program for cleaning and inspecting the SRW, CC, and ECCS heat exchangers was e
established.
The piping ultrasonic thickness inspection program was reviewed and revised.
An underground piping inspection program was established.
System hiterfaces The SW System interfaces with the following systems: [ Reference 2; Reference 11, Section 9.5.2.3]
Auxiliary Building IIcating and Ventilation System (ECCS pump room air coolers);
e Application for License Renewal 5.164 Calvert Cliffs Nuclear Power Plant
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t i
c, ATTACliME_NT_M)
APPENIHX A - TECHNICAL INFORMATION 5.16 SALTWATER SYSTEM Circulating Water System; e
Compressed Air System; and
[
e I
Engineered Safety Features Actuation System.
e Interfaces in the major now path are indicated on Figure 5.161.
Sy stem Scoping Results
%e SW System is in scope for license renewal based on 10 CFR $4.4(a). De following intended functions of the SW System were determined based on the requirements of 654.4(a)(1) and (2) in accordance with the CCNPP IPA Methodology Section 4.1.1 (Reference 12, Table 1]
Provide the vital auxiliary function of supplying cooling water to the CC and SRW llent e
Exchangers and the ECCS Pump Room Air Coolers during design basis events; To maintain the pressure boundary of the system (liquid and/or gas);
To maintain electrical continuity and/or provide protection of the electrical system; and To restrict flow to a speciHed value in support of a design basis event response.
e De following intended functions of the SW System were determined based on the requirements of
$54.4(a)(3): [ Reference 12 Table 1]
For environmental qualincation (10 CFR 5').49)
To maintain functionality of electrical e
components as addressed by the Environmental Qualification Program; For iire protection (10CFR 50.48) To provide the ultimate heat sink for the SRW and CC e
Systems to ensure safe shutdown in the event of a postulated severe fire; and For post.accidert monitoring To provide information used to assess the environs and plan',
condition during and after an accident.
5.16.1.2 Component Level Scoping 13ased on the intended functions listed above, the portion of the SW System that is within the scope of license renewal includes the components (electrical, mechanical, and instrumentation) and their suppons along the system Howpath shown in Figure 5.161. These components include the SW pumps and motors, the SRW and CC heat exchangers, the ECCS pump room air coolers, the basket strainers located upstream of the ECCS pump room air coolers, air aceumulators for control valves, and the associated piping, valves, instruments, and controls. [ Reference 1, Section 1.1.2; Reference 2; Reference 12, Table 2)
A total of 40 du he types within the SW System were designated as within the scope oflicense renewal because they have at least one intended function: These device types are listed in Table 5.16-1.
[ Reference 1. Table 21. Attachment 3s]
Al plication for License Renewal 5.16-5 Calvert Cliffs Nuclear Power Plant
s AIIACilMENT (3)
APPENDIX A
'!ECilNICAL INFORMATION 5.16 SALTWATER SYSTEM TABLE 5.161 SW SYSTEM DEVICE TYPES WITillN Tile SCOPE OF LICENSE RENEWAL Device Code Device Description Device Code Device Description
.JE2 Red Ilrass Piping LY Level Relay
.JO I 70 30 Copper Nickel Piping MA 4kV Motor LC2 Cast Iron or Carbon Steel Piping with MOV Motor Operated Valve Cement Mortar Lining LJi Carbon Steel Piping with Neoprene NA 4kV Local Control Station Lining MC6 Carbon Steel Piping with Saran or PCV Pressure Control Valve Neoprene Lining
.MC8 Carbon Steel Piping with Kynar PD1 Differential Pressure Indicator
^
Lining ACC Accumulator PDIS Differential Pressure Indicating Switch IIS Basket Strainer Pl Pressure indicator CKV Check Valve PS Pressure Switch Coll Coil 7T Pressure 'Iransmitter CV Control Valve PUMP Pump / Driver A'ssembly FO Flow Orifice RV Relief Valve FU Fuse RY Relay lilC lland Indicator Controller SV Solenoid Valve ils lland Switch TI Temperature Indicator ilV lland Valve TP Temperature Test Point ilX llent Exchanger TS Temperature Switch 1/P Current to Pneumatic Transducer XJ Expansion Joint 11 Ammeter ZL Position Indicating Lamp JL Power Indieniing Lamp ZS Position Switch in addition, some components within the scope of license renewal are common to many plant systems and perform the same passive functions regardless of system. *lhese components are not included in the above table and are as follows:
Structural supports for piping, cables and components; Electiical cabling; and Instrument lines (i.e., tubing and small bore piping), and the associated tubing supports, instrument valves (e.g., equalization, vent, drain, isolation), and fittings.
Application for License Renewal 5.16-6 C.dvert Cliffs Nuclear Power Plant
glTACllMFNT d)
APPENDIX A TECilNICAl, INFORMATION 5.16. SALTWATER SYSTEM 5.16.I.3 Cosmponents Subject to AMR
'this section describes the components within the SW System that are subject to AMR. It begins with a listing of passive intended functions and then dispositions the device types as either only associated with active functions, subject to replacement, evaluated in other system reports, evaluated in commodity reports, or remaining to be evaluated for aging management in this section.
Paulve Intendedfunctions in accordance with CCNpP IPA Methodology Section $.1, the following SW System functions were determined to be passive: (Reference 1. Table 3 1)
To maintain the pressure bounds of the system (liquid and/or gas);
[
e To maintain electrical continuity andier provide protection of the electrical system nd
]
To restrict flow to a specified value in support of a design basis event.
e
- Dnicclges Subject to AME Of the 40 device types within the scope oflicense renewal shown in Table 5.161:
Fourteen device types (Coil, ruse, lland Indicator Controller, lland Switch, Ammeter, Power e
-Indicating Lamp, Level Relay,4 LV Motor, Motor Operated Valve,4 kV Local Control Station, Relay, Temperature Switch, Position Indicating Lamp, Position Switch) only have active intended functions. [ Reference 1 Table 3 2j.
One device type (Expansion Joints)is subject to periodic replacement. Some current / pneumatic transmitters and so no solenoid valves are also subject to periodic replacement. [ Reference 1 Table 3 2; Reference 13, Attachment 2]
Five device types (Differential Pressure Indicator, Differential Pressure Indicating Switch, e
Pressure Switch, Pressure Indicator, Pressure Transmitter) are evaluated in the instrument Lines Commodity Evaluation in Section 6.4 of the BGE LRA. [ Reference 1 Table 3 2]
The remaining 20 device types, listed in Table 5.16 2, are subject to AMR and are included in the scope of this report. Unless otherwise annotated, all components of each listed type are covrred. [ Reference 1 Table 3 2, Attachment 3s)
~
Application for License Renewal 5.16 7 Calvert Cliffs Nuclear Power Plant
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ATTAC11 MENT D)
APPENDIX A TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM l
TABLE 5.16 2 SW SYSTEM DEVICE TYPES REQUIRING AMR Device Code Device Deteription DeviceCode
- Device Description JE2 _ Red Brass Piping FO Flow Orifice
.J01 70 30 Copper Nickel Piping flV lland Valve'
.LC2 Cast Iron or Carbon Steel Piping with IlX liest Exchanger Cement Mortar Lining
.LJ1 Carbon Steel Piping with Neoprene 1/P Current to Pneumatic Transducer" Lining MC6 Carbon Steel Piping with Swan or PCV Pressure Control Valve Neoprene Lining MC8 Carbon Steel Piping with Kynar PUMP Prmp/ Driver Assembly Lining ACC-Accumulator RV RellefValve ils llasket Strainer SV Solenoid Valve" CKV Check Valve TI Temperature Indicator CV Control Valve TP Temperature Test Point' Instrument line manual drain, equalization, and isolation valves and some temperature test points in the SW System that are subject to AMR are evaluated for the elTects of aging in the instrument Line Co imodity Evaluation in Section 6.4 of BGE LRA. Instrument line manual root valves and the rem ining temperature test points are evaluated in this report. [ Reference 13, Attachment 4A]
" Some current / pneumatic transmitters and some solenoid valves are subject to periodic replacement.
[Refeience 13, Attachment 2)
Some components in the SW System are common to many plant systems and perform the same passive function regardless of system (i.e., structural supports, electrical cabling, and instrument lines as discussed in Section 5.16.1.2 above). Therefore, these components are not included in the 40 SW System device types discussed above, and they were evaluated as follows:
Stmetural supports for piping, cables and components in the SW System that are subject to AMR
.are evaluated for the effects of aging in the Component Supports Commodity Evaluation in Section 3.1 of the BGE LRA.
Electrical cabling for components in the SW System that are subject to AMR are evaluated for the elTects of aging in the Electrical Cables Commodity Evaluation in Section 6.1 of the BGE LRA.
'Ihis commodity evaluation compictely addresses the SW System passive intended function, "To maintain electrical continuity and/or provide protection of the elect-ical system."
Instrument lines (l.c., tubing and small bore piping), and tiec associated tubing supports, e
instrument valves (e.g., equalization, vent, drain, isolation), and fittings for components in the SW System that are subject to AMR are evaluated for the effects of aging in the instrument Lines Commodity Evaluation in Section 6.4 of the BGE LRA. This commodity evaluation addresses the SW System passive intended function, "To maintain the pressure boundary of the system (liquid and/or gas)" for instrument lines, and the associated supports, instrument valves, and fittings.
! Application for License Renewal 5.16-8 Calvert Cliffs Nuclear Power Plant
i I
ATTACHMENT (3)
I APPENDIX A TECHNICAL INI'ORMATION 5.16. SALTWATER SYSTEM De only passive functions associated with the SW System that are not completely addressed by one of r
the commodity evaluations discussed above are:
To inaintain the pressure boundary of the system Osc,uld and/or gas); and To restrict flow to a specified value in suppon of a design basis event.
Therefore, only the two functions listed above for the 20 device types listed in Table 5.16 2 are addressed by the remainder of this section.
llaltimore Gas and Electric Company may elect to replace components for which the AMR identifies further analysis or examination is needed. In accordance with the License Renewal Rule, components subject to replacement based on qualified life or specified time period would not be subject to AMR.
5.16.2 Aging Management The list of potential Age-Related Degradation Mechanisms (ARDMs) identified for the SW System con ponents is given in Table 5.16 3, with plausible ARDMs identified by a check mark (/) in the appropriate device type column. [ Reference 1, Tables 41 and 4 2] A check mark indicates that the ARDM applies to at least one component for the device type listed. For efficiency in presenting the results of these evaiuations in this report, ARDM/ device type combinations are grouped together where there are similar characteristics and the discussion is applicable to all components within that group.
Exceptions are noted where appropriate. Table 5.16 3 also identifies the group to which each ARDM/ device type combination belongs. He following groups have been selected for the SW System:
Group 1 - includes device types without internal lining subject to crevice corrosion, general carrosion, microbiologi.: ally induced corrosion (MIC), and pitting.
Group 2 includes device types with internal lining subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, paniculate wear crosion, pitting, and clastomer degradation.
Group 3 Includes device types with air internal environments subject to general corrosion.
Group 4. Includes the CC and SRW heat exchangers subject to crevice corrosion, erosion corrosion, general corrosion, MIC, pitting, and elastomer Mradation.
Group 5 - Includes the ECCS pump room air coolers subject to crevice corrosion, general corrosion, MIC, and pitting.
Group 6 includes flow orifices subject to crevice corrosion, crosion corrosion, MIC, particulate wear crosion, and pitting.
Application for License Renewal 5.16-9 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (3)
APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATER SitMM TABLE 5.16-3 POTENaIAL AND PLAUSIBLE ARDMs FOR THE SW SYSTEM Potential ARDMs Device T3 pes
-JE
-Ki
-LC
-U
Pt.V R&F RV SV U
.1F fue Flausible -
for svinne Cavstauon Corro90n x
Corrosmo Faurue x
Crevice Corrosion
- (1)
<(I)
- C)
- C)
<C)
<C)
<( t. 2)
<( t. 2)
<(6)
<(I. 2)
<(4. 5)
<C)
<(I)
<(tI
<(1)
Dynamic Leadurg x
Elastomer Degradauon
<C)
<C)
<(2)
- C)
- 44)
Ucctncal Stressors x
Erosson Corronon
<(6)
<(4)
Fatigue x
Foulmg x
Galvanic Corresum
<C)
< C)
<(2)
- C)
<(2)
< C)
- C)
< C)
General Corrosion
<(I)
<C)
<C)
<C)
<Op
- C)
<c.3)
<(2.3)
<(4. 5)
<On
<C)
<(1)
Ilydrogen Damage x
Intergranular Attack x
<(1)
/(I)
<C) em
- C)
< C)
/(1. 2)
<(1,2)
<(6)
<( t. 2)
<(4. 5)
< C)
<(1)
<(t)
<(1)
Oxidauon x
Particulate Wear Lrosion
<(2)
<t6)
Pittmg
<(1)
<( t )
< C)
<C)
- C)
- C)
<(i. 2)
<( t. 2)
<(6)
- (1. 2)
<(4.5)
< C)
<(t) ett)
<(1)
Radianon Damage x
Salme Water Attack y
Selective Leaching x
Stress Corrosion Crximg x
Thermal Damage x
1herrna! Embrittlement x
O car e
x
/ - indicates plausible ARDM determinsuon
(#) - indicates the gmup(s) in which the AR~)Wdevice type combmauon is esaluated Application for Lice.se Renewal 5.16-10 Calvert Clifts Nuclear Power Plant
ArrACllMEYr d)
APPENDIX A TECilNICAL INFORMATION 5.16 - SALTWATER SYSTEM 1he following is a discussion of the aging management demonstration process for each group identified above. It is presented 17 group and includes a discussion of mh;erials and environment, aging mechanism efTects, methods to managing aging, aging management program (s), and aging management demonstration.
Group 1 (Device types without laternal lining subject to crevice corrosion, general corrosion, MIC, and pitting). Materials and Environment As shown in Table 5.16 3, Group 1 applies to device types JE, JG, CKV, CV, llV, RV, TI, and TP that are subject to crevice corrosion, general corrosion, MIC, and pitting.
Group I consists of piping, valves, temperature indicators, and temperature test points without any lining on their internal surfaces. [ Reference 1. Attachment 1 for Group lDs JE 01, JG 01, CKV 01, CV 05, IIV 01/02/03/06/07/10/11 RV 01,1101,TP 01)
' All of the G.oup 1 components have the passive intended function to maintain pressure boundary integrity. [ Reference 1 Attachment 1]
'the internal environment for all of the Group I components is SW. [ Reference I, Attachment 3s]
Crevice corrosion, MIC, and pitting are plausible for each of the Group I device types. One or more of these ARDMs are plausible for the metal internal subcomponent parts that are exposed to the process fluid (i.e., SW). General corrosion is only plausible for Group I device types JG and TP Crevice corrosion, pitting, and/or general corrosion are plausible for metal external subcomponent parts (e.g., bolting) that may be exposed to leakage of the process fluid.
[" crence 1, Attachment 1 s,5s, and 6s]
The materials of the Group I components subjcct to plausible crevice corrosion, MIC, and pitting include: red brass,70-30 copper nickel, bronze, stainless steel, and monel. The Group 1 components subject to general corrosion include bolting constructed of low alloy steel and carbon steel.
[ Reference 1. Attachment 1, Attachment 4s and 5s]
Group 1 (Device types without internal lining subject to crevice corrosion, general corrosion, MIC, and pitting). Aging Mechanism Effects Crevice corrosion is intense, localized coi.osion within crevices or shicided areas, it is associated with a small volume of stagnant solution caused by holes, gasket surfaces, lap joints, crevices under bolt heads, and other mechanicaljoints that have a crevice geometry. The crevice must be wide enough to permit liquid entry and narrow enough to maintain stagnant conditions, typically a few thousandths of an inch or less Crevice corrosion is closely related to pitting corrosion and can initiate pits (i..., loss of material) in many cases. In an oxidizing environment, a crevice can set up a differer.tial aeration cell to concentrate an acid solution within the crevice. Even in a reducing environment, ahernate wetting and drying can concentrate aggressive ionic species to cause pitting and crevice corrosion. (Reference 1, Attachment 7s]
Pitting is a form of localized attack with greater corrosion rates at some locations than at others. This form of corrosion essentially produces holes of varying depth to diameter ratios in the metal. These pits Application for License Renewal 5.16-11 Calvert Cliffs Nuclear Power Plant
ATTACHMENT (3)
APPENDIX A - TECHNICAL IN OPMATION 5.16 - SALTWATER SYSTEM are, in many cases, alled with oxide debri, especially in ferritic materials such as carbon steel. liigh concentrations of impurity anions such as chlorides and sulfates tend to concentrate in the oxygen depleted pit region, giving rise to a potentially concentrated aggressive solution in this zone.
[ Reference 1, Attachment 7s]
General corrosion is the thinning (wastage) of a metal by chemical attack (dissolution) at the surface of the metal by an aggressive environment. He consequences of the damage are loss of load-carrying cross sectional area. General corrosion requires an aggressive environment and materials susceptible to r
that environment. [ Reference 1 Attachment 7s)
Microbiologically induced corrosion is accelerated corrosion of materials resulting from surface microbiological activity. Sulfate-reducing bacteria, sulfur oxidizers, and iron oxidizing bacteria are most commonly associated with corrosion effects. This ARDM most often results in pitting, followed by excessive deposition of corrosion products. Stagnant or low How areas are most susceptible, and sedimentation aggravates the problem. Any system that uses untreated water, or is buried, is particularly susceptible. Consequences range from leakage to excessive differential pressure and now blockage.
Essentially all systems and most commonly used materials are susceptible. Temperatures from about 50*F to 120'F are most conducive to MIC. [ Reference 1, Attachment 7s]
Crevice corrosion and pitting are plausible for the internal metal surfaces of the Group 1 components since they are subjected to an aggressive SW environment. The components are susceptible to pitting and crevice corrosion due to the presence of sulfates and chlorides. Dissolved oxygen and stagnant Culd aggravates the pitting. [ Reference 1. Attachment 6s)
General corrosion, crevice corrosion, and pitting are plausible for bolting of the Group I components.
Although the bolting is not exposed to the process Guid, the potential for leakage of brackish water from the system onto the bolts exists. [ Reference 1, Attachment 6s]
Microbiologically induced corrosion is plausible for the internal metal surfaces of the Group I comynents due to the use of raw, untreated SW, Sulfate-reducing bacteria, sulfur oxidizers, and iron-oxidizing bacteria may be present in the process Guid. [ Reference 1, Attachment 6s]
These aging mechanisms, if unmanaged, could eventually result in a loss of material such that the Group I components may not be able to perform their pressure boundary function under current licensing basis (CLD) conditions.
. Group 1 (Device types without laternal lining subject to erevice corrosion, general corrosion, MIC, and pitting). Methods to Manage Aging Mitigation: Corrosion can be mitigated by design through the proper selection of materials. He occurrence of corrosion is expected to be limited, and is not likely to affect the intended function of components constructed of corrosion resistant materials such as brass, bronze, copper nickel alloys, and stainless steel developed for SW service. Therefore, there are no additional mitigation measures deemed practical. The discovery activities discussed below are deemed adequate to manage aging for the Group 1 components. [ Reference 1,Machment 8]
Application for License Renewal 5.16 12 Calvert Cliffs Nuclear Power Plant
4 0
ATTACHMENT 0)
APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM Discovery: Visual inspections of representative components can be used to provide assurance that slyni5 cant corrosion is not occurring for the Group I components. If any significant degradation is found, appropriate corrective actions can be taken to ensure that the components will continue to perform their intended functions during the period ofextended operation. [ Reference 1, Attachment 8]
Group 1 (Devlee types without laternal lining subject to erevice corrosion, general corrosion, MIC, i
and p! sting). Aging Management Program (s)
Mitiption: Since there are no mitigation measures deemed practical, there are no programs credited with mitigating aging for the Group 1 components.
Discos erv: To verify that no significant crevice corrosion, general corrosion, MIC, or pitting is occurring on the Group 1 components, a new plant program will be developed to provide inspections of representative components. The program is considered an Age Related Degradation Inspection (ARDI)
Program as defined in the CCNPP IPA Methodology (reference Section 2.0 of the BGE LRA). The b
h
- program details are provided elow. [ Reference 1, Attac ment 1 for Group ids JE-01, JG-01, CKV 01, CV 05,ilV 01/02/03/06/07/10/ll, RV 01,T101, TP 01]
AEDI Prostam The elements of the ARDI Program will include:
Determinstion of the exsmination sample size based on plausible aging effects; Identification ofinspedion locations based on plausible aging efTects and consequences ofloss of e
component intended function; Determination of examinatica techniques (including acceptance criteria) that would be effective, e
considering the aging effects for which the component is examined; Methods for interpretation of examination results; e
Methods for resolution of adverse examination findings, including consideration of all design e
loadings required by the CLB and specification of required corrective actions; and Evaluation of the need for follow up examinations to monitor the progression of any age-related degradation.
Any corrective actions that are required will be taken in accordance with the CCNPP Corrective Actions Program, QL-2, and will ensure that the Group 1 components remain capable of performing their passive intended functions under all CLB conditions.
Group 1 (Devlee types without internal lining subject to erevice corrosion, general corrosion, MIC, and pitting)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to the
- Group I components:
The Group I components have the passive intended function to maintain pressure boundary integrity under CLB conditions.
Application for L! cense Renewal 5.16-13 Calvert Cliffs Nuclear Power Plant
ATTACllMENT W APPENDIX A TECHNICAL INFORMATION 5.16. SALTWATER SYSTEM Crevice corrosion, general corrosion, MIC, and pitting are plausible for the Group I components which, if unmanaged, could eventually result in loss of material such that the components may not be abic to perform their presst,rc boundary function under CLB conditions.
He ARDI Program will conduct inspections of representative components to discover the effects of crevice corrosion, general corrosion, MIC, and pitting, and will contain acceptance criteria that ensure corrective actions will be taken such that the components remain capable of performing their passive intended functions under all CLB conditions.
Therefore, there is reasonable assurance that the effects of crevice corrosion, general corrosion, MIC, and pitting will be managed for the Group I components such that they will be capable of performing their intended ftmetions, consistent with the CLD, during the period of extended operation.
Group 2 (Device types with internal lining subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear erosion, pitting, and elastomer degradation) - Materials and Environment As shown in Table 5.16 3, Group 2 applies to device types -LC, LI, -MC, DS, CKV, CV, ilV, and PUMP that are subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear crosion, pitting, and clastomer degradation.
Group 2 consists of piping, basket strainers, valves, and pumps.,ith lining on their internal surfaces.
[ Reference 1. Attachment I for Group ids LC 01, LJ 01, MC 01, BS-01, CKV 02, CV-03/04, HV 04/05, PUMpOl]
All of the Group 2 components have the passive intended function to maintain pressure bounda y integrity. [ Reference 1, Attachment 1]
%e internal environment for all of the Group 2 components is SW. Most of the device type LC piping is below ground (i.e., external environment is soll). The external surfaces of the buried piping is protected from the soil per standard industry practice with a multiple layer wrap and enamel coating.
[ Reference 1, Attachment 3s, Attachment 6 for Group ID LC-Ol]
The Group 2 components are lined to protect the underlying metal surfaces from the aggressive SW environment. The metal surfaces can potentially be subjected to the SW environment in locations where the lining has failed. The Group 2 lining materials include: cement mortar, neoprene, saran, kynar, Deliona (brand name), Tuboscope (E and name), Buna N, natural rubber, hard rubber, polypropylene, and coal tar epoxy. The underlying metal materials include: cast iron, ductile iron, cast steel, and carbon steel. (Reference 1 Attachment 1]
Crevice corrosion, galvanic corrosion, MIC, and pitting are plausibic for each of the Group 2 device types. One or more of these ARDMs are plausible for the metal internal subcomponent parts that could be exposed to'the SW process fluid if the lining failed. Crevice corrosion, galvanic corrosion, MIC, and pitting are also plausible for the external surfaces of the buried piping that could be exposed to soil if the coating failed. Crevice corrosion, pitting, and general corrosion are plausible far metal external parts
-(e.g.,botting, can screws) that may. be exposed to leakage of the process fluid. The materials of the
= Application for License Renewal 5.16 14-Calvert Cliffs Nuclear Power Plant
[
a ATTACHMENT _R)
APPENDIX A - TECHNICAL INFORMATION 5.16 - SAI:TWATER SYSTEM Group 2 components subject to general corrosion include low alloy steel and carbon steel. [ Reference 1,. Attachment 4s, $s, and 6s]
Particulate wear erosion is only plausible for the Group 2 siping with cement mortar lining. Elastomer degradation is plausible for Group 2 components with lining constructed of neoprene, Buna N, natural rubber, and hard rubber. [ Reference 1, Attachment 4s,5s, and 6s)
Group 2 (Device types with laternal lining subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, partkulate wear erosion, pitting, and elastomer degradation)- Aging Mechanism Effecta The aging mechanism effects for crevice corrosion, general corrosion, MIC, and pitting are as discussed
~ bove for Group 1.
a Galvanic corrosion is an accelerated corrosion caused by dissimilar metals in contact in a conductive solution. Galvanic corrosion requires two dissimilar metals in physical or electrical contact, developed potential (material dependent), and conducting solution. (Reference 1 Attachment 7s]
Pnticulate wear crosion is loss of material caused by mechanical abrasion due to relative motion between the solution and material surface. This mechanism requires high velocity Huld and entrained particles, and turbulent How regions, How direction change, and/or impingement. Most materials are susceptible to varying degrees depending upon the severity of the environmental factors. (Reference L s]
Elastomers may degrade over time due to extended exposure to light, heat, oxygen, ozone, water, or radiation. When an elastomer ages, there are three mechanisms primarily involved: [ Reference 1 s]
Scission - The process of breaking of molecular bonds, typically due to ozone attack, ultraviolet light, or radiation; Crosslinking The process of creating molecular bonds between adjacent long-chain molecules, e
typically due to oxygen attack, heat, or curing; and Compound ingredient evaporation, teaching, mutation, etc.
e Scission and crosslinking have a major impact on physical property changes in clastomers. Scission results in increased clongation, decreased tensile strength, and decreased modulus. Crosslinking results in changes opposite to scission, i.e., decreased elongation, increased tensile strength, and increased modulus. For piping liner applications, clastomers are bonded to the inside surface of the pipe to prevent cortosive fluids from coming in contact with piping material. ' Piping liner debonding may occur if incorrect practices occurred during liner application. Piping liner debonding and degradation may result in failure of the clastomer material and allow the process fluid to come in contact with the underlying metal piping. [ Reference 1 Attachment 7s]
As discussed in the Materials and Environment section above, the Group 2 components are lined to protect the underlying metal surfaces from the aggressive SW environment. The internal metal surfaces of the Group 2 components are susceptible to locallied SW corrosive attack (l.c., crevict: corrosion and Appiication for Licem Renewal 5.16-15 Calvert ClitTs Nuclear Power Plant
ATTACilMENT d)
APPENDIX A TECHNICAL INFORMATION 5.16. SALTWATER SYSTEM pitting) in the event that there is lining failure. Galvanic corrosion (e.g.,at an interface between a stainless steel thennowell and a carbon steel pipe) and MIC (e.g., due to bacteria in the SW) may also be a concem at locations ofdamaged lining. [ Reference 1. Attachment 6s]
Crevice corrosion, galvanic corrosion, MIC, and pitting are plausible (although not likely) for the external surfaces of the buried piping (device type LC) if the protective coating falls. Ilowever, SW inside the piping is a more aggressive environment than the homogeneous soll conditions that exist under the Turbine Building where the piping is located, in addition, the impressed current cathodic protection system and the site grounding grid provide some protection from galvanic and stray current corrosion on the external surfaces. Thus, corrosive attack is considered much more likely on the interior of the piping than on the exterior. [ Reference 1. Attachment 6 for Group ID LC 01)
General corrosion, crevice corrosion, and pitting are plausible for the bolting and cap screw subcomponents of the Group 2 components. Although these extemal subcomponents are not exposed to the process fluid, the potential for leakage of SW from the system exists. [ Reference 1. Attachment 6s]
Particulate wear crosion is plausible for Group 2 piping with cement mortar lining. The lining is susceptible to deterioration from chemical attack by SW on concrete hydration products, alkall. aggregate expansion, and abrasive wear (crosion) due to entrained particles in the SW. Cement mortar lining failure will result in exposure of the underlying metal piping surfaces to locallred corrosive attack.
[ Reference 1, Attachment 6 for Group lD LC-01)
Elastomer degradation is plausible for Group 2 components with lining constructed of neoprene, Iluna N, natural rubber, and hard rubber due to the combined effects of scission, crosslinking, and changes associated with compound ingredients. Significant degradation is not expected due to the service conditions, liowever, lining failure svill result in exposure of the underlying metal component surfaces to localized corrosive attack. [ Reference 1. Attachment 6s]
1hese aging mechanisms, if unmanaged, could eventually result in a loss of material such that the Group 2 components may not be able to perfonn their pressure boundary fimetion under CLB conditions.
Group 2 (Device types with laternal lining subject to crevice corrosion, gelvanic corrosion, general corrosion, MIC, particulate wear crosion, pitting, and elastomer degradation). Methods to Manage Aging Mitigation; 1he effects of cievice corrosion, galvanic corrosion, general corrosion, MIC, and pitting for the Group 2 components are mitigated by design, I y protecting the inner surfaces of the components with co,rosion resistant linings. The lining provides physical separation of the susceptible metal surfaces from the aggressive SW environment.
The effects of crevice corrosien, galvanic corrosion, MIC, and pitting on the extemal surfaces of the buried piping are mitigated by design, by protecting the external surface with a protective coating. The coating provides physical separation of the susceptible metal piping from the soil, in addition, the impressed current cathodic protection system and the site grounding grid provide some protection from galvanic and stray current corrosion on the external surfaces. No other aging management methods are deemed necessary for managing galvanic corrosion on the external surfaces of the buried piping.
Application for License Renewal 5.16-16 Calvert Cliffi Nuclear Power Plant
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ATTACHMENT Q)
APPENDIX A - TECHNICAL INFORMATION t
5.16. SALTWATER SYSTEM Since particulate wear erosion of the Group 2 cement mortar lined piping is caused by mechanical abrasion due to entrained particles in the SW process flow, there are no reasonable methods to mitigate its effects. Similarly, since clastomer degradation of the Group 2 lined surfaces is caused by exposure of susceptible materials to environmental conditions tl.at are not feasible to control (e.g., heat, oxygen, water, ozone), there are no reasonable methods to mitigate its effects. The discovery methods discussed i
below are deemed adequate to manage these ARDMs.
Discovuya The occurrence of corrosion is expected to be limited and not likely to affect the intended function of the Group 2 components so long as their corrosion resistant linings remain intact. Visual inspections can be performed for signs of liner degradation and corrosion. If significant dgradation is found, appropriate corrective actions can be taken to ensure that the components continue to perfonn their intended functions during the period of extended operation. [ Reference 1, Attachment 8)
Group 2 (Device types with internal lining subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear erosion, pitting, and elastomer degradation) - Aging Management Program (s)
Mu6 tion:
For crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting, the mitigation measures are provided by design features (i.e., corrosion resistant lining). For particulate wear erosion and clastomer degradation, there are no reasonable mitigation measures. Therefore, there are no programs credited with mhlgating aging for the Group 7 components.
Discovery; Most of the Group 2 components are subject to periodic inspection through existing plant preventive maintenance (PM) activities as part of the CCNPP PM Program. These activities provide an effective means to discover and manage the age-releted degradation effects on the components, The CCNPP PM Program and the specific maintenance activities are discussed in detail below. [ Reference 1, Attachment i for GrouplDs LC 01, LJ 01, BS 01, CKV 02, CV 03/04, llV 04, PUMP-01, ]
Group 2 components that are not inspected by the PM Program will be included in a new plant program.
The Group 2 components covered by this program include saran, kynar, or neoprene lined carbon steel piping (device type MC) and hand valves (device type llV) constructed of ductile iron or cast steel.
These components are subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, pitting, and clastomer degradation. The program will inspect a representative sample of susceptible areas of the system for signs ofliner degradation and corrosion, if any significant degradation is found, the program will provide appropriate co:Tective actions to ensure that the Group 2 components continue to perform their intended functions during the period of extended operation. The program is considered an ARDI Program as defined in the CCNPP IPA Methodology (reference Section 2.0 of the BGE LRA). The
, program details are described above in the Group 1 Aging Management Program section. [ Reference 1, Attachment i for Group ids MC 01,ilV 05; Attachment 8, Attachment 10]
Application for License Renewal 5.16-17 Calvert Cliffs Nuclear Power Plant -
NITACitMENT (3)
APPENDIX A TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM CCNPP PMfygram
'!he CCNPP PM Program has been established to maintain plant equipment, structures, systems, and compo,3!d in a reliable condition for normal operation and emergency use, minimize equipment failure, and extend equipment and plant life. [ Reference 14, Section 1.l]
The program is governed by CCNPP Administrative Procedure MN 1102, " Preventive Maintenance Program," and covers all PM activities for nuclear power plant structures and equipment within the plant, including the SW System components within the scope oflicense renewal. References l$,16, and 17 were used in the development of this program. [ Reference 14, Section 2.l]
The PM Program includes periodic inspection of spccinc components through various maintenance activities. These activities provide an effective means to discover and manage the age related degradation effects on these components. The program requires that an issue Report be initiated according to CCNPP Procedure QL 2100," Issue Reporting and Assessment," for denciencies noted during performance of PM tasks. Correctivs actions are taken to ensure that the affected components r main capable of performing their passive miended functions under all CLil conditions. [ Reference 1 r..dion 4.3; Reference 14, Section 5.2.11.1.fj Specine responsibilities are assigned to 11GE personnel for evaluating and upgrading the PM Program and for initiating program improvements based on system performance. Issue Reports are initiated according to CCNPP Procedure QL 2100 to request changes ta the program that could improve or correct plant reliability and performance. Changes to the PM Program that require issue Reports included changes to the PM task scope, frequency, process changes, results from operating experience reviews, as well as other types of changes. [ Reference 14, Sections S.I.A and 5.4]
The PM Program is subject to periodic internal assessment. Internal audits are performed to ensure that activities and procedures established to implement the requirements of 10 CFR Part 50, Appendix B, comply with llGE's overall Quality Assurance Program. These auditt provide a comprehensive independent verincation and evaluation of quality related activities and procedures. Audits of selected aspects of operational phase activities are performed with a frs quency commensurate with their strength of performance and safety signincance, and in such a manner as to assure that an audit of all safety.
related functions is completed within a period of two years. An audit performed in 1997 of the CCNPP Maintenance Program (which includes the PM Program) concluded that the program is effectively implemented at CCNPP.
No age related degradation issues were identified.
[ Reference 18, Section 111.18]
For the Group 2 components, the specific maintenance activities that manage the efTects of aging are as foHows:
Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear crosion and pitting of cement mortar lined piping (device type LC) is carried out by periodic inspection through Repetitive Tasks 10122066, 10122067, 10122068, 20122070,-20122071, 20122072. These repetitive tasks are performed during refueling outages to inspect the inte-ior surface of the piping to verify that degradation is not occurring, and corrective actions are taken to repair any denciencies discovered. [ Reference 1, Attachments 1 and 8 for Group ID LC Ol]
Application for License Renewal-5.16 18 Calvert Cliffs Nuclear Power Plant
O A1TACIIMENT 0)
APPENDIX A - TECilNICAL INFORMATION 5.16 SALTWATER SYSTEM Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, pitting and e
clastomer degradation of neoprene lined piping (device type LJ) is carried out by periodic inspection through Repetitive Tasks 10j22063,10122064,10122065, 20122067, 20122068, 20122069. These repetitive tasks are performed during refueling outages to inspect the interior surface of the piping to verify that degradation is not occurring, and corrective actions are taken to repair any deficiencies discovered. [ Reference 1, Attachments 1 and 8 for Group ID LJ.01]
Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting for e
ECCS pump room air cooler basket strainers (device type BS) is carried out by periodic inspection and testing through PM Checklists MPM04004 and MPM04194.
Checklist MPM04004 is perfonned every 12 weeks and MPM04194 is performed every 48 weeks. These checklists include steps to inspect for signs ofleakage and corrosion and to verify the integrity of the liner. This activity detects degradation of the pressure boundary or bolting, and corrective actions are taken to repair any dcHelencies discovered. [ Reference 1, Section 4.?, Attachments I and 8 for Group ID 11S-01]
Management of crevice corrosion, galvanic corrosion, MIC, and pitting for SW pump discharge e
check valves (device type CKV) is carried out by periodic inspection and testing through PM Checklists MPM12200 and MPM12201. These PM checklists are performed on a six year frequency to inspect the lining and body of the valves for degradation. These routine activities identify any degradation of the pressure boundary, and corrective actions are taken to repair any deficiencies discovered. [ Reference 1, Section 4.3, Attachments I and 8 for Group ID CKV.02]
Management of crevice corrosion, galvanic corrosion, MIC, pitting, and clastomer degradation of control valves (device type CV) associated with the ECCS pump room air coolers is carried out by periodic inspection and overhaul through Repetitive Tasks 10122096 through 10122102,and 20122100 through 20122106. 'these repetitive tasks are performed every six years. The occurrence of corrosion and liner degradation is expect d to be limited and is not likely to affect the intended function of the valves. Periodic valve averhaul verifies that degradation is not occuning and corrective actions are taken to repair any deficiencies that are discovered.
[ Reference 1. Attachments I,3, and 8 for Group ID CV 03; Reference 12. Table 2]
Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, pitting, and e
clastomer degradation of control valves (device type CV) associated with the SRW heat exchangers is carried out by periodic inspection and testing through PM Checklists MPM01001 and MPM0ll81. These PM checklists are performed on a bl. annual frequency to inspect the lining and bodies of the valves for corrosion. These routine activities identify any degradation of the pressure boundary and corrective actions are taken to repair any deficiencies that are discovered. Checklist MPM01001 will be modified to add other SRW heat exchanger control valves that are not currently included in the checklist. [ Reference 1, Attachments 1,3, and 8 for Group ID CV-04, Attachment 10; Reference 12 Table 2]
Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, pitting, and elastomer degradation of the hand valves (device type llV) that provide the path to the circulating water discharge conduits is carried out by periodic inspection through Repetitive Tasks 10122068 and 20122072. These repetitive tasks are performed during refueling outages.
Periodic inspection of lves during piping inspection verifies that degradation is not occurring, and corrective actions are taken to repair any deficiencies discovered. [ Reference 1, Attachments 1, 3, and 8 for Group ID llV-04; Reference 2; Reference 12, Table 2]
Application for License Renewal 5.16 19 Calvert ClitTs Nuc! car Power Plant
~.
A'ITACHMENT (3)
APPENDIX A TECHNICAL INFORMATION l
5.16 SALTWATER SYSTEM Management of crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting for the e
SW pumps is carried out by pump inspection and overhaul through CCNPP Procedure PUMP 3,
" Saltwater Pump Overhaul," These activities are performed as required based on pump performance trends or corrective action requirements. The procedure requires that the pump volute be inspected for signs of wear, crosion, corrosion, scratches, or cracks. Performance of i
this activity willidentify degradation of the pump casings. Corrective actions are taken to repair any dc0clencies discovered. [ Reference 1, Section 4.3, Attachments I and 8 for GrouplD PUMP Ol; Reference 19, Page 29]
Group 2 (Device types with internal lining subject to crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear erosion, pitting, and elastomer degradation). Demonstration of Aging Management llated on the information presented above, the following conclusions can be reached with respect to the Group 2 components:
lhe Group 2 components have the passive intended function to maintain pressure boundary e
integrity under CLil conditions.
Crevice corrusion, galvanic corrosion, general corrosion, MIC, particulate wear crosion, pitting, and clastomer degradation are plausible for the Group 2 components which, if unmanaged, could eventually result in loss of material such that the components may not be able to perform their pressure boundary function under CLil conditions.
The PM Program conducts periodic inspections of speci0c components through performance of e
various maintenance activities that provide th s to discover the effects of crevice corrosion, galvanic corrosion, general corrosion, MIC, alate wear crosion, pitting, and clastomer degradation for specific components. Corrective naions are taken to correct any deficiencies that are found to ensure that the affected components remain capable of performing their passive intended functions under all CLil conditions.
For Group 2 components that are not inspected by the PM Program, the ARDI Program will conduct inspections of representative components to discover the effects et crevice corrosion, galvanic corrosion, general corrosion, MIC, pitting, and clastomer degradation, and will contain acceptance criteria that ensure corrective actions will be taken such that the components remain capable of performing theit passive intended functions under all CLil conditions.
Therefore, there is reasonable assurance that the effects of crevice corrosion, galvanic corrosion, general corrosion, MIC, particulate wear crosion, pitting, and clastomer degradation will be managed for the Group 2 components such that they will be capable of performing their intended functions, consistent with the CLil, during the period of extended operation.
Application for License Renewal 5.16 20 Calvert Clifts Nuclear Power Plant
AHACHMENT m APPENDIX A TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM Group 3 (I)eslee types with air laternal environments subject to general corrosion)- Materials and Environment As shown in Table 5.16 3, Group 3 applies to device types ACC, CV, llV, and PCV that are subject to general corrosion.
Group 3 consists of accumulators and valves that have air internal environments.
[ Reference 1 Attachment I for Group ids ACC 01, CV 01, CV-02,ilV 09, PCV 02]
All of the Group 3 components have the passive intended function to maintain pressure boundary integrity. [ Reference 1, Attachment 1)
The internal environment for all the Group 3 components is instrument air (IA). The IA supply is normally provided by the IA compressors and is very dry, filtered, oil free air, Particle site, dew point, and oil hydrocarbons are controlled in accordance with industry standards. Occasionally, air that does not meet the mme air quality standards may enter the IA System due to operation of the plant air compressors or the SW air compressors, which serve as backups to the I A compressors. Therefore, there is a possibility that moisture may enter the IA supply, although its effect is expected to be limited since the backup compressors are operated on a short term basis An inspection performed on the piping immediately downstream of the SW air compressors, where the worst case of general corrosion is expected, revealed only very light surface rust on the inside of each piece. After more than 20 years in operation, approximately 60% of the pipe interior contained no rust and appeared similar to the inside of L
new pipe. Measurements showed negligible loss of wall thickness. [ Reference 1, Attachment 3s, ; Reference 11, Section 9.10; Reference 20, Attachment C)
Gencial corrosion is plausible for the internal carbon steel and iron subcomponent parts of the Group 3 components. [ Reference 1, Attachment 1, Attachment 45, Ss, and 6s]
Group 3 (Devlee types with air internal environments subject to general corrosion) - Aging t
Mechanism Effects General corrosion is the thinning (wastage) of a metal by chemical attack (dissolution) at the surface of the metal by an aggressive environment. The consequences of the damage are loss of load carrying cross sectional area. General corrosion requires an aggressive environment and materials susceptible to that environment. This ARDM is plausible for the Group 3 components because susceptible materials of construction are exposed to potentially moist air, llowever, the exposure of these components to moisture is expected to be minimal and short term and is not expected to result in significant levels of degradation. [Refesence 1, Attachment 7s, Attachment S]
The expected effects of general corrosion on the internal carbon steel and iron subcomponent pans would be superficial rust speckles and a slight dusting ofloose surface rust. [ Reference 1 Attachment 6s]
This aging mechanism, if unmanaged, could eventually result in a loss of material such that the Group 3 components may not be able to perform their pressure boundary function under CLB conditions.
Application for License Renewal 5.16 21 Calvert Clifts Nuclear Power Plant
I*
ATTACHMENT 0)
APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM Group 3 (Device types with air laternal environments subject to general corrosion). Methods to Manage Aging Millgatinn: The effects of general corrosion for the Group 3 components can be mitigated by minimiting their exposure to an aggressive environment (i.e., minimiting moisture in the IA supply). As discussed above, the exposure of these components to moisture is expected to be minimal and short term and is not expected to result in significant levels of degradation. Continued maintenance of the IA System air quality to industry standards will ensure minimal component degradation. [ Reference 1 Attachments 6s, Attachment 8)
Dhsmrzy: There are no methods deemed necessary to discover general corrosion since the aging efTects are expected to be minimal and can be mitigated by continued maintenance of the l A System air quality.
Group 3 (Device types with air internal environments subject to general corrosion) - Aging Management Program (s)
Mitigation: Moisture in the lA supply is minimired through PM checklists that are performed as part of the PM Program. The PM program details are der.cribed above in the Group 2 Aging Management Program section. Ior the Group 3 components, the specific maintenance activities that mitigate the eITects of general corrosion are as follows:
Calvert Cliffs initiated Preventive Maintenance Checklist IPM 10000(10001)," Check Unit 1(2) instrument Air Q9ality," following a review of industry operating experience. *lhe industry operating experience recommends maintaining the air quality within the requirements of y
instrument Society of America (ISA) Standard ISA S 7.3," Quality Standard for instrument Alr."
Standard ISA S 7.3 recommends limits for maximum particle size, dew point temperature, and 11 content. Preventive Maintenance Checklist IPM 10000 (10001), checks instrument air quality at three locations in the I A System: at the dryer outlet, at the furthest point from the dryer, and at the approximate mid-point between the other two. The checklist is performed in accordance with CCNPP Repetitive Tasks 10191024 (20121022), " Check Unit 1(2) Instrument Air Quality at System Low Points." Measurements of dew point and particulate count are taken every 12 weeks. According to procedure, dew point data and particulate sample results are reviewed and trended. Ifit is determined the air quality is abnormal, corrective action is initiated to return the air quality to nonnal and the condition of the dependent load internals is investigated, as appropriate. This process ensures instrument air quality is maintained in accordance with industry star 4rds for moisture (dew point). Operating experience relative to instrument air quality control has shown that the air normally provided is very dry and contains little particulate matter. [ Reference 1. Section 4.3, Attachments 1 and 8; References 21 and 22]
Discoverv: Since there are no methods deemed necessary to discover general corrosion, there are no programs credited with discovery of the aging effects due to this ARDM.
f Application for License Renewal 5.16 22 Calvert Clifts Nuclear Power Plant
ATTACitMENT di APPENDIX A. TECHNICAL INFORMATION 5.16 SALTWATER SYSTEM Gresp3 (Desice types with air laternal environmets subject to general corrosion) -
Ikmonstration of Aging Management liased on the information presented above, the following conclusions can be terched with respect to the
. Group 3 components subject to general corrosion:
ne Group 3 components have the passive intended function to maintain pressure boundary e
integrity under CLil conditions.
General corrosion is plausible for the Group 3 components which, if unmanaged, could eventually result in loss of material such that the components may not be able to perform their pressure boundary function under CLil conditions, The PM Program minimires moisture in the IA System through performance of various e
maintenance activities that provide the means to mitigate the effects of general corrosion.
Corrective actions are taken to correct any deficiencies that are found to ensure that the affected components remain capable of performing their passive intended functions under all CLil conditions.
Therefore, there is reasonable assurance that the effects of general corrosion will be managed for the Group 3 components such that they will be capable of performing their pressure boundary function, consistent with the CLII, during the period of extended operation.
Groep 4 (CC and SRW heat enchangers subject to crevice corrosion, erosion corrosion, general corrosion, MIC, pitting, and elastomer degradation) Materials and Environment As shown in Table 5.16 3, Group 4 applies to device type llX that is subject to crevice corrosion, crosion corrosion, general corrosion, MIC, pitting, and elastomer degradation.
Group 4 consists of the CC and SRW heat exchangers. [ Reference 1 Attachments 1 and 3 for Group lD llXOl]
All of the Group 4 components have the passive intended function to maintain pressure boundary integrity, [ Reference 1. Attachment 1]
ne subcomrenent parts of the Group 4 heat exchangers, part materials, internal environment for each part, and plausible aging mechanisms are shown in the following table. [ Reference 1, Attachments 4,5, and 6 for Group ID llX Ol]
Application for License Renewal 5.16 23 Calvert Cliffs Nuclear Power Plant
i A'LTAC11 MENT f3)
APPENDIX A - TECHNICAL INFORMATION 5.15 SALTWATER SYSTEM i
TABLE 5.16-4 CC AND SRW llEAT EXCHANGERS Subcomponent Part Material Environment Plausible ARDMs crevice corrosion i
Shell Carbon Steel treated water general corrosion pitting crevice corrosion Channellicads Carbon Steel SW MIC pitting crevice corrosion Tube Sheets Aluminum Ilronte treated water and SW MIC pltting crevice corrosion Tubes Copper Nickel treated water and SW crosion corrosion MIC i
pitting Cha el ar innnel Rubber / Neoprene SW clastomer degradation Carbon or Low Alloy N/A extemalto crevice corrosion U
"8 Steel process Huld general corrosion pitting As discussed above in Section 5.16.1.1, the CCNPP SRW heat exchanger tubes have experienced erosion corrosion in the past. Ilattimore Gas and Electric Company currently plans to replace the existing tube and shell SRW heat exchangers with new plate and frame heat exchangers that are more resistant to erosion corrosion. The SRW heat exchangers are scheduled to be replaced prior to the period of extended operation. [ Reference 3J Group 4 (CC and SRW heat eschangers subject to crevice corrosion, erosion corrosion, general corrosion. MIC. pitting, and elastomer degradation)- Aging Mechanism Effects The aging mechanism effects for crevice corrosion. uneral corrosion, MlC, and pitting are as discussed atxn e for Group 1. Elastomer degradation is discussed in Group 2.
Erosion corrosion is an increased rate of attack on a metal because of the relative movement between a corrosive Guld and the metal surfax Mechanical wear or abrasion can be involved, characterized by grooves, gullies, waves, holes, or valleys on the metal surface. Erosion is a mechanical action of a Ould and/or particulate matter on a metal surface, without the innuence of corrosion. The corrosive procces is accelerated because the erosion removes the protective oxide film, which results in chemical attack or dissolution of the underlying metal. Inlet tube crosion conosion occurs in heat exchangers, due to turbulence of How from the heat exchanger head into the smaller tubes, within the first few inches of the tube. [ Reference 1. Attachment 7]
Crevice corrosion and p:tting are plausible for the shell because stagnant conditions may develop in idled portions of the system. [ Reference 1. Attachments 5 and 6) h :ation for License Renewal 5.16 24 Calvert Clifts Nuclear Power Plant
s A*ITACilMENT Un APPENDIX A. TECHNICAL INFORMATION 5.16 - sal,TWATER SYSTEM General corrosion is plausible for the shell because the material of construction is susceptible to this ARDM.- [ Reference 1. Attachments 5 and 6)
Crevice corrosion, MIC, and pitt!ng are plausible for the channel heads if the channel head lining material (rubber / neoprene) falla (see elastomer degradation discussion below). The wall of the charmel heads is susceptible to these ARDMs at the locations of damaged lining. [ Reference 1, Attachments 5 and 6)
Crevice corrosion and pitting are plausible for the tube sheets and the tubes in a SW environment. These components are susceptible to these ARDMs due to the presence of sulfates and chlorides. Dissolved oxygen and stagnant fluid will aggravate pitting. "Ihe materials of construction are resistant to most forms of corrosion and catastrophic failure of these components is not expected. [ Reference 1 Attachments 5 and 6]
Microbiologically induced corrosion is plausible for the tube sheets and the tubes due to the use of raw, untreated SW. Sulfate reducing bacteria, sulfur oxidizers, and iron oxidizing bacteria may be present in the process fluid. Stagnant or low flow areas are most susceptible, and sedimentation aggravates the problem. The materials of construction are resistant to most forms of corrosion and catastrophic failure of these components is not expected. [ Reference 1, Attachmenr 5 and 6)
Erosion corrosion is plausible for the inlet side of the heat exchanger tubes due to susceptible materials and flow conditions. It is also plausible based on plant operating experien.c as discussed above in Section 5.16.1.1.
Elastomer degradation is plausible for the channel and channel head lining due to the combined effects of scission, crosslinking, and changes associated with compound ingredients. Significant degradation is not expected due to the service conditions. Ilowever, lining failure will result in exposure of the underlying metal component surfaces to localized corrosive attack. [ Reference 1, Attachments 5 and 6)
Crevice corrosion, general corrosion, and pitting are plausible for the bolting. Although these external components are not exposed to the process fluid, the potential for leakage of SW from the system exists.
[ Reference 1. Attachments 5 and 6)
These aging mechanisms, if unmanaged, could eventually result in a loss of material such that the Group 4 components may not be able to perform their pressure boundary function under CLB conditions.
Group 4 (CC and SRW heat exchangers subject to erevice corrosion, tronion corrosion, general corrosion, MIC, p'.tting, and elastomer degradation). Methods to Manage Aging Mitintiom For the shell side of the heat exchangers, the effects of crevice corrosion, general corrosion, and pitting can be mitigated by minimizing the exposure of the shell to an aggressive environment.
Maintaining CC System and SRW System chemistry conditions to minimize impurities will aid in the prevention of most corrosive mechanisms [ Reference 1, Attachment 8)
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AITACllMINT 0)
APPENDIX.'.. TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM For the tube side of the heat exchanger (i.e., channel heads, tube sheets, tubes, channel and channel head lining, and bolting), the components are subject to a SW environment. 'lherefore, it is not feasible to control water chemistry. Corrosion of the channel heads is mitigated by the rubber / neoprene lining.
Ilowever, some corrosion may occur if the lining fails. Some corrosion protection is also provided by sacrificial anodes that are installed in the channel heads. Therefore, discovery methods are deemed necessary to manage aging for these components.
Dhcatso>: For the shell side of the heat exchangers, the occurrence of corrosion is expected to be limited and is not likely to affect the intended function of the heat exchangers. Visual inspections can be used to provide additional assurance that no signincant degradation is occurring. If any significant degradation is found, appropriate corrective actions can be taken to ensure that the heat exchangers continue to perform their intended function during the period of extended operation. [ Reference 1 ]
For the tube side of the heat exchangers, visual inspections and testing can determine if any degradation is occurring, if any signincant degradation is found, appropriate corrective actions can be taken to ensure that the heat exchangers continue to perform their intended function during the period of extended operation. (Reference 1. Attachment 8]
Group 4 (CC and SRW heat exchangers subject to crevice corrosion, erosion corrosion, general corrosion, MIC, pitting, and clastomer degradation) Aging Management Program (s) hiitigation: Calvert Cliffs Tecimical Procedure CP 206,"Speci0 cation and Surveillance for Component Cooling / Service Water Systems," is credited with managing the effects of crevice corrosion, general corrosion, and pitting for the shell side of the heat exchangers. The program provides for monitoring and maintaining CC ystem and SRW System chemistry to control the concentrations of oxyger., chlorides, other chemicals, and contaminants. The water is treated with hydrazine to minimize the amount of oxygen in the water, which aids in the prevention and control of most corrosive mechanisms. Cortinued maintenance of system water quality will ensure minimal piping or component degradation.
[ Reference 1, Attachment 8; Re?crence 23, Section 2.0)
Calvert Cliffs Technical Procedure CP-206 describes the surveillance and speciucations for monitoring the CC Sysicm and SRW System Guid. CP 206 lists the parameters to monitor, the frequency of monitoring these parameters, and the target and action levels for the Huid parameters. The parameters monitored by CP 206 are pil, hydrazine, chloride, dissolved oxygen, dissolved copper, dissolved iron, suspended solids, gamma activity, and tritium activity (normally not radioactive systems).
(Reference 23, Attachment 1)
These chemistry parameters are currently monitored on a frequency ranging from three times per week to once a month. All of the parameters listed in CP 206 currently have target values that give an acceptable range or limit Ibr the associated parameter. Two of the parameters, pil and hydrazine, have action levels associated with then.. If a target value or action level is not met, corrective actions are prescribed by the procedure, thereby ensuring timely response to chemic61 excursions. [ Reference 23, Section 6.0.C, ]
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ATTACllMENT LU -
- APPENDIX A TECHNICAL INFORMATION 5.16 - SALTWATER SYSTEM Operational experience related to CCNPP Technical Procedure CP 206 has shown no problems related to use of this procedure, in 1996, CP 206 was revised to include dissolved iron as a chemistry parameter.
Dissolved iron was added to CP 206 to act as a method to discover any unusual corrosion of the CC System and SRW System components. [ Reference 24)
Calvert Cliffs Technical Procedure CP 206 provides for a prompt review of CC System and SRW System chemistry parameters so that steps can be taken to return chemistry parameters to normal levels and, thus, minimize degradation due to corrosion mechanisms.
[ Reference 1 Attachment 8; Reference 23, Section 6.0.C]
Dimary: To verify that no significant crevice corrosion, general corrosion, or pitting is occurring for the shell side of the heat exchangers, a new plant program will be developed te provide inspections of a reprer.entative sample of susceptible areas for signs of degradation. T'e program is considered an ARDI Program as defined in the CCNPP IPA Methodology (reference Section 2.0 of the BGE LRA). The program details are discussed above in the Aging Management Program section for Group 1.
[ Reference 1 Attachment 8) ne tube side of the heat exchangers are subject to periodic inspection and testing through existing PM activities as part of the CCNPP PM Program. These activities provide an effective means to discover and manage the age related degradation effects on the heat exchanger tube side subcomponent parts.
The CCNPP PM Program details are discussed above in the Aging Management Program section for Group 2. The specific maintenance activities that manage the effects of aging for the tube side of the heat exchangers are as follows: [ Reference 1 Attachment 8)
Preventive Maintenance Checklists MPM00005 and MPM00006 are performed every two years e
to perform eddy current testing of the heat exchanger tubes. This routine activity will identify any degradation of the pressure boundary and corrective actions are taken to repair any defielencies that are discovered. [ Reference 1, Attachment 8]
Periodic cleaning and inspection of the tube side is carried out through Repetitive Tasks 10112052, 10112053, 10152023, 10152024, 20112006, 20112027, 20152020, and 20152021. These tasks inspect the channel heads, bolts, and sacrificial anodes, and clean the tubes every quarter (12 weeks). Periodic cleanir g and inspection verifies that degradation is not i
occurring and corrective actions are taken to repair any deficiencies that are discovered.
[ Reference 1 Attachment 8]
Group 4 (CC and SRW heat enchangers subject to erevice corrosion, erosion corrosion, general corrosion, MIC, pitting, and elastomer degradation)- Demonstration of Aging Management llased on the information presented above, the following conclusions can be reached with respect to the Group 4 components:
The Group 4 ' components havs the passive intended function to maintain pressure boundary integrity under CLB conditions, Crevice corrosion, crosion corrosion, general corrosion, MIC, pitting, and elastomer degradation e
are plausible for the Group 4 components which, if unmanaged, could eventually result in loss of material such that the components may not be able to perform their pressure boundary function under CLB conditions.
- Application for License Renewal 5.!6-27 Calvert Cliffs Nuclear Power Plant
ATTAcilMENT (3)
APPENDIX A. TECilNICAL INFORMATION 5.16 - SALTWATER SYSTEM For the shell side of the heat exchangers, Calvert Cliffs Technical Procedure CP 206 mitigates the, e
effects of crevice corrosion, general corrosion, and pitting by maintaining CC System and SRW System chemistry conditions, and contains acceptance criteria that ensure timely correction of adverse chemistry parameters.
For the shell side of the heat exchangers, the ARDI Program will conduct inspections of a representative sample of susceptible areas to discover signs 7f degradation, and will contain acceptance criteria that ensure corrective actions will be taks such that the heat exchangers remain capable of performing the*r passive intended functions und, 6 CLil conditions.
For the tube side of the heat exchangers, the pM Program conducts periodic inspection and testing through performance of various maintenance activities that provide the means to discover degradation. Corrective actions are taken to correct any deficiencies that are found to ensure that the affected components remain capable of performing their passive intended functions under all CLil conditions.
'lherefore, there is reasonable assurance that the efTects of crevice corrosion, crosion corrosion, general corrosion, MIC, pitting, and elastomer degradation will be managed for tiie Group 4 components such that they will be capable of performing their intended functions, consisunt with the CLil, during the period of extended operation.
Group 5 (ECCS pump room air coolers subject to crevice acorrosion, general corrosion MIC, and pitting). Materials and Environment As shown in Table 5.16 3, Group 5 applies to device type llX that are subject to crevice corrosion, general corrosion, MIC, and pitting.
Group 5 consists of the ECCS pump room air coolers. [ Reference 1, Attachments I and 3 for Group ID llX02]
All of the Group 5 components have the passive intended function to maintain pressure boundary integrity. [ Reference 1. Attachment l]
The internal environment for the heat exchangers is SW on the tube side and air on the shell side.
[ Reference I, Attachment 3]
Crevice corrosion, MIC, and pitting are plausible for the heat exchanger channel heads and the tubes.
'the channel heads are constructed of east iron and the tubes are copper nicket Crevice corrosion, getorni corrosion, and pitting are plausible for heat exchanger bolting which is constructed of carbon and low alloy steel. [ Reference 1. Attachment 1, Attachment 4,5, and 6]
There are no plausible ARDMs on the shell side of the ECCS pump room air coolers due to the air internal environment. [Rcference 1 Attachments 3,4, and 5]
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ATTACHMENT-Q)
J APPENDIX A - TECIINICAL INFORMATION 5.16 - SALTWATER SYSTEM Group 5 (ECCS pump room air coolers subject to crevice corrosion, general corrosion, MIC, and pitting)- Aging Mechanism Effects The aging mechanism effects for crevice corrosion, general corrosion, M:0, and pitting are as discussed above for Group 1.
The channel heads are lined with coal tar epoxy to protect the cast ira wall from the aggressive SW environment. Crevice corrosion, MIC, and pitting are plausible for the channel heads if the coal tar epoxy lining meterial fails. The wall of the chonnel heads is nusceptible to these ARDMs at the locations of the damaged lining. [ Reference 1, Attachments 5 and 6)
Crevice corrosion and pitting are plausible for the tubes in a SW cnvironment. These components are susceptible to these ARDMs due to the presence of sulfates and chlorides. Dissolved oxygen and stagnant duid will aggravate pitting. The materials of construction are resistant to most forms of corrosion and catastrophic failure of these components is not expected. [ Reference 1, Attachments 5 and 61 Microbiologically-induced corrosion is plausible for the tubes due to the use of raw, untreated SW.
Sulfate-reducing bacteria, sulfur oxidizers, and iron-oxidizing bacteria may be present in the process fluid Stagnant or low flow areas are most susceptible, and sedimentation aggravates the problem. The materials of construction are resistant to most forms of corrosion and catastrophic failure of these components is not expected. [ Reference I, Attachments 5 and 6]
Crevice corrosion, general corrosion, and pitting are plausible for the bolting. Although these external components are not exposed to the process fluid, the potential for leakage of SW from the system exists.
[ Reference I, Attachments 5 and 6]
rhese aging mechanisms, if unmanaged, could eventually result in a loss of material such that the Group 5 components may not be able to perform their pressure boundary function under CLB conditions.
Group 5 (ECCS pump room air coolers subject to crevice corrosion, general corrosion, MIC, and pitting)- Methods to Man. ige Aging Mitigation! For the tube side of the heat exchanger (i.e., channel heads, tubes, and bolting), the components are subject to a SW environment. Therefore, it is not feasible to control water chemistry.
Some corrgion protection is provided by sacrificial anodes that are installed in the channel heads. The discovery methods discussed below are deemed adequate to manage aging for these comporents.
Discoverv: For the tube side of the heat exchangers, visual inspections and testing can be used to determine if any degradation is occurring. If any significant degradation is found, appropriate corrective actions can be taken to ensure that the heat exchangers continue to perform theii intended function
- doing the period ofextended operatio i. [ Reference 1, Attachment 8]
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ATTACHMENT (3)
APFENDIX A - TECilNICAL INFORMATION 5.16 - SALTWATER SYSTEM Group 5 (ECCS pump room mir coolers subject to crevice corrosion, general corrosion, MIC, and '
pitting)- Aging Management Program (s)
Mitigation: Since there are no feasible mitigation methods, there are no programs credited with mitigating aging for the Group 5 components.
Dismury; Tne tube side of the heat exchangers are subject to periodic inspection and testing through existing PM activities as part of the CCNPP PM Program. These activities provide an effective means to discover and manage the age-related degradation effects on the heat exchanger tube side subcomponent parts. He CCNPP PM Program details are discussed above in the Aging Management Program section for Group 2. De specific maintenance activities that manage the effects of aging for the tube side of the heat exchangers are as follows: [Refesuce 1, Attachment d]
Preventive Maintenance Checklists MPM05000 and MPM05101, which are associated with the e
ECCS pump room air coolers, are performed every 24 weeks. Checklist MPM05000 replaces the sacruicial anodes, and Checklist MPM05101 inspects the channel heads and the tubes. Checklist MPM05101 presently calls for performance of a visual inspection of the tubes by using a light at one end of the heat exchanger while examining the tubes from the opposite end. Any debris found in the tubes is removed. Operating experience with this PM activity has indicated that there is little indication of age-related degradation of the tubes. In order to enhance the tube inspections, Checklist MPM05101 will be modified to visually inspect internal surfaces of a sample of the tubes at both the inlet and outlet ends of the heat exchanger. This maintenance activity will include appropriate surface cleaning of the tube surfaces that are inspected, and will include a requirement to bpect for roughness or irregularities that might indicate corrosion mechanisms are active. These routine activities will identify any degradation of the pressure boundary, and corrective actions will be taken to repair any deficiencies discovered.
[ Reference 1, Attachment 8]
Group 5 (ECCS pump room air coolers subject to crevice corrosion, general corrosion, M!C, and pitting)- Demonstration of Aging Management Based on the information presented above, the following conclusions can be reached with respect to the Group 5 components:
The Group 5 components have the passive intended function to maintain pressure boundary integrity under CLB conditions.
Crevice corrosion, general corrosion, MIC, and pitting are plausible for the Group 5 components which, if unmanaged, could eventually result in loss e material such that the components may not be able to perform their pressure boundary function under CLB conditions.
For the tube side of the heat exchangers, the PM Program conducts periodic inspection and testing through performance of various maintenance activities that provide the means to discover and manage age-related degradation effects. Corrective actions are taken to correct any deficiencies that are found to ensure that the affected components remain capable of performing their passive intended functions under all cub conditions.
L Application for License Renewal 5.16-30 Calvert Cliffs Nuclear Power Plant
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~ ATTACilMENT m APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATER WSTEM nerefore, there is reasonable assurance that the effects of crevice corrosion, general corrosion, MIC, and
- pitting will be managed for the Group 5 components such that they will be capable of performing their intended functions, consistent with the CLB, during the period of extended operation.
Group 6 (Flow orifices subject to crevice corrvslon, erosion corrosion, MIC, particulate wear erosion, and pitting)- Materials and Environment As shown in Table 5.16-3, Group 6 applies to device type FO that is subject to crevice corrosion, crosion corrosion, MIC, particulate wear crosion, and pitting.
Group 6 consists of flow orifices. [ Reference 1 Attachment i for Group ID FO-01]
All of the c oup6 components have the passive intended functions to maintain pressure boundary r
integrity and to restrict flow to a specified value in support of a design basis event. [ Reference 1, )
The internal environment for all of the Group 6 components is SW [ Reference 1, Attachment 3] -
Crevice corrosio e erosion corrosion, MIC, pmticulate wear crosion, and pitting are plausible for the internal surfaces of the now orifices. The flow orifices are constructed of stainless steel. [ Reference 1,,5, and 6]
Group 6 (Flow orifices subject to crevice corrosion, crosion corrosion, MIC, particulate wear erosion, and pitting)- Aging Mechanism Effects The aging mechanism effects for crevice corrosior., MIC, and pitting are as discussed above for Group 1.
Erosion corrosion is discussed in Group 4. Particulate wear crosion is discussed in Group 2.
Crevice corrosion and pitting are plausible for the flow orifices in a SW environment. The3e components are susceptible to these ARDMs due to the presence of sulfates and chlorides. Dissolved oxygen and stagnant fluid will aggravate pitting. The materials of ccnstruction are resistant to most forms of corrosion and catastrophic failure of these - omponents is not expected.
[ Reference 1, Attachments 5 and 6]
Microbiologically indu.:cd corrosion is plausible for the flow orifices due to the use of raw, untreated SW. Sulfate-reducing bacteria, sulfur oxidizers, and iron-oxidizing bacteria may be present in the process fluid. Stagnant or low flow areas are most susceptible, and sedimentation aggravates the problem. The materials of construction are resistant to most forms of corrosion and catastrophic failure of these components is not expected. [ Reference 1, Attachments 5 and 6]
Erosion corrosion and particulate wear crosion are plausible for the flow orifices due to susceptible material of construction in an aggressive SW environment. These ARDMs may result in a loss of the inner diameter surface area that has the potential to adversely affect the intended flow restriction function. [ Reference 1, Attachments 5 and 6]
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D AUACHMENT m APPENDIX A - TECIINICAL INFORMATION 5.16 - SALTWATER SYSTEM These aging mechanisms, if unmanaged, could eventua:ly result in a loss of material such that the Group 6 components may not be able to peiform their pressure boundary and flow restriction functions under CLB conditions.
Group 6 (Flow orifkes subject to crevice corrosion, erosion corrosion, MIC, particulate wear cresion, and pitting)- Methods to Manage Aging Mitigatiotn The stainless steel material of construction for the flow orifices is designed to mitigate most forms of corrosion. Since the flow orifices art, subject to a SW cnvironment it is not feasible to control watcr chemistry. The discovery methods discussed below are deemed adequate to manage aging for thae components.
Disemery: Visual inspections can be used to determine if any degradation is occurring, if any significant degradation is found, appropriate corrective actions can b taken to ensure that the flow orifices continue to perform their intended functions during the period of extended operation.
[ Reference 1, Attachment 8]
Group 6 (Flow orifices subject to crevice corrosion, erosion corrosion, MIC, particulate wear erosion, and pitting)- Aging Management Program (s)
Mitigatimn Since there are no feasible mitigation methods, there are no programs credited with mitigating aging for the Group 6 components.
Discoverv: All cacept one of the Group 6 flow orifices are subject to periodic inspection through existing PM activities as part of the CCNPP PM Program. These activities provide an effective means to discover and manage the age-related degradation effects. The CCNPP PM Program details are discussed above in the Aging Management Program section for Group 2. The specific maintenance activities that manage the effects of aging for the flow orifices are as follows: [ Reference 1, Attachment 8]
Periodic insper'lon of the flow orifices is carried out through Repetitive Tasks 10122095 and 20122099. These tasks are performed every six years. Periodic inspection verifies that degradation is not occurring and corrective ac+ ions are taken to repair any deficiencies that are discovered. [ Reference 1, Attachments 8 and 10]
As discussed above, one of the Group 6 flow orifices is not subject to periodic inspection through existing PM activities. This orifice (Unit i SRW heat exchanger SW emergency outlet orifice) was installed as part of a piping modification that was implemented in the 1993-1994 timeframe. Routine inspection of this orifice is not currently performed due to infrequent use of the flow path in which the orifice is installed. To verify that no significant age-related degradation is occurring for this orifice, it will be included in the ARDI Program inspections. The program details are discussed above in the Aging Management Program section for Group 1.
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ATTACHMENT G)
APPENDIX A - TECilNICAL INFORMATION 5.16. SALTWATER SYSTEM Group 6 (Flow oriflees subject to erevice corrosion, croslou corrosion, MIC, particulate wear erosion, and pitting). Demonst'.ation of Aging Management Based on the information presented above, the followit g conclusions can be reached with respect to the Group 6 components:
The Group 6 components have the passive intended functions to maintain pressure boundary.
integrity and to restrict flow under CLB conditions.
Crevice corrosion, erosion corrosion, MIC, particulate wear crosion, and pitting are plausible for the Group 6 components which, if unmanaged, could eventually result in loss of material such
' that the components may not be able to periorm their pressure boundary and flow restriction functions under CLB conditions.
The PM Program conducts periodic inspection through performance of various maintenance activities that provide the means to discover and manage age-related degradation effec:s.
Corrective actions are taken to correct any deficiencies that are found to ensure that the affected components remain capable of performing their. passive intended functions under all CLB conditions.
For the orifice the.t is not inspected by the PM Program, the ARDI Program will conduct inspections to discover signs of degradation and will contain acceptance criteria that ensure corrective actions will be taken such that the orifke remains capable of performing its passive intended functions under all CLB conditions.
Therefore, there is reasonable assurance that the effects of crevice corrosion, erosion corrosion, MIC, particulate wear crosion, and pitting will be managed for the Group 6 components such that they will be capable of performing their intended functions, consistent with the CLB, during the period of extended operation.
5.16.3 Conclusion The aging management programs discussed for the SW System are listed in the following table. These programs are administratively controlled by a formal review and approval process. As demonstrated abcVe, these programs will manage the aging mechanisms and their effects such that the intended functions of the SW System components will be maintained during the period of extended operation consistent with the CLB under all design loading conditions.
The analysis / assessment, corrective action, and confirmation / documentation process for license renewal is in accordance with QL-2, " Corrective Actions Program." QL-2 is pursuant to 10 CFR Part 50, Appendix B, and covers all structures and components subject ta AMR.
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ATTACIIMENT G)
APPENDIX A - TECIINICAL INFORMATION 5.16 - SALTWATER SYSTEM TABLE 5.16-5 LIST OF AGING MANAGEMENT PROGRAMS FOR THE SW SYSTEM
~
Program Credited For -
Existing CCNPP Technical Procedure CP-206, Mitigation of the cffects of crevice
" Specifications and Surveillance for corrosion, general corrosion, and pitting for Component Cooling / Service Water System" the shell side of the Group 4 heat exchangers.
Existing CCNPP Administrative Procedure Governs the specific maintenance activitics MN 1 102," Preventive Maintenance shown below.
Program"
, Modified For Group 2:
Disecvery of the efTects of crevice Renetitive teh corrosion, galvanic corrosion, general 10122063 through 10120268; corrosion, MIC, particulate wear erosion, 10122096 through 10122102; pitting, and elastomer degradation for the 20122067 through 20122072; and Group 2 components.
20122100 through 20122106 Checklists MPM04004; MPM04194; MPM12200; MPM12201; MPM01001 (modification needed); and MPM0ll81 Procedure PUMP.03 Existing For Group 3:
Mitigation of the effects of gen.'e al Checklists corrosion for the Group 3 components.
IPM10000 and IPM10001 Existing For Group 4:
Discovery of the effects of crevice Repetitig_ tasks corrosien, crosion corrosion, general 10112052; 10112053; 10152023; corrosion, MIC, pitting, and elastomer 10152024;20112006;20112027; degradation for the tube side of the Group 4 20152020; and 20152021 heat exchangers.
Checklists MPM00005 and MPM00006 Modified For Group 5:
Discovery of the effects of the crevice Checklists corrosion, general corrosion, MIC, and MPM05000 and MPM05101 pitting for the tube side of the Group 5 heat (modification needed) exchangers.
Modified For Group 6:
Discovery of the effects of crevice Repetitive tului corrosion, erosion corrosion,
- MIC, 10122095 (modification needed)and particulate wear erosion, and pitting for the l
20122099 Group 6 components.
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ATTACllMENT (3)
APPENDIX A - TECHNICAL INFORMATION 5.16 - SALTWATF.R SYSTEM Progrant Credited For-.
New-ARDI Program Discovery of the effects of crevice corrosion, general corrosion, MIC, and pitting for the Group I components.
Discovery of the - effects of crevice
+-
corrosion, galvanic corrosion, general corrosion, MIC, pitting, and elastomer degradation for the Group 2 components that are not inspected by the PM Program.
Discovery of the effects of_ crevice corrosion, general corrosion, and pitting for the shell side of the Group 4 heat exchangers.
Discovery of the effects of crevice corrosion, erosion corrosion, - MIC, paniculate wear erosion, and pitting for the Group 6 Unit 1 SRW overboard balancing orifice.
Application for License Renewal-.
5.16-35 Calvert Cliffs Nuclear Power Plant -
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ATTACHMFNT G)
APPENDIX A - TECilNICAL INFORMATION 5.16 4 SALTWATER SYSTEM 5,16.4 References 1.
CCNPP " Aging. Management Review Report for the Saltwater System," Revision 4, February Ii,1997 -
2.
CCNPP Drawing 60708S110002," Circulating Salt Water Cooling System," Revision 78 3.
Letter from Mr. C.11. Cruse (BGE) to NRC Document Control Desk, dated May 16,1997,
" License Amendment Request: Service Water lleat Exchangers Replacement" 4.
Letter from Mr, L. B. Russell (BGE) to NRC Document Control Desk, dated July 3,1984, Transmittal of Licensee Event Report 84-05, Revision 1 5.
NRC Information Notice 84 71, " Graphitic Corrosion of Cast Iron in Salt Water,"
September 6,1984 6.
Letter from Mr. E. C. Wenzinger (NRC) to Mr. A. E. Lundvall, Jr. (BGE), dated February 6,1985, "NRC: R1 Inspection 50-317/84-31, 50-318/84-31" 7.
Letter From Mr.
G.
C. Creel (BGE) to NRC Document Control Desk, dated November 27,1991," Temporary Non Code Repair of ASME Code Class 3 Piping" 8.
Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated June 4,1990, CCNPP License Event Report LER 90-17 " Leaking Weld and Bio Fouling in-Saltwater System" 9.-
Letter from Mr. C. J. Cowgill (NRC) to Mr. G. C. Creel (BGE), dated July 12,1990, "NRC Region i Resident inspection Report Nos. 50-317/90-13 and 50-318/90-13 (June 3,1990 to June 30,1990)"
10.
Letter from Mr. R. E. Denton (BGE) to NRC Document Control Desk, dated June 30,1994,
" Final Response to Generic Letter 89-13" 11.
CCNPP Updated Final Safety Analysis Report, Revision 20 12.
CCNPP Component Level Screening Results for the Salt Water Cooling System, Revision 3, July 151996 13.
CCNPP " Component Pre-Evaluation for the Salt Water System," Revision 4,
December 30,1996 14.
CCNPP Administrative Procedure MN-1-102," Preventive Maintenance Program," Revision 5, September 27,- 1996 15.
INPO 85-032," Preventive Maintenance," December 1988 16.
INPO 85-037," Reliable Power Station Operation," October 1985 17.
INPO Good Practice MA 319, " Preventive Maintenance Program Enhancement,"
December 1992 18.
BGE " Quality Assurance Policy for the Calvert ClilTs Nuclear Power Plant," Revision 48, March 28,1997 -
19.
CCNPP Procedure PUMP-3," Saltwater Pump Overhaul," Revision 3, May 25,1991 Application for License Renewal 5.16-36 Calvert Cliffs Nuclear Power Plant
c%
v AITACliMENT (3)
APPENDIX A - TECIINICAL INFORMATION 5.16 - SALTWATER SYSTEM 20.
CCNPP " Aging Management Review Report for the Compressed Air System," Revision 4, August 11,1997 21.
CCNPP NUCLEIS Database, Preventative Maintenance Checklists IPM 10000 (10001),
" Check Unit 1 (2) Instrument Air Quality," December 13,1996 22.
CCNPP NUCLEIS Database, Repetitive Tasks 10191024 (20191022), " Check Unit 1 (2)
Instrument Air Quality at Selected System Low Points" 23.
CCNPP Technical Procedure CP 206, " Specifications and Surveillance Component Cooling / Service Water System," Revision 3, November 4,1996 24.
CCNPP 1996 Component Cooling and Service Water System Assessment, February 26,1997 i
i Application for License Renewal 5.16-37 Calvert Clifts Nuclear Power Plant