ML12088A431
| ML12088A431 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 08/08/2011 |
| From: | Cullen R Entergy Nuclear Operations, Indian Point |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| Shared Package | |
| ML12088A422 | List: |
| References | |
| RAS 22102, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01 | |
| Download: ML12088A431 (35) | |
Text
ENT000069 Submitted: March 28, 2012 ft Entetgy IPEC SECONDARY STRATEGIC WATER Doc ID: SSWCP J Rev. 03 CHEMISTRY PLAN Page 1 of 35 Indian Point Energy Center SECONDARY STRATEGIC WATER CHEMISTRY PLAN Revision 03 August 2011 Prepared by:
Date: 0 $/b 8/&0 /1 Robert Cullen, Sr. Chemistry Specialist Reviewed by: ... -""
- faffies Peters, Sr. Chemistry Specialist Date
- ! . ". \ IJ I / /'-/1\.// "'-. . .. .,'-Date: VI ,la-O I /1 I Approved by:
?lO/li Thomas Orlando, Director of Engineering Approved Date: 9/2..0}1)
OO.....:::MM=P-O-------
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 2 of 35 Change Statement This revision was extensively reformatted to match the draft fleet template so there are
no revision bars identifying the changes.
The following changes were made in Rev. 3 to the IPEC Secondary Strategic Water
Chemistry Plan.
Added listing of Action Level 2 events since SG replacement for both units.
Revised the component prioritization to change the main condenser and condensate polisher (IP3) from medium to low.
Added a site specific Action Level 2 power reduction level of 30%.
Revised Action Level response times from those for A600TT to those for A600MA with
caveat that they may be changed to those for A600TT or A690TT as appropriate for
each unit.
Added additional references.
Updated the sludge lancing and sludge characterization results.
Added SG hideout return results.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 3 of 35 Table of Contents 1.0 Summary 4 2.0 Goals 4 3.0 Prioritization of Key Chemistry Issues 4 4.0 Key Plant Design Parameters & Notable Historical Events/Milestone Activities 5 5.0 Evaluation of Technical Issues, Including Risk/Susceptibility 9 6.0 Evaluation of Chemistry Control Strategies 16 7.0 Chemistry Control Strategies to be Implemented 27 8.0 Gap Analysis & Deviations 29 9.0 Innovative Approaches & Use of New Technology 30 10.0 References 31 Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 4 of 35 1.0 Summary 1.1 Overview of Goals and Chemistry Strategies The purpose of this Strategic Secondary Water Chemistry Plan, hereafter referred to as the Secondary Plan is to establish and maintain a site-specific chemistry program for the Indian Point Energy Center (IPEC), Units 2 and 3. The general goal of the Secondary Plan is to minimize chemically induced corrosion damage and performance degradation in the secondary water system, thereby maintaining the reliability, safety and economic performance of the two
units. The basic chemistry strategies to accomplish this goal are to provide high purity makeup water, monitor for cooling water leaks, inject chemicals to optimize
system pH and maintain a reducing environment. 1.2 Management Responsibilities The Chemistry Manager, or his designee, is responsible for the accuracy and
completeness of the Strategic Secondary Water Chemistry Plan, and is to ensure that the document is updated as indicated in Section 1.1 of EPRI Pressurized Water Reactor Secondary Water Chemistry Guidelines Rev 7. In
addition, the Chemistry Manager, or his designee, is to ensure that procedures needed to implement the Plan are kept up to date. The Entergy Chemistry Peer
Group is to evaluate new chemistry programs or initiatives, as to their applicability to IPEC.
2.0 Goals The specific goals of the Secondary Plan are as follows: Minimize chemistry-related corrosion damage to secondary water system components Maintain thermal performance of the steam generators to allow for full power operation Maintain steam generator tube plugging levels below 10% Minimize chemistry-related forced outages and repair costs Minimize the need for future steam generator chemical cleaning. 3.0 Prioritization of Key Chemistry Issues This section prioritizes the chemistry strategies in use at IPEC. 3.1 Optimize secondary side pH Optimizing the secondary side pH accomplishes two important things. First it reduces the general corrosion rate of secondary side piping which extends its Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 5 of 35 operating life. Second, the reduction in secondary side general corrosion leads to fewer corrosion products transported to the steam generators. Fewer corrosion products in the steam generators reduce the risk of fouling and also reduce the
areas where ionic impurities can concentrate. 3.2 Maintain a reducing environment in the final feedwater and steam generators A chemically reducing environment in the steam generators is also important to
reduce the potential for outside diameter stress corrosion cracking (ODSCC). To ensure that the steam generators are not exposed to oxygen, hydrazine is injected into the final feedwater to scavenge any residual dissolved oxygen. 3.3 Control secondary side ionic impurities Ionic impurities such as chloride and sulfate can concentrate in the steam generators and increase the potential for ODSCC. It is important to control both the concentration and the balance of the ionic species to avoid extreme pH
conditions in the steam generator crevice. To accomplish this goal the station contracts a vendor for a sophisticated deionized makeup water system. Unit 3 also has a SG blowdown recovery demineralization system. 4.0 Key Plant Design Parameters & Notable Historical Events/Milestone Activities4.1 Key Plant Design Parameters and System Materials The table below identifies key design parameters and system materials
considered in the development of this Plan.
Parameter Unit 2 Value Unit 3 Value Rated Core Thermal Power 3213 MWth 3186 MWth Electrical Output Capacity 1049 MWe 1076 MWe Initial Criticality n/a n/a Commercial Operation 09/28/1973 04/05/1976 Feedwater Flow Rate at full power 1.40 E07 lbs/hr 1.35 E07 lbs/hr Routing of Feedwater Drains Drains from 5th and 6th feedwater heaters are recovered in the heater drain tanks and pumped forward without polishing Steam Pressure (Full Power) 755 psia 755 psia Saturation Temperature of Steam 512 °F / 267 °C 512 °F / 267 °C Reactor Coolant System Average Temperature 565 °F / 296 °C 569 °F / 298 °C Reactor Coolant Hot Leg Temperature (PWR)595 °F / 313 °C 599 °F / 315 °C Reactor Coolant Cold Leg Temperature (PWR)538 °F / 281 °C 540 °F / 282 °C Steam Generator #/Make/Model (4) Westinghouse Model 44F Steam Generator tube material Alloy 600TT (repl 2000) Alloy 690TT (repl 1989) Number of Steam Generator tubes / %
plugged12856 / 0.26% 12856 / 0.12%
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 6 of 35 Parameter Unit 2 Value Unit 3 Value SG Tube Layout and Tube Expansion Square Pitch layout with full depth hydraulic expansion within the tubesheet Steam Generator Tube Surface Area, Primary Side, ft2 43,467 ft2 Steam Generator Tube Support material
& configuration 405SS, quatrefoil broached tube holes Steam Generator Blowdown Overboard Recovered Blowdown Polishing System None1% system flow, (3) 75 cu. ft. beds blowdown recovered through cation resin bed followed by mixed resin bed and 25 micron post filter.
Condensate Polishing None Graver Deep Bed: full flow during startup; bypassed during operation Condenser Tube Material Titanium Condenser Cooling Type Once Through Cooling Water Source Hudson River - brackish water Condenser Design Single pass, single pressure, three shells 6 water boxes with titanium tubes and tubesheets Feedwater Heater Tube Material 439 SS Moisture Separator Reheater Design /
Tube Material Stainless Steel Chevron Separators with 304 SS tubing TurbineWestinghouse designed. Turbine blades and new blade rings in the HP turbine are stainless steel. Turbine valves have some high alloy 4340 components and stainless steel. Turbine casing mainly carbon steel plate. Westinghouse designed. Westinghouse supplied stainless steel replacement HP Turbine blades and blade rings. ABB supplied stainless steel replacement LP Turbine blades. Turbine valves have some high alloy 4340 components and stainless steel. Turbine casing mainly carbon steel plate.LP Turbine Rupture Disks All 12 are lead 8 of 12 replaced with stainless steel; 4 remaining are lead Makeup Water GE Deltaflow DI Water System utilizing filter beds, carbon beds, reverse osmosis, gas transfer membrane (GTM), chemical deox with hydrazine/carbon bed, cation softener, EDI, carbon bed and low sodium mixed bed. Capacity is about 220 gpm Secondary Side Piping Material Carbon Steel and Chrome Moly Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 7 of 35 4.2 IP2 Notable Historical Events/Milestone Activities U2 Milestone/Activity Date Purpose Effect/Result Commercial Operation w/phosphate & hydrazine 1974Prevalent boiler chemistry at
timeAVT Chemistry 1975 Reduce solids in SG Boric Acid Addition 1978 Mitigate tube denting at
support plates Denting reduced Began SG Sludge Lancing each refueling 1978Remove secondary tubesheet
depositsRemoved significant amounts of sludge MSR tube replacement
w/stainless 1982Remove copper bearing alloys from secondary side Reduced copper inventory Replaced (3)HPFW heaters
w/stainless tubes 1982Remove copper bearing alloys from secondary side Reduced copper inventory Replaced (9)HPFW heaters
w/stainless tubes 1987Remove copper bearing alloys from secondary side Reduced copper inventory Replaced 21 Main Condenser w/titanium tubed modular
units 1991Remove copper bearing alloy
& reduce tube leaks Reduced copper inventory; reduced SG ionic impurities Replaced 22 Main Condenser w/titanium tubed modular units 1993Remove copper bearing alloy
& reduce tube leaks Reduced copper inventory; reduced SG ionic impurities Replaced 23 Main Condenser w/titanium tubed modular units 1995Remove copper bearing alloy
& reduce tube leaks Reduced copper inventory; reduced SG ionic impurities Began ETA addition 1995 Reduced HPFW corrosion product transport Corrosion product transport
reducedReplaced (6) LPFW heaters w/stainless & gland steam condenser w/titanium 2000Remove copper bearing alloys from secondary side Reduced copper inventory Changed DI Makeup Water System from house to vendor 1999Improve makeup water quality with sophisticated equipment SG ionic impurities were
reducedReplaced SGs with A600TT
tubing2000 Improved corrosion resistance Reduced risk for degraded
tubesAttempt to remove tramp copper from BOP w/ammonia 2000Chemical addition prior to S/U to remove copper Some success at removing
copper; able to increase pH Plant uprate by 1.4% 2003 Increase plant output by reducing measurement uncertainty Virtually no change in operating temperatures Plant uprate by 4.7% &
Moisture Separator Replacement 2004Demister pads replaced with SS chevrons Eliminated source for demister wire in SG; increased Thot from 587 to
597F4.3 IP3 Notable Historical Events/Milestone Activities U3 Milestone/Activity Date Purpose Effect/Result Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 8 of 35 U3 Milestone/Activity Date Purpose Effect/Result Commercial Operation w/ammonia & hydrazine 1976 Never used phosphates Reduced solids in SG SG tube leaks & denting 1978 n/a Forced outages Boric Acid Addition 1978 Mitigate tube denting at
support plates Denting reduced MSR tubing replaced
w/stainless 1982Remove copper bearing alloys from secondary side Reduced copper inventory Feedwater heater tubing replaced w/stainless 1985Remove copper bearing alloys from secondary side Reduced copper inventory Replaced main condensers
with titanium tubes &
titanium tubesheet 1985Remove copper bearing alloy
& reduce tube leaks Reduced copper inventory; reduced SG ionic impurities Installed Full Flow
Condensate Polisher 1986 Reduce ionic impurities Improved SG impurities/discontinued
boric acid Installed SG blowdown recovery system 1987Increase plant efficiency; improve SG chemistry Reduced water makeup led to improved SG chemistry.
Installed ultrafiltration on water treatment system 1987 Reduced halogenated organic in makeup water Reduced halogens in SG chemistry Replaced SGs w/A690 tubing 1989 Improved corrosion resistance Reduced risk for degraded
tubesReplaced gland steam & air
ejector condensers w/SS 1989Remove copper bearing alloys from secondary side Reduced copper inventory; ability to increase pH Started Morpholine chemistry 1989 Reduce BOP corrosion & HPFW iron transport Reduced iron transport;
required CPF partial flow Resumed boric acid addition 1989 Proactive measure against ODSCC Slight increase in iron
transportReplaced Morpholine w/ETA March 1998Reduce BOP corrosion &
HPFW iron transport Reduced iron transport; CPF bypassed except
during S/U Boric acid concentration
reduced 1999Reduce iron transport while getting some ODSCC benefit Improvement in iron
transport Reduced nominal SG blowdown flowrate 1999 Improve thermal efficiency Little impact on SG chemistry Significant BOP pipe
replacement 1999 Reduced FAC with chrome moly pipe Iron transport reduced Changed DI Makeup Water System from house to vendor system 1999Improve makeup water quality with sophisticated equipment SG ionic impurities were
reducedHPFW hydrazine reduced 2000 Per EPRI guidelines, no longer operating >100 ppb No impact Boric acid addition discontinued 2000 Evaluate effect on iron
transportIron transport reduced Plant uprate by 1.4% 2002 Increase plant output by reducing measurement uncertainty Virtually no change in operating temperatures Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LAN Page 9 of 35 U3 Milestone/Activity Date Purpose Effect/Result Replaced HP turbine and MSR internals 2005Modification to support stretch power uprate of 4.8% Eliminated source of demister pad wire in SG. 4.4 IP2 Significant Chemistry Transients Significant chemistry transients are those above the EPRI Guideline threshold for Action Level 2 or greater. There has been only once such chemistry event since
SG replacement. 4.4.1 On March 13, 2005 the steam generator blowdown chloride concentration exceeded the Action Level 2 (AL2) threshold of 50 ppb while at 100
percent power. The maximum recorded value was 55.5 ppb and sodium
peaked at 29 ppb. The source of the intrusion was a water box leak and
the duration above AL2 was less than 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The event was
considered to have an insignificant effect on the steam generators
because of the short duration. (CR-IP2-2005-01087) 4.5 IP3 Significant Chemistry Transients Significant chemistry transients are those above the EPRI Guideline threshold for Action Level 2 or greater. There have only been three such events since the
steam generator replacement at IP3 and they are identified below. 4.5.1 On January 5, 1991 the cation conductivity in steam generators 32 and 34 increased to 2.04 and 31 heater drain pump into service followingmaintenance. About 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
later the SG chlorides reached a maximum concentration of 55 ppb which
was also just above the Action Level 2 threshold of 50 ppb. SG Sodium
also peaked above AL2 with a maximum recorded value of 68 ppb. All
contaminants were returned to less than Action Level 1 values within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> so the event was considered to have an insignificant effect on the
steam generators. 4.5.2 On December 18, 1992, Steam generator cation conductivity increased mmediately after placing condensate polisher E vessel into service following maintenance. The contamination was organic and did not have significant levels of chloride or sulfate. Organic acids are
considered benign with respect to SG corrosion. 4.5.3 On April 1, 2007 steam generator blowdown chloride and sodium concentrations exceeded action level 2 for several hours as a result of a plug being dislodged from a tube in the main condenser during startup (CR-IP3-2007-01756). Integrated exposure was used to evaluate the
event as non-consequential. 5.0 Evaluation of Technical Issues, Including Risk/Susceptibility The objective of this section is to develop a reasonable framework for ranking the relative susceptibility of various major components/systems to corrosion Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 10 of 35 damage/performance degradation or in some cases their reliability in performing their design function. Only those design features or operating parameters which influence degradation through interaction with the water chemistry program were
considered. 5.1 Relative Corrosion Susceptibility of Major Components/Systems Table Component Susceptibility Cost Impact of Failure Influence on Establishing Water Chemistry ProgramSteam Generator Low - corrosion Medium - fouling High High HP & LP Turbines Low Medium Low Extraction Lines (large bore) High Medium Medium Extraction Lines (small bore) High Medium Medium MSR, Crossunder Piping &
Drains Medium Medium Medium Main Condenser Low High Medium Feedwater Heaters Low Medium Low Blowdown Piping Low Medium Low 5.1.1 Steam Generators The replacement SGs at both IP2 and IP3 with thermally treated Alloy 600 and
690 tubing respectively have a low susceptibility to corrosion. On the secondary
side of the tubes both units are susceptible to outside diameter stress corrosion
cracking (ODSCC) with the A 690TT tubing at Unit 3 being less susceptible. To date there has been no tube plugging due to corrosion degradation at either unit.
Other factors besides tubing material contributing to low corrosion susceptibility are hot leg temperatures less than 600F, stainless steel broached tube support plates and hydraulic expansion of the tubes over the full depth of the tubesheet. The steam generators at both units are ranked medium in susceptibility to fouling of the tube support plate (TSP) broach holes with corrosion products. This can
lead to thermal hydraulic instabilities which have contributed to tube fatigue
failures. Minimizing corrosion product transport mitigates this risk and chemical cleaning can correct the condition if warranted.
Because the control of contaminants and corrosion product transport to the steam generators is important for mitigating corrosion and fouling, the SGs are strong drivers for the secondary water chemistry program.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 11 of 35 5.1.2 HP and LP Turbines The HP and LP turbines are ranked as having low susceptibility to chemistry related corrosion attack since only minimal quantities of impurities are
transported from the steam generators as a result of moisture carryover. The cost of turbine rotor repair or replacement due to corrosion degradation is
medium. 5.1.3 Extraction Steam Lines and MSR Crossunder Piping The Extraction Steam system and MSR Crossunder piping are ranked as having
a medium susceptibility to corrosion. Repairs or replacement of system components has been extensive due to flow accelerated corrosion (FAC). Small
bore piping (<
2") has demonstrated low reliability because of piping failures from FAC. Future susceptibility of these components to FAC has been reduced due to repairs using FAC resistant materials and improvements to secondary cycle chemistry. Piping modifications using chrome moly steel has helped decrease
iron transport. 5.1.4 Main Condenser The original tubing in the main condensers at both units was admiralty brass and
prone to corrosion leading to frequent leaks of river water into the secondary system. The tubing at both units was replaced with titanium and has been essentially leak free. Titanium tubes have a low susceptibility to corrosion. The cost of failure is ranked high because the resulting contaminant ingress can lead
to accelerated corrosion of the tubing in the steam generators. They have a medium influence on the establishing the water chemistry program with
monitoring being the primary focus. 5.1.5 Feedwater Heaters and Piping The feedwater heaters and piping have been ranked low in susceptibility to
corrosion. The tubing in the feedwater heaters was replaced with 439 stainless steel so there is no copper in the secondary system to limit secondary system
pH. The shells of the feedwater heaters are susceptible to flow assisted corrosion (FAC) which can be controlled with pH control chemicals. The #31A, B&C feedwater heaters have had several tubes plugged as a result of steam
impingement erosion. The feedwater heaters and piping had a low influence on
establishing the secondary water chemistry program. 5.1.6 SG Blowdown System Piping The blowdown piping is stainless steel and is ranked low in corrosion susceptibility. The cost of failure is considered medium since blowdown is
required to control contaminants in the steam generators. Its influence on
establishing the water chemistry program is low.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 12 of 35 5.2 Relative Component Reliability with Impact on Water Chemistry Performance Component Reliability Cost Impact of Failure Impact of Component Performance on Water Chemistry Makeup Water High Medium Medium Chemical Feed System Medium Low Medium Main Condenser High High High Condensate Polishers (IP3 only) Medium Low Medium Blowdown Demineralizers (IP3 only) High Low Medium 5.2.1 Makeup Water In 1999 the station installed an advanced, vendor operated makeup water system. Prior to this each unit operated a standard demineralizer system
consisting of a carbon bed, cation, anion and mixed bed resins which was not
able to remove halogenated organics. The current system utilizes filter beds, carbon beds, reverse osmosis, gas transfer membrane (GTM), chemical deoxygenation with a hydrazine/carbon bed, cation softener, EDI, carbon bed and low sodium mixed bed. The system capacity is about 220 gpm. This capacity is not adequate to supply both units when one of them is starting up and requires high levels of blowdown. In this situation a portable system is brought in which provides adequate water quality but not as good as the installed system. The Make-up Water system has high system performance reliability in producing high quality water for plant make-up requirements. The system also has a high influence on the secondary cycle water program since poor quality make-up water will introduce impurities that influence increased secondary system corrosion. Since the installation of the "state-of-art" vendor operated system in 1999, compliance with EPRI recommended specifications for plant make-up
water has exceeded 99%. 5.2.2 Chemical Feed System The Chemical Feed system is very reliable in its operation. The Chemical Feed system has a high level of influence on the secondary cycle water program due
to the system's ability to introduce impurities into the secondary cycle. Continued use of treatment chemicals with low impurity content will allow this system to be a low impurity source for the secondary cycle. 5.2.3 Main Condenser The Main Condenser has a high influence on the secondary cycle water program. Tubesheet and tube leaks can introduce impurities into the secondary cycle, which influence various steam generator corrosion mechanisms. However Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 13 of 35 the Condensers at both units are highly reliable, the titanium materials of construction are corrosion resistant. Titanium is susceptible to fouling on the
riverside of the tubes from algae and other organic matter. As a result of this fouling, condensers are treated with chlorine weekly during warm weather
months to maintain performance.
Since Unit 2 does not have a condensate polisher and U3 no longer operates the condensate polisher during normal operations, neither unit has a protective barrier to limit impurities introduced to the steam generators as a result of a
condenser leak. That is why the main condenser has a high impact as a result of
failure. At Unit 3, 4 tubes were plugged on the south side of #35 water box as result of impact from a broken turbine blade subsequent to condenser replacement. At
Unit 2 4 tubes were plugged in #25 Water Box as a result of probable impact damage. One tube was plugged following identified leakage and 3 other tubes
were plugged as a result of follow up eddy current testing. 5.2.4 Condensate Polisher (Unit 3 only) The Condensate Polisher Facility (CPF) at Unit 3 has been reliable in operation.
However, due to costs and elevated SG sodium values when polishers are in-
service, the CPF is only used during start up from outages. The CPF is rated high on water chemistry influence because it is relied upon during start up of Unit
3 in full flow mode to decrease the corrosion product transport to the steam
generators and reduce the possibility of a mid-power value (MPV) power hold for chemical impurities. The impact of failure is low because it is not needed during
normal plant operations. 5.2.5 SG Blowdown Demineralizers (Unit 3 only)
The blowdown demineralizers at Unit 3 are highly reliable in performing their designed function and have a high impact upon secondary and steam generator system chemistry. There are two 75 ft3 cation demineralizers (one in service and the other in standby) followed by a 75 ft3 mixed bed 2:1 Anion to Cation by
volume and a 25 micron post filter. After exhaustion the cation beds are transferred to containers (HIC), transported to the CPF and regenerated. The
mixed bed resin is used once and replaced with new resin upon exhaustion. 5.3 Major Component Prioritization Component High MediumLow Steam Generator X HP Turbine X LP Turbines X Extraction Lines (large bore) X Extraction Lines (small bore) X Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 14 of 35 Component High MediumLow MSR Crossunder Piping & Drains X Feedwater Heaters and Piping X Blowdown System Piping X Blowdown Demineralizers (IP3 only) X Main Condenser X Condensate Polishers (IP3 only) X Makeup Water System X Chemical Feed System X 5.3.1 Steam Generators Replacing the IPEC steam generators was a costly modification that may not be economically feasible to repeat. Fortunately, the current steam generators are not expected to experience degradation over their service lives. The steam generators are susceptible to tube fouling over time as corrosion products build
on tube surfaces. This can reduce thermal performance to the point of lost generation capacity and the corrective action of chemical cleaning is expensive at $8-10 million. So keeping the SGs clean is a high priority. Keeping the SGs clean will also reducethe sludge sites where impurities can concentrate and raise the corrosion potential of the tube surfaces.
The Steam Generators are rated high in priority due to susceptibility of the tubing to corrosion, decreased performance from tube fouling and broach hole plugging.
In addition Steam Generator replacement, repair, and chemical cleaning are very
high cost items.
5.3.2 Turbines The turbines are ranked as low priority when optimizing the secondary system
water chemistry because of their low susceptibility to chemistry related corrosion
and performance degradation. 5.3.3 Extraction Steam Lines, MSR Crossunder Piping The Extraction Steam lines and MSR crossunder piping are ranked as medium priority components because of their continuing susceptibility to general and flow
accelerated corrosion (FAC). The iron transport caused by the corrosion of these components is deleterious to the SGs from both fouling and potential corrosion
perspectives .The optimization of the secondary cycle chemistry program has targeted portions of these systems for iron transport reduction and FAC
concerns. Piping modifications have helped decrease iron transport.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 15 of 35 5.3.4 Feedwater Heaters and Piping The Feedwater Heaters and piping are ranked low priority components for secondary chemistry optimization due to their low susceptibility to corrosion and
low influence on the secondary cycle water program. 5.3.5 SG Blowdown System Piping The Blowdown system piping is ranked as low priority components for secondary chemistry optimization due to their low susceptibility corrosion and low influence on the secondary cycle water program. 5.3.6 SG Blowdown Demineralizers (Unit 3 only)
The blowdown demineralizers at Unit 3 are ranked low on secondary chemistry
optimization due to their high reliability and the option to achieve SG contaminant control by directing blowdown overboard. 5.3.7 Main Condenser The Main Condenser has been ranked low in priority because of its reliability for leak free performance and its low contribution to corrosion product transport. 5.3.8 Condensate Polisher (Unit 3 only)
The Unit 3 Condensate Polisher system is ranked medium in prioritization because of the potential to use the CPF as a source of iron transport removal
during plant startups. 5.3.9 Makeup Water The Make-up Water system is ranked low in prioritization due to the high
performance of the system to produce high quality water for plant make-up
requirements. 5.3.10 Chemical Feed System The Chemical Feed System is ranked medium in prioritization due to the systems importance for injecting hydrazine to maintain a reducing environment. Loss of hydrazine injection for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> requires a plant shutdown per the
EPRI Guidelines. 5.4 Low Power Value (LPV) Selection Rev 7 of the EPRI Secondary Chemistry Water Guidelines requires each site to
establish a low power value LPV based on operational needs and impurity control. The LPV established shall be within 5 and 15% reactor power. For both
IP2 and IP3 the LPV is 15% reactor power. The basis is presented below:
LPV justification - The basis for setting the LPV to 15% reactor power is as follows: Sufficient steam flow to establish a good condenser vacuum and CPD oxygen concentration Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 16 of 35 Sufficient feedwater flow and time to move oxygen and hydrazine control parameters to high pressure feed water monitoring from CPD. Provide margin from some turbine trip permissives established in this power region; Permissive 10 which is armed at ~10 percent power and could result in an inadvertent feed water trip if power were to dip slightly if the unit was holding is this power range during startup. Permissive 8 which arms reactor trip to turbine trip circuitry at 18%. Allows the unit to move steam across turbine blades and limitedly through the MSRs and drains to access potential steam path impurities and clean them
up while the steam generator has little or no concentration factor. 5.5 Mid Power Value Selection The MPV established shall be within 30 and 50% reactor power. For IP2 and IP3
the MPV is 35%. The basis is presented below: This power value allows: Main boiler feed pump to be placed in automatic with ~ 4000 rpm Ensures that 1 st Heater Drain Tank pump is in service in auto Minimize concentration effects in the steam generators 5.6 Action Level 2 Power Value Selection The Action Level 2 power reduction value established shall be within 30 and 50% reactor power. The Action Level 2 power reduction value selected for both IP2
and IP3 is 30%. This value minimizes impurity hideout in the steam generators and there are no operational considerations that warrant establishing a higher value. There may be circumstances where a higher power level such as <50%
would be more appropriate for mitigating the effects of a chemistry excursion. An
example might be sodium contamination of the metal surfaces of the moisture
separators. Situations such as these will be handled on a case by case basis. 6.0 Evaluation of Chemistry Control Strategies This section presents a variety of chemistry control strategies that can be used to
adjust those parameters that were shown to accelerate corrosion of steam generator tubing materials. Included in this section are: ALARA Chemistry Control Molar Ratio Control (MRC)
Integrated Exposure Chemical Inhibitor Injection Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 17 of 35 Boric Acid Treatment (BAT) Titanium Dioxide Minimization of Steam Generator Oxidant Exposure Elevated Hydrazine Steam Generator Layup Secondary Cycle pH Control Steam Generator Deposit Management Dispersants Mechanical Cleaning Chemical Cleaning Hideout Return Evaluations Condensate Polisher Operation (IP3)
A summary of the expected impact of the above approaches on key secondary system components is given in the table below.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 18 of 35 6.1 Evaluation of Secondary Chemistry Strategies for IPEC Chemistry Initiative SteamGenerator HP & LP TurbinesExtraction Lines MSRConden-serFW System Condensate Polisher (IP3) Blowdown Demin (IP3)Cost/Benefit ALARA Chemistry Lowers risk to corrosion Lowers risk to corrosion No influence No influence No influence No influence Source of sodium and sulfate during operation Reduced ionic loading Cost of blowdown versus risk of low contaminant concentrations Molar Ratio Control May prevent /
mitigate IGSCC No influence No influence No influence No influence No influence No influence No influence low cost, low risk, potential benefit SG integrity Integrated Exposure Used to assess contaminant ingress No influence No influence No influence No influence No influence No influence No influence Low cost; qualitative assessment only Boric Acid Treatment May prevent IGSCC Little influence Slightly lower pH increases transport Slightly lower pH increases transport Slightly lower pH increases transport Little influence Increased sodium leakage Increased impurity leakage Low cost; not shown to prevent SCC; negative impact on iron transport Chemical Inhibitor Injection Potential IGA/SCC mitigation No influence No influence No influence No influence No influence No influence No influence Modification required; unproven benefit Elevated Hydrazine Maintains reducing environment No influence Reduced corrosion due to increased pH Reduced corrosion due to increased pH Reduced corrosion due to increased pH Reduced corrosion due to increased pH Increased loading Increased loading Moderate cost but potentially large benefit to SG corrosion Secondary Cycle pH Control Elevated system pH t to reduce iron transport and FAC Will increase pH t in turbine, reduce corrosion Will increase pH t in lines, reduce corrosion and FAC Will increase pH t in lines, reduce corrosion and FAC May decrease FAC if any source in the condenser Will increase pH t in lines, reduce corrosion and FAC No impact expected run in filtration mode Increase cation loading, reduce run length Benefit of reduced FAC and corrosion product transport to the SGs versus chemical costs Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 19 of 35 Chemistry Initiative SteamGenerator HP & LP TurbinesExtraction Lines MSRConden-serFW System Condensate Polisher (IP3) Blowdown Demin (IP3)Cost/Benefit Dispersants Reduces corrosion products retained in SG No influence No influence No influenceNo influenceNo influence, may influence corrosionproduct releasedownstream Increased loading due to
CO2 Increased
loading due
to CO2 High chemical cost; experience shows 50% of incoming corrosion products removed via blowdown versus 10%
SG Mechanical Cleaning Removes corrosion products No influence No influence No influence No influence No influence No influence No influence Relatively moderate cost; removes only percentage of tubesheet deposits SG Chemical Cleaning Removes corrosion products from entire SG No influence No influence No influence No influence No influence No influence No influence High cost; restores SG & reduces tube corrosion risk Hideout Return Evaluation Used to predict crevice pH No influence No influence No influence No influence No influenceNo influence No influenceLow cost; high uncertainties with low level returns Bypass Condensate Polisher Operation (IP3) Increased risk of contaminants during condenser tube leak; decreased sodium & sulfate during normal operations; useful for startup No influence No influence No influence No influence No influence Reduces operation; concern for maintaining equipment / resin No influence Lower cost and higher benefit to bypass under normal operation; use during S/U for corrosion product and impurity control Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 20 of 35 6.2 ALARA Chemistry Recirculating steam generators (RSGs) such as those at IPEC concentrate impurities introduced via the feedwater. In particular, local environments within the SGs such as crevices and sludge piles can accumulate impurities to the extent that extreme pH conditions are created. These conditions put stress on the SG tubing and can lead to intergranular attack (IGA) or stress corrosion
cracking (SCC). Industry experience has shown that the application of ALARA chemistry has been insufficient to prevent or mitigate IGA/IGSCC at most plants with susceptible tube material and design. Nonetheless, ALARA chemistry is the
most acceptable approach for minimizing the rate of impurity accumulation in steam generator crevices. Several initiatives have been implemented at IPEC
over the years to reduce the SG blowdown impurity concentrations from several
ppb to the sub-ppb range. The current makeup water system provides high quality water with effluent sodium nominally less than 0.05 ppb and total organic carbon less than 2 ppb.
This water quality is especially important for IP2 which does not recover its SG blowdown. The replacement of the condenser tubes with titanium has resulted in
virtually no condenser inleakage of cooling water impurities. The station also has an aggressive chemical control program especially with regards to new
secondary side components. New components are received with no preservative
coatings and are inspected prior to installation. The use of chemicals that can be used with secondary side components are tightly controlled. At unit 3 a SG blowdown recovery system was installed primarily for thermal efficiency but has improved SG chemistry by reducing the quantity of makeup water to the secondary system. Also, at unit 3 a decision was made to bypass the condensate polisher during normal operations because it was a source for sodium and sulfate contamination in the SGs. This was achievable as a result of the high reliability of the titanium condensers.
The current ALARA strategy is to maintain or better the current the makeup water quality and control SG blowdown as necessary to achieve SG sodium, chloride and sulfate concentrations below 0.8, 1.7 and 1.8 ppb respectively. 6.3 Molar Ratio Control The goal for molar ratio control (MRC) is to maintain a balance of cations and anions in the steam generator blowdown during normal operation such that the SG crevice pH is near neutral. Near neutral crevice pH is expected to minimize IGA/SCC initiation in the SGs. The effectiveness of MRC is measured through hideout return evaluations. If a balance can not be achieved by reducing certain
species then typically a form of chloride is added to the feedwater in low
quantities. A major obstacle in implementing molar ratio control is to determine which species and their amounts in the hideout return came from crevices relative to Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 21 of 35 the hideout return from other areas in the steam generator. The hideout return data are used to modify the bulk chemistry control during subsequent operation.
The preferred approach is to reduce the concentration of the dominant strong anion or cation. When this approach is exhausted or no longer cost effective, the remedy for excess cations over anions in some cases is to add chloride. The remedy for excess anions over cations is to reduce the anions. This is particularly difficult if the excess anion is sulfate, since the behavior of sulfate is different than that of monovalent anions such as chloride. Field data on the effectiveness
of MRC does not yet support its effectiveness.
IPEC has an MRC program available. Hideout fractions (HOF) were determined by decreasing blowdown and measuring the increase in ionic contaminants.
HOFs are 0.35 for chloride, 0.56 for sodium and 0.8 for sulfate. MRC will not be implemented at IPEC unless the hideout return molar ratio indicates a caustic condition in the SG crevices. 6.4 Integrated Exposure Research completed under EPRIs Heated Crevice Program shows that the mass of accumulated impurities in crevices in RSGs is proportional to the exposure. Integrated exposure was introduced in Revision 5 of the Guidelines as a diagnostic parameter for recirculating steam generators for assessing the relative amount of harmful impurities accumulated in RSG crevices. The current
revision of the Guidelines no longer has it as a diagnostic parameter but retained the methodology as a tool that may be useful for evaluating chemistry
excursions. Integrated exposure has been used at IPEC for evaluating a condenser tube leak and IPEC will use this tool again if there are significant chemistry excursions in the future. 6.5 Corrosion Inhibitor Injection 6.5.1 Boric Acid Treatment Both IP2 and IP3 used boric acid addition to mitigate tube denting in the original
SGs with carbon steel, drilled hole support plates. The replacement SGs at both units have stainless steel tube support plates with broach holes that are not susceptible to the tube denting phenomenon. There was some laboratory data to suggest that boric acid might mitigate the initiation of IGA/SCC and reduce crack propagation rates in caustic environments. Based on this information and the low
cost of treatment, IP3 continued boric acid addition after SG replacement but later discontinued the practice when it was determined that it contributed to
feedwater corrosion product transport. Boric acid addition was not done at IP2
after SG replacement. There are no plans to add boric acid at either unit. 6.5.2 Titanium Dioxide Treatment Tests indicate that titanium becomes incorporated in films on 600MA and thereby
increase resistance to SCC in high temperature caustic solutions. Laboratory Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 22 of 35 tests using C-rings and constant extension rate specimens have shown that titanium inhibits SCC in caustic environments. Titanium and some other materials inhibit attack in 50% caustic relative to that experienced in pure caustic without
the inhibitor. Model boiler tests indicate that titanium is effective against caustics if the crevices are clean, but are not effective if the crevices are packed with deposits; apparently deposits in the crevices prevent the titanium from reaching the crack tip location. Several plants have used titanium inhibitors. Those units that initiated its use after chemical cleaning have experienced relatively low rates
of IGA/SCC subsequent to the chemical cleaning. While this experience is encouraging, there is insufficient experience to make strong judgments
concerning the benefits provided by titanium inhibitors. In addition, several other plants that have recently chemically cleaned and have not added titanium have also observed less than expected IGA/SCC, which indicates that the benefits
may be more due to chemical cleaning than to use of titanium inhibitors. Since IPEC has not experienced problems with caustic crevices this option will not be used. The station will strive to have slightly acid crevices through ALARA
chemistry and MRC. 6.6 Steam Generator Oxidant Exposure 6.6.1 Elevated Hydrazine Hydrazine reacts with oxygen to form water, hydrogen, and nitrogen. Maintaining a feedwater hydrazine concentration at least eight times the condensate dissolved oxygen concentration promotes a reducing electrochemical potential (ECP) environment in the final feedwater and the steam generators. It also helps
to protect against the transport of reducible metal oxides to the steam generator.
Both of these effects contribute to reduce risk for corrosion in the steam generators. Hydrazine breaks down in the steam generators to ammonia which carries over in the steam to aid in pH control. This coupled with the pH additive
ETA serves to minimize the corrosion of BOP materials and corrosion product transport. Both units are currently all ferrous so elevated pH values are not a
concern. Previous revisions to the EPRI Secondary Chemistry Guidelines recommended maintaining feedwater hydrazine greater than 100 ppb which Entergy adopted but this recommendation has been removed from the current revision. Higher concentrations of hydrazine increase operating costs. At Unit 3 increased hydrazine puts additional loading on the SG blowdown demineralizers. The
current hydrazine strategy at both IP2 and IP3 is to maintain the feedwater concentration greater than either 20 ppb or eight times the condensate dissolved
oxygen concentration but below 100 ppb. Since plant operations can cause fluctuations in the condensate dissolved oxygen it is desirable to maintain a
margin for the greater than 8 X [CPD O2] requirement. Under normal operating conditions where the condensate dissolved oxygen concentration is less than 5
ppb, the target hydrazine concentration is typically 60 to 80 ppb.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 23 of 35 6.6.2 Steam Generator Layup Chemistry It is important to ensure the corrosion products that inevitably exist in the steam generators be kept in a reduced state to minimize the risk of corrosion that can occur with oxidized metal species. During plant cold shutdown conditions, oxygen content must be kept to a minimum and excess hydrazine must be added. In addition to this, pH must be controlled and a nitrogen blanket maintained over the SG water level. IPEC will establish SG layup chemistry as
soon as practical after establishing Mode 5 conditions commensurate with the
SG maintenance to be performed during the outage. Due to gas leakage past the main steam isolation valves, IPEC does not maintain a nitrogen overpressure in
the SGs during cold wet layup but has found that oxygen ingress is kept to a
minimum if the SGs are nitrogen sparged for 15 minutes at least once every 3
days. 6.7 Secondary Cycle pH Control The goal of secondary cycle pH control is to achieve a basic pH throughout the secondary cycle which minimizes corrosion of secondary piping and components
which in turn minimizes the mass of corrosion products transported to the steam generators. Each unit was originally designed for ammonia from the breakdown
of hydrazine as the secondary pH additive but this did not result in very high pH
values in the higher temperature, steam phases of the secondary cycle. Alternate amines have been evaluated and the current selection is ethanolamine (ETA)
along with the ammonia from the breakdown of hydrazine used for oxygen
control. The current IPEC secondary pH control strategy is to target a pH t of 1.0 or greater than pH t neutral throughout the secondary system. To accomplish this ETA is targeted at approximately 5 ppm and the secondary drains are routed inboard as much as possible to maximize the ammonia concentration. This chemistry combined with piping changes with chrome-moly associated with FAC
reduction have reduced feed water iron transport to <1.0 ppb at each unit.
Neither ETA nor hydrazine has a significant contribution to contaminant levels in
the steam generators. The use of ETA has increased the concentration of organics in the secondary system however; there are no reports of detrimental effects due to organics, at their current levels.
Unit 3 has been evaluated for feedwater ETA concentrations as high as 6 ppm and Unit 2 as high as 10 ppm. Entergys vendor for modeling FAC conditions prepared a report in 2010 which provides recommendations for optimizing secondary chemical concentrations to reduce FAC wear in the secondary system (reference 10.10). It is no surprise that higher concentrations of feedwater ETA, ammonia, hydrazine and condensate dissolved oxygen result in theoretically less wear. Based on the ranked chemistries, it appears that feedwater ammonia has
the largest impact on FAC wear with ETA having the second largest effect.
Currently, the feedwater ammonia concentrations at both units vary with the cooling water temperature with the highest concentrations occurring in January Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 24 of 35 and February (6-8 ppm) versus an August concentration of 1.5 ppm. Feedwater iron trends at Unit 2 supports the effect of ammonia with the iron concentration at
its lowest in the winter with ammonia at the maximum concentration. Currently there are no plans to inject more chemicals in the secondary system to further improve iron transport due to the increased chemical cost at both units
and the increased ionic loading on the Unit 3 SG blowdown cation demineralizers. For comparison with prior pH control treatments, feedwater iron concentrations were typically 20 ppb using ammonia and 6 ppb with morpholine at IP3. During the initial switch to ETA at about 2 ppm, the feedwater iron concentration dropped to about 3 ppb. As more of the extraction drain piping was replaced with
more FAC resistant materials the feedwater iron concentration has dropped to its
current nominal value of less than 1 ppb. 6.8 Steam Generator Deposit Management There are several means available to manage the corrosion products transported
to the steam generators. One is to filter the feedwater which can be done in preparation and during plant startup. Second is the option to use dispersants which increases the effectiveness of corrosion product removal via SG blowdown. Third is to perform periodic mechanical cleanings of the secondary side of the steam generators with techniques such as sludge lancing and high
volume bundle flush. These methods are considered proactive in maintaining SG cleanliness. A fourth option which is remedial in nature is chemical cleaning. This can be a mild chemical cleaning with an advanced scale conditioning agents (ASCA) or the more aggressive cleaning method such as the Steam Generator
Owners Group (SGOG) process. 6.8.1 Startup Corrosion Product Filtering This is currently done at both units in preparation for startup. At IP2 trailers with demineralizers are brought in to perform a long path recirculation of the condensate and feedwater systems. At IP3 the existing condensate polisher facility (CPF) is used to filter corrosion products during long path recirculation.
IP3 also uses the CPF during startup through 30% power to remove ionic
impurities to minimize the SG contaminants. 6.8.2 Dispersants Another chemical treatment option that is currently being tested in the industry is dispersants. Dispersants are chemicals that keep corrosion products suspended in the SG bulk water so they are more effectively removed by blowdown and dont deposit on SG tube surfaces. Dispersants have the potential benefit to keep SGs clean enough to avoid chemical cleaning and reduce the frequency for mechanical cleaning measures. As of 2011, 6 plants have initiated routine long-
term use of a dispersant during normal operation. Trials are being conducted on the use of dispersants during SG wet layup and long-path recirculation cleanup.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 25 of 35 It is reported that the cost for dispersant usage during normal operation is approximately $100k/year-unit. Given the current iron transport levels of less than 1 ppb at both IP2 and IP3 it is not clear that there is enough benefit to justify the expense at this time. EPRI is working with several plants to pilot the use of dispersants with SG layup and during long path recirculation of the condensate/feedwater systems during startup. The dispersant expenses are much lower in these applications and could
prove beneficial at IPEC in the future. IPEC staff will continue to monitor the use
of dispersants under these situations. 6.8.3 Steam Generator Mechanical Cleaning There are several methods available to mechanically clean the secondary side of the steam generators. The most common is top of tubesheet sludge lancing in which a high pressure (2500 psig) water lance is sprayed across the tubesheet between columns of SG tubes. Initially, the IP3 SGs were sludge lanced each
refueling outage. This was when unit 3 had feedwater iron transport of 5 ppb
resulting in about 300 pounds of corrosion products being transported to each
SG. This number dropped to about 100 pounds/SG with the feedwater iron at 1 ppb. The sludge lancing frequency was reduced to generally every other
refueling outage or 4 years.
When the unit 2 SGs were replaced in 2000, the iron transport was already significantly reduced so the sludge lance frequency has historically been every other refueling outage. Although the mass of corrosion products removed with sludge lancing has been less than 25 pounds/SG, another factor for not
extending the sludge lance frequency is the removal of small foreign objects from
the SG. In 2001, a high volume bundle flush was used in the unit 3 steam generators in an attempt to remove corrosion products from the upper portions of the SG tube
bundle. Using this method the percentage of transported deposits removed
increased from about 17 to 37%. The subsequent lower corrosion product
transport has not warranted a repeat of this cleaning process. 6.8.4 Steam Generator Chemical Cleaning The chemical cleaning process is remedial in nature and has been used with great success at many PWRs with recirculating steam generators to dissolve
deposits. These deposits are the prime factors in the initiation of many corrosion mechanisms that have affected steam generators in the industry. The corrosion
products may develop flow-occluded crevices were steam generator bulk water impurities can concentrate in thermodynamically limited regions. These regions
are considered the precursor to the development of various corrosion mechanisms. The chemical cleaning process can effectively remove significant
quantities of iron and copper materials from the steam generator, both on tube surfaces and in tube-to-support intersections. The chemical cleaning process has also been used by some utilities to recover steam generator thermal performance Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 26 of 35 lost due to deposits on tube surfaces and others have used it to clean blocked tube support plate (TSP) broach holes that resulted in SG water level oscillations. Due to its aggressive nature the standard chemical cleaning process (e.g. SGOG) can only be employed a limited number of times in the life of the steam generators due to corrosion concerns and are very expensive (~$10 million), so
the timing of chemical cleanings must be strategically analyzed.
As an alternative to chemical cleaning, vendors have developed less aggressive chemical cleaning processes (e.g. advance scale conditioning agents or ASCA) that can remove limited quantities of deposits but may be performed an almost
unlimited number of times. They are also much less expensive (~$2 million). This
cleaning process can be used to maintain the cleanliness of the SGs and forestall or eliminate the need for standard chemical cleaning over the life of the
The unit 3 steam generators have twice the service time of those at unit 2. There are no signs of a loss of thermal performance at either unit. Visual inspections of the TSPs at unit 3 have not identified the buildup of deposits in the broach holes that could lead to flow oscillations. Previously, Westinghouse has reported that a SG deposit loading of at least 4500 pounds/SG would be necessary before there is a risk to water level oscillations. Conservatively, there are probably less than
2500 lbs/SG in the unit 3 steam generators. The elevated concentrations of copper and lead found in the unit 3 steam generators are both issues that could be addressed by chemical cleaning if
deemed necessary. Both of these contaminant levels are being monitored via periodic corrosion product analysis. Because of the recent steam generator replacement at unit 2 and low corrosion product transport, there are no plans for chemical cleaning at this unit. Early deposit analyses from the IP3 SGs identified elevated copper levels even though all copper bearing components had been replaced prior to SG
replacement. The copper source is believed to be from historical plateout on
secondary system piping. The percentage of copper in SG deposits has declined to their current levels of 3 percent. Early deposit analysis also identified lead in hard tube collars as high as 1600 ppm. The bulk powder results were in line with industry averages. The few elevated lead results were not considered significant
enough to warrant chemical cleaning. 6.9 Condensate Polisher Facility (IP3 only) The condensate polisher facility (CPF) was installed at IP3 at a time when the unit was experiencing numerous condenser tube leaks. At the same time the unit replaced the leak prone condensers with titanium tube bundles that were virtually leak free. Because the CPF was more efficient at removing anion contaminants
than cation the ionic balance shifted to a higher molar ratio which would tend to a more caustic condition in the steam generators. The installation of a high quality Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 27 of 35 makeup water system contributed to lower contaminants to the point where the CPF was a significant contributor to the SG impurities. The switch from ammonia to ETA as a pH control chemical limited the CPF operation to a maximum of 30%
flow because of the increased loading on the demineralizers.
Use of the Unit 3 CPF at 30% flow for protection against condenser tube leaks was not warranted based on the high reliability of the condenser weighed against the increased sodium and operating costs. As a result, the station began the practice of bypassing the CPF during normal operation. The CPF is used during Unit 3 startups at 100% flow for protection against corrosion products and to help mitigate 30% power chemistry holds. The CPF is removed from service after satisfactory chemistry values are attained after
startup. 6.10 Hideout Return Evaluations Hideout return evaluations provide an opportunity to assess the likely steam generator crevice chemistry during normal operation. Currently, the hideout
return in one steam generator is monitored during the plant shutdown for a
refueling outage. To date, the quantity of impurities returned has been very low with some chemical species below the analytical detection limit. 6.11 Secondary Plant Layup During plant shutdown periods the Secondary Side of the plant must be properly maintained in order to prevent excessive corrosion products being introduced to
the steam generators during startup. In addition component degradation may occur if the proper environment is not applied during these shutdown conditions. The steam generators are placed in wet layup and treated with ETA and hydrazine during shutdown periods. A nitrogen blanket is also maintained on the steam generators by periodic nitrogen sparges. 7.0 Chemistry Control Strategies to be Implemented 7.1 Secondary Cycle pH Control Control ETA addition in the range of 4.5 to 5.5 ppm in the feedwater to maintain pH t 1.0 pH units greater than neutral pH t around the secondary cycle. Route the condenser air ejector drains inboard to maximize the condensate ammonia concentration. Monitor secondary cycle corrosion product transport. Identify source terms of corrosion products.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 28 of 35 Maintain corrosion product transport database and trends in order to track performance. Continue the replacement of FAC susceptible system piping with FAC resistant material as needed. 7.2 Steam Generator Oxidant Exposure Control condensate oxygen between 1 and 10 ppb Control high pressure feedwater hydrazine concentration during normal operation to the greater of 20 ppb or 8 times the condensate dissolved oxygen concentration. Try to limit the hydrazine to less than 100 ppb with a
target range of 60-80 ppb. Monitor steam generator deposit samples for reducible metal species each time sludge lancing is performed. 7.3 ALARA Chemistry Incorporate the control parameters from the EPRI Secondary Chemistry Guidelines in station procedure 0-CY-2410, Secondary Chemistry
Specifications. Control steam generator blowdown chemistry below the target values in the table below when above the mid-power value of 35%. Any variations from the target values during plant operation will be aggressively investigated and SG blowdown flow will be increased as necessary.
<1.7 ppb SG Sulfate
<1.8 ppb Monitor hideout return data each refueling outage to determine source of
impurities during operation. Perform periodic evaluation and data correlation of secondary cycle control and diagnostic parameters to determine inconsistencies.
Investigate main condenser integrity and take corrective actions to reduce impurity source term 7.4 Steam Generator Deposit Management Perform feedwater corrosion product monitoring when greater than 30% power in accordance with the guidelines.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 29 of 35 Perform chemical layup of the steam generators as soon as practical following a plant shutdown to Mode 5 conditions in accordance with the EPRI Guidelines. Perform SG sludge lancing every other refueling outage or each time primary inspections are performed. When possible, collect and analyze deposits each time sludge lancing is performed to monitor for reducible metal species. 7.5 Chemistry Parameter Target Values Parameter Goal Value Chemistry Effectiveness Indicator < 4.0 Steam Generator Blowdown Sodium < 0.8 ppb Steam Generator Blowdown Chloride < 1.7 ppb Steam Generator Blowdown Sulfate < 1.8 ppb Condensate Oxygen
<10 but >1 ppb Final Feedwater ETA 5 ppm Final Feedwater Hydrazine The greater of >= 8 times condensate dissolved oxygen or 20
ppb & <100 ppb Final Feedwater Iron
< 1.0 ppb Final Feedwater Copper
<0.1 ppb Steam Generator Layup pH >9.8 with hydrazine >25 ppm orpH >9.5 with hydrazine >75 ppm 7.6 Action Level Limits Action level limits from the EPRI Secondary Chemistry Guidelines will be
incorporated in station chemistry procedure 0-CY-2410. 7.7 Action Level Response Times For consistency between the units, the Action Level response times will be those required for steam generators with mill annealed Alloy 600TT tubing. This will prompt more conservative decision making, however if necessary, the response
times may be extended to those allowed by the guidelines for 600TT and 690TT
SG tubing for IP2 and IP3 respectively. 8.0 Gap Analysis & Deviations This section should identify where the Plans actions are less conservative than
those specified in the EPRI guidelines. For intentional deviations from standard practice, technical justification of the deviations should be provided.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 30 of 35 8.1 pH Measurement The EPRI Guidelines recommends pH monitoring of the steam generator blowdown daily as a diagnostic parameter to ensure that the pH agent is present.
IPEC uses the feedwater ETA concentration along with feedwater specific conductivity to ensure adequate pH control is maintained around the secondary
system and no longer measures the feedwater or SG blowdown pH. IPEC also subscribes to EPRIs Smart ChemWorks service which calculates the pH at various points in the secondary system based on chemical concentrations. 8.2 Feedwater suspended solids Table 5-3 in the EPRI Secondary Chemistry Guidelines recommends that
feedwater suspended solids be measured as a diagnostic parameter daily during startup, hot standby/reactor critical <5% power. The purpose is to minimize the
corrosion products transported to the steam generators during startup. IP3 utilizes the condensate polisher as part of the long path recirculation of the condensate/feedwater piping prior to startup and continues using the polisher in
full flow during startup to remove corrosion products. At IP2 the long path
recirculation of the condensate/feedwater piping is done through portable demineralizer trailers brought in for plant startups. 9.0 Innovative Approaches & Use of New Technology Entergy plans to monitor the pilot plant use of dispersants during steam
generator layup and long path recirculation as a means reduce deposits in the
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 31 of 35 10.0 References 10.1 Pressurized Water Reactor Secondary Water Chemistry Guidelines-Revision 7. EPRI, Palo Also, CA: 2009, 1016555 10.2 WOG Reactor Coolant Chemistry Initiatives MUHP-2070 10.3 Indian Point 2 Steam Generator Program, Entergy Nuclear Operations Inc, IP-RPT-04-00206 10.4 Indian Point 3 Steam Generator Program, Entergy Nuclear Operations Inc, IP3-RPT-SG-01796 10.5 Westinghouse Chemical Analysis of Indian Point 2RO19 Steam Generator Deposits , Westinghouse, LTR-CDME-10-64, July, 2010 10.6 Evaluation of Westinghouse Chemical Analysis of Indian Point 3R14 Steam Generator Deposits , Westinghouse, LTR-CDME-07-153, March, 2008 10.7 Evaluation of Steam Generator Cation Conductivity Excursion on December 18, 1992, Entergy Nuclear Northeast memo from R. Cullen (corporate chemical engineer) to J. Gillen (chemistry supervisor), June 11, 1993, WCHEM-93-107 10.8 Review of the May Startup Chemistry, Entergy Nuclear Northeast memo from M. Kerns (IP3 chemical engineer) to D. Quinn (Radiological & Environmental
Services manager), June 17, 1991, IPI-91-024N 10.9 Secondary Chemistry Specifications, Entergy Nuclear Operations Inc, 0-CY-2410 10.10 Indian Point Energy Center FAC Water Chemistry Optimization for CHECKWORKS SFA, June 17, 2010, Document Number: 0705.105-01 10.11 Steam Generator Hideout Return Study 3R16, July 25, 2011, Doc ID HIDEOUT RETURN 3R16.
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 32 of 35 Attachment 1 - SG Sludge Lance History IP2 SG Deposit Removal History since Replacement (pounds)RFO Year SG 21 SG 22 SG 23 SG 24 Total 14 2000 SG Replacement 15 2002 13 8 10 11 42 16 2004 SL not performed 17 2006 27.5 24.5 18 25.5 95.5 18 2008 SL not performed 19 2010 16.5 18.5 16.5 19.0 70.5 IP3 SG Deposit Removal History since Replacement (pounds)RFO Year SG 31 SG 32 SG 33 SG 34 Total 6 1989 SG Replacement 7 1990 42.0 43.5 31.0 39.5 156.0 8 1992 56.5 76.5 74.0 76.5 283.5 9 1997 49.8 63.2 55.3 54.7 223.0 10 1999 62.0 56.0 70.0 57.0 245.0 11 2001 106 103 209.0 12 2003 SL not performed 55 25 80 13 2005 SL not performed 14 2007 56.2 81.5 43.5 41.5 222.7 15 2009 SL not performed 16 2011 SL not performed
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 33 of 35 - SG Sludge Analysis History IP2 SG Deposit Iron Oxide History since Replacement (wt %) RFO Year SG 21 SG 22 SG 23 SG 24 Avg 15 2002 78.8 89.8 86.0 75.2 82.5 16 2004 Sludge lancing not performed - No samples taken 17 2006 Sludge lancing performed but samples not analyzed 18 2008 Sludge lancing not performed - No samples taken 19 2010 83.6 82.2 81.7 86.5 83.5 IP2 SG Deposit Elemental Copper History since Replacement (wt %) RFO Year SG 21 SG 22 SG 23 SG 24 Avg 15 2002 12 9.2 9.9 12.2 10.8 16 2004 Sludge lancing not performed - No samples taken 17 2006 Sludge lancing done but samples not analyzed 18 2008 Sludge lancing not performed - No samples taken 19 2010 1 .8 3.5 1.5 1.7 IP3 SG Deposit Iron Oxide History since Replacement (wt %)Outage Year SG 31 SG 32 SG 33 SG 34 Avg 7 1990 67.5 76.2 51.2 77.2 68 8 1992 86.8 58.5 65.5 50.4 65 9 1997 57 44 60 57 55 10 1999 93 91 88 92 91 11 2001 91.8 83.9 88 12 2003 Sludge lancing not performed No samples taken Not analyzed due to application of ASCA chemical agents 13 2005 Sludge lancing not performed - No samples taken 14 2007 94 97 100 97 97 15 2009 Sludge lancing not performed - No samples taken N/A 16 2011 Sludge lancing not performed - No samples taken N/A IP3 SG Deposit Elemental Copper History since Replacement (wt %)Outage Year SG 31 SG 32 SG 33 SG 34 Avg 7 1990 28.5 20.2 45.0 19.0 28 8 1992 10.5 38.3 31.2 46.3 32 9 1997 32 41 28 33 36 10 1999 5.9 8.4 11 7.2 8.1 11 2001 6.5 14.4 10.5 12 2003 Sludge lancing not performed No samples taken Not analyzed due to application of ASCA chemical agents N/A13 2005 Sludge lancing not performed - No samples taken N/A 14 2007 6 3 - 3 3 15 2009 Sludge lancing not performed - No samples taken N/A 16 2011 Sludge lancing not performed - No samples taken N/A Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 34 of 35 - Steam Generator Hideout Return Results Indian Point 2 SG Prompt Hideout Return History (g) Species 2R19-21 2R18-21 Al 0.065 0.060 Ca 0.097 0.293 Cl 0.021 0.066 F K Mg 0.048 0.018 Mn 0.092 0.161 Na 0.013 0.020 SiO2 0.000 0.802 SO4 0.063 0.209 MRI 2.53 pHt 7.12 pHn 5.77 Indian Point 2 SG Total Hideout Return History (g) Species 2R19-21 2R18-2 Al 0.175 0.171 Ca 0.408 1.955 Cl 0.038 0.134 F K Mg 0.130 0.214 Mn 0.249 0.232 Na 0.019 0.032 SiO2 0.000 1.118 SO4 0.456 0.755
Doc ID: SSWCP Rev. 03 IPECSECONDARY STRATEGIC W ATER C HEMISTRY P LANPage 35 of 35 - Steam Generator Hideout Return Results Indian Point 3 SG Prompt Hideout Return History (g) Species 3R16-32 3R15-33 Al 0.38 0.788 Ca 0.01 0.537 Cl 0.00 0.040 F 0.00 K 0.06 Mg 0.01 0.032 Mn 0.00 0.062 Na 0.01 0.091 SiO2 2.40 3.914 SO4 0.33 0.206 MRI 0.33 2.300 Indian Point 3 SG Total Hideout Return History (g) Species 3R16-32 3R15-33 Al 4.27 2.998 Ca 3.51 6.289 Cl 0.46 0.049 F 0.01 K 0.12 Mg 1.07 0.259 Mn 0.00 0.118 Na 0.05 0.158 SiO2 1.95 1.522 SO4 3.67 1.609