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Feed Water Chemistry & Control
Nalco Indonesia ~ Power Industry Seminar Pullman, Central Park ~ Jakarta 13-14 June 2012
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Agenda
Key Issues
Guidelines for Condensate, Feed Water, and Steam Chemistry Control
Practical considerations in application and control
New Technology
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Steam Cycle
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Key Issue #1 : Steam Turbine Requirements
Steam purity specs can be stringent!
Industry experts differ on specific allowed limits. Different manufacturers have different limits Limits may depend on design, service, age of unit
Limits vary with the boiler treatment selected.
Cation conductivity is principle measure in most plants (< 0.15, < 0.2, < 0.3, < 0.8 mS/cm as cation conductivity)
Na and SiO2 are more specific measures of contamination. Cl- and SO4 measurement important, but not commonly found online
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Critical Steam Cycle Chemistry Parameters
Boiler and feedwater chemistry driven by steam purity requirements
Turbine/Feedwater Cation conductivity (indirect measure) Sodium (NaOH) Silica Chloride (HCl) Sulfate (H2SO4) Organic acids
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Sources of Chemicals in Steam
Volatile Carry Over Higher pressure = greater volatility Cu an issue at > 2400 psi (160 bar)
Mechanical Carry Over Occurs in all boilers all the time Drops contain all boiler water solids
Contamination via Attemperation Shortcut of feedwater to turbine
Cu(OH)2 H2SO4
SiO2
NaOH
Na3PO4
NaCl
HCl
Volatile
Mechanical
Key Issue #2 : Cation (Acid) Conductivity
Conductivity after strong acid ion exchange
Neutral salts become strong acids
Magnifies conductivity 3-5 times Cl-
and SO4
2-
Targets
“De-gassed” cation conductivity uses a small boiler or N2 sparging to strip off CO2 from carbonic acid
Na, Ca, Mg : Cl salts to HCl
Na, Ca, Mg : SO4 salts to H2SO4
Na, Ca, Mg : HCO3 salts to H2CO3
Also removes amine and ammonia, but not organic acids
CO2 to H2CO3
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Key Issue #3 : High Purity Make Up
Purity Generally must be as good as feedwater. EPRI specifications are a good target for modern plants. Parameter Specific Cond, mS/cm
EPRI Std < 0.1
Cation Cond, mS/cm
VGB Std < 0.2
Na, Cl, SO4, ppb
<3
Silica, ppb
< 10
TOC, ppb
< 300
< 20
Deaeration Few plants deaerate make up or condensate storage tanks, or hot well during standby. Technically feasible – from 7 ppm to 100 ppb O2 Vacuum deaeration, steam sparging, nitrogen sparging, membrane deaeration
Key Issue #4 : Condensate and Feed Water Quality
Condensate Cogen plants must guard against contamination from steam host
Feedwater Feedwater used for attemperation must meet steam purity specs. - The LP section of most HRSGs is upstream of attemperation, and is treated as feedwater. (AVT)
Feedwater purity and consistency drive treatment selection. - Minimizing corrosion and corrosion product transport is critical. - FW heaters corrode on both shell and tube side!
EPRI Guidelines are excellent targets, but: May be difficult for older plants to meet without capital investment in system upgrades. All plants should develop unit specific guidelines, taking design, pressure, service, and water quality into account.
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Key Issue #5 : Control of Dissolved Oxygen
EPRI research and field study led to reduction in O2 target From < 20 ppb at CPD to < 10 ppb at CPD For all treatment programs Required for corrosion control
Overfeed of passivator is not a good option Too strong of a reducing environment contributes to FAC Excess hydrazine and carbohydrazide produce ammonia Excess organic passivators can add to TOC, organic acids
EPRI recommends / Nalco concurs: Limit air inleakage – have active detection and repair program Deaerate make up Nitrogen cap hotwell for standby
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Corrosion ~ Iron ~ Deposition ~ Corrosion For high purity boiler systems, iron is the focus of performance CORROSION leads to IRON IRON leads to DEPOSITION
DEPOSITION leads to CORROSION (again) & OVERHEAT
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Corrosion ~ Iron ~ Deposition ~ Corrosion NaOH Magnetite
Steam Out NaOH NaOH Water In
Fe3O4
porous deposit
NaOH
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Chemically Influenced BTFs 2001 survey results
1997 survey results
Organizations having chemically influenced BTFs
81%
61%
•Hydrogen damage
57%
37%
•Acid phosphate corrosion
25%
17%
•Corrosion fatigue
45%
43%
•Pitting
40%
7%
•Stress corrosion cracking
28%
18%
•Caustic Gouging
11%
11%
Source: 2002 EPRI Study, “ Priorities for Corrosion R&D”
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Boiler Tube- Hydrogen Damage
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Key Issue #6 : Metal Passivation Passivation:
Iron oxides to magnetite (reducing environment) - Passivation Reactions: Hydrazine N2H4 + 6Fe2O3 4Fe3O4 + N2 + 2H2O N2H4 + 4CuO 2Cu2O + N2 + 2H2O
- Passivation Reactions: Carbohydrazide 12 Fe2O3 + (N2H3)2CO --- 8Fe3O4 = 3H2O + 2N2 + CO2 8CuO + (N2H3)2CO --- 4Cu2O + 3H2O + 2N2 + CO2
Or magnetite / hematite mix (neutral or oxidizing environment)
Copper oxides to cuprous form (Cu2O) - Less protective cupric oxide surfaces have 30 times the Cu release! - Cuprous oxide will oxidize to cupric within 10 hours in O2 environment!
Iron Oxide Passive Layer ~ Reducing Environment
Source: EPRI, Cycle chemistry Guidelines for Fossil Plants, Phosphate Continuum and Caustic Treatment, 2004.
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Iron Oxide Passive Layer ~ Neutral-Oxidizing Environment
Source: EPRI, Cycle chemistry Guidelines for Fossil Plants, Phosphate Continuum and Caustic Treatment, 2004.
Key Issue #7 : Flow Accelerated Corrosion
Over half of utilities report FAC
Two failure mechanisms – single-phase and two-phase
Occurs in -
Condensate and Feedwater Piping around BFP Piping to Economizer Inlet Header Economizer Inlet Header Tubes Deaerators Heater Shells and Drains Steam Turbine Exhaust LP Evaporators
Second-most common failure mechanism
What is FAC ?
Dissolving of protective magnetite layer (Fe3O4)
Influenced by several factors:
Velocity Flow geometry Two phase flow Temperature pH Oxygen concentration Overfeed of Passivators Metallurgy
that contribute to magnetite solubility
Factors Affecting FAC - Temperature
Extremely temperature dependent: Occurs in HRSG IP & HP Economizer tubes & headers, and in LP evaporators & drums. Occurs in cold re-heat return lines, FW heater drip lines.
Tendency for FAC Moderate Range Severe Range Moderate Range
Temperature Deg C 80 150 150 180 180 230
Deg F 176 302 302 356 356 446
Saturation Pressure psia 7 70 70 146 146 409
Factors Affecting FAC – pH
Factors Affecting FAC
~ Oxidizing & Reducing Environment
Source: EPRI, Cycle chemistry Guidelines for Fossil Plants, Phosphate Continuum and Caustic Treatment, 2004.
FAC Solution
Material upgrade to 1 or 2% chrome
Maintain pH in proper range with ammonia or amines - Higher end of range is better! - Pay attention to amine distribution ratio in multi-pressure HRSGs
Avoid a highly reducing environment! - Do not allow excess feed of reducing agents! - Cycling units: do not feed high levels of reducing agent to compensate for high O2 at start up.
- Monitor feedwater ORP, consider control of passivator to ORP
Monitor with soluble iron tests before and after suspect areas - Need proper sample points!
Key Issue #8 : Use of Organic Amines & Passivators
EPRI & VGB recommend Ammonia and Hydrazine
Stuttgart Conference on Organics – June 2005 Co-Sponsored by EPRI and PowerPlant Chemistry Organic Amines -
Used safely for many years No factual evidence of contribution to turbine corrosion Some breakdown to organic acids, contributing to cation conductivity Ammonia counter ion neutralizes the acids Many feel okay to continue use
Organic Passivators
- Some breakdown to organic acids, contributing to cation conductivity - No alkaline counter ion - Most believe should not use
Carbohydrazide
- Produces CO2 on breakdown. Excess carbohydrazide will produce ammonia. - CO2 not believed to cause any significant corrosion in steam cycle - Estimate that 20 ppb Carbohydrazide contributes 10 ppb CO2, and creates 0.08 mS/cm cation conductivity from the CO2. - Most believe carbohydrazide is okay to use
Organic Amine & Passivator – CO2 Myth
CO2 is not solid so it won’t be deposited in the LP blade and creating localized acidic condition
It is required ~ 200 ppb of CO2 to drop the pH of pure water from 6.5 to < 6.0
At low pressure, V/L of CO2 is quite the same with Ammonia and higher than neutralizing amines. It is mean all of CO2 will be neutralizing by proper dosing of ammonia/amines.
There are some literatures from independent parties that clearly explained that CO2 won’t depress pH of initial condensation in the level that we commonly found boiler operation (<2 mS/cm) and when the alkalizing agent is exist (Robert Svoboda and Alstom)
Nalco 1250 (ELIMIN-OX) • Active Content : CARBOHYDRAZIDE (CHZ) • ALL VOLATILE & NON-SOLIDS Contribution in Steam Cycle • It is used as a METAL PASSIVATOR • Much SAFER than HYDRAZINE • NOT A SUSPECT CARCINOGEN
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Slight increase in cation conductivity from CO2
20 ppb CHz contributes 10 ppb CO2, which contributes 0.08 mS/cm cation conductivity (But 0 degassed cation conductivity)
O II
NH2-NH-C-NH-NH2 CARBOHYDRAZIDE
MECHANISM REACTION of ELIMIN-OX
At LOW Temp. (T 1350C) 1 ppm Elimin-Ox 29 ppb (,or 0.029 ppm) CO2 & NO IMPACT to STEAM & CONDENSATE corrosivity
Practically, it is very simple to check @ BFW sample, as residual of 10 – 30 ppb (as N2H4) ~ local (site) BFW sampling w/t T > 1800C
Increasing Passivation
Passivation Better than Blank at All Temperatures
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Blank Carbohydrazide Methlyethylketoxime
*
150
200
*
*
250
300
350
400
Temperature (oF) 28
Increasing Passivation
Passivation Better than Blank at High Temperatures
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Blank Hydrazine Erythorbic Acid
* * 150
*
200
250
300
350
400
Temperature (oF) 29
Increasing Passivation
Passivation Equal to Blank
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Blank Sulfite DEHA Hydroquinone
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* 150
200
* 250
300
350
400
Temperature (oF) 30
Feedwater Iron Reduction in 1500 psig boiler with ELIMIN-OX
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Feedwater Copper Reduction in 1500 psig boiler with ELIMIN-OX
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Reaction and/or Breakdown Products Chemical/Formula Hydrazine N2H4
%C (wt.)
Reaction and/or Breakdown Products
0
Nitrogen, water, ammonia
Carbohydrazide (N2H3)2CO
13.3
Hydrazine, nitrogen, water, ammonia, carbon dioxide
Hydroquinone C6H4(OH)2
65.5
Benzoquinone, light alcohols, ketones, low molecular weight species, carbon dioxide
Diethylhydroxylamine (CH3CH2)2 NOH
53.9
Acetaldehyde, acetic acid, dialkylamines, ammonia, nitrate, nitrite
Methylethylketoxime (CH3)(CH3CH2)C=NOH
55.2
Methylethylketone, hydroxylamine, nitrogen, nitrous oxide, ammonia, carbon dioxide
Erythorbic Acid C 6H 8O 6
40.9
Dihydroascorbic acid, salts of lactic and glycolic acid, carbon dioxide
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Comparison of Acute Toxicology of ELIMIN-OX and 35% Hydrazine Study Performed
ELIMIN-OX
35% Hydrazine
Acute oral LD50 rats
>5000 mg/kg
370 mg/kg
Acute dermal LD50 - rabbits
>2000 mg/kg
420 mg/kg
Primary eye irritation - rabbits (24 hr) Primary dermal irritation - rabbits
Non-irritating (0.33/110)
Irritating (26.5/110)
Mild irritant (0.23/8.0)
Severe irritant (7.0/8.0) May be corrosive. (Most suppliers ship as a corrosive liquid) 34
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References of Nalco 1250/Elimin-Ox
Steam & Condensate Equipment Steam Turbine – Advantages of Amines
If not neutralized, organic acids may drop the pH in initial condensation zone & cause corrosion in steam turbine Low V/L Amine is a better choice than NH4OH to neutralizeI organic acids in this particular area
Species
Relative V/L
Destination
Carbonic Acid
High
Final condensation
Acetic & Formic Acid
Low
Early stage of condensation
Ammonia
High
Final condensation
Low or high
Early & final stage of condensation
Amines
(initial condensation)
Nalco 5711
Minimum contribution of cation conductivity. Deliver <0.2 mS/cm cation conductivity in system with no contamination (0.1-0.3 mS/cm lower than amine available in the market)
Containing low V/L amine that will increase the pH in early condensation zones in the LP turbine, feedwater heaters and extended steam distribution system
Low V/L amine will also improve pH in the LP section of multi pressure HRSG and minimize potential of FAC
Increase the pH with relatively same dosage with 19% NH3
Has higher boiling point. Safer to handle, easier to pump without off gassing, and produces fewer odor Reference : PT. Freeport Indonesia
N5711 Dosage vs Ammonia Amine Product Concentration vs. pH in pure water 15 14
19% NH3
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1800
Amine Product, mg/L
12 11
CA-300C
10
356
9 8
5711
7 6 5 4 3 2 1 8.6
8.7
8.8
8.9
9.0
9.1
9.2
Condensate / FW pH
9.3
9.4
9.5
9.6
Condensate, FW, and Steam Guidelines EPRI Guidelines Industrial
PC(L)
PC(H)
Caustic Treat
AVT(O)
AVT(R)
OT
9.0–9.6 8.8-9.2
9.2–9.6 9.0-9.3
9.2–9.6 9.0-9.3
9.2–9.6 9.0-9.3
9.2–9.6
9.2–9.6 9.0-9.3
D 9.0–9.6 O 8.0-8.5
Cat Cond, mS/cm
< 0.3
< 0.2
< 0.3
< 0.2
< 0.2
< 0.2
< 0.15
Na, Cl, SO4 ppb
<5
<2
<3
<2
<2
<2
<2
Silica, ppb
< 20
< 10
< 10
< 10
< 10
< 10
< 10
Fe, ppb @EI
< 10
<2
<2
<2
< 2 (1)
<2
< 2 (0.5)
Cu, ppb @EI
< 10
<2
<2
<2
<2
<2
<2
Oxygen, ppb @CPD
< 20
< 10
< 10
< 10
Parameter pH (all steel) (Cu alloys)
Oxygen, ppb @EI
Reducing Agent
ORP, mV @DA In
< 10
< 10
< 5 (< 2)
D 30-50 O 30 150
yes
no
yes
no
+/- 50
-300 to 350
100 to 150
Condensate, FW, and Steam Guidelines NALCO Guide for Implementation Industrial
PC(L)
PC(H)
Caustic Treat
AVT(O)
AVT(R)
OT
9.0–9.6 8.8-9.2
9.2–9.6 9.0-9.3
9.2–9.6 9.0-9.3
9.2–9.6 9.0-9.3
9.2–9.6
9.2–9.6 9.0-9.3
D 9.0–9.6 O 8.0-8.5
< 0.3 < 0.6
< 0.2 < 0.4
< 0.3 < 0.6
< 0.2 < 0.4
< 0.2 < 0.4
< 0.2 < 0.4
< 0.15
Na, Cl, SO4 ppb
<5
<2
<3
<2
<2
<2
<2
Silica, ppb
< 20
< 10
< 10
< 10
< 10
< 10
< 10
Fe, ppb @EI
< 10
<2
<2
<2
<2
<2
<2
Cu, ppb @EI
< 10
<2
<2
<2
<2
<2
<2
Oxygen, ppb @CPD
< 20
< 10
< 10
< 10
Parameter pH (all steel) (Cu alloys) Cat Cond, mS/cm W/ organic amine
Oxygen, ppb @EI
Reducing Agent ORP, mV @DA In
< 10
< 10
<5
D 30-50 O 30 150
yes
Yes, if cycling
yes
no
+/- 50
-250 to 350
100 to 150
The Nalco Latest Technology to Monitor/Control Corrosion Tendency of Feedwater Systems
What is ORP ? H2
Reduction of Oxygen (CATHODE)
Corrosion = REDOX Reactions
REDOX Reactions Electron Flow
Electron Flow = ORP (Oxidation Reduction Potential)
ORP = bulk FW corrosivity
Precipitation of Red Oxide
Fe2O3 o O2
O H
RED OXIDE
o
-
BLACK OXIDE o
MAGNETITE
o
o
MAGNETITE
Fe3O4
Precipitation of Black Oxide (CATHODE) FeOH++ + Fe(OH)+2 Oxidation and Hydrolysis
o H++FeOH+ Evolution of Hydrogen (CATHODE)
Hydrolysis of Dissolved Iron lowers pH Fe+2 Acid Pit Solution with Lower Oxygen Content
eFe
Oxidation of Iron ANODE
ORP indicates the potential of bulk water to corrode ORP provide the best way to control BFW corrosion stress
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Corrosion and corrosion product transport varies significantly in condensate and feedwater systems.
Corrosion varies with:
Metallurgy Flow velocity (FAC) Temperature pH Dissolved oxygen Conductivity Stability of oxide layer / passivation
Corrosion product transport varies with: Load / flow velocity Expansion / contraction Vibration
Monitor corrosion stress with At Temperature ORP (AT ORP)
Cycling Base Load Monitor corrosion product transport with Chemtrac Particle Monitor
Nalco, the logo, 3D TRASAR, and AT ORP are trademarks of Nalco Company. Chemtrac is a trademark of Chemtrac Systems, Inc.
Two Shifting
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ORP1 and At Temperature ORP (AT ORP)
ORP correlates to the corrosion stress of the aqueous environment
+ 0
RT ORP is measured on a cooled sample at room temperature.
AT ORP is measurement of ORP at the temperature and pressure of the condensate / feedwater system.
More oxidizing - can be more corrosive
Greatly improves sensitivity and response. Allows AT ORP to be used for feedback control.
Potential difference between measuring and reference electrodes More reducing – can be more passive
ORP is influenced by temperature, pH, O2, dissolved solids, etc.
Development of AT ORP has been an industry goal. Nalco is the first to develop a practical AT ORP system. Developed by Dr. Peter Hicks of Nalco. Work began in 1992, commercial production from 2008. Over 50 AT ORP units currently installed in Power plants globally.
1. ORP and Oxidation / Reduction Potential are used in this presentation to have the same meaning as Redox Potential.
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EPRI Cycle Chemistry Guidelines for Fossil Plants: Phosphate Continuum and Caustic Treatment, Jan 2004, Appendix B. “Thus ORP should be used to control the oxidizing power of the feedwater in allferrous systems or, and more importantly, the reducing power of the feedwater in mixed-metallurgy feedwater systems.” “The future direction should be to develop the technology to measure ORP in-situ in feedwater, and to extend the mixed-potential model for use at the elevated temperatures, where components are actually in contact with high temperature water, such as in the boiler.”
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Advanced Monitoring: At Temperature ORP
Oxidation / Reduction Potential (ORP) can now be measured and controlled in condensate and feedwater systems: At system temperature and pressure. On-line in real time. To make corrosion events visible. To allow the plant to correlate corrosion stress to plant operational and chemistry changes. To respond with appropriate magnitude and sensitivity for feedback control. To control chemical feed to maintain the system within an AT ORP control specification range. - Reducing or oxidizing agent - Feed on demand and eliminate over or under feed.
Nalco Europe AT ORP Control Equipment
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Why is it important? AT ORP can help the plant to maintain a more consistent oxidation state on the metal surfaces.
Reduce condensate / feedwater system corrosion Extend feedwater heater life Reduce FAC in LP section of HRSGs
Reduce corrosion product deposition in boilers Reduce boiler tube failures Reduce boiler start up chemistry holds Reduce frequency and duration of boiler chemical cleaning
Prevent turbine efficiency loss from deposition of corrosion products (Cu, Fe) Lower heat rate, higher generation
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AT ORP Monitoring and Control Equipment Control PLC, Communications
AT ORP Electrode
Optional Sample Conditioning
EPBRE (External Pressure Balanced Reference Electrode)
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AT ORP Electrodes: Pt measuring electrode, Ag/AgCl Reference Electrode
Sensor design limits 133 bar, 260 oC Sample: 250-500 ml/min
Typical install is after condensate heating, but before feedwater pump.
Installation (prioritized) Deaerator inlet or LP drum inlet Condensate after chemical feed LP drum or other point of interest
Existing sample may be routed through AT ORP and then to: Sample panel instruments Sample conditioning and Particle Monitor or drain
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Advanced Monitoring : Chemtrac® Particle Monitor
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Corrosion product released in “crud bursts”. – Occur every time there’s a thermal, chemical, or hydraulic shock to the system. – Usually invisible, as not monitored on line.
• •
On-line monitoring makes visible Particle monitor helps to: – – – –
Correlate crud bursts to specific events. Correlate particle counts to ppb iron levels. Correlate particle counts to AT ORP. Correlate to metal passivation over time.
Introducing:
Nalco Corrosion Stress Monitor
Nalco Corrosion Stress Monitoring (NCSM) with @T ORP Technology
What Types of System Stresses NCSM can address ?
Mechanical Dearator Performance Pump Leaks
Operational
Load changes Startup and shutdown Condensate flow Makeup flow Process leaks Temperature
Chemical Dissolved oxygen (All) Oxygen scavenger/ passivator dosage pH Condensate treatment recycle
NCSM
What Types of Corrosion NCSM can Minimize ?
Oxygen Pitting Corrosion
Flow Accelerated Corrosion (FAC)
NCMS is superior to conventional measurements Feature Response Time Sensitivity Accuracy Precision Dosage Control Corrosion Control
NCSM
Scavenger Residual
Corrosion DO Monitor Monitor
DO Test
V. Fast V. High High High
Slow Med Med Med
Slow Med Med Med
Med Med High High
Slow Poor Poor Poor
Slow Low Low Low
High
Poor
Poor
Poor
Poor
Poor
High
Poor
Poor
Med
Poor
Poor
RT ORP
NCSM Respond to Small Increase of Dissolved Oxygen
NCSM Responds Air In Leakage in Condensate Pump
NCSM Responds to Small Changes of pH/Amine Feed Problem
Nalco Corrosion Stress Monitoring (NCSM) 3DTfB for Power
Nalco 3DT Corrosion Stress Monitoring (NCSM) Package One @ T ORP controller per boiler, 2 probes each One Particle Monitor per boiler, w/ 2 sensors
Nalco analytical support program
Nalco service / consulting support program
NCSM with Nalco 3D TRASAR Platform Technology Measure Response Detects
Communicate
NCSM with Nalco 3D TRASAR Platform Technology Measure
Detects
Control Your Boiler Response 24/7 from Anywhere ….
Communicate
Thank You
