Boiler Water.pdf - The Jamaican Sugar Industry

Sugar Boiler Water 

Treatment Technology 

2010 Jamaica Association of Sugar Technologists 

(JAST) 

Confidential and proprietary to Garratt-Callahan Company

Bagasse Boiler 


Typical Firetube Boiler 

Confidential and proprietary to Garratt-Callahan Company 

3

Boiler Types 

Water-Tube Units 

– Water passes through (inside) tubes. 

– Used in power generation and industrial process steam. 

– Used for high pressure and high steam demand applications, 

also used with low demand application too. 

– Best suited for large plants with steam turbines. 

– Very high and fast steaming rate, with low contained volume 

of water. 


4


Water-Tube Units 

– Has large square feet of heating area. 

– Responds quickly to fluctuating steam loads. 

– Requires more care in water treatment, as tubes can get 

plugged with scale, inhibiting circulation. 

– Has a steam drum and mud drum with interconnecting tubes. 

– Must be treated with preconditioned water. e.g. Softened. 


5


Water-Tube Unit Circulation 


6


Water-Tube Unit Types 

7



8



9

Boiler System Overview 

Makeup 

(Pretreatment) 

Feed Water 

Tank or 

Deaerator 

Condensate 

Load 

Steam 

Ion 

Exchange 

Feedwater 

Pump 

Boiler 

Surface 

Blowdown 

Bottom 

Blowdown 

10

Condensate 

• Condensate from the evaporators, pans and turbines supply in excess 

of 150% of the boiler feed water 

• Condensate can be contaminated with sugar 

• Sugar contamination 

– Drops the pH to acid levels under pressure. 

– Low pH feed water corrodes the tubes. 

– Corroded iron is laid down as scale on the tubes. 

– Sugar can caramelize and be laid down as carbon scale on the 

tubes 


Pre-Treatment Systems 

Sodium Cycle Cation Exchange 

Influent 

Ca 

Regenerant 

NaCl 

Mg 

2Na 

2HCO 3 

Ca 

Mg 

2Na 

SiO 2 

SO 4 

2Cl 

2NO 3 

Regenerant Waste 

Strong Acid 

Cation 

Exchanger 

Sodium 

Cycle 

To Process 

NaHCO 

Na 2 CO 3 

Na 2 SO 4 

NaCl 

NaNO 3 

SiO 2 

CaCl 2 

MgCl 2 

NaCl 


12

Make-up Water 

Softener 

13

Elution Study 

•Use a graduated cylinder and 

a Salometer 

•Take samples every 5 

minutes and plot curve. 

14

Deaerating Heaters - Oxygen 

Removal .005 cc/L 7 pbb. 


15

Dissolved oxygen: 

– Can cause corrosive pitting attack on 

feed water/boiler surfaces. 

– Usually caused by dissolved oxygen 

gas brought in by makeup water. 

– Best removed with a deaerator 

(removes O 2 down to 7 ppb). 

– Oxygen scavengers are used to react 

with remaining amounts of oxygen. 


16

Deaerating Heaters 

• Mechanical Deaeration 

– Spray Type 

– Tray Type 

– Atomizing Type 


17

Deaerator 


18

Pressure vs. Temperature 

• For every 1 # pressure there is a loss or 

gain of 3 o F temperature 

• 5 # pressure = 227 o F 

• At 5 # pressure or 227o F the deaerator 

removes O 2 down to 7 ppb 

• Insure that you have gages to measure 

both pressure and temperature 


19

Deaerating Heaters 

• Mechanical malfunction or flow control problems result in poor 

Oxygen removal. 

• Causes of Improperly operating deaerators. 

– Inadequate venting. 

– Inadequate quantities of steam or steam pressure fluctuations. 

– Wide fluctuations in feed water flow. 

– Flow rates outside design specifications. 

– Malfunctioning spray nozzles, missing, plugged or broken. 

– Malfunctioning trays, missing, plugged or broken. 

• Problems will almost always manifest as a broad temperature 

differential (>2°F; 1°C) between dome and storage section. 


20

Oxygen Removal - Reducing Agents 

and Passivating Agents. 

•Reducing Agents: Include a wide variety of oxygen scavengers and 

passivating agents, reducing agents are electron donors. 

Oxygen scavengers react with dissolved oxygen directly. 

Passivating agents react with iron and copper to form a 

protective oxide films even in the presence of up to 5 pbb 

dissolved oxygen. 


21

Oxygen Removal / Passivation 

Sodium Sulfite (or Bisulfite) 

Oxygen Scavenger: 

2SO 3= + O2 2SO 4 

= 

No Passivating Properties 

Control Range: Boiler Water 

25-50 ppm 1250 psig 

Non-volatile, adds TDS, Can Poison Process catalysts. 

Not for use in attemperating water or standby in nondrainable 

superheaters. 


22



Hydrazine 

N 2 H 4 + O 2 2H 2 O +N 2 

Passivating Properties: 

N 2 H 4 + 6Fe 2 O 3 4Fe 3 O 4 + 2H 2 O + N 2 


20-50 ppb Feedwater at economizer inlet. 

Passivates iron and copper, Does not increase TDS, 

non-volatile, suspect carcinogen, and breaks down to 

ammonia. 


23


Diethylhydroxylamine (DEHA) 


4(C 2 H 5 ) 2 NOH + 9 O 2 8 CH 3 COOH+ 2N 2 + 6H 2 O 

Passivating Properties: 

2(C2H5)2NOH + 27Fe 2 O 3 18Fe 3 O 4 + 4CH 3 COOH + 3H 2 O + N 


100-150 ppb Feedwater at economizer inlet. 

Very similar to hydroquinone but: generates very little ammonia, 

volatile, and not as thermally stable. Volatizes with steam. 


24


• Chemical Feed Considerations 

– Use stainless steel feed systems. 

– Use floating lids to minimize loss of products. 

– Use high purity, warm condensate or deaerated water 

to prepare feed solutions. Never use cold water. 

– Limit agitation of the feed solution to 1-2 minutes 

– If there is no attemperation (control of superheated 

steam temperature), any of the products may be fed to 

the deaerator storage section, just below the waterline. 

– With attemperation, all sulfite products, are to be 

injected after attemperation takeoff. 


25

Dissolved Oxygen 

Analyzer 

The Series μAI-9060 Dissolved Oxygen 

System is a state-of-the-art 

microprocessor-based instrument 

package developed specifically for use 

in measuring low and high 

concentrations of dissolved oxygen in 

the power, desalination, and 

petrochemical industry. 

•Disposable DO Sensor 

•Automatic Calibration 

•Auto Range Switching 


26

Internal Boiler Water 

Treatments 


27

Internal Boiler Water Treatment Programs 

• Carbonate Cycle 

• Phosphate-hydroxide 

• Coordinated pH-phosphate 

• Phosphate and polymer 

• Chelant Treatment and/or chelant polymer 

• All-polymer 


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• Chelant Treatment and/or chelant polymer 

– Chelant react with residual divalant metal ions 

to form soluble complexes. 

– The complexes are removed through continues 

blowdown. 

– Inconsistency in boiler water chemistry create an 

imbalance: 

• Excessive chelant will result in attack on boiler 

tubes. 

• The presents of dissolved oxygen will result in 

greater deposition problems. 


29


• All-polymer 

– Polymers maintain clean heat transfer surfaces in 

several ways: scale inhibition, metal ion 

solubilization, crystal modification, and particulate 

dispersion. 

– Polymer inhibit scale formation by disrupting the 

growth of deposits. 

– Carboxylated polymers will form a soluble complex 

with feed water hardness. 

– Polymers cannot be tested in process for residual, 

therefore inbalances in boiler water chemistry 

create dosing problems 


30

Crystal Modification

Crystal Modification


• Phosphate and polymer 

– Phosphate precipitation. 

– Polymers disperse particles. 

– Polymers alter particle surface area and 

surface charge to non scaling. 

– Can clean scaled boiler online. 

– Can be measured in process 


33

THE HIDDEN COSTS OF BOILER 

WATER TREATMENT 

AN EVALUATION OF BOILERS IN THE 

LOUISIANA SUGAR INDUSTRY 

James A. Cuddihy, Jr., Walter J. Simoneaux, Robert N. Falgout, and James 

S. Rauh 

34

Do you have 

Boiler Problems? 


35

Borescope Observation Form 

Facility: 

Date 3/17/2004 

Boiler Clean Slightly Moderately Heavily Chipped Pit Under 

Tube Scaled Scaled Scaled Scaling Corrosion Scale 

Corrosion 

Boiler # 

Ctr Tube X Iron Oxide X 

Dn Cmr 

X 

Up Comr X X 

Ctr Tube X X 

Up Comr X X 

Dn Cmr X X 


Ctr Tube X X 

Dn Cmr X X 

Up Cmr X X 

Ctr Tube X X 

Up Cmr X X 

Dn Cmr X X 


Ctr Tube 

X 

Dn Cmr 

X 

Up Cmr 

X 

Ctr Tube X X 

Up Cmr X X X 

Dn Cmr X X 


Ctr Tube 

X 

Dn Cmr X X 

Up Cmr 

X 

Ctr Tube 

36

Borescope Summary 

Mill Clean Slightly Moderately Heavily Chipped Pit Under 

Tube Scaled Scaled Scaled Scaling Corrosion Scale 

8 Mills / 43 Boilers / 222 

Tubes 1/32" 1/16"+ Corrosion 

A 3 4 10 2 1 3 

B 6 10 12 9 3 7 7 

C 3 8 16 7 15 

D 3 15 1 2 3 

E 1 1 18 3 1 1 

F 5 12 19 2 26 4 

G 2 1 7 25 7 11 20 

H 9 12 5 5 6 5 

Total 24 51 55 92 24 54 58 

Average 10.8% 23.0% 24.8% 41.4% 10.8% 24.3% 26.1% 

37

Scale/Deposit Formation 

• The primary reason for deposit and scale formation in steam generating systems 

is the fact that the solubility of many of the deposit forming salts decreases with 

an increase in temperature and concentrations. The water constituents usually 

responsible for these deposits are: 

Calcium (Ca) 

Bicarbonate (HCO3) 

Sulfate (SO4) 

Silicate (SiO2) 

Magnesium (Mg) 

Iron (Fe) 

Carbonate (CO3) 

Phosphate (PO4) 


38

Light Scale (1/32”) 


39

Light Scale (1/32”) 

40

Calcium Phosphate Scale 

Typical 1/16” Deposit 


41

Heavy Scaling 


42

Heavily Scaled 


43

Heavy Scale 


44

Heavy Scaling / Corrosion 


45

Chip Scale 


46

Chip Scale 


47

Pit Corrosion 


48

Pit Corrosion 


49

Pit Corrosion 


50

Scale & Corrosion 


51

Under Deposit Corrosion 


52



53



54

EFFECTS OF DEPOSIT AND 

SCALE FORMATION 

1. Heat transfer is retarded 

• Boiler tube metal temperatures increase. The approximate 

softening temperature of boiler tube metal is about 900 0 F. If 

heat retardation of boiler deposits causes this temperature to 

be reached, tube softening and rupture will occur. 

• Even when deposit build-up may not be sufficient to cause 

tube failure, their insulating effect may still result in reduced 

boiler operation efficiency and energy wastage by 

allowing excessive heat to exit the boiler with the stack gas. 


55

2. Deposits in boilers can reduce circulation through tubes. 

• This encourages further deposit formation due to the 

reduction of the washing effect of circulating water on solids 

concentrating at heat transfer surfaces. 

• Since deposits are poor conductors of heat, they retard heat 

transfer from combustion gases. 


56

3. Deposits can also create differential corrosion cells 

beneath their surfaces (under scale corrosion). 

• The result is localized corrosion or pitting. If such 

corrosion is severe, boiler metal can become thinned and 

weakened, resulting in ruptures due to internal boiler 

pressure. 


57

Fuel Value of Bagasse 

• 1 mt fresh bagasse fiber 

– (50% moisture) 

• 2.2 barrels of fuel oil 

– (assuming 58% boiler efficiency) 

• 13,200 cu ft of natural gas 

– (assuming 75% boiler efficiency) 


58

Cost of Scale Formation 

Assumptions 

• Mill grinds 10,000 TC/Day 

• Bagasse = 33% of cane weight 

• Fuel Prices 

– Fuel oil = $100.00 /barrel 

• 1 ton of bagasse = 2.2 barrels of oil 

– Natural gas = $7.50 / mcf 

• 1 ton bagasse = 13.2 mcf 


59

What is the Cost of Scale? 

Mill grinding 10,000 tons cane per day 

Tons bagsse 3,300 

Scale % Fuel Tons Bagasse Fuel Oil Natural Gas 

Thickness Wasted Wasted Cost Cost 

($100 x 2.2 x bwt) ($7.50 x 13.2 x bwt) 

1/32" 7% 231 $50,820 $22,869 

1/25" 9% 297 $65,340 $29,403 

1/20" 11% 363 $79,860 $35,937 

1/16" 13% 429 $94,380 $42,471 

1/11" 15% 495 $108,900 $49,005 

1/9" 16% 528 $116,160 $52,272 


60

Additional Costs of Scale Formation 

• Production Downtime 

• Mechanical Cleaning of Boilers 

• Acid Cleaning of Boilers 

• Tube Replacement 

• Increased Use of Boiler Water Chemicals 


61

Field Analysis 

FIELD ANALYSIS Plant of: Date: November 19,2003 

AND Address: 

SERVICE REPORT Attention: 

Copy To: 

Midland Copy To: 

SAMPLE 

FROM 

pH P M OH Cl TH Ca 

H 

Fe Cu mmho 

s 

SO 3 

PO 4 

Mo O- 

N 2 

H 4 P 

NO 2 

Feedwater 12.4 60 64 20 0 .14 .02 280 2.5 0.0 

Boiler #G 12.7 76 136 16 56 28 3.33 .07 2600 12.5 .10 

Boiler #A 12.1 28 60 4 16 84 4.00 1.94 1200 5.0 7.9 

Boiler #B 

Boiler #C 

Boiler #D 

Boiler #E 

12.6 

12.4 

11.8 

11.9 

80 124 36 40 92 4.10 2.25 2800 15.0 0.0 

60 115 5 24 28 4.20 4.60 2300 12.5 0.0 

20 28 12 16 20 3.56 4.63 660 5.0 0.6 

24 40 8 8 68 3.06 .77 800 5.0 1.9 

Boiler #F 12.5 64 76 52 16 80 4.21 2.34 2200 2.5 0.1 

Control 

Range 

9.5 

11. 

5 

700 

150 

300 

0 

0.1 

0 

.0 

5 

2000 

3000 

20 

40 

2 

0 

4 

0 


Boiler Tube 

Scale Deposit Analyses 

Constituent 

% Dry Weight 

Tube #1 Tube #2 

Calcium Phosphate 10.7 15.0 

Calcium Carbonate 5.0 0.0 

Iron Oxide 65.0 51.8 

Copper II Oxide 10.0 11.2 

Magnesium Hydroxide 5.8 7.2 

Magnetic Yes Yes 


63

Hawaiian Sugar Mill 

• Produces 60,000 tons raw sugar annually 

• Generates electric power for HELCO utility grid 

BOILER PLANT - STARTUP 1972 

• Babcock & Wilcox - Sterling, two drum design 

• Operating Pressure 1200 psi 

• 825 o F Superheated Steam 

• Boiler Rating 375,000 lbs steam per hour 

• Operating Load 330,000 lbs steam per hour (average) 

• Turbine Generator - 23,800 kW 

• 160 psi Extraction Steam Used For Factory Operation 

• Condensate Return Averages 85% 

• Demineralized Makeup 

• Cochrane Deaerator 


64

NEW DIRECTIONS IN BOILER 

WATER TREATMENT 

• Phosphate Polymer Technology 

• combines internal phosphate treatment with the 

latest in synthetic polymer technology 

• blends of polymers formulated to deal with specific 

problems 

• enhanced thermal stability for high pressure boiler 

performance 

• gives improved phosphate stability for hardness 

control 

• disperses metal oxides and transports them 

through the system 

• provides on-line removal of deposition - including 

metal oxides 


65

CHEMICAL TREATMENT 

PROGRAM RESULTS 

• Tube failure in old section of arch tubes 

• Boiler inspected: 

• one leak found in a waterwall tube 

• lesser amounts of loose deposit found in boiler 

• significant removal of old deposit on waterwall 

tubes 

• new (replaced) arch tube sections deposit free 


66

• Tube samples 

• Arch (Nose) tube and waterwall tube 


67

• Sections cut from waterwall tube 

• A - “bracelet” distorted 

• B - “hot” side 

• C - “cold” side 


68

• 1 inch length tube “bracelet” 

• Distorted to show extent of deposit 


69

• Original deposit condition 

• Waterwall tube removed 

70

• 8X magnification 

• Original deposit on waterwall tube 

removed 


71

• Deposit condition after 12 months on Polymer 

Program 

• Adjacent waterwall tube removed 

• Significant removal of old deposit 


72


• Diminished deposit on adjacent 

waterwall tube removed after 1 year 


73

• New Arch tube installed 

• No adhering deposits 


74


• Clean arch tube after one year 


75

Identifying Sugar Incursions 

• Conductivity meters cannot measure sugar in boiler 

feed water 

– You measure the carryover solids (i.e.; ammonia, 

non-sugars, organics) 

• Tracers and florescence light have not proved effective 

at identifying sugar incursions at ppm. 


Conductivity Meter Setup 

1. Install automatic dump valve prior to feed water storage tank 

2. Place conductivity probe in condensate line prior to the dump 

valve 

1. False sugar positives will occur during stop and go 

production as ammonia will buildup and set-off the alarm 

3. Set the conductivity valve set-point just above the background 

reading 

4. When the conductivity meter sets off the alarm, the dump valve 

should open automatically 

5. Factory personnel should test the water with Alpha-Naphthol 

Test 

1. Find the point of contamination or if it was a false positive, 

close the automatic valve. 


Steam Treatment: Sugar Industry 

Due to the ammonia carryover from the organics in 

the evaporators, the residual effect maintains a 

high enough pH so that amines are not normally 

needed for steam line treatment. 


78

Chemical Feeding Methods 

and Feed Points 

Treatment Feedpoint 

Sulfite 1 

Hydrazine 1 

Sludge Conditioner 2 

Chelant 

3 or 3a 

Feed Water 

Tank or 

Deaerator 

1 

2 

Condensate 

4 

Load 

Steam 

Phosphate 4 

Neutralizing Amine 2,4,or 5 (a) 

3 3a 

5 

Filming Amine 

5 or 3a 

Economizer 

Boiler 

(a) 

Must be diluted with 

condensate of feedwater. 

Feedwater 

Pump 

Surface 

Blowdown 

Bottom 

Blowdown

Boiler Blowdown 

• Surface blowdown 

– Removes dissolved solids, controls the 

cycles of concentration. 

• Bottom blowdown 

– Removes suspended solids, normally done 

once a shift for 5-10 seconds. Do not use to 

control cycles. 


80

Anti-Foams 

1. Counteracts the surfactant effect of High TDS, 

suspended solids, oil, or other organics. 

2. May be more economical than increased 

blowdown or additional external treatment. 

3. Frequently reduce fuel consumption by 

permitting lower blowdown rates while producing 

high quality steam. 

4. Will only help with normal entrainment. Will 

not prevent volatile (Silica) carryover. 


81

Anti-Foams 

•Two types: 

•Polyglycols 

•Use in all boilers. 

•Feed directly to boiler drum. 

•Silicone 

•Use in boilers with low operating pressure. 

•Feed directly to boiler drum. 

•Use in very small applications. 


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Boiler Water.pdf - The Jamaican Sugar Industry

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