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Water Treatment Manual

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Table of Contents

1 STEAM BOILER SYSTEMS ...................................................................................................... 5

1.1 Introduction ....................................................................................................................................... 5

1.2 The water cycle................................................................................................................................... 5

1.3 Scale formation .................................................................................................................................. 7 1.3.1 Typical scaling mechanisms .................................................................................................................. 7 1.3.2 Effects of scale deposition .................................................................................................................... 9

1.4 Scale control by external pre-treatment ........................................................................................... 11 1.4.1 Sea water evaporation ....................................................................................................................... 12 1.4.2 Reverse osmosis ................................................................................................................................. 16 1.4.3 Ion exchange processes ...................................................................................................................... 18

1.5 Boiler classifications ......................................................................................................................... 23 1.5.1 Water-tube boilers ............................................................................................................................. 23 1.5.2 Vertical water tube boilers ................................................................................................................. 23 1.5.3 Dual circuit boilers .............................................................................................................................. 25 1.5.4 Exhaust gas boilers ............................................................................................................................. 26 1.5.5 Steam generators ............................................................................................................................... 28

1.6 Ancillary equipment ......................................................................................................................... 29 1.6.1 Boiler water level controllers ............................................................................................................. 29 1.6.2 Anti priming devices ........................................................................................................................... 30 1.6.3 Internal feed pipes ............................................................................................................................. 30 1.6.4 Superheaters ...................................................................................................................................... 31 1.6.5 Steam traps ........................................................................................................................................ 31 1.6.6 Steam turbines ................................................................................................................................... 32

1.7 Boiler operation – blowdown ........................................................................................................... 34

1.8 Chemical scale control ...................................................................................................................... 35 1.8.1 Carbonate cycle control...................................................................................................................... 35 1.8.2 Phosphate cycle control ..................................................................................................................... 35 1.8.3 All polymer control cycle .................................................................................................................... 36

1.9 Corrosion in the steam boiler system ............................................................................................... 37 1.9.1 Oxygen attack ..................................................................................................................................... 38 1.9.2 Caustic Corrosion ................................................................................................................................ 40 1.9.3 Acidic attack - condensate line corrosion ........................................................................................... 41 1.9.4 Ammonia corrosion ............................................................................................................................ 42 1.9.5 Descriptions of common types of corrosion encountered ................................................................. 43

1.10 Corrosion control .............................................................................................................................. 43 1.10.1 Physical oxygen removal ................................................................................................................ 43 1.10.2 Chemical oxygen removal .............................................................................................................. 48

1.11 Condensate line corrosion ................................................................................................................ 52 1.11.1 Control of condensate line corrosion ............................................................................................. 52 1.11.2 Neutralising amines........................................................................................................................ 53 1.11.3 Filming Amines ............................................................................................................................... 54


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1.12 Boiler lay-up ..................................................................................................................................... 54 1.12.1 Short term lay-up (< 1-2 months) .................................................................................................. 54 1.12.2 Long term lay-up (> 1-2 months) ................................................................................................... 55

1.13 Chemical cleaning of boilers ............................................................................................................. 56

1.14 Chemical dosing and control ............................................................................................................. 57 1.14.1 Dosage locations ............................................................................................................................ 57 1.14.2 Sampling and monitoring ............................................................................................................... 59

1.15 Glossary of terms .............................................................................................................................. 60 1.15.1 Heat ................................................................................................................................................ 60 1.15.2 Steam ............................................................................................................................................. 60 1.15.3 Boiler pressure ............................................................................................................................... 61 1.15.4 Boiler efficiency .............................................................................................................................. 61 1.15.5 Rated evaporation of the boiler ..................................................................................................... 61 1.15.6 Superheated steam ........................................................................................................................ 62 1.15.7 De-superheating (attemperating) .................................................................................................. 62 1.15.8 Reheat ............................................................................................................................................ 63 1.15.9 Thermal compression ..................................................................................................................... 63 1.15.10 Steam release rate ......................................................................................................................... 64 1.15.11 Water evaporation and fuel consumption ..................................................................................... 64 1.15.12 Packaged Oil-fired boilers .............................................................................................................. 66 1.15.13 Carryover (priming and foaming) ................................................................................................... 66

2 ENGINE COOLING SYSTEMS ............................................................................................... 68

2.1 Introduction ..................................................................................................................................... 68

2.2 Scale deposition ............................................................................................................................... 70 2.2.1 Scale formation .................................................................................................................................. 70 2.2.2 Typical scaling mechanisms ................................................................................................................ 70 2.2.3 Effects of scale deposition .................................................................................................................. 71 2.2.4 Scale control ....................................................................................................................................... 72

2.3 Corrosion mechanisms ..................................................................................................................... 72 2.3.1 Steel (Fe) ............................................................................................................................................. 72 2.3.2 Stainless steels .................................................................................................................................... 73 2.3.3 Copper (Cu) ......................................................................................................................................... 74 2.3.4 Aluminium (Al) .................................................................................................................................... 74 2.3.5 Zinc (Zn) .............................................................................................................................................. 74

2.4 Factors affecting corrosion rates....................................................................................................... 75 2.4.1 Temperature ....................................................................................................................................... 75 2.4.2 pH/alkalinity ....................................................................................................................................... 75 2.4.3 Chloride ions ....................................................................................................................................... 76 2.4.4 Galvanic corrosion .............................................................................................................................. 77 2.4.5 Cavitation ........................................................................................................................................... 78 2.4.6 Corrosion fatigue cracking .................................................................................................................. 79

2.5 Corrosion Inhibition .......................................................................................................................... 79

2.6 Mechanisms of corrosion inhibition ................................................................................................. 80 2.6.1 Anodic Inhibitors ................................................................................................................................ 80


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2.6.2 Cathodic inhibitors ............................................................................................................................. 81 2.6.3 Combination and organic inhibitors ................................................................................................... 81

2.7 Corrosion monitoring ....................................................................................................................... 82

2.8 Microbiological fouling ..................................................................................................................... 83

2.9 Sea water cooling systems ................................................................................................................ 84 2.9.1 Corrosion and scaling ......................................................................................................................... 84 2.9.2 Microbiological fouling ....................................................................................................................... 85 2.9.3 Control of fouling................................................................................................................................ 86 2.9.4 Marine growth protection systems .................................................................................................... 86


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1 Steam boiler systems

1.1 Introduction

A boiler is a steel pressure vessel in which water under pressure is converted into steam by the application of combustion. In other words, it is simply a heat exchanger which uses radiant heat and hot flue gases, liberated from burning fuel, to generate steam and hot water for heating and processing loads. In early designs the boiler was a simple metal shell with a feedwater inlet and a steam outlet. Fuel was burned on a grate within a fire space below this shell and in early years of steam powered ships the fuel used was coal. Steam propulsion has in the main been replaced by the use of diesel engines and these engines are usually fired on heavy fuel oil. The marine industry has also seen an increase in the number of boiler systems designed to raise steam using heat rejected from diesel engines (exhaust gas boilers). Steam is raised mainly for heating the heavy fuel oil used to fire the ‘diesel engines’, for space heating, to power cargo handling pumps and as an aid to cleaning storage tanks and surfaces.

1.2 The water cycle

This section considers how the properties and impurities in water can lead to corrosion and scaling in steam systems. The water cycle is used to describe the life cycle of water on the earth. The water cycle (also known as the hydrologic cycle) is the journey water takes as it circulates from the land to the sky and back again. The sun's heat provides energy to evaporate water from the earth's surface (oceans, lakes, etc.). Plants also lose water to the air which is called transpiration. The water vapour eventually condenses, forming tiny droplets in clouds. When the clouds meet cool air over land, precipitation (rain, sleet, or snow) is triggered, and water returns to the land (or sea). Some of the precipitation soaks into the ground. Some of the underground water is trapped between rock or clay layers; this is called groundwater. But most of the water flows downhill as runoff (above ground or underground), eventually returning to the seas as slightly salty water. As water flows through rivers, it picks up small amounts of mineral salts from the rocks and soil of the river beds. This very-slightly salty water flows into the oceans and seas. The water in the oceans only leaves by evaporating (and the freezing of polar ice), but the salt remains dissolved in the ocean - it does not evaporate. So the remaining water gets saltier and saltier as time passes. Pure rain water, flowing through rock strata such as limestone or dolomite will slowly dissolve the minerals present in the rock and take them into solution.


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Figure 1: The water cycle

The most soluble minerals are those containing calcium, magnesium and sodium. These exist in water as calcium and magnesium bicarbonates and sulphates and sodium chloride. Sea water has a predominance of sodium chloride with significantly amounts of calcium and magnesium salts.

Sea water River water Bore hole water

Total Hardness 160 80 300

Calcium Hardness 120 60 220

Sulphate 2,000 30 280

Sodium Chloride 14,000 40 50

Conductivity 20,000 300 600

pH 7.4 7.4 7.2

Table 1: Typical water analyses (ppm)

The bicarbonate salts are termed alkaline hardness (or temporary hardness) while other calcium and magnesium salts are termed non-alkaline hardness (or permanent hardness). The salts of calcium and magnesium we typically encounter in water exhibit an inverse solubility. That is, as the water temperature rises their solubility reduces and at temperatures above 70°C they will come out of solution and redeposit as scale. In the boiler system, by returning a high proportion of good quality condensate, the amount of hardness entering the boiler can be reduced but in many cases the hardness salts must be removed before the water can be fed to the boiler. Guidance about maximum feedwater hardness and maximum total dissolved solids in various types of boiler is given in several available standards. Among these are BS 1170:1983, Treatment of water for marine boilers and BS 2486:1997, Recommendations for Treatment of Water for Land Boilers.


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1.3 Scale formation

Deposits on heating surfaces occur as a result of exceeding the solubility limits of impurities dissolved in the feedwater. As the feedwater becomes heated and/or concentrated the impurities become insoluble and form deposits. Calcium carbonate for example will deposit as scale at 65 – 70°C. It will be appreciated that very broadly, scale formation will tend to be greatest where the heat flux is greatest: the greater the rate of evaporation the greater will be the amount of solids left behind. Modern boilers transfer more heat over a smaller heating surface and higher peak fluxes tend to take place. Thus modern boilers with higher heat flux can be expected to be more prone to scale deposition than earlier types. The latest recommendations for Water Treatment take heat flux into consideration as well as operating pressure.

1.3.1 Typical scaling mechanisms

Calcium carbonate

Calcium carbonate scale appears as a pale cream yellow deposit and is formed by the thermal decomposition of calcium bicarbonate at heat transfer surfaces: Ca(HCO3)2 + Heat → CaCO3 + H2O + CO2 Calcium Calcium Bicarbonate Carbonate

Magnesium silicate

Magnesium Silicate scale is a rough textured, tan to off-white deposit found in boilers where sufficient amounts of Magnesium are present in conjunction with adequate amounts of silicate ions coupled with a deficiency of OH Alkalinity. Mg 2+ + OH- → MgOH+ H2SiO3 → H+ + HSiO3

- MgOH+ + HSiO3

- → MgSiO3 + H2SO4 We will see later that the maintenance of an adequate amount of OH alkalinity is a key step in the prevention of magnesium silicate scale.

Amorphous silica (SiO2)

Amorphous silica appears as a smooth glass like deposit that is strongly adherent and insulating and can only be removed by acid washing with Hydrofluoric Acid. In high pressure boilers (>40 bar) silica can distil from the boiler as silicic acid and cause deposits on turbine blades.

Calcium phosphate (Hydroxyapatite) (Ca10(PO4)6(OH)2)

Calcium phosphate is a tan/cream deposit, that can be found in boilers on phosphate cycle programmes where high levels of hardness salts have entered the boiler or over dosing of phosphate has occurred and there is not enough dispersant and alkalinity in the programme to maintain precipitated calcium phosphate in suspension for removal by blowdown.


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Iron oxide deposits

Hematite (Fe2O3)

This type of red/brown iron oxide deposit is found because of active corrosion occurring within the steam/boilers system. This could arise from the Feed, Boiler or Condensate systems.

Magnetite (Fe3O4)

This type of black/grey iron oxide deposit is formed on the surface of steel in the absence of stoichiometric levels of oxygen and is generally considered to be an indication of that good corrosion protection is being achieved at the point where it is found. Magnetite forms a protective layer on steel surfaces and prevents further corrosion attack. The presence of Magnetite can be problematic in high pressure boiler if the layer becomes too thick and acts to insulate the metal surface and cause overheating.

Copper

The presence of copper deposits in a boiler presents a very serious corrosion risk because of the initiation of galvanic corrosion mechanisms with boiler steel. The boiler metal is anodic to the copper and rapid loss of boiler metal will occur. Copper can appear in various form as a deposit in the boiler. As a copper coloured metallic deposit, usually in a corrosion pit, as bright red/orange tubercles on the boiler metal surface or as brown tear-drop shaped formations on the steel surface. Copper in the boiler usually arises from corrosion and/or erosion of copper condensate lines or clorifiers but can also arise due to corrosion/erosion of feed pump impellers and from feed-lines fabricated from copper. Erosion of copper in the condensate system is very common when the boiler is priming or foaming as the presence of suspended matter plus high pH acts to scour copper surfaces. Excess amounts of hydrazine will decompose to ammonia which is steam-volatile and is well documented as a corrosive agent for copper and its alloys. It is quite normal to find mixtures of the above compounds in a boiler deposit and it is the relative amounts of these compounds that can help us to deduce the most probable scaling mechanisms.


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Figure 2: Typical mixed scale deposit has caused overheating of boiler tube

Figure 3: Iron oxide deposit

1.3.2 Effects of scale deposition

The effect of scale is to thermally insulate the waterside of the heating surface retarding the flow of heat from the metal to the water. The only way the heat can get out is by raising the metal temperature and by raising the exit gas temperature from the boiler. The former may endanger the boiler structure, the latter will reduce efficiency. The loss of efficiency may not be too serious but consider the effect of 1 mm of scale on the waterside of the furnace of a shell boiler, the furnace being 25 mm (2.5 cm) thick and subject to a heat flux of 378 kW/m2 (37.8 W/cm2). Let the thermal conductivities be 45 W/m.K (0.45 W/cm.K) for the steel and 2.25 W/m.K (0.0225 W/cm.K) for the scale, both being typical values:


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Temperature drop through metal 37.8 x 2.5 = 210 °C 0.45 Temperature drop through scale 37.8x 0.1 = 168 °C 0.0225 Temperature drop through waterside film, say 16 °C Total temperature drop 394 °C

Figure 4: Effect of scale on boiler metal temperature

If the saturation temperature is 205°C, the fireside metal temperature will be 599°C which is well beyond the temperature of about 445°C, where creep begins to dominate the elastic properties of the metal. If scale were not present the temperature would have been only 431°C; within the safety range. Moreover, the higher the furnace temperature, the greater its expansion and hence its thrust on the end plates of the boiler. These factors illustrate the importance of preventing scale formation, and that current and future trends in boiler design will require high quality feedwater treatment. The most common deposits encountered are carbonates, silicates and phosphates of calcium and magnesium. The second most common deposit encountered is iron oxide which may be present in the raw water or may originate from corrosion occurring in the feed or condensate system. In water tube boilers, in particular, iron can form deposits which adhere very tenaciously and insulate the tube causing rapid overheating and failure of the tube. The salts of silica and can produce scales of extremely low thermal conductivity and even in very thin layers can produce the effects described earlier. The chemical structure of the scale as well as the design and method of operation of the boiler, all influence the amount of heat lost. Heat transfer may be reduced by as much as 10 - 12% by the presence of scale. A scale of 3 mm (1/8 “) can cause an overall loss of efficiency of 2 - 3 % in fire tube boiler and water-tube boilers without heat recovery.


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Figure 5: The effect of boiler scales on tube metal temperature

1.4 Scale control by external pre-treatment

The control of scale deposition in steam boiler is a combination of external and internal chemical treatments. In general as the boiler pressure and heat flux increase there is a requirement for higher purity feed-water: 0 – 18 bar < 10 ppm 8.5 - 9.5 18 – 31 bar < 5 ppm 8.5 - 9.5 31 – 42 bar < 2 ppm 8.5 - 9.5 External treatment is used to remove the great majority of problematic salts. The type of external water treatment to be selected will be governed by:

a) The quality of the raw water. b) The percentage make-up in relation to total feedwater requirements. c) Boiler operating conditions. d) Economics


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1.4.1 Sea water evaporation

The evaporator is a critical part of the integrated water systems found on sea-going vessels. These units are essentially low or negative pressure boilers designed to evaporate, condense and collect pure water from sea-water make-up. They are normally fed with warm sea-water that has been used to cool the engine cooling system and extra heat is applied to cause evaporation. Pure water is condensed and collected for subsequent use in:

Engine cooling circuits

Boiler make-up water

Potable drinking water supply The evaporation of pure water from sea-water is probably the most common route to produce high quality feed water for marine boilers. These units typically function by distilling pure water from heated sea-water under an induced vacuum. The water vapour is condensed using a sea-water cooling jacket and pumped to storage. The concentrated brine produced is ejected to waste. 1. Evaporators operation 2. Seawater feed 3. Heating medium in 4. Heating medium out 5. Seawater cooling in 6. Seawater cooling out 7. Fresh water out 8. Evaporated steam 9. Demister 10. Condenser 11. Evaporator 12. Brine out Figure 6: Typical evaporator layout


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Figure 7: Alfa Laval multi-effect evaporator

Figure 8: Weir single effect evaporator


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Operational Issues

There are numerous suppliers and types of evaporators and they all function to produce pure water with concentrated sea-water as waste. This concentration effect can lead to the formation of damaging scales within the evaporator and lead to downtime for cleaning and maintenance. Over concentration is usually prevented by having a continuous stream of sea-water passing through the unit thus maintaining a satisfactory dilution of the sea-water side of the evaporator. However, because of the high salt content, when sea-water is elevated to temperatures above 30°C scales can begin to form on heat transfer surfaces. Depending on the degree of concentration these scales can be:

Calcium carbonate

Magnesium carbonate

Calcium/magnesium sulphate Additionally as the majority of evaporators operate under vacuum there is a tendency for the make-up water side to foam, which can give rise to carry-over and contamination of the pure water stream. There are many mechanisms governing the rate of scale formation but the main ones are:

Supersaturation

This is where the concentration of dissolved salts exceeds their solubility at the particular temperature encountered and precipitation begins to occur. When deposition occurs under these conditions heavy scale deposits can rapidly build up and lead to a loss of heat transfer efficiency. Scale deposition due to supersaturation is often localised in areas of elevated temperature such as heat transfer surfaces in heat-exchangers. This is because of localised over concentration of salts with respect to the temperature of the thin water layer at the surface of the metal. Scale deposition can therefore occur on heat-exchange surfaces even when the conditions in the bulk of the water are not scale forming.

Nucleation

This effect describes the initial precipitation of scale particles which can occur in a spontaneous manner or when a foreign particle acts as a ‘seed’ or nucleation site for the scale to bind onto and form around. The roughness of internal surfaces plays an important factor in this process and metal surfaces contain many microscopic peaks and valleys that act as nucleation sites for scale.

Contact time

In the environment at the heat transfer surface, scale is being precipitated and re-dissolved continuously and it is only when the rate of precipitation exceeds the rate of dissolution that scale deposition occurs. In general the contact time required for scale deposition to occur will reduce as temperature at the surface rises and as flow rate reduces.

pH and alkalinity

As the pH and alkalinity of water increase there is naturally a greater tendency for the water to be scale forming.


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Temperature

Compounds such as calcium carbonate and calcium sulphate exhibit an inverse solubility with temperature i.e. as temperature rises these compounds become less soluble.

Figure 9: Solubility of Calcium Carbonate and Calcium Sulphate

To minimise the rate of scale deposition it is recommended to strictly adhere to the manufacturers recommended operating temperatures and procedures. However, for the reasons previously explained, scale deposition is always likely to occur at the operating temperatures found at the heat transfer surfaces

Flow velocity

Low flow rates can lead to non-turbulent or laminar flow across heat transfer surfaces. This effect will increase the incidence of scaling as it will allow the water to reach higher temperatures and increase the contact time in an environment for scale formation.

Scale prevention in evaporators

Concentration Factor

In order to prevent excessive concentration of salts in the body of sea-water in the evaporator it is necessary to apply a continuous blowdown. The maximum concentration which can be tolerated before calcium and magnesium sulphate or carbonate scales will begin to form is around 2. Thus for an evaporator producing 5 tons/day or distilled water the minimum feed rate should be 10 tons/day, and 5 tons of blowdown is required to maintain the concentration factor below 2. The concentration factor of the evaporator can be calculated from the amount of feed divided by input, less the output of distilled water: Concentration factor = Total sea-water feed Total sea-water feed - evaporated water output


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The maximum concentrations permitted in an evaporator are governed by the design characteristics of the unit and is normally quoted by the manufacturer in their operating manuals.

Chemical treatment

Even when the concentration factor is maintained in recommended limits there is still a great risk of scale formation at the heat transfer surfaces due to the mechanisms already described and it is necessary to apply a suitable scale inhibitors and antifoams to the sea-water make up line to minimise the occurrence of such problems. A suitable automatic dosing system can be fitted to provide accurate treatment application. Successful evaporator performance will be achieved by paying close attention to the following parameters:

Ensure correct mechanical operation

Ensure correct Feed-water flow

Work to specified design temperatures

Apply and control a suitable scale inhibitor/antifoam

Approvals

Where water from the evaporator is used to provide drinking water or water for cooking, then the scale inhibitors and antifoams must have suitable approval status such as that from the U.K. Department Of Transport, Marine Safety Agency, Norwegian National Institute for Public Hygiene and Health, Japan Food Research Laboratories.

1.4.2 Reverse osmosis

Reverse osmosis (RO) is a process commonly used in desalination and is finding increased use for the treatment of boiler feed-water. RO relies on the principle that when solutions of differing concentrations are separated by a semi-permeable membrane, water from the less concentrated solution passes through the membrane until the concentrations of both solutions are equalised. A hydraulic pressure gradient thus builds up across the membrane. The process will continue until the hydraulic gradient is equal to the osmotic pressure. This is determined by the difference in concentration between the two solutions. If a pressure greater than the osmotic pressure is applied to the more concentrated solution, the process is reversed. Water from the more concentrated solution is forced back through the semi-permeable membrane diluting the more dilute solution on the other side. The concentration of the stronger solution is thus increased. Water from the dilute side of the membrane passes to service while that from the concentrated side is either run to waste as brine or used for low grade purposes. This treatment is capable of removing up to 90% of dissolved solids depending upon the age of the plant. Further treatment is required if water of demineralised quality is required. Water containing high levels of hardness is usually pre-treated prior being fed onto the RO membranes to prevent them becoming fouled with calcium salts.


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Figure 10: Schematic of RO Process

Ions % Passage % Reject

Ammonium 8 92

Sodium 5 95

Potassium 5 95

Magnesium 3 97

Strontium 3 97

Calcium 2 98

Nitrate 15 85

Bisilicate 10 90

Chloride 5 95

Fluoride 5 95

Bicarbonate 5 95

Sulphate 3 97

Phosphate 1 99

Table 2: Typical passage of ions across RO membrane

Figure 11: Spirally wound membrane cartridge


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Figure 12: RO membrane filament

1.4.3 Ion exchange processes

Although only used to a lesser extent on marine vessels, another pre-treatment approach for boiler feed water involves some form of ion-exchange treatment. Ion-exchange is a specialised branch of polymer chemistry where beads of polymeric resins (usually styrenes) are formed with particular reactive ions attached. These are held in a vessel and the water requiring treatment is passed over the resin bed.

Figure 13: Schematic of ion exchange resin bead


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Figure 14: Photograph of ion exchange resin beads

When these reactive sites are exposed to concentrations of similar ions they will chemically exchange with these ions. This technology is employed to remove troublesome ions such as calcium, magnesium and silica for low pressure boilers and even sulphates and chlorides for high pressure boilers.

Base exchange softening

This is primarily used for the removal of the cations, calcium and magnesium, in low to medium pressure boilers. The Ca and Mg ions are exchanged at the resin surface with Sodium (Na). The sodium salts formed such as sodium carbonate are much more soluble than the equivalent calcium or magnesium salts and therefore do not precipitate in the boiler to form scales. Once all the reactive sites on the resin are used up the resin is regenerated and reactivated with a concentrated solution of sodium chloride.


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Figure 15: Sodium ion exchange process

Demineralisation

For high pressure boiler it is usual to employ ion-exchange systems that are designed to remove all cations and anions from the incoming water supply. The most common arrangement is a strong acid cation exchanger in the hydrogen form in series with a strong base anion exchanger in the hydroxide form (with or without a degassing tower between them). Water passes first through the cation exchanger where it is converted to a solution of dilute acids. The partially treated water passes through the anion exchanger where the anions (chloride, sulphate, nitrate etc.) are exchanged for hydroxide ions. The hydrogen ions produced in the first stage react with the hydroxide ions from the second stage to produce water: H+ + OH- = H2O The resins are regenerated when all reaction sites are used up. Cation resins are regenerated using dilute hydrochloric or sulphuric acids and the anion resin with dilute sodium hydroxide. For lower water throughputs a single vessel, mixed bed treatment approach can be utilised for demineralisation.


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Figure 16: Cation exchanger


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Figure 17: Anion Exchanger

The following table shows the effect of various routes for pre-treatment. The best approach for any boiler system is dependent on the quality of raw water, and the quality of water recommended to supply the boiler.

Treatment Total Hardness

Calcium Hardness

Silica Sodium Chloride

TDS

Sea Water 250 200 14 15000 15000

Evaporator < 0.2 < 0.2 < 0.2 < 20 < 20

R.O. 20 5 < 1 < 750 < 750

B/Ex < 5 < 5 14 15000 15000

Demin. 0 < 1 trace < 2 < 3

Table 3: Summary of effect of external treatment options


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1.5 Boiler classifications

Boilers are mainly classified as Water Tube or Fire Tube designs. These can be sub-classified into fired and non-fired types.

1.5.1 Water-tube boilers

Figure 18: The water tube circuit

In a simple water tube circuit, steam bubbles form on the heated side of the tube. The resulting steam-water mixture weighs less than the cooler water on the unheated side and is displaced. When the steam water mixture reaches the steam drum the steam bubbles rise to the surface and disengage into the steam distribution system. This repeated pattern ensures that steam is produced continuously with adequate water circulation to prevent overheating of the internal surfaces of the boiler. Most steam boilers found on ships rely on this principle for water circulation.

1.5.2 Vertical water tube boilers

This design of boiler is by far the most common found on marine vessels and are almost exclusive to the marine industry because of their compact construction and ease of operation. A cylindrical shell contains a hemispherical or cylindrical furnace chamber at the base of the shell. The burner is fired onto this space. From the furnace the hot gases pass through a single internal flue to the stack. To compensate for the short retention time of gases, water tubes can be disposed horizontally, vertically, or obliquely (cross-tubes) in the furnace section. Natural water circulation is effected by having a series of non-heated down-comers connecting the upper steam/water chamber to the lower ring-shaped bottom header. Maximum design pressures do not normally exceed 17 bar (250 psig).


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Figure 19: Vertical steam boiler


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Figure 20: High pressure water tube boiler

High pressure Water Tube boiler systems are fabricated from heavier gauge pipe-work and this design means that much higher steam pressures and flows can be obtained. Water-tube boiler can operate at pressures up to 140 bar with steam outputs up to 300 tons/hr. Large water-tube boiler utilities used for power generation can be around 5 stories high. Smaller ‘packaged’ units are the most common steam boiler arrangement found on marine vessels. Figure 20 shows a D-type water-tube boiler with an approximate output of 5 tons/hr. The burner fires onto the loop of the D causing steam/water circulation up the inner tubes and down the cooler outer tubes. There are a large number of these circuits within the boiler which are linked by the horizontal pipe-work of the steam and mud drums and sometimes by ancillary header pipes. The large upper steam drum ensures clean steam and water separation and blowdown is taken from the bottom mud-drum.

1.5.3 Dual circuit boilers

Because of the oil heating duty and subsequent risk from contamination due to leaks, the steam system on a ship can consist of primary and secondary steam circuits (Figure 21). Here the primary steam circuit operates as a closed cycle and the steam/water circuit is used to evaporate steam from the secondary circuit. The secondary circuit can also be linked to an exhaust gas boiler for improved efficiency. For water treatment applications the two systems have to be considered separately and individual treatment regimes applied.


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Figure 21: Dual circuit boiler system

1.5.4 Exhaust gas boilers

It is very common for the steam system on a ship to incorporate an exhaust gas boiler. This type of unit is essentially a heat-recovery system designed to take heat from the hot engine exhaust flow. Exhaust gas boilers can be built into the exhaust flue-gas ducting (Figure 22) or incorporated into the vertical boiler construction (Figure 23). It is normal practice to fire the boiler using the burner when in dock or manoeuvring and to utilise the most heat possible from the exhaust gas boilers when underway.


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Figure 22: Typical exhaust gas boiler configuration

Figure 23: Internal exhaust boiler (combi-boiler)


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Figure 24: Typical exhaust gas boiler schematic

1.5.5 Steam generators

A steam generator, or coiled tube boiler, is compact and lightweight. It has a rapid steam-making capacity from cold and responds quickly to fluctuating loads. Water is pumped through the coiled tube, which receives heat from the centrally situated burner. The firing rate is proportional to the load. There are no drums; the feedwater circulates through the coils, partially flashed into steam in a separator, and the remainder re-circulated. The size and weight of the boiler are, therefore, considerably reduced. The combustion chamber is pressurised and heat is released at a higher rate than in a conventional boiler. A combination of forced flow on both the gas and water sides of the coiled tube provides high turbulence and velocities for efficient and rapid heat transfer. The fully automatic controls and proportioning system for fuel and air enable the unit to be operated with the minimum of supervision. The boiler is a packaged unit in the sense that it is mounted with its auxiliaries on a single base plate. High quality feedwater is essential.


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Figure 25: Steam generator layout

1.6 Ancillary equipment

1.6.1 Boiler water level controllers

Level controllers are designed to control the flow of feed water to the boiler in proportion to steam demand and use the change in boiler water level as the load detector. They usually comprise a single element electro-hydraulic control with an electronic feedback system or multi-tip conductivity probes. These can be installed to provide either simple on/off control of the boiler feed pumps or modulating control where the feed-pumps run continuously and the controller adjusts the feed-water inlet valve to allow the correct amount of water flow to enter the boiler.

Figure 26: Feed-water on/off control


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Figure 27: Feed-water modulating control

1.6.2 Anti priming devices

1½ - 2% steam wetness is considered to be typical of packaged boilers at 75-100% output while 4% would be anticipated from highly rated boilers. Assuming the wetness to be wholly due to entrainment gives the maximum TDS in condensate, which is: 10 ppm/1,000 ppm TDS in the boiler/1% steam wetness. From the general range of TDS in this type of boiler (2,000 - 4,000 ppm) the TDS in condensate may therefore range from 30 to 160 ppm with the above wetness figures, without any unusual carryover having occurred. A frequent cause of priming is sudden increases in boiler loading. Even though the final steam output is not greater than the boiler rating, rapid changes in steam demand can require rates of load increase which the boiler cannot handle. This position can be met by installing an orifice plate after the steam stop valve to control maximum output at any time to 100-125% of nominal rating. If a greater demand develops, the steam after the orifice expands. The quantity required is thus supplied, although at somewhat lower pressure, until the boiler 'catches up' with the demand rate. It must be emphasised that an orifice plate is not useful where the boiler is undersized for the output required. The orifice size can be calculated approximately by the following formula: G = 18796 f pV where: G = steam flow rate (kg/hr) f = orifice size (cm2) p = steam pressure before orifice (bar) V = volume of 1 kg of steam at pressure p

1.6.3 Internal feed pipes

Where these are fitted, part or all of the feed-pipe is invariably slotted or perforated. This allows alkaline boiler water to enter and mix with the incoming feed along the whole of the slotted length. Precipitation can occur and the pipe may ultimately block if hardness salts are present in the feed-water. This item requires thorough cleaning each time the boiler is opened, particularly in the case of single boiler installations. In cases of difficulty some


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improvement may be achieved by enlarging the holes in the pipe, or shortening the perforated length. Some boiler makers have taken the latter process to its logical conclusions and entirely dispensed with an internal feed pipe, providing only a baffle plate over the feed entry port. Good control of pre-treatment (e.g. softening) and modern treatment regimes have largely eliminated precipitation problems.

1.6.4 Superheaters

Superheaters are additional heat recovery systems designed to take extra heat from the furnace of the boiler into the steam. They are usually fitted to water-tube boiler systems and consist of a bank of pendant tubes hanging in the furnace chamber. Steam passing through this arrangement can absorb heat which raises its temperature above its saturation point. This gives a good thermodynamic gain in efficiency and also acts to further dry the steam which prevents condensation in turbines if fitted.

Figure 28: Common superheater arrangements

1.6.5 Steam traps

Steam traps are installed at regular points in the steam lines to remove condensate water from the steam flow. This is to ensure a smooth passage for the steam by preventing restrictions due to the build up of pockets of water, to enable recovery of valuable hot condensate for re-use and to allow the steam to give up its heat at optimum efficiency free from the insulating effect of condensate water. There are various designs available and the most common is a ball-float type that is designed to collect condensate water and direct it into the condensate collection pipe-work. The collection of hot condensate water is an important heat recovery cycle in the boiler system as it amounts to a re-use of heat via the feed system. As a rule of thumb, a 5°C increase in feed-water temperature equates to a 1% reduction in fuel consumption.


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Figure 29: Ball float steam trap

Operating mechanism On start-up a thermostatic air vent allows air to by-pass the main valve (1) to prevent air-locking. As soon as condensate reaches the trap, the float is raised and the lever mechanism opens the main valve (2) to allow condensate water to flow into the return pipe-work. When steam arrives at the float it drops and closes off the main valve ensuring that live steam does not enter the condensate return system. This cyclic process ensures efficient removal of condensate water.

1.6.6 Steam turbines

Turbines utilise the principle that steam issuing from a small orifice attains a high velocity and expands. The velocity attained (kinetic energy) is directly proportional to the initial and final heat content of the steam. A turbine that makes use of the driving force of the steam is termed an impulse turbine and that which makes us of the reaction forces produced by the flow of steam is termed a reaction turbine. In practice modern turbines utilise a combination of impulsive and reactive forces and their blading is designed to take advantage of both forces to instigate rotation. The rotational forces are then used to produce electrical power via a generator set. Turbines are designed to operate at velocities of 1500 - 3600 rpm and can have power outputs ranging from 750 W to 1,000,000 kW. Turbines can be categorised into two main classes, condensing and non-condensing. Condensing turbines exhaust steam at less than atmospheric pressure and non-condensing turbines exhaust steam at pressures higher than atmospheric. Operational Concerns The efficiency and reliability of modern steam turbines can be seriously impaired when contaminated steam is admitted to the unit. Contaminants in the steam usually cause deposits on the turbine blades or act to erode the blades due to an increase in abrasive action. Specific problems due to contaminated steam include the following:

Stress corrosion cracking

Solid particle erosion

Deposit build-up

Corrosive pitting


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In all cases the important factor is impure steam. Where turbines are employed it is vital to ensure that high purity steam is produced by the correct control of water chemistry and blowdown.

Figure 30: Various turbine layouts


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1.7 Boiler operation – blowdown

The boiler should always be operated per the instructions of the boiler manufacturer, and these should also include blowdown procedures. The boiler will have a bottom blowdown valve and/or a surface skimmer valve. Managing proper blowdown control is essential in maintaining stable operations of a boiler. There are several factors influencing how blowdowns should be performed. The main purposes are:

Control of sludge deposits in the boiler – bottom blowdown

Control of floating matter – surface skimmer

Control of dissolved solids, prevents carryover and corrosion – both methods are applicable

Bottom blowdown

Periodic bottom blowdown is necessary if the boiler operates on shore water as this may produce calcium phosphate sludge deposits. These will often settle in the bottom of the boiler, and periodic operation of the bottom blowdown will aid in removing these deposits. Failure to do so may result in excessive amounts of sludge deposits in the boiler and the risk of potential overheating of the boiler heating surfaces.

Surface skimmer

Surface skimmers may not be present on all boilers. If the water is distilled or very soft, the need for bottom blowdowns may be less and the dissolved solids in the water may be controlled by the surface skimmer. Some boilers may have automatic systems for maintaining the conductivity in the boiler water.

Cycles of concentration

This term is defined as the ratio of the dissolved solids content between the feed water and the boiler water. There are several ways to calculate this, measuring chloride levels in the feed water and the boiler water is a common approach. Figure 31 shows a basic example of a boiler with 5% blowdown. In this case the cycles of concentration is 20 (10 t / 0.5 t). Typically this value will be in the range of 10-30.


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Figure 31: Schematic of boiler blowdown

1.8 Chemical scale control

In addition to adequate pre-treatment of boiler feed-water, controlled reserves of treatment chemicals need to be maintained in the boiler-water to ensure that any traces of deposit forming compounds such as salts of calcium, iron, silica, copper and magnesium are prevented from forming hard scales or baked on sludges. There is a number of treatment options used to prevent scale deposition.

1.8.1 Carbonate cycle control

This treatment approach is only recommended for package boilers up to 10 bar, without any external feed-water treatment. This could give us in the order of 40 ppm calcium hardness in the feed water. The aim is to maintain a minimum of 250 ppm carbonate alkalinity in the boiler water by the addition of sodium carbonate. This causes any calcium present to precipitate in the bulk of the boiler water rather than at the heat transfer surfaces as baked on scale. The fine precipitate is then removed with the boiler blowdown. Excess carbonate will break down to form hydroxide alkalinity and carbon dioxide. Magnesium precipitates as magnesium hydroxide or magnesium silicate if silica is present in the boiler-water. It is important that dispersants are incorporated into this programme to ensure that precipitated compounds are maintained in suspension to facilitate removal by blowdown.

1.8.2 Phosphate cycle control

This treatment approach relies on good quality pre-treatment, (usually sea water evaporators) plus the addition of soluble phosphate and hydroxide alkalinity to the boiler-water. These react with any trace calcium, magnesium and silica impurities to form fine precipitates of: Calcium Hydroxyapatite, Ca10(PO4)6(OH)2

Boiler water

Feed water

10 ton/day

Blowdown

250 liter x 2/day

(0,5 ton/day)

Steam

9,5 ton/day


36

Serpentine, MgSiO3Mg(OH)2H2O Magnesium Hydroxide, Mg(OH)2 Since these products have extremely low solubility they will precipitate in the boiler water and can subsequently be removed by blowdown. Again it is important to incorporate dispersants in the treatment programme to ensure that precipitated compounds are maintained in suspension and facilitate removal by blowdown.

Silicate scales

Where phosphate cycle chemistry is employed it is important to maintain adequate OH alkalinity levels to ensure that magnesium precipitates as magnesium hydroxide or as hydrated magnesium silicate, which are not adherent. To achieve these conditions then we must aim for a Silica : OH alkalinity ratio of 0.4 : 1 and secondly a PO4 : OH alkalinity ratio of 1 :10. Overdosing of phosphate must also be avoided to prevent the formation of phosphate scales.

1.8.3 All polymer control cycle

Where good and consistent pre-treatment of boiler feed-water can be relied upon : control of deposition can be more than adequately maintained by the use of polymeric conditioning treatments. These are generally based on proprietary formulations of long chain negatively charged polymers and co-polymers with good stability at the high temperatures found in boiler-waters. All polymer treatments can be described to inhibit scales by the following mechanisms:

Crystal modification:

Figure 32: Crystal modification

The dispersant acts on the surface of the scale as it is formed to prevent the formation of large angular crystals which are adherent to the heat transfer This action causes the scale to form in smaller, more rotund particles which are less adherent to surfaces.

Dispersion


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Figure 33: Dispersion

The negatively charged polymers attach to boiler metal and surround particles in the boiler-water. This mechanism sets up repulsive forces that inhibit the particles from agglomerating to form scale or sludge deposits.

Complexation

Figure 34: Complexation

Negatively charged polymers can form weak sub-stoichiometric complexes with calcium, magnesium and iron which allow these impurities to exceed their normal solubility levels and acts to inhibit deposition at heat transfer surfaces. For best scale control it is important to maintain an adequate reserve of free polymer in the boiler water at all times.

1.9 Corrosion in the steam boiler system

In the hot, aqueous environments encountered in steam boiler systems, corrosion is an ever present threat to equipment integrity.


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Corrosion can occur throughout the boiler system. The most common causes of corrosion are:

Oxygen attack

Over concentration of alkalinity

Acid attack due to presence of Carbon dioxide and Carbonic Acid

Ammonia Attack

1.9.1 Oxygen attack

Oxygen is present in cold water up to a level of 9 ppm and reduces in an open system with increasing temperature (Figure 36). This may not seem like a lot, but for the corrosion processes we encounter in the steam boiler system it is enough to cause corrosion leading to catastrophic plant failure in a matter of months.

Figure 35: Corrosion cell

With reference to the corrosion cell the corrosion process can be represented as an electrochemical reaction: At the Anode: Metal goes into solution Fe → Fe2+ + 2 e- OXIDATION At the Cathode: Oxygen is reduced ½ O2 + H2O + 2 e- → 2 OH- REDUCTION The variables pH, temperature and the concentration of oxygen affect the rate of corrosion.


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As temperature and/or oxygen levels rise the corrosion rate accelerates. pH and oxygen corrosion are inversely related to corrosion rate. This is why alkaline conditions are maintained in the boiler system. Oxygen reacts with iron to give ferric oxide (rust) Fe2O3 which will not protect the metal from further attack and metal is continuously dissolved. 4Fe + 3O2 → 2 Fe2O3

Haematite (ferric oxide) Oxygen corrosion is usually observed as localised pitting on a metal surface. This form of corrosion can be reduced to acceptable levels by three strategies:

by reducing the level of oxygen as far as possible using mechanical means which include deaeration and/or judicious heating, coupled with good feed-system design

by ensuring that there is an adequate and controlled reserve of alkalinity in the boiler water at all times.

by the application and maintenance of an adequate reserve of a chemical oxygen scavenger.

It should be noted that not all metal oxides are detrimental. Under low oxygen conditions iron oxide forms a very thin, dense and adherent layer on the metal, protecting the metal from further attack. An example is the outside layer of the boiler metal which oxidises and forms the protective magnetic iron oxide film Fe3O4 (magnetite). Corrosion will only take place if this film is removed or penetrated and not immediately repaired.


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Figure 36: Variation in the concentration of dissolved oxygen with temperature

1.9.2 Caustic Corrosion

This type of corrosion is mainly confined to high pressure boilers with high heat transfer rates. At the metal surface the high rate of steam evolution causes concentration of salts at the heat transfer surface.

Figure 37: Example of caustic attack

Oxygen saturation in water

0

2

4

6

8

10

12

14

16

0 10 20 30 40 50 60 70 80 90 100

Temperature/°C

Oxyg

en

/pp

m


41

This mechanism is exacerbated by the presence of deposits such as scale and iron oxide. If even small amounts of deposit are present alkalinity levels of up to 20000 ppm have been reported to exist in such environments. High concentrations of alkalinity will begin to attack the boiler metal:

1. 4 NaOH + Fe3O4 → 2 NaFeO2 + Na2 FeO2 + 2 H2O

Magnetite film breaks down

2. Fe + NaOH + H2O → Na2FeO2 + H2

Tube-wall attack and wastage of metal Hydrogen evolution

3. 4 H + C → CH4 (methane) Here inter-granular penetration by hydrogen causes de-carbonisation of the metal along grain boundaries which can cause catastrophic failure. In high pressure boilers close control of free OH alkalinity is vital to the prevention of alkalinity attack. We will see later that there are specialised treatment programme designed to minimise the occurrence of this type of corrosion.

1.9.3 Acidic attack - condensate line corrosion

The gas most commonly associated with condensate line corrosion is carbon dioxide (CO2). It can be found in small amounts, free in solution, however, the greatest source of the gas is from the thermal breakdown of bicarbonate and carbonate alkalinity present in the feedwater. At temperatures and pressures found on the boiler the following reactions occur: Ca/Mg(HCO3)2 → Ca/MgCO3 + CO2 + H2O Calcium or Calcium or Magnesium Bicarbonate Magnesium Carbonate Ca/MgCO3 + H2O → 2 NaOH + CO2

Sodium Hydroxide Breakdown of bicarbonates (1) proceeds to 100% completion Breakdown of carbonate (2) proceed 70 - 100% completion depending upon boiler pressure. The CO2 liberated in both reactions is carried over with the steam and dissolves with the condensate. As it dissolves it forms Carbonic Acid. CO2 + H2O H2CO3 H+ + HCO3

-


42

Carbonic Acid Since condensed water is very pure, even small quantities of carbonic acid can significantly reduce the pH of the condensate and greatly increase its corrosivity. As little as 1 ppm CO2 in the steam can reduce the condensate pH from 7.0 to 5.5 (Figure 38). At a pH of 5.5 rapid corrosion of steel will occur. Corrosion due to acid attack usually shows as thinning of metal. Especially at bends and threaded joints. The on-set of condensate line corrosion can occur very quickly, leading to steam leaks and high replacement costs.

Figure 38: Effect of CO2 on pH / Condensate corrosion

1.9.4 Ammonia corrosion

Corrosion caused by ammonia is usually found in systems with components constructed from copper or copper alloys such as condensers, feedwater pump impellers, and condensate pipe-work and is not exclusive to high pressure boiler plant. Ammonia can be present as part of a treatment approach to raise the condensate pH and reduce corrosivity to steel or by the thermal degradation of other treatments such as hydrazine. Ammonia is especially corrosive to copper and its alloys in the presence of oxygen.


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The oxygen reacts with copper to produce a copper oxide coating on the metal which can be rapidly dissolved by ammonia. The reaction cycle produces a soluble cupric ammonia complex and cause rapid metal loss. Cu + 1/2O2 → CuO CuO + 4NH3 + H2O → Cu(NH3)4

2+ + 2 OH- This mechanism is especially aggressive below pH 8.5 and above 9.2

1.9.5 Descriptions of common types of corrosion encountered

Grooving and thinning is often observed in condensate systems where the condensate is high in carbon dioxide. Pitting often occurs in low pressure boilers due to oxygen attack at breaks in the protective magnetite film. This form of attack can be very localised and can result in a deep pit leading to perforation of the metal. Tuberculation is normally confined to feed-tank and feed-lines of plants using poor quality feedwater with a high dissolved oxygen content, high bicarbonate alkalinity and low pH. Crevice attack can occur where tubes are rolled into the boiler end plates and is due to the setting up of a concentration cell where there are differences in the concentration of salts, oxygen content and hydrogen ions. Caustic cracking occurs in areas of high stress, where caustic soda can concentrate and attack the steel. The advent of all welded boilers, and stress relieving has greatly reduced the incidence of this type of attack. Hydrogen embrittlement is confined to high pressure boilers and is the result of the direct attack of caustic soda on the boiler steel in areas of high heat flux. The hydrogen generated by the reaction penetrates the grain boundaries of the steel leading to metal failure. Most of these problems can be minimised by proper operation of pre-treatment equipment and a well controlled chemical control programme.

1.10 Corrosion control

1.10.1 Physical oxygen removal

Heating

Figure 36 shows that by raising the temperature of the feed-water the concentration of dissolved oxygen can be substantially reduced. Heating can also be applied by returning hot condensate waters and the installation of proprietary steam injection equipment in the feed-tank.


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Feed tank design

To obtain the best and most consistent removal of dissolved oxygen especially in lower pressure boilers with open feed-systems, attention must be paid to the internal configuration of the Feed-tank. Figure 39 shows an idealised design which incorporates some common-sense features that are used to achieve a consistent and even water temperature. It is advised that this diagram is referred to as the optimum required configuration for the minimisation of oxygen in the feed-water system. Note: Significant amounts of Carbon dioxide are not removed by simple heating as the level of CO2 encountered is usually associated with bicarbonate and carbonate impurities in the feed-water.

Cavitation

Care must be taken when heating the feed-water as at temperatures above 90°C, with a low suction head on the feed-pump there is a risk of cavitation on the feed-pump impellers. This phenomenon occurs because the reduced pressure on the suction side of the impellers causes the water to boil and steam bubbles to form. Subsequent collapse of these steam bubbles can be so energetic as to physically destroy the metal surface. The onset of this problem can be rapid and impeller failure has been known to occur within hours of operation.


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Figure 39: A well designed open feedwater tank

Deaeration

This is a process of removing dissolved gasses down to very low levels for increased corrosion protection, especially in high pressure boiler systems. Deaeration relies on the fact that when water is raised to its saturation point (boiling point), all freely dissolved gases become insoluble. In practice this effect is made more efficient by agitating the water and breaking it up into small droplets. In high pressure boiler plants it is normal practice to employ a deaerating plant in which dissolved gases (oxygen and carbon dioxide) are removed from solution by steam heating either under pressure or under vacuum. These gases are then ejected to atmosphere. The dissolved oxygen content of the water leaving the deaerator should be as low as possible (0.007 - 0.02 ppm). The trace quantities of dissolved oxygen remaining after mechanical deaeration should be removed by chemical treatment. In those cases where a deaerator is not fitted, full oxygen removal by chemical treatment should be employed. The need for the installation of a mechanical deaerator is dependent upon various factors such as plant loading, percentage condensate return etc.


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Generally speaking, however, plants with an hourly evaporation in excess of 22,000 kg/hr irrespective of boiler pressure should be provided with full flow mechanical deaeration.

Figure 40: Spray type deaerator

Here, feed-water enters via the first stage heater through spring loaded spray valves. Droplets formed by spraying increases the surfaces area of the water which improves heating efficiency and removal of dissolved gases. The feed-water then enters the second stage heater where it rises to within 0.5 - 2°C of the steam temperature. Oxygen levels are further lowered and gases are vented to atmosphere. The fully deaerated feed-water then drops into the storage section.


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Figure 41: Tray type deaerator

Again the feedwater is sprayed into the heating chamber. The water is then allowed to contact the gas free steam as a thin film passing over a series of trays. The gas free water falls into the bottom section for storage.


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Figure 42: Deaerating head

Deaerating heads can also be employed to reduce oxygen levels. These units more simply apply the principles outlined previously and will significantly reduce the level of dissolved gases in the boiler feedwater.

Trouble shooting

Poor deaeration is the result of either a mechanical malfunction or flow control. Problems, such as:

1. Inadequate or restricted venting. 2. Inadequate steam flow or fluctuating steam pressure. 3. Wide fluctuations in feed-water flow. 4. Feed-water flow rates outside design specifications. 5. Plugged, broken or missing nozzles and/or trays.

1.10.2 Chemical oxygen removal

After due consideration of the feed system the operation of the deaerator (if installed) it is still necessary to apply a chemical oxygen scavenger to eliminate oxygen residuals and assist in the passivation of metal surfaces. There are various types of oxygen scavenger available to carry out this task and selection of the best approach is a function of the amount of oxygen present, risk, feed system design, economics and any particular limitations required by the process using the steam.

Sulphite

Sodium sulphite (Na2SO3) is widely used for oxygen scavenging. Sodium sulphite has been found satisfactory at pressures up to about 62 bar (900 psig). Above these pressures


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decomposition products such as H2S and SO2 can affect steam purity. The preferred method of application is to dose the feedwater continuously to maintain the concentration in the boiler water within a specific range. Sodium sulphite reacts with oxygen to give sodium sulphate. 2 Na2SO3 + O2 → 2 Na2SO4 Where corrosion is experienced in the feed system, the use of a catalysed form of sodium sulphite is an advantage. The effect of the catalyst (usually a cobalt salt) is to speed up the oxygen / sulphite reaction, so that it is complete well before the feedwater reaches the boiler, thus giving a greater degree of protection to feed lines and economisers. The speed of reaction is influenced by pH of the feedwater which should be between 8.0 and 9.5. Sodium sulphite adds some solids to the feed-water and care should be taken not to overdose or utilise cold feed-water as this may lead to and increased blowdown requirement.

Hydrazine

Hydrazine, unlike sodium sulphite, does not increase the dissolved solids content of the boiler water. Hydrazine is very volatile and should be injected at the earliest possible point in the feed system. The reaction with oxygen is: N2H4 + O2 → N2 + 2 H2O The ammonia produced by the decomposition of excess hydrazine can provide a suitable alkaline condition in the steam and in the condensate system. 3 N2H4 → 4 NH3 + N2 Provided the excess is controlled to avoid an undue rise in the ammonia level in the steam, there is little danger of copper corrosion in the condensing plant. Hydrazine is a hazardous chemical and precautions are essential when handling the product. It is also important to note that hydrazine is not permitted for use where the steam comes in contact with foodstuffs.

DEHA

DEHA (DiEthylHydroxylAmine) is an organic oxygen scavenger and metal passivator, enhancing formation of a protective magnetite layer. It is significantly more volatile than hydrazine, resulting in increased protection in the steam and condensate system. Being an amine, it has also some neutralising properties. It is more thermally stable than hydrazine and can be used for all types of boilers from low to high pressures. The reaction with oxygen is show below, in practice around 3 ppm DEHA is needed per ppm oxygen. 4 (CH3CH2)2NOH + 9 O2 → 8 CH3COOH + 2 N2 + 6 H2O

Carbohydrazide

Carbohydrazide is a 'combined form' of hydrazine. It was designed to minimise exposure to hydrazine vapours during handling. Carbohydrazide and its reaction products will add no dissolved solids to the water. Carbohydrazide can be used as an oxygen scavenger and metal passivator at both high (230 °C) and low (65 °C) temperatures. Carbohydrazide can be applied to boilers up to 170 bar (2500 psi).


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The reaction with oxygen is: (N2H3)2CO + 2 O2 → 2 N2 + 3 H2O + CO2 In the boiler, hydrazine is one of the thermal degradation products of carbohydrazide, and for this reason it cannot be used for steam humidification or where FDA approval is required.

Tannins

Certain alkaline tannin solutions have a good oxygen absorbing ability, with approximately 6 ppm of certain tannin extracts being required to remove 1 ppm of dissolved oxygen at pH 12. This figure compares favourably with the concentration of 8 ppm of sodium sulphite required to remove 1 ppm of dissolved oxygen. However, the stoichiometry of the `tannin' reaction with oxygen is complex, and the use of tannins is at best empirical.

Erythorbic acid

Another effective oxygen scavenger and metal passivator, it is the only non-volatile scavenger which can be used for spray attemperation. It does not add measurable solids to the boiler water, is non-volatile, and will not jeopardise steam purity. Erythorbic acid can be used in boilers up to 122 bar (1800 psi). Erythorbic acid is also on the FDA list of Generally Recognised as Safe Substances (GRAS). The reaction with oxygen is: R1-C(OH)=C(OH)-R2 + ½ O2 → R1-(C=O)2-R2 + H2O As with hydrazine, a small amount of ammonia is produced in the boiler. Erythorbic acid is not recommended for boiler lay-up. Good corrosion control requires a high boiler water pH value since the magnetite film is at its most stable when the pH value is between 10.5 and 11.5. These pH conditions will normally be achieved by the methods used for scale control.

pH control

In low and medium pressure boilers it is usual to maintain a level of free OH alkalinity to aid in the prevention of corrosion of steel. The recommended level of free OH alkalinity is dependent on boiler pressure and heat flux and can be found in the literature e.g. BS 2486 1997 and TUV regulations.

Coordinated and congruent pH control

In high pressure boilers where there is a risk of caustic concentration and subsequent caustic attack it is common to apply a coordinated or congruent phosphate control programme. These control methods are based on the hydrolysis of tri-sodium phosphate (TSP) and di-sodium phosphate (DSP) in the boiler water. Na3PO4 + H2O Na2HPO4 + NaOH Na2HPO4 + NaOH Na3PO4 + H2O The objective is to maintain a desirable pH without the presence of free OH alkalinity. The desired conditions are obtained by maintaining the relationship of the pH to phosphate concentration in the boiler water at less than that of the equivalent stoichiometric solution of


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Na3PO4 (<3:1). This is achieved by the equilibrium reaction above. The congruent phosphate approach utilises mixtures of TSP and DSP to further ensure the absence of free OH alkalinity and usually run with a Na:PO4 ratio of <2.8. Other variations on this approach may be encountered in the industry. Control charts such as the in Figure 43 are used to check whether the water chemistry is correct e.g. if the water analysis lies in the control box then free OH alkalinity should not be present.

Hide-out

In high pressure water-tube boiler it is sometimes observed that the concentration of soluble salts, notably phosphate salts, do not rise in line with other salts and when the boiler load reduces their concentrations suddenly rise. This is phenomena termed ‘hide-out’ and is due to the reduced solubility of sodium phosphate at temperatures above 250 °C. As load and temperature at heat transfer surfaces increases then some of the sodium phosphate will precipitate and measured PO4 reserves will fall. When load and temperature reduce the PO4 salts resolubilise and the reserve is seen to increase. When phosphate hide-out occurs there is a risk of permanent scale deposition and/or localised evolution of free caustic which in turn could lead to severe corrosion.

pH control - All volatile treatment (AVT)

If there is a history of boiler deposits or phosphate hide-out is a recognised problem, it may be prudent to consider an All Volatile Treatment approach (AVT). This approach uses entirely volatile solids free chemicals such as Hydrazine, Carbohydrazide, Erythorbic acid and neutralising amines (Ammonia, Morpholine, Cyclohexylamine) to maintain the boiler pH at a level to high enough to control corrosion and give good passivation of metal surfaces. All steel systems are normally controlled at a pH of 9.2 - 9.6 and those containing copper or its alloys at a pH of 8.8 - 9.2. A drawback is that the boiler water is relatively un-buffered and if contamination occurs the boiler pH can be reduced dramatically. Additionally it is important to be aware of the amount of silica in the system as there is no free OH alkalinity to handle it correctly. High levels of silica in the feed-water will preclude this treatment approach.


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Figure 43: Example of a coordinated/congruent phosphate control chart

1.11 Condensate line corrosion

As previously discussed, most condensate system corrosion is caused by carbon dioxide and oxygen carried into the system with the steam. Carbon dioxide dissolved in the pure condensed steam forms corrosive carbonic acid. If oxygen is present with carbon dioxide the corrosion rate is much higher, and is likely to produce localised pitting. Ammonia in combination with carbon dioxide and oxygen attacks copper alloys. Apart from the loss of metal which will necessitate costly replacement of pipe-work and may shutdown a part of the plant, the products of corrosion will deposit in traps and strainers. Some of these corrosion products will be returned to the boiler with the condensate and will deposit as scale. Above 41 bar (600 psig) iron and copper produced by corrosion, if returned to the boiler, can be particularly damaging, and causing 'hot spots' leading to tube failure. Every effort should therefore be made to minimise pick up in the condensate and feed system. Suggested limits on iron and copper oxides in feedwater to boilers operating at pressures above 41 bar (600 psig) are less than 0.03 ppm total iron and copper.

1.11.1 Control of condensate line corrosion

A good approach to prevent steam condensate corrosion will involve removing oxygen from the feedwater mechanically and chemically and providing pre-treatment of the make-up water to minimise potential carbon dioxide formation in the boiler. In addition, an effective chemical treatment programme to specifically protect the condensate system is required. Chemically these corrosion inhibitors are based on amines.


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1.11.2 Neutralising amines

These are steam volatile, alkaline compounds with the basic formula RNH2 where R denotes an organic molecule. When applied to the boiler feed-water or direct to the boiler drum these materials volatilise, pass into the steam system and condensed with the condensate water. They react with carbonic acid in the condensate water to form an alkaline amine carbonate: RNH2 + H+ + HCO3

- → RNH3+ + HCO3-

Above pH 8.3 excess amine hydrolyses to maintain an elevated pH: RNH2 + H2O → RNH3

+ + OH- This action neutralises the CO2 present and elevates the pH of the condensate water thus providing good protection against corrosion. The alkalinity (basicity) of neutralising amines varies, for example Cyclohexylamine is a much stronger base than Morpholine.

Vapour/liquid (distribution) ratio

The characteristic of importance when considering the application of neutralising amine is their Vapour/Liquid (V/L) ratio. This is a measure of the volatility of the amine and is the ratio of the vapour/ liquid fractions of the amine that are present at a particular temperature or pressure. For example at 10 bar Cyclohexylamine has a V/L ratio of 4. This means that 75% of the amine is available as a vapour and 25% as a liquid. Under the same conditions Morpholine has a V/L ratio of 0.5 which means that 50% of this amine is present as a liquid i.e. Morpholine condenses more readily. A range of temperatures and pressures are encountered in a typical condensate system and therefore it is usual to apply these inhibitors as mixtures to give best protection of the entire condensate system. For example, Cyclohexylamine is more volatile than Morpholine and will reach to long condensate pipe-runs. Morpholine will condense more quickly and protect the earlier, hotter parts of the condensate system.

Pressure Cyclohexylamine Morpholine CO2

psi Bar pH 7.5-9.5 pH 10-11.5 pH 7.5-9.5 pH 10-11.5 pH 7.5-9.5

10 0.7 2.7 13 0.4 0.4 3

150 10 4 20 0.5 0.99 8.5

450 30 * 21.6 * 1.1 *

600 40 10 10 1.22 1.22 15.8

900 60 6.6 6.6 1.22 1.22 >99

Table 4: V/L ratios of some common neutralising amines. (* Experimental data not available)

Mechanical conditions such as poor trapping and draining of lines, and air ingress may also need to be corrected. The correct choice of corrosion inhibitor depends on the boiler system, plant lay-out, operating conditions and feedwater composition. In general volatile neutralising amines are better with low make-up, low feedwater alkalinity and good oxygen control. Filming inhibitors


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usually give more economical protection with high make-up, air ingress, high feedwater alkalinity or where the system is operated intermittently. In some cases a combination of treatment is required.

1.11.3 Filming Amines

These are higher molecular wt. amines made up of very long chain hydrocarbons. One end of the molecule is hydrophilic (attracts water) and the other is hydrophobic (repels water). The hydrophilic end physically attaches to the metal of the condensate system and as the concentration of amine molecules increases a protective hydrophobic film is formed on the surface. The film acts as a physical barrier to between metal surface and corrosive condensate water offering protection against both carbon dioxide and oxygen. The protective film is generally stable but extreme pH conditions (high or low) can upset stability and cause the film to be stripped off. Caution must be exercised when applying filming amines as they act to clean off any loose iron oxide present in the condensate pipe-work. If this happens to a great extent the blockages of steam traps and valves may occur. Because of this it is usual to build up the dose rate slowly. Overdosing can case the filming amine to accumulate as a sticky mass ‘gunk balls’ which again can cause problems in steam traps, valves etc. The primary filming amines are very viscous and difficult to apply and have therefore been superseded by neutralising amine blends in the majority of applications.

1.12 Boiler lay-up

It is important to take extra measures to protect boilers from corrosion when they are taken offline and for short or long term periods of time. When a boiler is off-line, rapid corrosion attack will occur when air comes into contact with moist metal surfaces. There are two general approaches to prevent corrosion during periods of shutdown; 1) drain the boiler down and keep all surfaces dry and 2) completely fill up the boiler to exclude all air and apply treatments to inhibit corrosion.

1.12.1 Short term lay-up (< 1-2 months)

For short term lay-up the recommended practice is to fill up the boiler with an excess level of oxygen scavenger and adjust the pH to alkaline conditions. The procedure cannot be used if exposed to temperatures below the freezing point.

1. At least 30 minutes before the boiler is to come off-line make addition of the treatment chemicals. The chemicals must be well distributed in the boiler water. If the boiler is on low load then natural circulation will effect mixing. If an auxiliary boiler is incorporated and is to also go off-line then ensure that treated water circulates through this system.

2. The boiler should then be filled to the top of the drum and/or auxiliary boiler blanking

off outlets as necessary to avoid flooding steam lines or the superheater. A simple header device (Figure 44) can be used to verify that the boiler is full and as a check for leakage.

3. The boiler water should be tested every week to check that oxygen scavenger and

alkalinity levels are being maintained. Extra treatment can be added via the header arrangement or via a by-pass feeder.

Recommended lay-up conditions


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DEHA or hydrazine 100 – 200 ppm or Sodium sulphite 200 – 400 ppm Alkalinity 100 – 300 ppm (pH 9,5 – 10,5)

Figure 44: Arrangement to maintain constant head on an idle boiler

1.12.2 Long term lay-up (> 1-2 months)

Wet lay-up

At least 30 minutes before the boiler is to come off-line make addition of a nitrite based corrosion inhibitor. If the system may be exposed to freezing conditions, glycol must be added.

1. At least 30 minutes before the boiler is to come off-line make addition of the treatment chemicals. The chemicals must be well distributed in the boiler water. If the boiler is on low load then natural circulation will effect mixing. If an auxiliary boiler is incorporated and is to also go off-line then ensure that treated water circulates through this system.

2. The boiler should then be filled to the top of the drum and/or auxiliary boiler blanking

off outlets as necessary to avoid flooding steam lines or the superheater. A simple header device (Figure 44) can be used to verify that the boiler is full and as a check for leakage.

3. The boiler water should be tested every 2-3 weeks to check that nitrite levels and pH

are being maintained. Extra treatment can be added via the header arrangement or via a by-pass feeder.

Recommended lay-up conditions Nitrite 2000 – 3000 ppm


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pH 9,5 – 10,5

Dry lay-up

1. After the boiler has cooled it should be drained completely, ensuring water is removed from all low spots.

2. The internal surfaces of the boiler should be thoroughly dried using warm air

circulation.

3. Trays of silica gel (or quick lime) should be placed in the boiler drum and headers to mop up any moisture. As a rule of thumb, allow 5 kg silica gel per tonne/hr steaming capacity. Alternatively, a vapour phase inhibitor (neutralising amines) may be used.

4. Seal the boiler carefully, blanking off all openings through which air or steam might

enter. Inspect the moisture absorbent every 8 weeks and replace as required.

Boiler start-up

Ensure that all of the moisture absorbent is removed, fill up boiler with good quality evaporated water and make initial additions of treatment chemicals. The boiler can then be brought on-line as usual.

1.13 Chemical cleaning of boilers

This chapter is just a brief overview of boiler cleaning; please revert to the cleaning manual for detailed procedures. Many different types of contaminants can be found in the waterside of a boiler system. These can originate from impurities naturally found in or added to the water or from extraneous materials which have gained entrance due to faulty, worn or defective equipment associated with the system. This contamination can be in the form of hardness scale, oil, metallic oxides, sludge and various combinations of these as well as other miscellaneous materials. The procedure(s) required to clean the system will therefore depend on the nature and condition of the substances to be removed. The best initial approach to chemical cleaning is to inspect the fouled system as thoroughly as possible to determine the nature and extent of contamination. If possible, samples of the offending materials should be taken for examination and if necessary sent in for laboratory analyses. Once the results of this preliminary investigation and/or lab analysis are known, the appropriate cleaning procedure or procedures can be determined and implemented as follows.

Boil-out

Boil-out procedures are commonly used for pre-commission cleaning of new systems to remove preservatives, mill scale and other contaminants of construction, subsequent to major system repairs, prior to returning to service and for the removal of trace amounts of oil contamination. Mechanically remove as much oily matter and as many other loose contaminants as possible.


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Degreasing

For removal of light to heavy contamination resulting from ingress of oil due to defective machinery, equipment seals, or bunker or cargo tank heating coils. Determine the source of oil contamination and take appropriate steps to eliminate the problem prior to initiating the cleaning operation. Inspect boiler interior as thoroughly as possible to determine the approximate degree of contamination (i.e. light, moderate, heavy). While boiler is open, muck out as much oil and oily sludge found in boiler as possible before closing the boiler up. You are also recommended to plug down comers, if present, to allow circulation through main tubes of boiler. Install external circulation pump to circulate cleaning solution from water drum back to steam drum. Make all necessary connections.

De-scaling and de-rusting

Inspect boiler interior as thoroughly as possible to determine degree of contamination (i.e. light, moderate, heavy). If deposits are covered with an oily or greasy film, degrease as outlined in the cleaning manual. Subsequent to degreasing or, if not required, construct a circuit for recirculating the acid cleaning solution through the boiler, being certain to by-pass all sections of the system containing non-ferrous metals. Ensure this circuit is vented at its highest point to allow the release of gases produced during the cleaning process.

1.14 Chemical dosing and control

1.14.1 Dosage locations

There are several possible dosing points for a boiler system, and the choices depend on several factors like system configuration, boiler pressure and product combinations. Figure 45 below shows typical dosing points for a low pressure system. All chemicals should be dosed with a suitable metering pump. This will allow continuous dosage of the products and will minimise the handling of chemicals. Batch or slug dosing is never recommended.


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Figure 45: Typical dosage point locations

Dosing point 1

Dosing into the hotwell is common, and can be used for non-volatile chemicals. Sulphite, alkalinity and scale inhibitors can be dosed here. Neutralising amines and oxygen scavengers based on DEHA, hydrazine or carbohydrazide should not be dosed here as there will be some vaporization in the hotwell. The dosage point should be below the water level, preferably close to a water inlet that can provide some mixing.

Dosing point 2

This is the preferred point for volatile oxygen scavengers and neutralising amines. This will provide protection from dissolved oxygen as early as possible in the system, avoiding excessive vaporisation in the hotwell.

Dosing point 3

This dosage point is used where separate dosing to multiple boilers is necessary. Scale inhibitors and some combined treatment are sometimes dosed here. Keep in mind that when dosing on the pressure side of the feed water pump, the metering pump need to be designed for pumping against a higher pressure.

Exhaust

Hotwell Evaporator/

R.O system

Aux.

boilers

Exhaust boilers

Steam users

Condensate return

Dosing point 1

Dosing point 2

Dosing point 3


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1.14.2 Sampling and monitoring

Because of the constantly changing load on a boiler, daily monitoring of the chemical levels is important to make sure that the system is in good condition. For a small system sampling is typically taken from the boilers and the condensate return. More complex system would require samples from the feed water as well. All sampling points should have a sample cooler to ensure the sample is at a temperature of 20-25°C when sampled. This is important because it will prevent flashing of the volatile components like the amines and DEHA, yielding lower results than actual when sampling. Additionally, this will prevent burn incidents of the personnel. When sampling, there should always be used clean sampling bottles. A good practice could be to have pre-labelled bottles so that the same bottle is used for the condensate each time. Trace amounts of boiler water from last sample may very well ‘ruin’ a condensate sample if bottles are mixed. Ideally, the bottle should be flushed with the water to be sampled a few times before the samples are collected. Cleanliness is important when analysing the water. Dirty hands and working benches may contaminate the samples. As an example, human sweat contains app. 6000 ppm chlorides, so there is not much needed to contaminate a condensate sample with chloride.

Figure 46: Example of a sample cooler


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1.15 Glossary of terms

1.15.1 Heat

The units of heat are the same as those of work since both are types of energy. Hence heat is usually measured today in kilojoules kJ where 1 kJ = 1000 J. The British Thermal Unit (BTU) is still used. Strictly one BTU is defined as the heat required to raise one pound of water from a temperature of 60°F to 61°F. In practice it is taken as 1/180 of the heat required to raise one pound of water from 32°F to 212°F. Sensible heat - is that heat which when added to water causes a change in temperature of the water. Latent heat - is that heat which causes a change in state, e.g. the vapour produced from boiling water is steam and the amount of heat needed to change water into steam at the same temperature is known as the latent heat of evaporation. Latent heat is not constant and is reduced as the pressure of steam above the water increases, for example: The latent heat of steam at atmospheric pressure is 2257.5 kJ/kg (970.6 BTU/lb). At 6.9 bar (100 psi), latent heat of steam is 2050.5 kJ/kg (881.6 BTU/lb). Total heat or enthalpy of steam One kg of water at 0°C (32°F) can produce one kg of steam if it is raised to boiling point 100°C (212°F) by the addition of sensible heat and evaporated to steam by the addition of latent heat. The sum of these two additions of heat is known as the total heat or enthalpy of steam. While the value of the latent heat becomes less as the pressure rises the value of the sensible heat increases so there is a steady increase in total heat up to pressures of around 27.6 bar (400 psi) after which the total heat begins to fall off.

1.15.2 Steam

Saturated Steam - is steam without entrained or condensed moisture and without superheat. It is an ideal condition rarely obtained in the steam space in a boiler as there is always some entrainment of water. Saturated steam in a pipeline develops moisture content due to condensation caused by heat losses due to radiation. Dry Steam - is steam containing no moisture. It should be noted that all superheated steam is dry. Wet Steam - is steam containing moisture due to either entrainment or condensation of water in the liquid form. Superheat - When steam is formed and all the water was evaporated, the addition of heat will raise the steam temperature. This further increase in heat is known as superheat of steam. Superheaters must be fitted externally to the boiler in order to raise the steam temperature at any given steam pressure. Dryness fraction - is the ratio, weight of saturated steam to total weight of 'steam'. It is sometimes expressed as a percentage. For example a 'Dryness Fraction' of 0.9 means that in 1 kg of steam there is a 0.9 kg of saturated steam and 0.1 kg of moisture. As a


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percentage this would be expressed at '90% Dry'. A conventional boiler without a superheater may give steam of dryness fraction about 0.97, i.e. it contains 3.0% of un-evaporated water as droplets. Dry saturated steam - is a term that may be encountered in practice. It is simply a double assurance that the steam is dry and not superheated, i.e. it is true saturated steam.

1.15.3 Boiler pressure

The force per unit area is called pressure and is measured in such units as Pounds Per Square Inch (psi), kilogram’s per square centimetre (kg/cm2), Newtons Per Square Metre (N/m2), also called the Pascal (Pa, the official SI unit) and the special unit of pressure, the bar. Absolute pressure bara or psia Gauge pressure barg or psig There are two possible zeros on which boiler pressures can be based:

a) Zero is taken as the pressure in a perfect vacuum. On this basis boiler pressures are expressed as 'x' bara/psia.

b) Zero is taken as atmospheric pressure. Upon this basis boiler pressures are expressed as 'x' gauge pressure which in practice is contracted to barg/psig. Zero barg = 1 bara = atmospheric pressure.

1.15.4 Boiler efficiency

Thermal efficiency - as applied to boilers is simply the ratio of the useful heat output in steam to the heat in the fuel. Thermal efficiency = Heat in Steam above Feed Temperature (kJ/kg) x wt/steam/kg/fuel Calorific Value of Fuel (kJ/kg) The heat in the steam can be obtained from steam tables. In the case of petroleum fuel oils and natural gas the published data for their calorific or heat value is sufficiently accurate for most practical purposes. In order to arrive at the ratio, the weight of fuel used and the total steam output from the boiler must be known. The thermal efficiency may be expressed in the gross or net calorific value of the fuel. Overall efficiency - is used in Power Houses. It is the percentage of heat in the fuel which leaves the Power House in the form of mechanical or electrical energy. Two factors are thus taken into account:

The efficiency of the boiler.

The efficiency of the "engine". Historically, Power House overall efficiencies may be from 30% to 35% and modern CHP systems can yield overall efficiencies of 55%.

1.15.5 Rated evaporation of the boiler

This is quoted in pounds steam per hour (lb/hr), or kilograms per hour (kg/hr) and sometimes as kilowatt (kW). The evaporation can vary widely depending on the temperature of the feed


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water, the class of fuel burnt, the boiler pressure, and the amount of superheat. All variables except the calorific value of the fuel can be eliminated by the use of this method:

Evaporation from and at 100°C (212°F)

This simply means that the feed water temperature is assumed to be 100°C (i.e. from 100°C, that the water is converted to steam at 100°C (i.e. at 100°C), and that no superheat is added; in other words assume that all the heat in the fuel is used in the provision of latent heat. This evaporation can of course vary with the class of fuel in use and the efficiency of combustion. It does give an excellent standard provided the fuel and combustion conditions are stated.

1.15.6 Superheated steam

If steam is superheated before use then condensation through heat loss is reduced. This is a valuable property in a steam distribution system. It is even more important in turbines because condensation causes erosion. Under certain conditions steam may have to be 'reheated' to remove moisture before passing to lower pressure stages in a turbine. Superheated steam at any given pressure has more energy than saturated steam at the same pressure and this increase in energy is in the form of sensible heat. The total heat of saturated steam at a pressure of 'P' is more than the total heat of saturated steam at pressure (P-p). If dry saturated steam at pressure 'P' is passed through a valve and reduced in pressure to (P-p) there is no loss of heat and the steam at the lower pressure (P-p) becomes superheated.

1.15.7 De-superheating (attemperating)

The extra heat imparted to superheated steam may be wholly or partly removed by water injection or surface cooling; this process is known as de-superheating. In works practice, where superheated steam is used for a turbine, a de-superheater (attemperator) may be installed to provide saturated steam for process use. In power house practice, the steam temperature at the turbine stop valve must be kept close to the design temperature for maximum efficiency. A de-superheater is therefore installed to reduce excessive superheat which may be imparted to steam under conditions of reduced load or, in the case of some water tube boilers, high load. De-superheaters are thermostatically controlled and take one of the following forms:

Superheated steam is admitted into a vessel into which water is sprayed in sufficient quantity to reduce the superheat. Condensate or de-mineralised water should be used since this form of de-superheating involves the evaporation of water. The use of raw or treated water may lead to deposition of solids in the de-superheater or further along the system.

The superheated steam is passed through "U" tubes or a coil in the water/steam drum of the boiler.

The superheated steam is passed through "U" tubes or a coil in a vessel filled with boiler water and connected to the water and steam sides of the boiler. The term 'Attemperator' is usually applied to this type of de-superheater.


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De-superheating is commonly practiced on turbine driven ships to provide lower temperature steam for the astern turbine when manoeuvring. This eliminates the danger of superheated steam reaching the condenser.

1.15.8 Reheat

When superheated steam does work in a turbine, there is an intermediate range of conditions where superheat and part of the total heat at the saturation has been lost. Although the steam pressure within this range is substantially reduced, a good deal of useful work can be obtained if the steam continues to expand. However, the efficiency of the power unit can be increased if at this stage the steam is superheated again before being used further. This superheating of steam which has already done some work is known as reheat. Reheat, unlike superheat, does not increase steam pressure but only its temperature. Its advantages show best with a large installation, and it is not usually practiced with small boilers. Normally, in land practice, the steam is led from the machine at the end of the high pressure stage into a re-heater section in the boiler. The re-heater will not differ in essential design from the superheater but will be situated in a cooler part of the boiler. After reheat, the steam is fed back to the inlet of the intermediate stage of the power unit. With the very high pressure boilers now being built (above 138 bar) two stages of reheat may be employed. In marine practice the initial superheat given is frequently appreciably greater than that required by the engine or turbine. Before reaching the engine or turbine inlet, the superheated steam passes through a heat exchanger of more or less conventional design, where the excess superheat is transferred to the steam passing from the high pressure stage to the intermediate stage. This heat exchanger is also known as a re-heater.

1.15.9 Thermal compression

Where evaporators are installed, the vapour has to be condensed for use, which involves the loss of latent heat. Thermal compression is a method of re-cycling part of the vapour produced back to the evaporator, so that its latent heat can be used to produce more vapour, which results in a substantial heat economy. The method applies only to installations operating about 0 - 5 psi and it is necessary to raise the pressure of the re-cycled vapour from its outlet pressure (usually atmospheric) to a pressure a little greater than that in the body of the evaporator. This may be done either by injection of higher pressure steam into the re-cycled vapour, or by a motor operated compressor, or a combination of both.

Gross calorific value of fuels - at constant volume

This is the number of heat units liberated when unit mass of the fuel is burnt at constant volume, in oxygen saturated with water vapour, the original and final materials being at 15.5°C, the residual products being carbon dioxide, sulphur dioxide, nitrogen and water, and water other than that originally present being in the liquid state.

Gross calorific value of fuels - at constant pressure

This is the number of heat units liberated when unit mass of the fuel is burnt at constant pressure in air saturated with water vapour, the original and final materials being at 15.5°C and the residual products being carbon dioxide, sulphur dioxide, nitrogen and water, and water other than that originally present being in the liquid state.


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BTU/lb MJ/kg

Gas oil 19,500 45.36

Medium fuel oil 18,900 43.96

Heavy fuel oil 18,760 43.63

Residual fuel oil 18,300 42.56

Anthracite coal 14,500 33.73

Bituminous COAL 8,000-13,000 18.61-30.24

Coke 11,000-13,500 25.59-31.40

Low grade coal, washed slurry or washery fines

3,000-8,000 6.98-18.61

Town gas 375-550 0.87-1.28

Natural gas 1,025-1,049 2.38-2.44

Commercial butane 3,270 7.61

Commercial propane 2,500 5.81

Table 5: Typical calorific values of fuels

1.15.10 Steam release rate

The rate at which steam is evolved through the water surface in a boiler has obvious implications for carryover, since excessive agitation of the surface will cause entrainment of water droplets and the contained solids. The steam release rate is often expressed either as kg of steam released per m2 of boiler water surface per hour (kgm-2hr-1) or as m3 of steam per m2 of water surface per hour. The latter unit is useful in comparing data at different operating pressures. Data on such values is sparse, and the possibility of establishing critical values also depends on other factors, e.g. the size of the steam space, the quality of the feed, and the degree of boiler water concentration.

1.15.11 Water evaporation and fuel consumption

Feed and water consumption’s are related by the formula: E = CV x B 2260 100 where: E = kg of water evaporated per kg of fuel consumed, from and at 100 °C (212°F) CV = Calorific Value of the fuel in kJkg-1 (Note: Where CV is given as BTU/lb, use 970 in place of 2260 in the above formula) B = Boiler Efficiency expressed as a percentage Where neither steam output nor water consumption are measured, it is possible to estimate the evaporation from the fuel consumption, provided data on fuel CV and boiler efficiency are available. A well-known fuel efficiency organisation has published data on the average boiler efficiency for various types. A selection of the data is reproduced below, together with E values calculated by the above formula for coal and oil having, respectively, CV of 25.59 and 41.89 MJ/kg (11,000 and 18,000 BTU/lb). These are useful in calculating approximately the evaporation, and hence the likely off-take of chemical treatment - where specific data for CV and B are lacking for a particular plant. An example is given later.


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Boiler Type Coal Oil

B %

E kg/kg

B %

E kg/kg

Lancashire without economisers Lancashire with economisers Economic Cross-tube Vertical Smoke-tube Vertical Water Tube

57.3 65.6 68.3 48.8 58.4 70.2

6.5 7.5 7.75 5.5 6.65 8.0

63.8 72.9 77.0 62.0 62.0 70.3

12.0 13.6 14.2 11.5 11.5 13.2

Example: A compact water tube boiler has been surveyed and the manual gives normal

maximum evaporation as 3200 kg/hr. A check on fuel ordering shows that 3 tonnes of coal per working day of 10 hours is used.

Hourly coal rate = 3 x 1000 = 300 kg/hr 10 E for smoke-tube vertical = 6.65 Hourly evaporation = 300 x 6.65 = 1995 kg/hr

Conditions better than average

Under the best conditions (and with the exception of oil-fired economics) evaporation rates calculated from the above table can be increased by up to 10%. By 'the best conditions' is meant: 1) Steady boiler loading. 2) Good quality fuel. (Note from the formula given, that of two boilers with the same

efficiency, the one with a fuel of low CV will produce less steam per kg of fuel). 3) Good control of combustion air, involving, e.g.:

a) absence of air leakage through brickwork of casings, b) correct size of draught fans, c) adequate design of under-grate air supply systems, d) good control of excess air (excess O2).

4) Adequate fuel feeding system. The average oil-fired economic boiler works closer to the maximum attainable efficiency, and for this class not more than 5% increase is allowable on the table values.

Conditions worse than average

Deficiencies in items 1 to 4 above are each capable of reducing the table values by up to 10%. For small boilers with unskilled manual firing and poor maintenance, the actual E value may be about half the table value. Where it is found difficult to make an appraisal of deficient items in percentage terms, it is advisable to use the following:


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kg/hr calculated from table Up to 110 - Reduce by 30% 110 - 225 - Reduce by 25% 225 - 1150 - Reduce by 20% 1150 - 4500 - Reduce by 15% Above 4500 - Reduce by 10%

1.15.12 Packaged Oil-fired boilers

Claims for 80 - 84% efficiency are made for this type of boiler. There are three difficulties in using such figures for average operational calculations:

1) A drop of 2 - 4% is to be expected as the fireside surfaces become 'conditioned' with even the minor amounts of deposits which occur when there is no significant fireside problem.

2) Intermittent working can cause a drop of 10% efficiency - largely due to air intake during stand-by periods.

3) If on-off burners are installed rather than those with a turn-down mechanism, a further 10% loss can be expected, for the same reason.

On this basis, the following is advised:

Operating conditions kg steam/kg fuel oil

Steady load with turn-down burner 14.2 Intermittent load with turn-down burner 13.0 Steady load with on-off burner 13.0 Intermittent load with on-off burner 12.0 Most modern boilers use modulating control which will provide improvement in the last 3 figures given above.

1.15.13 Carryover (priming and foaming)

Spray carryover

This term is used to describe the carryover of fine particles of spray or mist with the steam, due to the ejection of small drops of water into the steam space when steam bubbles arrive at the surface and burst. It is a function of the surface tension at the steam/water interface and some carryover of this kind takes place in all boilers. It can be minimised by correct design, i.e. attention to the rate of steam release per unit area of water surface, etc. All boilers will exhibit the type of carry over to some extent.

Foaming

More accurately referred to as 'carryover due to foaming', this phenomenon arises from the development of a stable foam upon the surface of a boiler water so that some of it is torn off by the escaping steam and is carried into the steam and condensate system. In severe cases the whole of the steam space within the boiler drum or shell may become filled with foam, which can then pass 'en masse' into the steam system. This can lead to dangerous problems with float type level control switches as false water levels may be detected. The causes of foaming are not entirely understood but it is associated with absorption of dissolved salts and suspended solids onto the films of water which are the walls of individual


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bubbles, so that small bubbles, instead of coalescing to form larger ones, repel one another. High alkalinity and/or TDS levels are associated with this type of carryover. It is thought that the principal function of an antifoam material is to prevent this absorption into bubble films.

Priming

This describes the ejection of comparatively large masses of water into the steam space, owing to 'spouting' or 'surging' of the boiler water. This spouting or surging may be due to a number of factors, mainly connected with the rate of steam release and the ease with which steam and water pass from one section of the boiler to another, and with which steam and water separate. Priming mainly occurs when steam demand is high and/or variable and is frequently associated with the too rapid opening of steam supply valves.

Antifoams

Foaming can be minimised by the application of suitable antifoams. When fully dispersed in the boiler water the antifoam will be present in the steam bubble skin. Here it acts on the surface of the bubbles. Its presence there weakens the film causing it to rupture easily and foaming is reduced.


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2 Engine cooling systems

2.1 Introduction

Marine diesel engines are used primarily to provide ships propulsion and electrical power. Contrary to their name they do not usually burn diesel fuel but heavy fuel oil that is heated and cleaned by centrifugal filtration. Large quantities of waste-heat are evolved from the combustion processes. Some of the energy from this waste-heat is recovered and used to produce steam via exhaust gas boiler systems. The majority of the heat produced by combustion must be dissipated to prevent overheating and failure of the engines moving parts such as the pistons, valves and associated seals. This heat dissipation is carried out by the incorporation of a water cooling circuit into the engine design which provides cooling for the combustion chamber and cylinder head. The engine cooling circuit is designed to be a ‘closed cooling system’, i.e. the make-up is normally less than 5% of the system capacity per week.

Figure 47: Large capacity marine diesel engine


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Figure 48: Typical engine cooling circuit

Figure 49: Close-up of engine cylinder head


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2.2 Scale deposition

Engine cooling circuits are designed to be ‘closed systems’, that is, the normal make up rate should be <5% of the system water capacity per week. However, because of age which leads to leakage and the need for routine and/or breakdown maintenance, make-up rates can be much higher than expected. If the make-up water is from the evaporated water system then scaling is not usually a problem as this water does not contain scale forming salts. Where the make-up water is shore-water and the makeup rate is high then scale deposition is likely to occur and lead to operational problems and risk of shutdown for repairs.

2.2.1 Scale formation

Deposits in engine cooling systems occur as a result of exceeding the solubility limits of impurities dissolved in the make-up water. As the cooling circuit becomes heated and/or concentrated the scale forming impurities become insoluble and deposit. Calcium carbonate for example will deposit at 65°C – 70°C. It will be appreciated that very broadly, scale formation will tend to be greatest where the heat flux is greatest e.g. around the cylinder lining and valve seats. The greater the amount of scale forming salts in the make-up water and the greater the rate of water loss/make-up the greater will be the amount of scale that will be formed. Modern, high efficiency engines running on shore water can be expected to be especially prone to scale deposition.

2.2.2 Typical scaling mechanisms

Calcium carbonate

Calcium carbonate scale appears as a pale cream. yellow deposit and is formed by the thermal decomposition of calcium bicarbonate at heat transfer surfaces: Ca(HCO3)2 + Heat → Ca CO3 + H2O + CO2

Calcium Calcium Bicarbonate Carbonate

Magnesium silicate:

Magnesium Silicate scale is a rough textured, tan to off-white deposit found in cooling circuits where sufficient amounts of Magnesium are present in conjunction with adequate amounts of silicate ions with a deficiency of OH Alkalinity. Mg2+ + OH- → MgOH+ H2SiO3 → H+ + HSiO3

- MgOH+ + HSiO3

- → MgSiO3 + H2SO4 Silicate deposits are also a risk where silicate additives are used to as corrosion protection for aluminium metal in the cooling circuit. The corrosion mechanism relies on the silicate forming a protective film in the metal surface and the silicate is maintained in solution by maintaining a relatively high pH in the cooling circuit (9.5 - 10.5). If this pH is reduced due to ingress of shore-water or sea-water then the silicate will precipitate in the bulk of the cooling water (as magnesium or calcium silicate) and cause gross fouling of the cooling circuit.


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It is vital when operating a silicate treatment regime for cooling circuits containing aluminium that the system under consideration should be made up with evaporated or softened water to prevent this problem.

Iron oxide deposits

Hematite (Fe2O3)

This type of red/brown iron oxide deposit is found because of active corrosion occurring somewhere within the cooling system.

Copper

The presence of copper deposits in a cooling system presents a very serious corrosion risk because of the initiation of galvanic corrosion mechanisms with steel. The steel in the cooling system is anodic to the copper and rapid loss of metal will occur. It is usual to incorporate specific copper corrosion inhibitors in the formulation of cooling system corrosion inhibitors

Figure 50: Calcium carbonate scale deposition on valve seat / typical iron oxide deposition

2.2.3 Effects of scale deposition

The effect of scale is to thermally insulate the waterside of the cooling surface and retard the flow of heat from the metal to the water. The only way the heat can get out is by raising the metal temperature and by raising the exit gas temperature from the engine. The former may endanger the engine structure, the latter will reduce engine efficiency. The presence of scale on the heat transfer surfaces of the cooling circuit can lead to a situation where the alkalinity in the system begins to concentrate by evaporation within the scale deposit. High concentrations of OH alkalinity can attack boiler steel and in particular lead to rapid failure of aluminium pipe-work and components.


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Figure 51: Caustic attack

2.2.4 Scale control

The primary method of scale control for engine cooling circuits is to ensure that the makeup water is delivered from an evaporator or is suitably pre-treated to remove scale forming salts. If the system is made up with shore-water then the amount of make-up should be minimised to <5% per week and the corrosion inhibitor selected should contain a suitable polymeric scale inhibitor to help prevent deposition. Where the cooling circuit is predominately aluminium the it is strongly advised that the make-up water is from an evaporator or suitable ion-exchange unit.

2.3 Corrosion mechanisms

The engine cooling system usually contains multi-metal components, typically: Mild Steel, Stainless Steel, Copper and its alloys, Aluminium The corrosion mechanism pertaining to each metal are different and need to be considered before selecting the proprietary corrosion inhibitor to give best protection.

2.3.1 Steel (Fe)

In and aqueous environment mild steel will readily corrode by reaction with oxygen in the water. For corrosion to occur there are 4 basic criteria have to be met:

Anode - metal surface

Cathode - metal surface

Electrolyte - water

Electron pathway (circuit) - metal Anodic and cathodic sites are formed on the metal surface by numerous mechanisms such as surface stresses, presence of deposits, grain boundaries, impurities or connection to other metals of differing nobility.


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Figure 52: Corrosion cell

Once there is an anode and cathode in existence then, with reference to the corrosion cell above, the corrosion process will commence and can be represented as an electrochemical reaction: At the Anode: Metal goes into solution Fe → Fe2+ + 2e- OXIDATION At the Cathode: Oxygen is reduced ½ O2 + H2O + 2e- → 2(OH-) REDUCTION The variables pH, temperature and the concentration of oxygen affect the rate of corrosion. As temperature and/or oxygen levels rise the corrosion rate accelerates. pH is inversely related to corrosion rate. This is why alkaline conditions are maintained in steam boiler systems and closed cooling circuits. Oxygen reacts with iron to give ferric oxide (rust) Fe2O3 which will not protect the metal from further attack and metal is continuously dissolved. 4Fe + 3 O2 → 2Fe2O3 Haematite (ferric Oxide) Oxygen corrosion is usually observed as localised pitting on a metal surface often with large tubercles of iron oxide covering the pit.

2.3.2 Stainless steels

These are alloys of steel with variable levels of chromium (over 11%). This alloying process gives the material excellent corrosion and wear resistance compared to mild steel. Oxygen


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combines with the chromium and iron to form a highly adherent and protective oxide film. If this film is ruptured in an oxidising environment then the oxide film is rapidly re-formed. Therefore the corrosion resistance of stainless steels is reduced in deaerated waters, which is the opposite to normal steels. The presence of chlorides and other strong ‘de-passivating’ ions can seriously reduce the corrosion resistance of stainless steels. The main drawback of more widespread use of stainless steels is extra cost and susceptibility to stress corrosion cracking in the presence of high chloride levels especially at elevated temperatures.

2.3.3 Copper (Cu)

Copper and its alloys are often used in heat exchangers because of their excellent heat transfer properties and relative low corrosion rate in water systems when compared to mild steel. In oxygenated water the corrosion of copper is slow as the metal forms a protective copper oxide film through which oxygen must diffuse for further corrosion to occur. Because copper is a softer metal than steel, water velocities and the scouring effect of suspended solids can act to disrupt the oxide film and increase corrosion rates. Corrosion of copper in the presence of steels is very serious as the copper can re-deposit on the steel and instigate very rapid galvanic corrosion of the steel and risk of failure. Copper and its alloys can be corroded by weak solutions of ammonia in the presence of oxygen. This topic is covered in the section on steam boilers.

2.3.4 Aluminium (Al)

In water containing oxygen, aluminium, like copper and stainless steel is protected by an oxide layer. Aluminium is a amphoteric metal which means that it can be aggressively attacked in an aqueous environment with low or high pH. In water of relatively neutral pH at temperatures up to 180 °C, aluminium is essentially inert. 2Al + 6 H2O → Al2O3 . 3H2O +3H2 At pH above 9 in the presence of sodium carbonate or sodium hydroxide this protective, oxide layer is rapidly dissolved and corrosion becomes severe: Al + NaOH + H2O → NaAlO2 + 3/2H2 In the engine cooling circuit, like in steam boiler systems, this corrosion mechanism can be exacerbated by localised boiling and the formation of high concentrations of OH ions at the metal surface. This will lead to aggressive corrosion and rapid failure.

2.3.5 Zinc (Zn)

Zinc is the principle metal used to protect steel as a galvanised coating. Here the zinc is anodic to the iron and preferentially corrodes at a slow rate thus protecting the steel. Zinc corrodes at a rate somewhere between that of iron and copper in most natural waters. Attack will occur in the absence of oxygen as with aluminium. Zinc is also an amphoteric metal and is corroded at high and low pH. Caution: At temperatures above 60°C there is a reversion in the catholic/anodic relationship with iron. The steel piping becomes highly anodic and rapid galvanic corrosion will occur. This is an important consideration for engine cooling circuits and if galvanised pipe-work or tanks are present then the zinc coating must be removed by a controlled acid wash prior to the system going into service.


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2.4 Factors affecting corrosion rates

2.4.1 Temperature

As a general rule, each 10°C increase in temperature doubles the rate of most chemical reactions. Therefore an increase in temperature will increase the speed of corrosion because the reactions at the cathode will proceed faster. The rate of oxygen diffusion is also increased up to around 80°C . In an open system the increase in corrosion rate begins to reduce because of the reduced solubility of oxygen. However, in a closed system the oxygen cannot escape and increased corrosion rates will continue to be observed.

Figure 53: Effect of oxygen concentration in open and closed systems

2.4.2 pH/alkalinity

As previously discussed the corrosion rates of metals with respect to pH can vary depending on their electrochemical nature. For example the corrosion rate of steel is greatly increased in acid conditions as they prevent the formation of a protective oxide layer. Corrosion rate of mild steel reduces as pH rises up to around 13 because of the reducing solubility of iron oxide in this range. Copper behaves in a similar manner. Aluminium and zinc because of their amphoteric nature exhibit increased corrosion rates at extremes of pH. The following diagrams show the general influence of pH on the corrosion rates of metals.


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Figure 54: Aluminium pipe from engine circuit with corrosion damage due to high pH

Figure 55: Relationship between corrosion rate and pH

2.4.3 Chloride ions

Small negatively charged ions such as chloride ions tend to gather at the anodic sites to electrochemically balance the positive ions (Fe2+ etc.) produced by oxidation of the metal. These ions increase the localised conductivity and therefore the voltage difference between the anode and the cathode. This effect creates an accelerated environment for corrosion to progress. In the marine environment it is usual to recommend higher levels of corrosion inhibitor when sea-water contamination has occurred. Stress corrosion cracking due to chlorides is a phenomena mostly associated with stainless steels. Here the chloride ions are just the right size to enter the atomic matrix of the metal and their concentration accelerates corrosion and causes the propagation of cracks in the metal. Catastrophic failure is often the outcome of such corrosion mechanisms.


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2.4.4 Galvanic corrosion

This relatively common form of corrosion occurs when two dissimilar metals are connected and exposed to an aqueous environment. One metal becomes anodic and the other cathodic thus setting up what is termed a ‘galvanic cell’. The anodic metal will exhibit corrosion in preference to the cathodic one. The most common example of this type of corrosion is when copper and mild steel are connected in water. The mild steel becomes anodic because it will give up electrons more readily than copper and subsequently corrodes. Figure 56 shows the Galvanic Series of common metals and alloys. The closer the metals are together in the series the less the corrosion rate and vice versa. The rate of corrosion at the anode is very much related to the relative surface areas of the anodic and cathodic metals.

Larger cathode - Higher corrosion rate

Smaller cathode - Lower corrosion rate

Large anode - General metal loss

Small anode - Pitting type attack Noble or cathodic end of series Platinum Gold Graphite Titanium Silver Chlorimet 3 (62Ni-18Cr-18Mo) Hastelloy C (62Ni-17Cr-15Mo) 18-8Mo stainless steel (passive) 18-8 stainless steel (passive) Chromium stainless steel 11-30% Cr (passive) Inconel (passive) (80Ni-13Cr-7Fe) Nickel (passive) Silver solder Monel (70Ni-30Cu) Cupronickels (60-90Cu, 40-10Ni) Bronzes (Cu-Sn) Copper Brasses (Cu-Zn) Chlorimet 2 (66Ni-32Mo-1Fe) Hastelloy B (60Ni-30Mo-6Fe-1Mn) Inconel (active) Nickel (active) Tin Lead Lead-tin solders 18-8Mo stainless steel (active) 18-8 stainless steel (active) Ni-Resist (high-nickel cast iron) Chromium stainless steel, 13% Cr (active) Cast iron Steel or iron


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Aluminum alloy 2024 Cadmium Aluminum alloy 1100 Zinc Magnesium and magnesium alloys Active or anodic end of series

Figure 56: Galvanic series in sea water

2.4.5 Cavitation

Cavitation can be described as the instantaneous formation and collapse of vapour bubbles in a liquid that is subject to rapid, intense localised pressure changes. In essence this is localised boiling without a temperature increase. Cavitation damage occurs when this phenomena act at the metal surface and the hydrodynamic forces created by the collapsing vapour bubbles create microscopic ‘torpedoes’ of water. These torpedoes can have velocities of up to 500m/s and on impact with the metal surface dislodge the protective oxide coating and deform the metal itself. Cavitation is common in feed-pumps on steam boiler systems and is becoming more common in engine cooling systems as engine manufacturers move to produce more compact high efficiency diesel engines with smaller, more compact cooling circuits where the risk of localised boiling is increased.

Figure 57: Engine liner showing cavitation damage


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Figure 58: Cast iron pump impeller showing severe cavitation

2.4.6 Corrosion fatigue cracking

This type of corrosion is a result of a combination of both a corrosive environment and repeated tensile stress. The metal fatigue is brought on by the routine cyclical application of stress which, in a corrosive environment, eventually causes the metal to crack. These cracks usually appear as families of fine to broad cracks at right angles to the stress loading, filled with dense corrosion product. The resultant rate of damage is greater than if only stress or corrosion mechanisms were occurring. Corrosion fatigue can occur with any kind of metal and in numerous corrosive environments

Figure 59: Example of corrosion fatigue cracking

2.5 Corrosion Inhibition

Although many options exist for minimising corrosion by improved design, material selection and improved construction techniques, economics dictate that most systems are designed and fabricated in such a way that a chemical inhibitor is required to control corrosion. As indicated earlier, the four elements of a corrosion circuit must be completed for corrosion to proceed. Therefore any chemical treatment applied to the water that stops the anodic reaction will stop corrosion and in turn any inhibitor that stops the cathodic reaction will reduce corrosion. Corrosion inhibitors are classified on how they affect the corrosion cell and are placed in three categories:


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Anodic inhibitors

Cathodic inhibitors

Combination inhibitors/organic inhibitors

Common corrosion inhibitors

Principally Anodic Inhibitors Principally Cathodic Inhibitors Chromate Carbonate Nitrite Polyphosphate Orthophosphate Phosphonates Bicarbonate Zinc Silicate Molybdate

Both anodic and cathodic inhibitors

Soluble Oils Mercaptobenzothiazole (MBT) Benzotriazole (BZT) Tolytriazole (TTZ)

Organic acid technology (OAT)

More recent development types of inhibitors are based on long chained carboxylic acids. These have the advantage that they do deplete very slowly, hence after initial dosage little replenishment of inhibitor is needed. The OAT inhibitors protect all metals typically used in a cooling system, including aluminium. One of the above azoles is typically blended in to protect yellow metals (copper and its alloys).

2.6 Mechanisms of corrosion inhibition

2.6.1 Anodic Inhibitors

Nitrite (NO2-)

Nitrites are by far the most common corrosion inhibitor used in engine cooling systems and prove to be excellent corrosion inhibitors for mild steels. Nitrites oxidise mild steel surfaces to form an extremely thin and highly tenacious layer of corrosion product. Because of the relatively high dose rates required, nitrites are used primarily in closed systems for economic reasons. Hydrocarbons and glycols do not affect the performance of nitrite.

Silicates

Silicates (SiO32-) react with dissolved metal ions at the anode. The resultant metal

ion/silicate complex forms a gel that deposits on anodic sites. The gel forms a thin, adherent layer that is relatively unaffected by pH in comparison to other commonly used inhibitors. The inhibiting properties of silicates increase with increasing temperature and pH. Silicates are normally used to inhibit aluminium corrosion at elevated pH (9.5 - 10.5). This pH range is critical to maintain the silicate in solution and prevent gross precipitation.


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It must be noted that in this environment, if localised boiling causes cavitation and concentration mechanisms, then extremely rapid corrosion of the aluminium will occur as the protective oxide layer is destroyed and the metal is dissolved by the high pH conditions.

Orthophosphate

Orthophosphate (PO4) forms an insoluble complex with dissolved ferric ions, such as Fe2+ that deposit at anodic sites. Ferric orthophosphate is more adherent and less pH sensitive than other anodic inhibitors. The film forms more effectively in a pH range of 6.5 - 7.0. Typical minimum dose rate in neutral waters are around 10ppm.

2.6.2 Cathodic inhibitors

Polyphosphate

Polyphosphates will form complexes with calcium, zinc and other divalent ions to form positively charged colloidal particles. These migrate to the cathodic sites and precipitate to form a corrosion inhibitor film. Polyphosphates required the presence of calcium to function, typically a minimum of 50ppm. Extremes of pH can upset the stability of the inhibitor film as with zinc hydroxide. Additionally reversion to orthophosphate will occur with time and temperature.

Zinc

Zinc ions are positively charged and are therefore attracted to the cathodic site of the corrosion cell. The soluble zinc ions react with the free OH ions surrounding the cathode to form a stable film of zinc hydroxide (Zn(OH)2). This protective film is susceptible to changes in pH. If the pH is acidic then the film will dissolve and not re-form and if the water conditions are too alkaline the zinc hydroxide will precipitate in the bulk of solution rather than at the cathodic site. Typical pH limits for the application of corrosion inhibitors based on zinc are 7.4 - 8.2.

Phosphonates

These materials were initially introduced into water treatment as scale inhibitors to replace polyphosphates. They have been shown to exhibit adsorption onto the metal surface by the P-O group especially in alkaline, hard waters. Phosphonates are normally used in conjunction with other inhibitor types to achieve best corrosion performance.

2.6.3 Combination and organic inhibitors

Benzotriazole (BZT) and Tolytriazole (TTZ)

These materials are used as specific corrosion inhibitors for copper and brass. They adsorb onto the metal surfaces and break the electrochemical circuit. These materials are stable under the temperatures and pH conditions found in engine cooling systems and are usually blended into proprietary corrosion inhibitor formulations.

Soluble and dispersible oils

These materials find use in closed cooling systems. A loose emulsion of the oil is fed into the water and the emulsion breaks at the heat transfer surface to lay down a thin, protective oil film on the metal surface. They are difficult to control as testing is unreliable and because of their organic nature can be prone to microbiological activity and subsequent bio-fouling and blockages.


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2.7 Corrosion monitoring

Once a suitable corrosion inhibitor has been selected and is applied to an engine cooling circuit general testing of water quality would be undertaken to measure the levels of inhibitor, pH and chlorides (as a check for contamination) and hardness salts. It may be a requirement to monitor the performance of the inhibitor, and this can be done using a specialised corrator probe (Figure 60) which measures the electrical current resulting from the application of a small, steady voltage across the electrodes of the probe tips. This current is measured using a suitable instrument and translated into a corrosion rate in mm/y. The use of pre-weighed corrosion coupons and an ASTM corrosion test rig are probably the most common method of corrosion monitoring available. In closed cooling circuits the ASTM rig is usually fitted across a flow and return line to ensure flow in the pipe-work and the coupons are attached to plastic holders fitted to pipe plugs. The test coupon is usually left in position for 30 - 90 days then removed and sent to the lab for processing. The weight loss of the coupon is calculated as a corrosion rate in mm/y and the coupons are returned for storage and discussion with the customer. Measurement of actual corrosion results can be valuable extension of our service and give confidence to our customers.

Figure 60: ASTM corrosion rig


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Figure 61: Corrosion coupons showing varying degrees of corrosion

Typical corrosion rates expected in engine cooling systems:

Mild Steel < 0.02 mm/y

Copper < 0.01 mm/y

Aluminium < 0.01 mm/y

2.8 Microbiological fouling

Bacteria are simple, microscopic life-forms that inhabit almost all waters found on Earth. Under certain circumstances the bacteria present in engine cooling circuits can adapt to feed on the nitrite-based chemicals used in corrosion inhibitors and also on oils entering the cooling circuit as contaminants. The bacteria act to oxidise nitrite to nitrate and corrosion inhibition is lost. This situation can lead to rapid bacterial population growths which in turn can give rise to the formation of insulating bio-films on the internal surfaces of the cooling system and blockage of filters and control equipment. As with scale deposits the cooling efficiency will be reduced and there will be an increased risk of corrosion due to the presence of the deposit and a depletion of the corrosion inhibitor. Typical evidence of this situation is a loss of nitrite reserve but a stable or increasing trend in system conductivity as the nitrate formed still contributes to conductivity. The incidence of microbiological fouling in engine cooling circuits is low due to the high temperatures and pH levels typically encountered. If microbiological fouling is uncovered then a proprietary biocide should be applied to kill the troublesome bacteria and prevent re-growth


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2.9 Sea water cooling systems

Sea-water is used to provide feed-water to the Evaporators, secondary cooling for the Engine Cooling Circuits and cooling for the Air Charge Coolers. Sea-water is introduced into the ship through open inlets and stored in containing tanks called ‘sea-chests’ within the body of the hull. These cooling duties utilise a variety of Heat-exchanger designs which can become severely fouled due to impurities and contamination in the sea-water supply.

Figure 62: Typical plate exchanger and shell and tube exchanger layouts

2.9.1 Corrosion and scaling

As described earlier, dissolved gases (oxygen and carbon dioxide) and salts of magnesium, calcium in the sea-water can lead to problems due to corrosion and scaling. However, because of the high, once through flow of these cooling systems it is not economical to continuously apply treatment to inhibit scale and corrosion as in boilers and engine cooling circuits. Prevention of scaling and corrosion is best achieved by the correct selection of heat-exchanger metallurgy and by maintaining sea-water temperatures below 50 °C.


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2.9.2 Microbiological fouling

The main problem associated with sea-water cooling circuits is fouling due to presence of micro-organisms found naturally in sea-water. The two main problematic organisms are the Mussel (Mytilus Edulis) and the Barnacle (Balanus Balanoides)

Figure 63: The blue mussel

These are common, shelled, filter feeding forms of marine life found world-wide - Australia, New Zealand, India, Japan, Europe, North America and South America. They can grow up to 10 cm in length and 5 cm in diameter and cause severe fouling where sea-water is used as a coolant. These species are very common throughout the world and their spawning periods will vary depending on the prevalent conditions. Spawning activity occurs when water temperatures rise above 10-15°C. This means that most deep-sea vessels are susceptible to contamination and fouling. Fully grown mussels and barnacles can be eliminated by filters and strainers; however it is the freshly spawned species (veligers) that cause problems. These veligers start life in a microscopic size and can easily find their way into the cooling circuit. Once in the system pipe-work they attach themselves to surfaces using strong elastic threads of protein (Byssus). Once attached, they can readily feed and grow. As their size and numbers increase, fouling and blockage of waterways takes place. The presence of this type of fouling will lead to:

Reduced cooling efficiency

Risk of under deposit corrosion and failure

Risk of cavitation and impingement corrosion

Increased pumping and maintenance costs


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2.9.3 Control of fouling

As the problem species are live, micro-organisms they can theoretically be killed using a variety of biocide additives or the installation of Marine Growth Protection Systems (MGPS). Chlorine has been used, but it is found that fully grown species can require 0.2 - 1.0ppm free chlorine for a period of up to 10 days which often impractical on a sea-going vessel. Additionally fully developed mussels and barnacles can detect the presence of chlorine as an irritant and will ‘close up’ and secrete a mucous seal that is impervious to the biocide. The best approach is to eliminate the mussels and barnacles when they are in their most vulnerable state (as veligers) and prevent them from attaching and growing. This can be accomplished by the routine application of a proprietary biocide and anti-foulant.

Figure 64: Typical chlorine or chemical injection system.

2.9.4 Marine growth protection systems

Marine Growth Prevention System (MGPS) are used for the treatment of sea water used for ships services. MGPS are electrolytic in action and consists of copper and aluminium (or soft iron) anodes strategically located in sea chests or sometimes in-board, but as close to the sea water intake point as possible. The anodes are connected to a control panel that feeds a current to the anodes.

Copper alloyed anodes

Copper ions are biocidal and act to kill marine life contaminants in the sea water. Copper alloyed anodes are used to prevent marine fouling found in pipe work strainers, heat exchangers, pumps, box coolers that cause blockage and accelerate corrosion.


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Aluminium alloyed anodes

Aluminium alloyed anodes are used in conjunction with copper alloyed anodes to prevent corrosion throughout ferrous pipe work.

Ferrous alloyed anodes

Ferrous-alloyed anodes are used in conjunction with copper alloyed anodes to prevent corrosion throughout Cu/Ni pipe work.

Figure 65: Typical MGPS installation

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