Boiler blowdown and refuse losses

Boiler blowdown and refuse losses

Issue

Besides the losses through the stack gas, boiler blowdown and refuse are the second largest losses in solid fuel boiler operation.

Learning Objectives

·       Recognizing the importance of chemical treatment of boiler feedwater ·       Understanding the risks of reducing boiler blowdown ·       Knowing how to calculate blowdown losses ·       Exploring methods to calculate the refuse loss of high ash fuel combustion ·       Knowing how to measure the refuse loss

1.   Introduction

Besides the sensible and latent heat losses in the stack gas, there are two more, sometimes major losses in steam generation.

·        The blowdown losses

·        The refuse losses

Blowdown is a necessary task in boiler operation intermittently reducing the concentration of solids in the boiler. How much blowdown is necessary depends on the quality of the feedwater, the use of the life steam, and the quality of the make-up water.

In practice we see a blowdown of 0 % to 15 % of feedwater. The consequence of too much blowdown is an increased fuel consumption. Too little blowdown also increases fuel consumption, because it may lead to scale formation at the boiler water side.

Because too much blowdown will increase energy consumption and too little as well, there is a no-win situation. It is admittedly very difficult to perform a “point landing” and operate at the best possible blowdown rate. One of the inherent dangers to reduce blowdown is a possible negative side effect of increased scale formation.

In particular coal and biomass fired boilers, have an additional energy loss through the solid refuse. By solid refuse, we mean a mixture of minerals and Carbon left in the ash pit. Depending on firing technique and skill of the operator there is more or less Carbon left in the refuse. The energy loss occurs in two ways. First the refuse is removed from the ash pit at a temperature between 100 to 250 ^oC. Secondly the remaining Carbon in the refuse has not been burned, but paid for. The more ash a fuel has, the higher the danger of Carbon left in the refuse.

2.   A crash course in boiler water chemistry

The boiler water chemistry is complicated and the key to success is testing of the feedwater as often as possible. The issue of chemical treatment is not only one of reducing fuel costs, but even more important avoiding costly repair and maintenance costs due to the danger of pipe rupture and corrosion. This short introduction is based on a water treatment manual provided by one of our cooperators, GAMLEN, a supplier of feedwater chemicals.

2.1    Boiler Deposits

Deposition is a major problem in the operation of steam generating equipment. The accumulation of material on boiler surfaces can cause overheating and corrosion.

The need to provide high quality feed water is a result of the advances made in boiler performance. The ratio of heating surface to evaporation has decreased with the increase in heat transfer rates making modern steam generating equipment less tolerant to scale deposition.

Water softeners and demineralisers are frequently used to pretreat boiler feed water, but even with the quality of feed water that this equipment can provide, good internal water treatment programs are necessary.

Common feed water contaminants that can form boiler deposits include calcium, magnesium, iron, copper, aluminum and silica.

Most deposits can be classified as one of two types

·        Scale that crystallized directly onto tube surfaces

·        Sludge deposits that precipitated elsewhere and were transported to the metal surface by flowing water

Scale is formed by salts that have limited solubility in the boiler water. These salts reach the deposit site in a soluble form and precipitate when concentrated by evaporation.

Sludge is the accumulation of solids that precipitate in the bulk boiler water or enter the boiler as suspended solids.

2.2    Scale Prevention

The most common cause of boiler scale is the breakdown of calcium bicarbonate to form Calcium Carbonate.

Typical analyses of boiler scale generally show large proportions of Calcium Carbonate along with Magnesium Hydroxide, Calcium Silicate, Calcium Sulphate and other silica and aluminum complexes.

Today’s methods of scale control are based on the use of polyphosphates and synthetic polymer dispersants. Polyphosphates are used to react with calcium salts to form the insoluble Calcium Phosphate. The preferred Hydroxyapatite is a particle with a relatively non adherent surface charge and forms in boiler waters with sufficient alkalinity (pH 11.0 - 12.0).

The magnesium portion of the hardness is precipitated preferentially as Magnesium Silicate and Magnesium Hydroxide. With boiler pH values above 10.5, Magnesium Hydroxide (Brucite) will form.

In practice, boiler water pH levels of 11.0 - 12.0 must be maintained so that non adhering precipitates are formed. At boiler pressures up to 25 bar, the caustic alkalinity level should be held above 200 mg/l or 2.4 times the silica level - whichever is the greatest.

Excess phosphate reserves must be maintained to ensure completeness of calcium precipitation and to provide a buffer against hardness variations in the make up water. In practice 30 - 60 mg/l of Phosphate should be held with low hardness or pre-softened make up and up to 100 mg/l with high hardness water.

2.3    Sludge Conditioning

Phosphate treatment results are improved by organic supplements. Naturally occurring organics such as Lignins, Tannins and Starches were the first supplements used. These were used to promote the formation of a fluid sludge that would settle in the mud drum or the bottom of the boiler shell to be removed by blowdown.

There have been many advances in organic treatments. Synthetic polymers are now widely used, and the emphasis is on dispersion of particles rather than fluid sludge formation. Although this mechanism is quite complex, polymers alter the surface area and the surface charge to mass ratio of typical boiler solids.

Some polymers are used specifically for hardness salts or for iron; some are effective for a broad spectrum of ions.

2.4    Corrosion

Boiler water corrodes mild steel. However, boiler water chemistry relies on this fact by ensuring that a layer of magnetite is established on the boiler surfaces. The formation of magnetite prevents further steel/water contact and thus the reaction is self limiting. Once formed there is only minor corrosion to repair the magnetite film which is continually being weakened by temperature variations of the metal substrate.

Because magnetite is vital to a boiler’s longevity, its maintenance is a primary objective of the treatment program.

Magnetite formation is dependent upon:

·        pH

·        maintenance of zero oxygen levels

2.5    Oxygen Corrosion

Water reacts with iron to form magnetite only in the absence of oxygen. The presence of oxygen promotes the formation of Hematite or Red Iron Oxide which is non-protective. Oxygen corrosion takes the form of localized deep pitting and can quickly lead to tube failure.

Preventing oxygen corrosion is quite simple: Keep oxygen out!

In practice, this is achieved by a two step process:

1)      Mechanical removal

2)      Chemical scavenging

Mechanical removal may involve the use of a steam de-aerator, few factories have this equipment and dependence must be placed upon good feed tank design to eliminate as much oxygen as possible from the feed water.

·        A direct steam sparge is used. Direct steam provides not only heat, but also mechanical agitation which is essential for efficient oxygen removal.

·        Both the returned condensate and make up lines enter the tank below the surface of the water. This prevents splashing which entrains further oxygen.

·        Insulate the tank to conserve heat.

·        Ensure that the suction head of the feed pump is sufficient to prevent cavitation of the pump.

·        Run the system as hot as possible.

·        Add the chemical scavenger at the outlet of the tank. This will provide protection from air attack of the feed system. To ensure that scavenging is complete before the Sulphite enters the boiler, catalysed Sulphite must be used. Incomplete oxygen scavenging of the feed water will mean some of its oxygen will flash off into the steam system thus promoting corrosion particularly in the condensate return lines.

Reserves of Sulphite must be maintained at all times within the boiler. As a guide, boilers operating at up to 25 bar should have 30-70 mg/l Sodium Sulphite reserve.

2.6    Condensate Line Corrosion

Carbon Dioxide is very soluble in water, dissolving to form carbonic acid which is aggressive to steel and will dissolve steel pipes rapidly.

Feed water contains an appreciable amount of natural alkalinity, typically 30 mg/kg as HCO₃. When used as boiler feed the bicarbonate ions in the water dissociate at the high temperatures and pressures (typically 10 bar and 180 ^oC) to produce caustic ions and Carbon Dioxide.

The Carbon Dioxide leaves the boiler with the steam, as the steam condenses and gives off its heat the Carbon Dioxide is dissolved in the Condensate. The carbonic acid produced is very aggressive to the steel pipework. Condensate lines should be designed with sufficient fall to reduce the possibility of condensate being retained in the system.

The iron pipe work dissolves to form ferrous Carbonate which is soluble and is therefore returned to the boiler with the condensate via the feed tank.

Once in the boiler the ferrous Carbonate reacts to form ferric Hydroxide and Carbon Dioxide. The ferric Hydroxide appears as a brown precipitate in the boiler water, whilst the Carbon Dioxide again enters the condensate system via the steam lines.

There are three approaches to solving the problem:

1)      Accepting the corrosion and replace the condensate lines when they start to leak. Many plants opt for this as the pipework is relatively inexpensive to repair.

2)      Introduce a neutralizing amine, such as Morpholine - this compound is added to the boiler where it is volatilized off with the steam. Control is effected by monitoring the pH of the condensate which is maintained at 8.5 - 9.0 thus corrosion is prevented.

3)      In some plants volatile amines are unacceptable as some of the steam may be used for food processing or sterilising. In such cases, dealkalising of the boiler make up using ion exchange resins - Sodium/Hydrogen cycle split stream.

2.7    Carry Over Prevention

Carry over is a term used to describe impurities contained in generated steam. Our aim is to maintain the steam in a pure a state as possible to prevent the formation of deposits in the steam distribution lines, steam traps, superheaters, and turbines.

The two most common types of carry over fall into the following categories

·        Chemically induced

·        Mechanically induced

2.8    Chemically Induced Carry Over

Chemically induced carry over is a result of exceeding the maximum limit in the boiler water for dissolved solids, suspended solids, alkalinity, silica, and organics that can occur as treatment chemicals or as process contamination.

Carry over may be due to the entrainment of small droplets of boiler water that contain solids. It may also result from stable foam that forms at the water-steam interface in the steam drum being carried with the steam into the superheaters. In addition, in what is known as priming, a slug of foam or water can be drawn into these superheaters.

2.9    Mechanically Induced Carry Over

The other common form of carry over may be mechanically induced. Some typical causes for mechanically induced carry over include:

·        Liquid level control malfunction such as carrying the liquid level too high

·        Sudden changes in boiler load

·        Defective or improperly installed steam purification equipment

·        Missing or improperly installed baffling on both the water and fireside

Beyond maintaining the boiler water parameters within the specified control limits, the only other chemical approach to reducing carry over is the use of antifoams. The most widely used type of antifoam is a Polyalkylene Glycol. The antifoam affects the surface tension of the water so that the bubbles that form rupture quickly due to weak spots in the wall of the bubble. These weak spots are caused by the inclusion of antifoam in the water forming the wall of the bubble.

In addition to minimizing foam formation, other advantages can be realized by the proper use of an antifoam in the boiler water. By minimizing foam formation, liquid vapour separation is cleaner, with less splashing and the internal boiler metal surfaces are exposed to better and more complete water washing. This minimizes solids buildup and lowers the potential of localized corrosion.

3.   Boiler Blowdown

Boiler operators resort to three ways of blowdown:

1)      None at all

2)      Continuos bleed

3)      Intermittent blowdown in regular intervals

Finding out the amount of blowdown in the field is more or less guess work. Only in installations that have calibrated in line steam and feedwater meters it is simple, because the blowdown is the difference between feedwater input and steam output. In all other cases one has to collect the blowdown and measure its volume. The work of an energy advisor concentrates therefore on assessing the means and ways a client does its boiler feedwater treatment. Before one recommends reduction of blowdown consider the following:

·        Too many feedwater chemical suppliers only supply the chemicals and don’t offer any service to also establish the correct feedwater chemistry.

·        Establishing the correct feedwater chemistry would require to perform standard boiler drum water tests on a daily or at least weekly basis.

·        Larger boilers should have in line pH and conductivity meters that record two important parameters, the amount of suspended solids in the boiler drum water and the pH-value.

·        Boiler owners have rarely staff and equipment to conduct frequent feedwater chemistry tests and to adjust the chemistry.

·        Any recommendation to reduce boiler blowdown can only be done if periodic monitoring of the feedwater chemistry is initiated.

In other words, recommendations to reduce boiler blowdown should be done only if one has a complete picture of the present feedwater chemistry and if one can as well take over the service of feedwater chemistry analysis. As experience has shown, almost all boiler operators need help to adjust their feedwater chemistry and this help is rarely provided by chemical suppliers.

4.   Blowdown energy losses

During blowdown saturated water (not steam) at the boiler drum pressure is released. Occasionally there is the misconception that saturated steam is released which would have a much higher energy content.

Blowdown losses account for about 1 % to 3 % of the fuel consumption. In exercise 1 we explore the order of magnitude of fuel saving potential.

5.   Losses in the refuse

It is mostly impracticable to weight the refuse to determine the losses. An alternative method is to measure the remaining Carbon or combustibles in the refuse and use the equation

Refuse per kg of as fired fuel  = 

The % combustible in the sample is also called Loss of Ignition (LOI), because one measures the % combustibles in the refuse sample and assumes this is mostly Carbon.

Different norms use different heating values for the LOI. The American ASME test form for abbreviated efficiency test states 14,100 BTU/lbm of LOI (= 32.875 MJ/kg) while the German norm (DIN 1942) allocates 33 MJ/kg (LHV) for “Steinkohle” and 27.2 MJ/kg for “Braunkohle” (lignite). The HHV of pure Carbon is about 33.8 MJ/kg.

The LOI is a chemical energy loss, because unburned Carbon is discharged. However there is also a sensible heat loss, because the refuse has a temperature above 25 ^oC when discharged. The German norm assumes a specific heat of between 0.84 - 1.0 kJ/kg^oC for the refuse, depending whether the refuse is ash or slag.

A high concentration of unburned Carbon in the refuse is a clear sign of insufficient firing control and a cause of considerable losses as shown in exercise 2.

The sensible heat losses of the refuse are given as:

       

where

m_R = refuse mass per kg or ton of fuel fired.

T_R  = refuse discharge temperature, °C

c_p = Integral specific heat of the refuse between 25 °C and T_R.

EXERCISES

Task 1

Assessment of the relative importance of blowdown losses can be easily done by hand. Follow the steps to calculate the blowdown loss in “% of additional fuel consumption” at 10 % blowdown (BD) for saturated steam at 10 bar, and feedwater at 80 ^oC.

Steps	Results
Enthalpy of one ton feedwater at 80 oC, MJ/ton *
Enthalpy of saturated steam at 10 bar, MJ/ton
Adsorbed heat at 0% blowdown, MJ
Fuel consumption at h= 80% and BD=0 %, kg **
Feedwater at 10 % blowdown, tons
Enthalpy of feedwater at 80 oC, MJ
Enthalpy of saturated feedwater, MJ
Heat of evaporation of one ton of water, MJ
Adsorbed heat at 10 % blowdown, MJ
Fuel consumption at h= 80% and BD=10%, kg
% additional fuel consumption

*      Specific heat of water 4.21 MJ/ton between 25 ^oC and 150 ^oC.

**   HHV of light fuel oil, 44,003 MJ/ton

It is recalled that feedwater is first heated up to the saturation temperature and than evaporated to steam (lecture 14).

In the case of 10 % blowdown, 1/0.9 = 1.111 tons of feedwater are required to generate 1 ton of steam. However only 1 ton of saturated water is evaporated to steam, while 0.111 ton of saturated water are released as blowdown. The additional fuel consumption is therefore caused by heating 0.111 ton of feedwater from the feedwater temperature to the saturated water temperature at 10 bar. Applying the above explanation can you propose a short cut to calculate the additional energy consumption.

Does this percentage of additional fuel consumption increase if the steam pressure is higher?

o Yes     o No

Does this percentage of additional fuel consumption decrease if the boiler efficiency is higher?

o Yes     o No

Task 2

In this exercise the order of magnitude of solid refuse losses are explored. Consider a high ash coal B and ash bin temperature of 200 ^oC. Calculate the chemical energy and sensible heat loss of the refuse if 5 %, 10 %, and 30 % LOI were measured. Follow the steps.

Step	5 %	10 %	30 %
Refuse per ton of fuel fired (kg)
Sensible heat at 200 oC (MJ/ton of fuel)
Chemical energy loss (MJ/ton of fuel)
Total loss, MJ/ton of fuel
Fractional sensible heat loss (%)
% fuel energy loss at h = 80 %

Note:   Specific heat of refuse:                        0.84 kJ/kg ^oC

                HHV of refuse:                                      33.8 MJ/kg

                System boundary temperature:          25 ^oC

                Ash content of coal B:                        15 %

                HHV of fuel:                                          23,243 MJ/ton

Do you think it is justified to neglect the sensible heat losses of the refuse?

Task 3

Although not covered in this lecture the losses by radiation and convection can be as well significant. Losses cannot be measured and norms provide charts that express the loss either

·        in percent of Gross Heat Input (= HHV of fuel) for a given nominal output capacity given in Million BTU/hr (American norm), or

·        as a loss,, (MW) by radiation and convection as a function of the nominal adsorbed heat capacity (_N) of the boiler.

The functional relationship is

where   C  =  0.0113 for fuel oil and gaseous fuels

                C  =  0.0220 for anthracite coal furnaces

                C  =  0.0315 for lignite and fluidized bed boilers

Note, that the losses by radiation and convection do not change with load. This implies that the R+C loss doubles at 50 % rating, is 5 times at 20 % rating and 10 times at 10 % rating. Operating a boiler at much less than its capacity will significantly increase R+C losses. This makes sense because a hot boiler radiates all the time, no matter whether steam production rates are high or low.

Assume a 10 bar boiler that has a rated saturated steam capacity of 15 tons/hour. Follow the steps to calculate the R+C losses at nominal load.(i.e. 8760 hours of operation at rated heat output)

Steps	Results
Enthalpy of saturated steam at 10 bar, MJ/ton
Enthalpy of feedwater at 90 oC, MJ/ton
Adsorbed heat, MJ/ton
Rated output  at 15 tons/h, MW

Steps	Results
R+C losses of light fuel oil fired boiler, MW
R+C losses, MJ/h
Light fuel oil required to generate nominal steam output at h = 80 %
R+C losses as % of light fuel oil input

Note:   3,600 MJ/h  =1 MW

                HHV light fuel oil  =  44,003 MJ/ton

Task 4

Most boilers operate well below their nominal capacity. Assume the boiler in task 3 generates 40,000 tons of steam per year during 7,000 hours of operation. Calculate the R+C losses as percentage of fuel input. Follow the steps.

Steps	Results
R+C losses as calculated in task 3, MJ/h
R+C losses per year, MJ/year
Amount of light fuel oil to generate 40,000 tons of steam at h= 80 %, tons
R+C losses as % fuel oil input