boiler blowdown

boiler blowdown:

When water is boiled and steam is generated, any dissolved solids contained in the water remain in the boiler. If more solids are put in with the feed water, they will concentrate and may eventually reach a level where their solubility in the water is exceeded and they deposit from the solution. Above a certain level of concentration, these solids encourage foaming and cause carryover of water into the steam. The deposits also lead to scale formation inside the boiler, resulting in localized overheating and finally causing boiler tube failure. It is, therefore, necessary to control the level of concentration of the solids and this is achieved by the process of ‘blowing down’, where a certain volume of water is blown off and is automatically replaced by feed water – thus maintaining the optimum level of total dissolved solids (TDS) in the boiler water. Blow down is necessary to protect the surfaces of the heat exchanger in the boiler. However, blow down can be a significant source of heat loss, if improperly carried out. The maximum amount of total dissolved solids (TDS) concentration permissible in various types of boilers is given in Table 4.1.

Recommended TDS Levels For Various Boilers

Boiler Type Maximum TDS (ppm)
1. Lancashire 10,000
2. Smoke and water tube boilers (12 kg/cm2) 5,000
3. Low pressure Water tube boiler 2000–3000
4. High Pressure Water tube boiler with super heater 3,000–3,500
5. Package and economic boilers 3,000
6. Coil boilers and steam generators 2000 (in the feed water)

4.5.1  Conductivity as Indicator of Boiler Water Quality

Since it is tedious and time consuming to measure total dissolved solids (TDS) in boiler water system, conductivity measurement is used for monitoring the overall TDS present in the boiler. A rise in conductivity indicates a rise in the “contamination” of the boiler water. Conventional methods for blowing down the boiler depend on two kinds of blowdown –intermittent and continuous

  1.             Intermittent Blowdown:

The intermittent blown down is given by manually operating a valve fitted to discharge pipe at the lowest point of boiler shell to reduce parameters (TDS or conductivity, pH, Silica and Phosphates concentration) within prescribed limits so that steam quality is not likely to be affected. In intermittent blowdown, a large diameter line is opened for a short period of time, the time being based on a thumb rule such as “once in a shift for 2 minutes”. Intermittent blowdown requires large short-term increases in the amount of feed water put into the boiler, and hence may necessitate larger feed water pumps than if continuous blowdown is used. Also, TDS level will be varying, thereby causing fluctuations of the water level in the boiler due to changes in steam bubble size and distribution which accompany changes in concentration of solids. Also substantial amount of heat energy is lost with intermittent blowdown.

2.            Continuous Blowdown:

There is a steady and constant dispatch of small stream of concentrated boiler water, and replacement by steady and constant inflow of feed water. This ensures constant TDS and steam

Even though large quantities of heat are wasted, opportunity exists for recovering this heat by blowing into a flash tank and generating flash steam. This flash steam can be used for preheating boiler feed water or for any other purpose (see Figure 9 for blowdown heat recovery system). This type of blow down is common in high-pressure boilers

Blowdown Calculations:

The quantity of blow down required to control boiler water solids concentration is calculated by using the following formula:

Blow down (%) = 

                       (Feed water (TDS) ×  % Make Up Water)/Maximum Permissible TDS in the Boiler

If maximum permissible limit of TDS as in a package boiler is 3000 ppm, percentage make up water is 10% and TDS in feed water is 300 ppm, then the percentage blowdown is given as:

                                    = 300 x 10/ 3000

                                    = 1%

If boiler evaporation rate is 3000 kg/hr then required blowdown rate is:

                                      =        3000 x 1/100

                                       = 30 kg/hr

Benefits of Blowdown:

Good boiler blowdown control can significantly reduce treatment and operational costs that include:

  • Lower pretreatment costs
  • Less make-up water consumption
  • Reduced maintenance downtime
  • Increased boiler life
  • Lower consumption of treatment chemicals

water treatment

Boiler Water Treatment:

Producing quality steam on demand depends on properly managed water treatment to control steam purity, deposits and corrosion. A boiler is the sump of the boiler system. It ultimately receives all of the pre-boiler contaminants. Boiler performance, efficiency, and service life are direct products of selecting and controlling feed water used in the boiler. When feed water enters the boiler, the elevated temperatures and pressures cause the components of water to behave differently. Most of the components in the feed water are soluble. However, under heat and pressure most of the soluble components come out of solution as particulate solids, sometimes in crystallized forms and other times as amorphous particles. When solubility of a specific component in water is exceeded, scale or deposits develop. The boiler water must be sufficiently free of deposit forming solids to allow rapid and efficient heat transfer and it must not be corrosive to the boiler metal.

1  Deposit Control

Deposits in boilers may result from hardness contamination of feed water and corrosion products from the condensate and feed water system. Hardness contamination of the feed water may arise due to deficient softener system. Deposits and corrosion result in efficiency losses and may result in boiler tube failures and inability to produce steam. Deposits act as insulators and slow heat transfer. Large amounts of deposits throughout the boiler could reduce the heat transfer enough to reduce the boiler efficiency significantly. Different type of deposits affects the boiler efficiency differently. Thus it may be useful to analyse the deposits for its characteristics. The insulating effect of deposits causes the boiler metal temperature to rise and may lead to tube-failure by overheating.

2  Impurities Causing Deposits

The most important chemicals contained in water that influences the formation of deposits in the boilers are the salts of calcium and magnesium, which are known as hardness salts. Calcium and magnesium bicarbonate dissolve in water to form an alkaline solution and these salts are known as alkaline hardness. They decompose upon heating, releasing carbon dioxide and forming a soft sludge, which settles out. These are called temporary hardness-hardness that can be removed by boiling. Calcium and magnesium sulphates, chlorides and nitrates, etc. when dissolved in water are chemically neutral and are known as non-alkaline hardness. These are called permanent hardness and form hard scales on boiler surfaces, which are difficult to remove. Non-alkalinity hardness chemicals fall out the solution due to reduction in solubility as the temperature rises, by concentration due to evaporation which takes place within the boiler, or by chemical change to a less soluble compound.

3  Silica

The presence of silica in boiler water can rise to formation of hard silicate scales. It can also associate with calcium and magnesium salts, forming calcium and magnesium silicates of very low thermal conductivity. Silica can give rise to deposits on steam turbine blades, after been carried over either in droplets of water in steam, or in volatile form in steam at higher pressures. Two major types of boiler water treatment are: Internal water treatment and External water treatment.

4  Internal Water Treatment

Internal treatment is carried out by adding chemicals to boiler to prevent the formation of scale by converting the scale-forming compounds to free-flowing sludges, which can be removed by blowdown. This method is limited to boilers, where feed water is low in hardness salts, to low pressures- high TDS content in boiler water is tolerated, and when only small quantity of water is required to be treated. If these conditions are not applied, then high rates of blowdown are  required to dispose off the sludge. They become uneconomical from heat and water loss consideration.

Different waters require different chemicals. Sodium carbonate, sodium aluminate, sodium phosphate, sodium sulphite and compounds of vegetable or inorganic origin are all used for this purpose. Proprietary chemicals are available to suit various water conditions. The specialist

must be consulted to determine the most suitable chemicals to use in each case. Internal treatment alone is not recommended.

5  External Water Treatment

External treatment is used to remove suspended solids, dissolved solids (particularly the calcium and magnesium ions which is a major cause of scale formation) and dissolved gases (oxygen and carbon dioxide). The external treatment processes available are: ion exchange; demineralization; reverse osmosis and de-aeration. Before any of these are used, it is necessary to remove suspended solids and colour from the raw water, because these may foul the resins used in the subsequent treatment sections.

Methods of pre-treatment include simple sedimentation in settling tanks or settling in clarifiers with aid of coagulants and flocculants. Pressure sand filters, with spray aeration to remove carbon dioxide and iron, may be used to remove metal salts from bore well water.

The first stage of treatment is to remove hardness salt and possibly non-hardness salts. Removal of only hardness salts is called softening, while total removal of salts from solution is called demineralization.

The processes are:-

Ion-exchange process (Softener Plant):

In ion-exchange process, the hardness is removed as the water passes through bed of natural zeolite or synthetic resin and without the formation of any precipitate. The simplest type is ‘base exchange’ in which calcium and magnesium ions are exchanged for sodium ions. After saturation regeneration is done with sodium chloride. The sodium salts being soluble, do not form scales in boilers. Since base exchanger only replaces the calcium and magnesium with sodium, it does not reduce the TDS content, and blowdown quantity. It also does not reduce the alkalinity. Demineralization is the complete removal of all salts. This is achieved by using a “cation” resin, which exchanges the cations in the raw water with hydrogen ions, producing hydrochloric, sulphuric and carbonic acid. Carbonic acid is removed in degassing tower in which air is blown through the acid water. Following this, the water passes through an “anion” resin which exchanges anions with the mineral acid (e.g. sulphuric acid) and forms water. Regeneration of cations and anions is necessary at intervals using, typically, mineral acid and caustic soda respectively. The complete removal of silica can be achieved by correct choice of anion resin.

Ion exchange processes can be used for almost total demineralization if required, as is the case in large electric power plant boilers

De-aeration:

In de-aeration, dissolved gases, such as oxygen and carbon dioxide, are expelled by preheating the feed water before it enters the boiler. All natural waters contain dissolved gases in solution. Certain gases, such as carbon dioxideand oxygen, greatly increase corrosion. When heated in boiler systems, carbon dioxide (CO2) and oxygen (O2) are released as gases and combine with water (H2O) to form carbonic acid, (H2CO3).

Removal of oxygen, carbon dioxide and other non-condensable gases from boiler feedwater is vital to boiler equipment longevity as well as safety of operation. Carbonic acid corrodes metal reducing the life of equipment and piping. It also dissolves iron (Fe) which when returned to the boiler precipitates and causes scaling on the boiler and tubes. This scale not only contributes to reducing the life of the equipment but also increases the amount of energy needed to achieve heat transfer. Deaeration can be done by mechanical deaeration-aeration, by chemical de-deration or by both together.

Mechanical deaeration:

Mechanical deaeration for the removal of these dissolved gases is typically utilized prior to the addition of chemical oxygen scavengers. Mechanical deaeration is based on Charles’ and Henry’s laws of physics. Simplified, these laws state that removal of oxygen and carbon dioxide can be accomplished by heating the boiler feed water, which reduces the concentration of oxygen and carbon dioxide in the atmosphere surrounding the feed water. Mechanical de-aeration can be the most economical. They operate at the boiling point of water at the pressure in the deaerator. They can be of vacuum or pressure type.

The vacuum type of de-aerator operates below atmospheric pressure, at about 82 °C, can reduce the oxygen content in water to less than 0.02 mg/litre. Vacuum pumps or steam ejectors are required to maintain the vacuum.

The pressure-type de-aerators operates by allowing steam into the feed water through a pressure control valve to maintain the desired operating pressure, and hence temperature at a minimum of 105 °C. The steam raises the water temperature causing the release of O2 and CO2 gases that are then vented from the system. This type can reduce the oxygen content to 0.005 mg/litre.

Where excess low-pressure steam is available, the operating pressure can be selected to make use of this steam and hence improve fuel economy. In boiler systems, steam is preferred for de-aeration because:

  1.             Steam is essentially free from O2 and CO2,
  2.             Steam is readily available

III.            Steam adds the heat required to complete the reaction.

c:

While the most efficient mechanical deaerators reduce oxygen to very low levels (0.005 mg/litre), even trace amounts of oxygen may cause corrosion damage to a system. Consequently, good operating practice requires removal of that trace oxygen with a chemical oxygen scavenger such as sodium sulfite or hydrazine. Sodium sulphite reacts with oxygen to form sodium sulphate, which increases the TDS in the boiler water and hence increases the blowdown requirements and make-up water quality. Hydrazine reacts with oxygen to form nitrogen and water. It is invariably used in high pressures boilers when low boiler water solids are necessary, as it does not increase the TDS of the boiler water.

Reverse Osmosis:

Reverse osmosis uses the fact that when solutions of differing concentrations are separated by a semi-permeable membrane, water from less concentrated solution passes through the membrane to dilute the liquid of high concentration. If the solution of high concentration is pressurized, the process is reversed and the water from the solution of high concentration flows to the weaker solution. This is known as reverse osmosis. The quality of water produced depends upon the concentration of the solution on the high-pressure side and pressure differential across the membrane. This process is suitable for waters with very high TDS, such as sea water.

The semi-permeable nature of the membrane allows the water to pass much

more readily than the dissolved minerals. Since the water in the less concentrated solution seeks to dilute the more concentrated solution, the water passage through the membrane generates a noticeable head difference between the two solutions. This head difference is a measure of the concentration difference of the two solutions and is referred to as the osmotic pressure difference.

When a pressure is applied to the concentrated solution which is great that the osmotic pressure difference, the direction of water passage through the membrane is reversed and the process that we refer to as reverse osmosis is established. That is, the membrane’s ability to selectively pass water is unchanged, only the direction of the water flow is changed.

The feed water and concentrate (reject stream) ports illustrates a continuously operating RO system.

Recommended boiler and feed water quality:

The impurities found in boiler water depend on the untreated feed water quality, the treatment process used and the boiler operating procedures. As a general rule, the higher the boiler operating pressure, the greater will be the sensitivity to impurities. Recommended feed water and boiler water limits are shown in Table 4.2 and Table 4.3.

Recommended Feed Water Limits

Factor Upto 20 kg/cm2 21 – 39 kg/cm2 41 – 59 kg/cm2
Total iron (ppm) 0.05 0.02 0.01
Total copper (ppm) 0.01 0.01 0.01
Total silica (ppm) 1.0 0.3 0.1
Oxygen (ppm) 0.02 0.02 0.01
Hydrazine residual ppm 0.02-0.04
pH at 25°C 8.8-9.2 8.8-9.2 8.02-9.2
Hardness, ppm 1.0 0.5

Recommended Boiler Water Limits   (Is 10392, Year 1982)

Factor Upto 20 kg/cm2   21 – 39 kg/cm2 40 – 59 kg/cm2
TDS, ppm 3000-3500 1500-2500 500-1500
Total iron dissolved solids ppm 500 200 150
Specific electrical conductivity 1000 400 300

at 25°C (mho)

1000 400 300
Phosphate residual ppm 20-40 20-40 15-25
pH at 25°C 10-10.5 10-10.5 9.8-10.2
Silica (max) ppm 25 15 10

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rankine cycle

Ideal rankine cycle:

1-2: Isentropic expansion of superheated steam in the turbine.

2-3: Condensation in the condenser which converts steam into water. It is the constant pressure and constant
temperature heat rejection from steam which causes condensation. The volume is reduced about 1000 time in the condenser, thus saving huge amount of mechanical work.

rankine cycle
ideal rankine cycle

3-4: Constant entropy pressure rise in the pump.

4-5: There is constant pressure heat supply in the economizer or with feed water heating.

5-6: Heat supply at constant temperature and pressure in the Boiler.

6-1: The steam is superheated at constant pressure.

4-5-6-1 ; This is the line of constant pressure.

5-6: Is the line of constant Temperature.

After expansion inside the turbine, the dryness fraction is kept more than 0.85, as high water content causes damage like rust etc.

To reduce mechanical work for pumping, we cool until saturated liquid is obtained and no steam content remains.

Actual rankine cycle:

In actual Rankine cycle, the processes are deviated from those of Ideal Rankine cycle.
Solid lines are showing ideal processes and dotted lines are showing actual processes.

rankine cycle
actual rankine cycle

1’-2’: Actual adiabatic expansion of superheated steam in the turbine. Turbine is surrounded by insulating material such as fiber glass or asbestos to prevent heat loss.

2’-3’: Actual process of condensation.

3’-4’: Adiabatic rise in pressure in the pump.

S’2 is higher than S2 and S4 is higher than S4, showing that entropy is generated in these processes.

Isentropic Efficiency
 = Actual work/ Ideal work when expansion is isentropic.

Unfortunately, the entropy is generated in cases, the expansion and the compression.

4’-5’: Heating in the economizer.

5’-6’: Actual process of heating in the boiler.

6’-1’: Super-heating process in the super heater.

It must be mentioned here that all the process in the Rankine Cycle are control volume as mass is entering and leaving and also the heat and work.

Ideal rankine Cycle is a Cycle in which all the thermodynamic processes go ideally without losses and there is no entropy generation during any of the process.

In the figure below, the actual rankine cycle is shown on the T-S diagram.

Reheat rankine cycle:

The drawback of having high pressure in the boiler is the increase of water content at the blades steam turbine. To avoid this problem, reheat Rankine cycle is used.
The diagram for the Reheat Rankine cycle is shown.

reheat rankine cycle
reheat rankine cycle

We can enhance the thermal efficiency of the steam turbine power plant by reheating the steam coming from high pressure turbine, approximately to same temperature as the inlet of the first turbine and then passing it from an another turbine operating at low pressure, called low pressure turbine. By this arrangement, the dryness fraction at the exit of low pressure turbine is increase which is desirable to increase the thermal efficiency of the Plant.

The various processes in Reheat Rankine Cycle are:

1-2: Isentropic Expansion of superheated steam in the high pressure turbine.

2-3: Constant pressure reheating in the Re-heater.

3-4: Isentropic expansion in low pressure turbine.

4-5: Heat rejection in the condenser at constant temperature and pressure.

5-6: Isentropic pressure rise in the Pump.

6-7: Heating of subcooled liquid

7-1: Constant Pressure Reheating in the Boiler.

Heat supplied to the Boiler = h1 – h6 = Q1

Heat rejected to the condenser = h4 – h5 = Q2

Total Work output = Wt1 + Wt2 = Work done in low pressure turbine + Work done in high pressure turbine = (h1 – h2) + (h3 – h4)

Total Heat supplied = heat supplied in the Boiler + Heat supplied in the Re-heater = (h1 -h6) + (h3 – h2)

Thermal efficiency = Net work output/ Total heat supplied = {(h1 – h2) + (h3 – h4) – (h6 – h5)}/ {(h1 -h2) + (h3 – h2)}.

boiler efficiency

The various energy efficiency opportunities in boiler system can be related to combustion, heat transfer, avoidable losses, high auxiliary power consumption, water quality and blowdown. Examining the following factors can indicate if a boiler is being run to maximize its efficiency:

Boiler efficiency depends on following 11 things:

1.stack temperature

2.Feed Water Preheating using Economiser

3.Combustion Air Preheat

4.Incomplete Combustion

5.Excess Air Control

6. Radiation and Convection Heat Loss

7.Automatic Blowdown Control

8.Reduction of Scaling and Soot Losses

9.Reduction of Boiler Steam Pressure

10.Variable Speed Control for Fans, Blowers and Pumps

11.Effect of Boiler Loading on Efficiency

13. Proper Boiler Scheduling

1.Stack Temperature

The stack temperature should be as low as possible. However, it should not be so low that water vapor in the exhaust condenses on the stack walls.

This is important in fuels containing significant sulphur as low temperature

stack temperature
this image is from https://www.ogj.com/articles/print/volume-115/issue-4/processing/understanding-draft-limitations-in-fired-heaters.html

can lead to Sulphur dew point corrosion. Stack temperatures greater than 200°C indicates potential for recovery of waste heat. It also indicate the scaling of heat transfer/recovery equipment and hence the urgency of taking an early shut down for water/ flue side cleaning.

 

2    Feed Water Preheating using Economiser

Typically, the flue gases leaving a modern 3-pass shell boiler are at temperatures of 200 to 300 °C. Thus, there is a potential to recover heat from these gases. The flue gas exit temperature from a boiler is usually maintained at a minimum of 200 °C, so that the sulphur oxides in the flue gas do not condense and cause corrosion in heat transfer surfaces. When a clean fuel such as natural gas, LPG or gas oil is used, the economy of heat recovery must be worked out, as the flue gas temperature may be well below 200 °C.

boiler efficiency
image from.
https://www.energystar.gov/products/low_carbon_it_campaign/12_ways_save_energy_data_center/air_side_economizer

The potential for energy saving depends on the type of boiler installed and the fuel used. For a typically older model shell boiler, with a flue gas exit temperature of 260 °C, an economizer could be used to reduce it to 200 °C, increasing the feed water temperature by 15 °C. Increase in overall thermal efficiency would be in the order of 3%. For a modern 3-pass shell boiler firing natural gas with a flue gas exit temperature of 140 °C a condensing economizer would reduce the exit temperature to 65 °C increasing thermal efficiency by 5%.

  3. Combustion Air Preheat

Combustion air preheating is an alternative to feedwater heating. In order to improve thermal efficiency by 1%, the combustion air temperature must be raised by 20 °C. Most gas and oil burners used in a boiler plant are not designed for high air-preheat temperatures.

combustion air preheating
image from: https://www.energystar.gov/products/low_carbon_it_campaign/12_ways_save_energy_data_center/air_side_economizer

Modern burners can withstand much higher combustion air preheat, so it is possible to consider such units as heat exchangers in the exit flue as an alternative to an economizer, when either space or a high feed water return temperature make it viable.

 

 

 

4.  Incomplete Combustion

Incomplete combustion can arise from a shortage of air or surplus of fuel or poor distribution of fuel. It is usually obvious from the colour or smoke, and must be corrected immediately. In the case of oil and gas fired systems, CO or smoke (for oil fired systems only) with normal or high excess air indicates burner system problems. A more frequent cause of incomplete combustion is the poor mixing of fuel and air at the burner. Poor oil fires can result from improper viscosity, worn tips, carbonization on tips and deterioration of diffusers or spinner plates.

With coal firing, unburned carbon can comprise a big loss. It occurs as grit carry-over or carbon-in-ash and may amount to more than 2% of the heat supplied to the boiler. Non uniform fuel size could be one of the reasons for incomplete combustion. In chain grate stokers, large lumps will not burn out completely, while small pieces and fines may block the air passage, thus causing poor air distribution. In sprinkler stokers, stoker grate condition, fuel distributors, wind box air regulation and over-fire systems can affect carbon loss. Increase in the fines in pulverized coal also increases carbon loss.

5.    Excess Air Control

The Table 4.4 gives the theoretical amount of air required for combustion of various types of fuel. Excess air is required in all practical cases to ensure complete combustion, to allow for the normal variations in combustion and to ensure satisfactory stack conditions for some fuels. The optimum excess air level for maximum boiler efficiency occurs when the sum of the losses due to incomplete combustion and loss due to heat in flue gases is minimum. This level varies with furnace design, type of burner, fuel and process variables. It can be determined by conducting tests with different air fuel ratios.

Theoretical Combustion Data- Common Boiler Fuels

Fuel kg of air req./kg of air kg of flue gas /kg of fuel mof flue/kg of fuel Theoretical CO2% in dry flue gas CO2% in flue gas achieved in practice
Solid Fuels
Bagasse 3.2 3.43 2.61 20.65 10-12
Coal (Bituminous) 10.8 11.7 9.40 18.70 10-13
Lignite 8.4 9.10 6.97 19.40 9-13
Paddy Husk 4.6 5.63 4.58 19.8 14-15
Wood 5.8 6.4 4.79 20.3 11.13
Liquid Fuels
Furnace Oil 13.90 14.30 11.50 15.0 9-14
LSHS 14.04 14.63 10.79 15.5 9-14

Typical values of excess air supplied for various fuels are given in Table–4.5.

 Excess Air Levels for Different Fuels

Fuel Type of Furnace or Burners Excess Air (% by wt)
Pulverised coal Completely water-cooled furnace for slag-tap or dry-ash removal 15–20
Partially water-cooled furnace for dry-ash removal 15–40
Coal Spreader stoker 30–60
Water-cooler vibrating-grate stokers 30–60
Chain-grate and traveling-gate stokers 15–50
Underfeed stoker 20–50
Fuel oil Oil burners, register type 15–20
Multi-fuel burners and flat-flame 20–30
Natural gas High pressure burner 5–7
Wood Dutch over (10–23% through grates) and Hofft type 20–25
Bagasse All furnaces 25–35
Black liquor Recovery furnaces for draft and soda-pulping processes 30–40

Controlling excess air to an optimum level always results in reduction in flue gas losses; for every 1% reduction in excess air there is approximately 0.6% rise in efficiency.

Various methods are available to control the excess air:

  1.             Portable oxygen analysers and draft gauges can be used to make periodic readings to guide the operator to manually adjust the flow of air for optimum operation. Excess air reduction up to 20% is feasible.
  2.             The most common method is the continuous oxygen analyzer with a local readout mounted draft gauge, by which the operator can adjust air flow. A further reduction of 10–15% can be achieved over the previous system.

    III.            The same continuous oxygen analyzer can have a remote controlled pneumatic damper positioner, by which the readouts are available in a control room. This enables an operator to remotely control a number of firing systems simultaneously.

The most sophisticated system is the automatic stack damper control, whose cost is really justified only for large systems.

6.    Radiation and Convection Heat Loss 

The external surfaces of a shell boiler are hotter than the surroundings. The surfaces thus lose heat to the surroundings depending on the surface area and the difference in temperature between the surface and the surroundings. The heat loss from the boiler shell is normally a fixed energy loss, irrespective of the boiler output. With modern boiler designs, this may represent only 1.5% on the gross calorific value at full rating, but will increase to around 6%, if the boiler operates at only 25 percent output.

Repairing or augmenting insulation can reduce heat loss through boiler walls and piping.

7.    Automatic Blowdown Control

Uncontrolled continuous blowdown is very wasteful. Automatic blowdown controls can be installed that sense and respond to boiler water conductivity and pH. A 10% blow down in a 15 kg/cm2 boiler results in 3% efficiency loss.

8.    Reduction of Scaling and Soot Losses

In oil and coal-fired boilers, soot buildup on tubes acts as an insulator against heat transfer. Any such deposits should be removed on a regular basis. Elevated stack temperatures may indicate excessive soot buildup. Also same result will occur due to scaling on the water side. High exit gas temperatures at normal excess air indicate poor heat transfer performance. This condition can result from a gradual build-up of gas-side or waterside deposits. Waterside deposits require a review of water treatment procedures and tube cleaning to remove deposits.

scale and soot losses in boiler
image from: https://www.goodway.com/resources/tips-tricks/soot-scale-affects-boiler-performancehttps://goodway.com

An estimated 1% efficiency loss occurs with every 22 °C increase in stack temperature. Stack temperature should be checked and recorded regularly as an indicator of soot deposits. When the flue gas temperature rises about 20 °C above the temperature for a newly cleaned boiler, it is time to remove the soot deposits. It is, therefore, recommended to install a dial type thermometer at the base of the stack to monitor the exhaust flue gas temperature. It is estimated that 3 mm of soot can cause an increase in fuel consumption by 2.5% due to increased flue gas temperatures. Periodic off-line cleaning of radiant furnace surfaces, boiler tube banks, economizers and air heaters may be necessary to remove stubborn deposits.

9.    Reduction of Boiler Steam Pressure

This is an effective means of reducing fuel consumption, if permissible, by as much as 1 to 2%. Lower steam pressure gives a lower saturated steam temperature and without stack heat recovery, a similar reduction in the temperature of the flue gas temperature results. Steam is generated at pressures normally dictated by the highest pressure / temperature requirements for a particular process. In some cases, the process does not operate all the time, and there are periods when the boiler pressure could be reduced. The energy manager should consider pressure reduction carefully, before recommending it. Adverse effects, such as an increase in water carryover from the boiler owing to pressure reduction, may negate any potential saving. Pressure should be reduced in stages, and no more than a 20 percent reduction should be considered.

10.    Variable Speed Control for Fans, Blowers and Pumps

Variable speed control is an important means of achieving energy savings. Generally, combustion air control is affected by throttling dampers fitted at forced and induced draft fans. Though dampers are simple means of control, they lack accuracy, giving poor control characteristics at the top and bottom of the operating range. In general, if the load characteristic of the boiler is variable, the possibility of replacing the dampers by a VSD should be evaluated.

11.   Effect of Boiler Loading on Efficiency

The maximum efficiency of the boiler does not occur at full load, but at about two-thirds of the full load. If the load on the boiler decreases further, efficiency also tends to decrease. At zero output, the efficiency of the boiler is zero, and any fuel fired is used only to supply the losses.

The factors affecting boiler efficiency are:

  • As the load falls, so does the value of the mass flow rate of the flue gases through the tubes. This reduction in flow rate for the same heat transfer area reduced the exit flue gas temperatures by a small extent, reducing the sensible heat loss.
  • Below half load, most combustion appliances need more excess air to burn the fuel completely. This increases the sensible heat loss

In general, efficiency of the boiler reduces significantly below 25% of the rated load and as far as possible; operation of boilers below this level should be avoided.

12. Proper Boiler Scheduling

Since, the optimum efficiency of boilers occurs at 65–85% of full load, it is usually more efficient, on the whole, to operate a fewer number of boilers at higher loads, than to operate a large number at low loads.

Boiler Replacement

The potential savings from replacing a boiler depend on the anticipated change in overall efficiency. A change in a boiler can be financially attractive if the existing boiler is:

  • old and inefficient
  • not capable of firing cheaper substitution fuel
  • over or undersized for present requirements
  • not designed for ideal loading conditions

The feasibility study should examine all implications of long-term fuel availability and company growth plans. All financial and engineering factors should be considered. Since boiler plants traditionally have a useful life of well over 25 years, replacement must be carefully studied.

Battery

Now a days we all are familiar with name of battery because every gadget we use, have battery inside from our handset to laptop. The battery can be from  tiny to large as 2 v 2000 ampere cells.

The first device source of power was battery in form of electrical term. Battery was invented before the faraday’s law who invented generator for electrical power.

Battery provide power by conduction +ve ions and -ve ions. these ions flow through the complete path externally by connected wires. That current provide power to any load from lights to motors or any other like electronic circuit board etc.

There is three types of basic battery.

  1. Dry Battery

2. Wet Battery

.Gel Battery

Dry Battery

                       Dry battery terminology is used for maintenance free battery which are in sealed casing and don’t need any extra work for maintenance.

dry battery
image from:http://atiqtraders.com/northstar-sealed-lead-acid-dry-battery-12v-100ah

There batteries are mostly rechargeable and can be charged when low in power or voltage. Now a days these batteries are becoming common in wide range of use.

 

 

 

 

Wet Battery

wet battery
image from: http://sollatek.co.ke/shop/solar-systems/wet-lead-acid-30-200-ah/

Wet batteries are also used in some applications. these batteries need special water to be added and maintained at prescribed levels of water.

 

 

 

 

 

 

Gel Battery

Gel batteries are modern form of batteries which are in between dry and wet batteries. This is latest battery technology which are also maintenance free and long lasting.

Gel battery
image from: https://www.upsbatterycenter.com/blog/gel-battery/#prettyPhoto

These kind of batteries are in wide range of industries usage in large power banks. Power banks are becoming common in power plants and most commonly in wind and Solar power Plants. Batteries power banks are also used in thermal, hydel and other kind of power plants for emergency cases.

Combined Cycle Power Plants

The combined cycle power plant is power plant which consists of two power cycles.

1.Brayton Cycle

2.Rankine Cycle

Brayton Cycle:

In Brayton cycle Gas turbine is powered by gas to spin the generator and produce electrical power. In this cycle Gas turbine also can be power by furnace oil or High speed diesel. The efficiency of brayton cycles gas turbines is up to 40%.

Rankine Cycle:

The other cycle is called HRSG (Heat recovery steam generation). In this process, steam is generated from the exhaust of gas turbine and this is fed to steam turbine to spin the attached generator. The temperature of exhaust is too high near 650c which is enough to generate useable steam. overall efficiency of power plant is increased from 40% to 54%. There are many other accessories for combined cycle power plant which work with parallel as like auxiliary pumps for fuel, water , lube oil, air intake etc.

rankine cycle  for detailed procedure.

rankine cycle is cycle of steam power plant which is explained cycle by cycle.

A steam turbine power plant converts the energy of the fuel into the shaft work continuously and ultimately from the shaft work, electricity is produced.  In the boiler, there is combustion of fuel (fossil fuel) like oil, natural gas, and coal or fissile fuel such as Uranium or Thorium to produce steam.

In the combustion process, heat generated is supplied to the boiler which is a heat exchanger. Boiler is a tube separating two fluids by a walls and thermal conductivity of this wall is very high. In the Nuclear Power plant, the furnace is replaced by Nuclear reactor.

The steam is produced at very high temperature and pressure which expands in steam turbine to produce Mechanical energy and the electrical energy.

Where
Mf     = Mass of fuel

C.V   = Calorific value

Wp    = Work of  the Pump

Q1     = Heat Supplied

Q2     = Heat rejected

Wt is the shaft work, which is form of mechanical energy.  Steam coming from the turbine is fed to the condenser where condensation of the steam takes place. Here heat is extracted from steam to convert it into liquid. Steam emitted from the turbine has both liquid and vapor phases.

River or see water can be used to extract heat from steam and there is change of phase from vapor to liquid. If no river or see is present in nearby area, cooling tower is needed to supply cold water to condenser. The pressure inside the condenser is 10% of the atmospheric pressure. So, a pump is used to raise the pressure from condenser pressure to boiler pressure.  Therefore steam turbine power plant work in a sequence.

B —–> T ——-> C ——> P  ——> B

And the cycle is going on repeatedly.

Co-Generation:

The production of electric power and heat in a single unit is called co-generation. Co-generation is applicable to the industries like paper, Textile, sugar, chemical, cement etc.

Advantages of Cogeneration:

Isothermal process is maintained by steam as it is the best fluid to maintain constant temperature.  The constant process is maintained by using its latent heat of vaporization.

Process is good for safety point of view. For example in inflammable environment, e.g in oil refinery, the direct heat can blow up the whole plant. Steam use for this process is safe.

Feasibility of the plant must be seen before choosing a cogeneration plant.

There are two types of cogeneration cycle.

A.    Topping cycle:
B.    Bottoming cycle:

Topping cycle:

It is cycle where main emphasis is on the production of electricity. High grade steam is used to generate power and then low grade steam is used in industrial process. Topping cycle finds its application in process industry.

topping cycle
topping cycle

 

 

 

 

 

Bottoming Cycle:

Here the steam generated by the steam generator is mainly utilized in the Industrial process and then the steam from the discharge of industrial process is used to generate electricity.

bottoming cycle
bottoming cycle

In the cement industry, this type of cycle is applicable as the steam required there should be high grade. ( High temperature and pressure)

Band Pass Filter

Band pass filter is terminology which is used in telecommunication. Filter is device which passes or stops specific things.

 Filter:  Filter is as like net used to catch fishes or birds or beasts etc. Filter is also used for water purification. Here terminology used for filter, is for telecommunication. This filter is electronics circuit which passes or stops the specific frequency.

Band: As written up, here things are discussed are about the telecommunication. Band is range of frequencies. as like from 2 hz to 10 hz. this is called band.

Band Pass Filter: Band pass filter is electronics circuit which pass specific range of frequencies. These filters blocks the specific range frequencies or allow to pass the range of frequencies. When there is modulated signal then for transmission, one of bands or both bands are transmitted. After receiving the signal, for demodulation we have to separate the signal from carrier frequency. Here Band pass or Band stop filters are used. Mostly these filters are used in telecommunication system. Communication system can be of Radio, television, telephone etc

Automatic Transfer Switch

Automatic transfer switch or in short ATS is an electronic circuit which is attached with generator. It operates generator automatically when there is outage of power from the utility. In this circuit there are comparators which look at the line voltage and when the line voltage of utility goes down they switch on the generator and when voltage of generator get stable, they switch on the contactor of main supply to load and thus there is no need for generator operator for all time. Battery is main power source for this panel for operation or self start of generator. The other work it does, is to maintain the voltage level and if the level goes down it cut off the line and starts the generator. This is how Automatic transfer switch work.

Audio frequency

Audio frequency is frequency which can be heard by human or animals. Its range is 4k hz to 20khz. All humans and animal which have audible sound have frequency of voice in this range. The voice, which have more or less frequency than this range it can’t be heard.

In telecommunication transmission is done in high frequencies for fast transmission. These messages or data is then converted to audible frequency for hearing. As like television when its data is transmitted, it is in high frequency but when television set receive and decodes the data and convert it to visible and audible messages. it produces audible message in range these frequencies. So it is called audio frequency.

Apparent power

Apparent power is electrical power summed up of two powers, real power and reactive power. Real power is power which is actually  used by devices , machines, instruments etc in form of heat or magnetic field. it also can be used in other farms as storages like batteries, capacitors, inductors etc.

AC power has two components real power and reactive power. Apparent power is power which appears on the terminal of ac load like motors mostly.  Apparent power is measured in VA,KVA MVA. All the generators are rated in KVA , VA or MVA. Apparent power is sum of reactive and real powers. Reactive power is always present but it is not used. Reactive power is always transmitted back to the system or generator while real power is used by the load. All inductive load or lagging power factor loads transmits reactive power back to the system.

Only resistive load like lights or heaters etc don’t use reactive powers but real power.

In figure you can see the apparent power, real power and reactive power. Real power is also called Active power and True power. Real power is measured in KW and denoted by S. Reactive power is measured in KVAR,VAR,MVAR and denoted by Q

Here is another picture

Apparent power
image source:http://www.buckles-smith.com/tech-blog/understanding-power-factor

which describes best about electrical power triangle.