energy audit

The facility inspection for energy Audit

The Facility Inspection:

Once all of the basic data has been collected and analyzed, the audit team should tour the entire facility to examine the operational patterns and equipment usage, and should collect detailed data on the facility itself as well as on all energy using equipment. This facility inspection should systematically examine the nine major systems within a facility, using portable instrumentation and common sense guided by an anticipation of what can go wrong. These systems are: the building envelope; the boiler and steam distribution system; the heating, ventilating, and air conditioning system; the electrical supply system; the lighting system, including all lights, windows, and adjacent surfaces; the hot water distribution system; the compressed air distribution system; the motors; and the manufacturing system. Together, these systems account for all the energy used in any facility; examining all of them is a necessary step toward understanding and managing energy utilization within the facility.

  1. 1. Introductory Meeting

The audit leader should start the audit by meeting with the facility manager and the maintenance supervisor. He should briefly explain the purpose of the audit and indicate the kind of information the team needs to obtain during the facility tour. If possible, a facility employee who is in a position to authorize expenditures or make operating policy decisions should be at this initial meeting.

  1. Audit Interviews

The auditor must also interview the floor supervisors and equipment operators to understand the building and process problems. Line or area supervisors usually have the best information on the times their equipment is used. The maintenance supervisor is often the primary person to talk to about types of lighting and lamps, sizes of motors, sizes of air conditioners and space heaters, and electrical loads of specialized process equipment. Finally, the maintenance staff must be interviewed to find the equipment and performance problems.

  1. Initial Walk through Tour

An initial facility/plant tour should be conducted by the facility/ plant manager, and should allow the auditor or audit team to see the major operational and equipment features of the facility. The main purpose of the initial tour is to obtain general information, and to obtain a general understanding of the facility’s operation. More specific information should be obtained from the maintenance and operational people during a second and more detailed data collection tour.

  1. Identification of EMO’S

As the audit is being conducted, the auditor should take notes on potential EMOs that are evident. As a general rule, the greatest effort should be devoted to analyzing and implementing the EMOs which show the greatest savings, and the least effort to those with the smallest savings potential. Therefore, the largest energy and cost activities should be examined carefully to see where savings could be achieved. Identifying EMOs requires a good knowledge of the available energy efficiency technologies that can accomplish the same job with less energy and less cost. For example, over-lighting indicates a potential lamp removal or lamp change EMO, and inefficient lamps indicate a potential lamp technology change. Motors with high use times are potential EMOs for high efficiency replacements. Notes on waste heat sources should indicate what other heating sources they might replace, and how far away they are from the end use point. Identifying any potential EMOs during the walk-through will make it easier later on to analyze the data and to determine the final EMO recommendations.

  1. Energy Audit Report

The next step in the energy audit process is to prepare a report which details the final results of the energy analyses and provides energy cost saving recommendations. The length and detail of this report will vary depending on the type of facility audited. A residential audit may result in a computer printout from the utility. An industrial audit is more likely to have a detailed explanation of the EMOs and benefit-cost analyses. The following discussion covers the more detailed audit reports. The report should begin with an executive summary that provides the owners/managers of the audited facility with a brief synopsis of the total savings available and the highlights of each EMO. The report should then describe the facility that has been audited, and provide information on the operation of the facility that relates to its energy costs. The energy bills should be presented, with tables and plots showing the costs and consumption. Following the energy cost analysis, the recommended EMOs should be presented, along with the calculations for the costs and benefits, and the cost-effectiveness criterion. Regardless of the audience for the audit report, it should be written in easy format.

Energy Audit Report Format:

  • Executive Summary

A brief summary of the recommendations and cost savings

  • Table of Contents
  • Introduction

Purpose of the energy audit

Need for a continuing energy cost control program

  • Facility Description

Product or service, and materials flow

Size, construction, facility layout, and hours of operation

Equipment list, with specifications

  • Energy Bill Analysis

Utility rate structures

Tables and graphs of energy consumptions and costs

Discussion of energy costs and energy bills

  • Energy Management Opportunities

Listing of potential EMOs

Cost and savings analysis

Economic evaluation

  • Energy Action Plan

Recommended EMOs and an implementation schedule

Designation of an energy monitor and ongoing program

  • Conclusion

Additional comments not otherwise

  1. The Energy Action Plan

An important part of the energy audit report is the recommended action plan for the facility. Some companies will have an energy audit conducted by their electric utility or by an independent consulting firm, and will then make changes to reduce their energy bills. They may not spend any further effort in the energy cost control area until several years in the future when another energy audit is conducted. In contrast to this is the company which establishes a permanent energy cost control program, and assigns one person—or a team of people—to continually monitor and improve the energy efficiency and energy productivity of the company. Similar to a Total Quality Management program where a company seeks to continually improve the quality of its products, services and operation, an energy cost control program seeks continual improvement in the amount of product produced for a given expenditure for energy. The energy action plan lists the EMOs which should be implemented first, and suggests an overall implementation schedule. Often, one or more of the recommended EMOs provides an immediate or very short payback period, so savings from that EMO—or those EMOs—can be used to generate capital to pay for implementing the other EMOs. In addition, the action plan also suggests that a company designate one person as the energy monitor or energy manager for the facility if it has not already done so. This person can look at the monthly energy bills and see whether any unusual costs are occurring, and can verify that the energy savings from EMOs is really being seen. Finally, this person can continue to look for other ways the company can save on energy costs, and can be seen as evidence that the company is interested in a future program of energy cost control.


After the energy consumption data has been collected and analyzed, the energy-related systems have been carefully examined, the ideas for improvement have been collected, and management commitment has been obtained, the next steps are to obtain company support for the program, to choose goals, and to initiate action.

  1. Energy Action Team

Now that the preliminary audits have uncovered some energy management measures that can save significant amounts of money or can substantially improve production, funding for the changes and employee support are two additional critical ingredients for success. These can best be obtained with the help of a committee, preferably called something like the energy action team.

No program will work within a company without employee support, particularly such a program as energy management which seems to promise employee discomfort at no visible increase in production. Therefore, one function of the energy action committee is to give representation to every important political group within the company. For this purpose, the committee must include people from unions, management, and every major group that could hinder the implementation of an energy management plan. The committee must also include at least one person with financial knowledge of the company, a person in charge of the daily operation of the facility, and line personnel in each area of the facility that will be affected by energy management.

  1. Goals

At least three different kinds of goals can be identified. First, performance goals, such as a reduction of 10 percent in Btu/unit product, can be chosen. Such goals should be modest at first so that they can be accomplished— in general, 10-30 percent reduction in energy usage for companies with little energy management experience and 8-15 percent for companies with more. These goals can be accompanied by goals for the reduction of projected energy costs by a similar amount. The more experienced the company is in energy management, the fewer easy saving possibilities exist; thus lower goals are more realistic in that case.

A second type of goal that can be established is an accounting goal. The ultimate objective in an energy accounting system is to be able to allocate the cost of energy to a product in the same way that other direct costs are allocated, and this objective guides the establishment of preliminary energy accounting goals. A preliminary goal would therefore be to determine the amount of electricity and the contribution to the electrical peak from each of the major departments within the company. This will probably require some additional metering, but the authors have found that such metering pays for itself in energy saving (induced by a better knowledge of the energy consumption patterns) in six months or less.

The third type of goal is that of employee participation. Even if an energy management program has the backing of the management, it will still fail without the support and participation of the employees. Ways to measure this include the number of suggestions per month; the dollar value of improvements adopted as a result of employee suggestions, per month; and the number of lights left on or machines left running unnecessarily, on a spot inspection. Work sampling has been used to estimate the percentage of time that people are working at various tasks—it can be used equally well on machines.

  1. Implementing Recommendations

In addition to providing and evaluating ideas, setting goals, and establishing employee support, the energy action committee has the duty of implementing the most promising ideas that have emerged from the energy evaluation process. Members of the committee have the responsibility to see that people are assigned to each project, that timetables are established, that money is assigned, and that progress reporting procedures are set up and followed.

  1. Monitoring

Energy management is not complete without monitoring and its associated feedback, and neither is the energy audit process. In an energy audit, monitoring discloses what measures contributed toward the company goals, what measures were counterproductive, and whether the goals themselves were too low or too high. Monitoring consists of collecting and interpreting data. The data to collect are defined by the objectives chosen by the energy action committee. At the very least, the electrical and gas bills and those of other relevant energy sources must be examined and their data graphed each month. Monthly graphs should include: the total energy used of each type (kWh of electricity, therms [105 Btu] of gas, etc.); the peaks, if they determine part of the cost of electricity or gas; and any other factors that contribute to the bills. At the same time, other output-related measures, such as Btu/ ton, should also be calculated, recorded, and graphed. The monitoring data should provide direct feedback to those most able to implement the changes. Often this requires that recording instruments be installed in a number of departments in addition to the meters required by the utility company. The additional expense is justified by increased employee awareness of the timing and amounts of energy consumed, and usually this awareness leads to a reduction in energy costs.

Metering at each department also enables management to determine where the energy is consumed and, possibly, what is causing the energy consumption. Such metering also helps each department manager to understand and control the consumption of his or her own department. Monitoring should result in more action. Find what is good, and copy it elsewhere. Find what is bad, and avoid it elsewhere. If the goals are too high, lower them. If the goals are too low, raise them. Wherever the difference between the planned objectives and the achievements is great, initiate an analysis to determine the reasons and then develop new objectives, initiate new action, and monitor the new results. In this way, the analysis, action, and monitoring process repeat itself.


energy management

Energy Management Opportunities in Thermal Power Plant:

The major EMO’S in thermal power plant are;

The Boiler And Steam Distribution System:

boiler burns fuel to produce heat that converts water into steam, and the steam distribution system takes the steam from the boiler to the point of use. Boilers consume much of the fuel used in many production facilities. The boiler is thus the first place to look when attempting to reduce natural gas or oil consumption. The steam distribution system is also a very important place to look for energy savings, since every pound of steam lost is another pound of steam that the boiler must produce.

The Heating, Ventilating, And Air Conditioning System:

All heating, air conditioning and ventilation (HVAC) equipment should be inventoried. Prepared data sheets can be used to record type, size, model numbers, age, electrical specifications or fuel use specifications, and estimated hours of operation. The equipment should be inspected to determine the condition of the evaporator and condenser coils, the air filters, and the insulation on the refrigerant lines. Air velocity measurements may also be made and recorded to assess operating efficiencies or to discover conditioned air leaks. This data will allow later analysis to examine alternative equipment and operations that would reduce energy costs for heating, ventilating, and air conditioning.

The Electrical Supply System:

This system consists of transformers, wiring, switches, and fuses— all the components needed to enable electricity to move from the utility owned wires at the facility boundary to its point of use within the company. By our definition, this supply system does not include lights, motors, or electrical controls. Most energy problems associated with the distribution of electricity are also safety problems, and solving the energy problems helps to solve the safety-related problems.

Electricity from a utility enters a facility at a service transformer. The area around the transformer should be dry, the transformer fins should be free from leaves and debris so that they can perform their cooling function and the transformer should not be leaking oil. If a transformer fails to meet any one of these conditions there is a serious problem which should justify a call to the local electrical utility, or, if the transformer is company owned, to the person or department in charge of maintaining the electrical system

Similarly Insulation Systems, Waste heat recovery, Energy Control systems, Energy system maintenance etc.



types of boiler

There are virtually infinite numbers of boiler designs but generally they fit into one of two categories:

1. Fire Tube Boilers:

types of boiler

  Fire tube or “fire in tube” boilers; contain long steel tubes through which the hot gasses from a furnace pass and around which the water to be converted to steam circulates (Figure 4.2). Fire tube boilers, typically have a lower initial cost, are more fuel efficient and easier to operate, but they are limited generally to capacities of 25 tons/hr and pressures of17.5 kg/cm2.

2 .Water Tube Boilers:

water tube boiler
water tube boiler

Water tube or “water in tube” boilers are those in which the conditions are reversed with the water passing through the tubes and the hot gasses passing outside the tubes (Figure 4.3). These boilers can be of single- or multiple-drum type. These boilers can be built to any steam capacities and pressures, and have higher efficiencies than fire tube boilers.

  1.    Packaged Boiler

The packaged boiler is so called because it comes as a complete package.  Once delivered to site, it requires only the steam, water pipe work, fuel supply and electrical connections to be made for it to become operational. Package boilers are generally of shell type with fire tube design so as to achieve high heat transfer rates by both radiation and convection

The features of package boilers are:

Small combustion space and high heat release rate resulting in faster evaporation.

  1.             Large number of small diameter tubes leading to good convective heat transfer.

III.            Forced or induced draft systems resulting in good combustion efficiency.

  1.             Number of passes resulting in better overall heat transfer.
  2.             Higher thermal efficiency levels compared with other boilers.

These boilers are classified based on the number of passes – the number of times the hot combustion gases pass through the boiler. The combustion chamber is taken, as the first pass after which there may be one, two or three sets of fire-tubes. The most common boiler of this class is a three-pass unit with two sets of fire-tubes and with the exhaust gases exiting through the rear of the boiler.

4.    Stoker Fired Boiler

Stokers are classified according to the method of feeding fuel to the furnace and by the type of grate. The main classifications are:

  1. Chain-grate or traveling-grate stoker
  2. Spreader stoker
  1. Chain-Grate or Traveling-Grate Stoker Boiler

Coal is fed onto one end of a moving steel chain grate. As grate moves     along the length of the furnace, the coal burns before dropping off at the end as ash. Some degree of skill is required, particularly when setting up the grate, air dampers and baffles, to ensure clean combustion leaving minimum of un burnt carbon in the ash.

  The coal-feed hopper runs along the entire coal-feed end of the furnace. A coal grate is used to control the rate at which coal is fed into the furnace, and to control the thickness of the coal bed and speed of the grate. Coal must be uniform in size, as large lumps will not burn out completely by the time they reach the end of the grate. As the bed thickness decreases from coal feed end to rear end, different amounts of air are required- more quantity at coal-feed end and less at rear end.

  1. Spreader Stoker Boiler

Spreader stokers utilize a combination of suspension burning and grate burning. The coal is continually fed into the furnace above a burning bed of coal. The coal fines are burned in suspension; the larger particles fall to the grate, where they are burned in a thin, fast burning coal bed. This method of firing provides good flexibility to meet load fluctuations, since ignition is almost instantaneous when firing rate is increased. Hence, the             spreader stoker is favored over other types of stokers in many industrial applications.

5.    Pulverized Fuel Boiler

Most coal-fired power station boilers use pulverized coal, and many of the larger industrial water-tube boilers also use this pulverized fuel. This technology is well developed, and there are thousands of units around the world, accounting for well over 90% of coal-fired capacity. The coal is ground (pulverized) to a fine powder, so that less than 2% is +300 micro meter (μm) and 70-75% is below 75 microns, for a bituminous coal. It should be noted that too fine a powder is wasteful of grinding mill power. On the other hand, too coarse a powder does not burn completely in the combustion chamber and results in higher un burnt losses.

The pulverized coal is blown with part of the combustion air into the boiler plant through a series of burner nozzles. Secondary and tertiary air may also be added. Combustion takes place at temperatures from 1300-1700°C, depending largely on coal grade. Particle residence time in the boiler is typically 2 to 5 seconds, and the particles must be small enough for complete combustion to have taken place during this time. This system has many advantages such as ability to fire varying quality of coal, quick responses to changes in load, use of high pre-heat air temperatures etc. One of the most popular systems for firing pulverized coal is the tangential firing using four burners corner to corner to create a fireball at the center of the furnace

6. FBC Boiler:

When an evenly distributed air or gas is passed upward through a finely divided bed of solid particles such as sand supported on a fine mesh, the particles are undisturbed at low velocity. As air velocity is gradually increased, a stage is reached when the individual particles are suspended in the air stream. Further, increase in velocity gives rise to bubble formation, vigorous turbulence and rapid mixing and the bed is said to be fluidized. If the sand in a fluidized state is heated to the ignition temperature of the coal and the coal is injected continuously in to the bed, the coal will burn rapidly, and the bed attains a uniform temperature due to effective mixing. Proper air distribution is vital for maintaining uniform fluidization across the bed. Ash is disposed by dry and wet ash disposal systems. Fluidized bed combustion has significant advantages over conventional firing systems and offers multiple benefits namely fuel flexibility, reduced emission of noxious pollutants such as SOx and NOx, compact boiler design and higher combustion efficiency.

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


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.


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


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

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.

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
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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
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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.

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.

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.


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)


Actuator is a arm, coil, or something like this which converts one energy to mechanical energy for releasing or closing gas or liquid. in other words we can say it is a type of special motor.  The actuator can be electrical biased, mechanical biased, thermo biased, hydraulic biased or pneumatic biased.

Electrical Biased Actuator: electrical biased actuators are solenoids which are used to control flow, it can be fluid or pneumatic flow. solenoid also control electrical energy.

Mechanical Biased Actuator: Mechanical biased actuators are hydraulic or pneumatic cylinders which control the flow of fluid or compressed air.

Thermo Biased Actuator: Actuators which are actuated by thermally or magnetically are called thermo biased actuators. 

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