THERMODYNAMICS SECTION

Technical Report on

Design, Analysis and Fabrication of Biogas Boiler

University of Engineering & Technology Lahore, Pakistan

Contents Acknowledgments

Preface

ASME UET Project

Abstract

Introduction

Project details

Water tube boilers basics

Main parts of a boiler

Operation of a water tube boiler

General design consideration of a boiler

Boiler classification

Boiler layouts

Different configuration of a water tube boiler

Heat transfer mechanisms

Boiler circulation & its types

Maintenance analysis of water tube boiler

Factors to achieve efficient operation of a boiler

Key boiler safety features

Factors influencing boiler efficiency

Boiler optimization & emission control

Improvement of boiler efficiency

Strategies to increase boiler net thermal efficiency

Boiler tube failure assessment

Boiler tube failure reduction

Boiler tubing life assessment

Procedure for boiler tube failure analysis

Different techniques to analyze the failures

Visual examination

Chemical analysis

Elemental mapping

Alloy analysis

Metallography

Finite element analysis

CFD Analysis

Fracture mechanics

Boiler safety analysis

Boiler safety measures

Hydrostatic testing & repairs

Water side inspection of drums & headers

Hydrostatic test

Deaeretor cracking

Feedwater line erosion

Economizer tubes

Failure due to overheating

Failure due to corrosion

Design analysis of biogas plant

Introduction

What is biogas?

Properties and composition of biogas

Chemical composition

Physical characteristics

Biogas plant & its components

Types of biogas plants

Design analysis of continuous fixed demo biogas plant

Selection of design of the biogas plant

Design parameters

Digester

Calculation of the biogas plant

Calculation of the volume of the digester

Displacement tank

Design check-list

Construction (Fixed-Demo Generator)

Field extrusion

Construction

Safety analysis

Global environmental benefits of biogas technology

Health benefits of biogas technology

Project safety & design analysis

Conclusion

References

ACKNOWLEDGEMENT

Team Thermodynamics Section thanks Allah for blessing them with the strength to make this project a

reality using the knowledge we have gained through our hard work. This project is the most emotionally challenging work I have ever done as a leader of my thermodynamics team. For all the struggling and depression I have been through, I am grateful that we can be here writing acknowledgements. I pay a humble thanks to our project advisor, Professor Dr. Ijaz Chaudhary, for his prompt and detailed advice, for his valuable guidance and hard work, showing me what an academic professional ought to be. I also thank his for encouraging us to attend professional meetings. Without his, this project could not have been done. I am also grateful to the “The Industrial Enterprises Group of Companies” for their co-operation and all the fabrication process they offered us. They honoured me and encouraged me to complete the welding phase in the fabrication of our project. I am also grateful to administration of “Descon Engineering Limited, Lahore” that they were kind enough to approve the industrial tour of thermodynamics section ASME-UET to Descon and sharing the exposure to the manufacturing of industrial boiler in detail. I also pay a humble thanks to the “American Society of Mechanical Engineering” for their support and building up my mind for innovative idea for the project. I could not have survived this challenge without the assistance of ASME UET Chapter. I also pay my gratitude to the manager and other members of the Thermodynamics Technical Section, ASME UET for their dignity and enthusiasm they put forth in this project. We unanimously dedicate this project to our seniors, ASME UET Lahore Student Chapter which became rudiment of our recognition, to our teachers who encouraged us and last but not the least to our preeminent parents without whom we might not successful. I thank God for using this work to reveal our weakness to us and build us up. All glory to God for He makes the impossible become possible!

Rizwan Ali Bsc. Mechanical Engineering Student

Assistant Manager Thermodynamics Section

ASME UET Lahore, Pakistan rizwanali976@gmail.com

+92-300-4094863

PREFACE

Project initiation is the process of formally conceiving, approving, and launching a new project. You don’t really have a project until the appropriate stakeholders have approved it during initiation. The time and thought invested during initiation lays the groundwork for all the project work that follows. All project managers know of certain steps to take at the beginning of a project. They need to develop a business case, write a project charter, obtain sponsorship and funding, assign a project manager, assemble the team, acquire other resources, and develop a project plan. However, numerous other activities are also vital to getting a project off to a good start. Our team tour to the ‘DESCON Engineering Limited’ helped a lot for the project fabrication and safety measures and qualitative analysis for the project. The work described in this report was performed under the direction of the American Society of Mechanical Engineering (ASME). The objective of my team is to identify, evaluate, and recommend - through analyses of industrial plants' operations - the most significant opportunities to conserve energy, prevent pollution, and increase productivity, thereby reducing associated costs and increasing profits. Our recommendations are based upon observations and measurements we noted in our visits to different industries and steam power plants; because our time was limited, we do not claim to have complete detail on every aspect of our project. The opportunities presented in this report identify economic benefits for energy efficiency, pollution prevention, and productivity improvement. Other recommendations that may not provide economic incentives are also presented; consideration of these recommendations is strongly encouraged. Note that the interrelationships between energy, wastes, and production are also explored and presented. Other possible benefits, such as improved workplace conditions, reduced liability exposure, improved public image, and reduced environmental damage should also be considered. The recommendations are not intended to deal with the issue of compliance with applicable hazardous materials regulations.

ASME UET PROJECT

American Society of Mechanical Engineering, UET Lahore chapter this year, like every year, organised a team for the Thermodynamic Section and assigned a project, ‘Design Analysis and Fabricate of Biogas Boiler’. The team comprises of 18 members working headed by a Manager and an Assistant Manager as a unit to put forth their immense effort in reaching a new milestone. The Water Tube Boiler that is being worked on is to be forwarded in various project exhibitions to demonstrate the calliper of ASME UET Lahore chapter.

Abstract

The project aims at the evaluation of potential of Biogas as a renewable energy resource. We have

designed and fabricated a Biogas Boiler template. Our project is viable and economical for industrial as well

as domestic applications. The study encompasses the design analysis of Water tube boiler and

corresponding Biogas plant as a fuel source. We have considered certain design parameters in our project

and have utilized them in the fabrication phase. We have used different designing and simulation softwares

like AutoCAD, Pro E and FireCAD. Our project will address the energy crisis that today’s communities are

facing all over the world. We have conducted different industrial visits (Descon Engineering Limited Lahore,

Tie Group of Companies, Taj Textile) to evaluate the prevailing energy crisis and finding the solution of this

very problem.

Keywords

Biogas, Renewable Energy Resource, Optimum Design configuration, Design Analysis of Biogas Boiler

Introduction

Ever since man has evolved on earth there is continuous requirement of energy to fulfill daily needs. Coal,

wood and fossil fuels are being in use as the energy sources, but these sources are going to deplete one

day because the rate of their consumption is much greater than the rate at which they are being

replenished. With the evolution of new technologies and growing technical knowledge man has devised a

way to address this energy shortage by incorporating renewable energy resources. Another major problem

that modern world is facing these days is the recycling of organic material. This project is an attempt to

provide a solution to all these issues by providing a renewable energy source that will use waste organic

material to produce methane gas which is a potential fuel for many applications.

Biogas is an organic base fuel which originates from bacteria in the process of bio-degradation of organic

materials in anaerobic environment. In this method of gas production we utilize organic waste from our

daily life. A biogas plant consists of a digester which is a simple air tight, insulated tank which in this case is

built underground. Organic material is placed in this digester for several days and bacteria develop inside

the tank which produces biogas as a by-product of organic degradation. This gives us biogas, which can be

used as fuel and the remaining organic material is used as fertilizer because of its high nitrogen contents. In

our study we have proposed to use this biogas as a fuel for water tube boiler.

A water tube boiler is a type of boiler in which water is circulated inside the tubes which are heated

externally by hot gases. Water tube boilers are used for high pressure applications. Fuel is burned in the

furnace which produces hot gases, which heats up water in the steam generating tubes.

Project details

In the first phase of our project we have designed a model of water tube boiler; this process encompasses

design considerations, modifications, pressure and temperature calculations, analysis of combustion

capability & heating surface area, along with factors influencing efficiency, boiler circulation methods & its

calculations, metallurgy of boiler parts, safety factors and maintenance issues. We have also studied

corresponding Biogas plant as a fuel source and its calculations required for recommended fuel for boiler

are also calculated. We have also designed and fabricated a Biogas plant model using thermo pole sheets.

Water Tube Boiler

A water-tube boiler is a type of boiler in which water circulates in tubes which are heated externally by the

fire. Water-tube boilers are used for high-pressure boilers. Fuel (coal) is burned inside the furnace, creating

hot gas which heats up water in the steam-generating tubes. In smaller boilers, additional generating tubes

are separate in the furnace, while larger utility boilers rely on the water-filled tubes that make up the walls

of the furnace to generate steam.

A water tube boiler is more geared towards the latter setting than the former though, since water tube

boilers can create large amounts of steam and recycle water for use again and again if kept in a closed

system. There are several, important pieces that make up a water tube boiler, though.

In water tube boilers, water is circulated though the tubes and hot flue gases flow outside the tubes, e.g.

Bob cock & Wilcox, Admiralty three drum, Y-160 and Foster wheeler D-type. The water tube boiler is

employed for high pressure, high temperature, high capacity steam applications, e.g. providing steam for

main propulsion turbines of cargo pump turbines.

Main Parts of a Water Tube Boiler

The boiler consists of furnace, bi-drum boiler bank and economizer and sometimes an air preheater. There

are several types of water tube package boilers based on shape of the boiler like , 'D' type, 'O' type , 'A'

type etc. 'D' type boilers are most widely used. Parts are explained below.

Furnace

Furnace is usually membrane walled and gas tight. Most of the heat transfer occurs in the furnace in the

form of direct radiation. 'D' type furnace is widely used compared to other configurations. Most of these

boilers operate under positive pressure on gas side as there are provided only with FD fan and no ID fan. So

leak proof casing is very much required to arrest gas leakage into boiler room.

Super Heater

There are several types of super heaters employed in water tube package boilers. Inverted 'U' is most

widely used. There are other types like vertical 'S' type drainable. Super heater is usually embedded in the

boiler bank. When superheat temperature is high, part of the super heater section is directly place in the

furnace to increase direct radiation and reduce size.

Boiler Bank

Boiler bank connects both the drums. Natural circulation occurs without the aid of any external down

comers. First 20-30% rows act as risers and the rest act as down comers. Membrane division wall separates

the boiler bank and the furnace. Drum coil heaters are provided in the lower drum to preheat the feed

water before sending it to Economizer.

Economizer

Economizer is used downstream of Boiler bank to preheat the feed water absorbing heat from hot exhaust

gases. Economizers are always water tube type. Bare tubes in Economizers are widely used in Industrial

boilers and in some applications like Heat recovery boilers in Sulfuric acid plants, Gilled tubes are

employed. Finned tubes are popular in HRSG applications. Economizers are retrofitted to many old boilers

to increase the fuel efficiency of the boiler. Feed water can be heated up to a level about 20 - 30 C below

saturation temperature of the boiler. Economizers need hot water input to reduce condensation of

corrosive gases like SO2 on tubes. Depending up on the sulfur content in the fuel, water inlet temperature

of 80 C up to 150 C is required for economizers.

Pipes

In a water tube boiler, water runs through pipes. The pipes are heated by surrounding fire or hot gases,

and the more the water is heated, the higher it goes until it becomes steam. The pipes then allow the

steam to escape into the upper drum.

Upper Drum

The upper drum is where the steam goes once it's traveled the length of the pipes. The steam collects in

the upper drum, away from the heated pipe, and begins to condense back into water. As the steam once

more becomes liquid it drips down from the upper drum and is collected in a lower drum, or the mud

drum.

Lower Drum

The lower drum is set at the bottom of the water tube boiler beneath the upper drum. The condensed

steam collects here and from the mud drum it goes back into the pipes. The more pressure is from built-up

water, the more water that will be turned back into steam and passed through the pipes yet again.

Reheater

The function of Reheater is to reheat the steam coming out from high pressure turbine. The reheater is composed of two sections, the front pendant section and rear pendant section.

Burners

Burner is literally the most important part of the boiler. The burner is heated through fuel, and there are a number of different types of fuel that can supply the boiler burner. For instance you could use natural gas, coal, or even wood pellets.

The burner initiates the combustion reaction within the boiler. Thermostats send messages to the burner electronically when the system needs to produce heat. Fuel is pumped by a filter mechanism to the boiler from an outside source -- often an adjacent fuel tank. A nozzle on the burner turns this fuel into a fine spray and ignites it, creating the reaction in the combustion chamber.

Operation of a Water Tube Boiler

In the water-tube boiler, water flowed through tubes heated externally by combustion gases, and steam

was collected above in a drum. Water tube boilers are very huge and their water holding capacity is

enormous. The water-tube boiler became the standard for all large boilers as they allowed for higher

pressures than earlier boilers, higher than 30 bar. Example, Babcock & Wilcox boiler manufactured at

Thermax Boilers Ltd., Pune.

It is a horizontal, externally fired, stationary, high pressure, and water tube boiler with a super heater as

shown below.

The coal is fed from hopper on to the grate where it is burnt. The flue gases are deflected by the fire brick

baffles so that they pass across the left side of the tubes in a beneficial path transferring heat to water in

the tubes and to the steam in the super heater and finally they escape into the atmosphere through the

chimney. The drought is regulated by a damper placed at the back chamber.

The position of water tubes near the furnace is heated to a higher temperature than the rest. Owing to

higher temperature, the density of water decreases and hence the water rises through the uptake header

and short tube to the drum. The water at the back end, which is at a lesser temperature, now travels down

through the long tube and the downcomer header. Thus, a continuous circulation of water called as

natural circulation is established between the water tubes and the drum. The steam produced gets

collected above the water in the drum. Here, saturated steam is drawn off the top of the drum.

Since water droplets can severely damage turbine blades, dry steam from the steam drum is again heated

to generate superheated steam at 730°F (390°C) or higher in order to ensure that there is no water

entrained in the steam. Cool water at the bottom of the steam drum returns to the feedwater drum via

large-bore 'downcomer tubes', where it helps pre-heat the feedwater supply. To increase the economy of

the boiler, the exhaust gasses are also used to pre-heat the air blown into the furnace and warm the

feedwater supply. Such water-tube boilers in thermal power station are also called steam generating units.

‘

Here is the drawing illustration of a water tube boiler installed in a power plant along with the accessories.

The accessories include – 1. Economizer 2. Boiler Drum 3. Down comers 4. Water walls 5. Water wall plates (used for low pressure boilers) 6. Primary super heater 7. Platen super heater 8. Final Super heater 9. Reheater 10. Burner 11. Ignitors.

Fundamentals of Boiler Design

In a steam generating unit two distinct fundamental processes take place: - Conversion of the potential energy of the fuel into thermal energy. Transfer of this liberated thermal energy to the working fluid to generate steam for useful purpose.

This being the case, the basic task of a boiler designer is to maximize the output of these two processes simultaneously. And for that purpose he must design the layout of the entire heat-absorbing surface in such a manner that it will receive maximum available heat in the process of fuel combustion. Following factors must be taken into account in the design consideration of a boiler: 1. Service requirements. 2. Load characteristics. 3. Fuel characteristics. 4. Mode of fuels burning. 5. Hydrodynamics of gas flow. 6. Feed water quality. 7. Furnace size, shape and material of construction. 8. Type of furnace bottom. 9. Boiler proper. 10. Boiler operation. 11. Capital investment Accessibility for operation, maintenance and repairing must be easy and quick to ensure higher operating efficiency and offset the long outage time.

Boiler Proper

The factors which control the design of boiler proper are: The operating pressure and temperature. The quality of steam – whether the steam required should be wet, dry or superheated. If wet

steam is required, the designer may do away with the separators and superheaters. Layout of heating surface – The prime aim of boiler designer is to obtain the best disposal of

heating absorbing surface within the limitations of space as dictated by the furnace and other components.

Heating surface requirements – These depend upon the duty of the element heat exchangers such as primary evaporators, secondary evaporators, superheaters radiant and connective reheater, economizer and air preheater.

Circulation of steam and water – Natural or forced. Provision of continuous blow drum. The capacity of Boiler drums.

Adequate provision must be made for: Soot blowing Tube cleaning – chemically / mechanically Wasting economizer and air preheated surfaces.

Automation should be injected wherever it leads to higher reliability and greater ease in boiler operation.

General Design Consideration of a Boiler

There are several different approaches used to treat boilers and their selection and performance depend upon many factors. Some of these include:

1) Feed water characteristics. 2) The type and reliability of external treatment. 3) Boiler type. 4) Boiler pressure and heat flux. 5) Steam load and variations in load. 6) Waterside condition of the boiler and current and long-term goals of the program such as cleaning up

scale or maintaining present conditions. 7) Steam purity requirements. 8) Regulatory restrictions such as FDA requirements, other health and safety concerns, or process

restrictions.

9) Feed, testing, and control needs or restrictions. 10) Economic considerations. 11) Boiler room layout and number of boilers.

Boiler Classification

Boilers can be classified by several criteria Utilization:

It is utilized to produce steam for electrical power generation. Normally have large capacity, high steam parameters, and high boiler efficiency. There are two type boilers: industrial boiler and marine boilers.

Industrial Boiler is utilized to produce steam for electrical power generation. Normally have large capacity, high steam parameters, and high boiler efficiency.

Marine Boiler is utilized as a source of motive power for ships. Normally compact general shape, lighter general weight, and mostly fuel oil fired.

Steam / Water Circulation.

Natural Circulation Boiler – the circulation of the working fluid in the evaporating tube is produced by the difference in density between the steam / water mixture in the risers and water in the down comers.

Forced Multiple Circulation Boilers – the circulation of the working fluid in the evaporating tube is forced by means of a circulating pump included in the circulation circuit.

Once Though Boiler – no drum, the working fluid passes through the evaporating tubes only under the action of the feed water pump.

Combined Circulation Boiler – the system includes a pump, back pressure valve, and a mixer in the circuit. At starting the back pressure valve is opened and the boiler operates as a forced multiple circulation boiler.

Pressure

Low to medium pressure (< 10 Bar) – used as industrial boilers, normally has natural circulation.

High pressure (10 – 14 Bar) – used as utility boilers, normally has natural circulation

Super high pressure boilers (> 17 Bar) – used as utility, can be natural or forced circulation. The prevention of film boiling and high temperature corrosion should be considered.

Heat Source

Solid Fuel Fired Boiler – Typically low cost. The components of fuel and the characteristics of the ash are important factor for boiler design.

Fuel Oil Fired Boiler – Has higher flue gas velocity and smaller furnace volume.

Gas Fired Boiler – Natural Gas is utilized with higher flue gas velocities and smaller furnace volumes.

Waste Heat Boiler - Utilizing waste heat from any industrial process as the heating source. Tube Layout

Fired Tube Boiler – Flue of hot gas is flowing inside the tubes. Water is contained inside the shell. Normally for small capacity boilers. Fired tube boilers consist of a series of straight tubes that are housed inside a water-filled outer shell. The tubes are arranged so that hot combustion gases flow through the tubes. As the hot gases flow through the tubes, they heat the water surrounding the tubes. The water is confined by the outer shell of boiler. To avoid the need for a thick outer shell fired tube boilers are used for lower pressure applications. Generally, the heat input capacities for fired tube boilers are limited to 50 Mbtu per hour or less, but in recent years the size of fired tube boilers has increased. Fired tube boilers typically have a lower initial cost, are more fuel efficient and are easier to operate, but they are limited generally to capacities of 25000 kg/h and pressures of 17.5 kg/cm2

Water Tube Boiler – Water is flowing inside the tubes. Flue or hot gas is flowing inside the furnace or shell. Normally this is for large capacity boilers. Water tube boilers are designed to circulate hot combustion gases around the outside of a large number of water filled tubes. The tubes extend between an upper header, called a steam drum, and one or lower headers or drums. Because the pressure is confined inside the tubes, water tube boilers can be fabricated in larger sizes and used for higher-pressure applications. Typically, the tubes should be greater than 5 mm in diameter and should be space so as to allow plenty of room for a flame path between them. Increasing the number of tubes may not increase the boiler's ability to generate steam. The inner surface of the outer casing is insulated with a ceramic sheet. Most modern water boiler tube designs are within the capacity range 4,500 –20,000 kg/h of steam, at very high pressures. Many water tube boilers are of “packaged” construction if oil and /or gas are to be used as fuel. Solid fuel fired water tube designs are available but packaged designs are less common. The features of water tube boilers are: Forced, induced and balanced draft provisions help to improve combustion efficiency. Less tolerance for water quality calls for water treatment plant. Higher thermal efficiency levels are possible.

Table: Comparison of fired tube and water tube boiler

No. Parameter Fired tube Water tube

1- 2- 3- 4- 5- 6- 7- 8- 9- 10- 11-

Rate of steam generation Pressure Temperature Risk of explosion Cost Operating skill Cleaning Tubes replacement Physical Size Cost Applications

Less rapid, Limitation for high capacity steam generation < 25 kg/cm2, Not suitable for high pressure applications 250 psig and above Comparatively low Less Relatively inexpensive Less Easy Easy to replace tubes Compact Low comparatively Well suited for space heating applications

More rapid, up to several million pounds per hour of steam > 125 kg/cm2, able to handle higher pressures up to 5,000 psig Have the ability to reach very high temperature More Higher Higher Difficult, due to the complexity of design Difficult , No commonality between tubes Physical size may be an issue High initial capital cost Industrial process applications

Boiler Layouts

There are three basic design layouts: A, D and O type. The names are derived from the general shapes of the tube and drum arrangements. All have steam drums for the separation of the steam from the water, and one or more mud drums for the removal of sludge. Type A:

Have two mud drums symmetrically below the steam drum. Drums are each smaller than the single mud drums of the type D or O. Bottom blows should not be undertaken at more than 80% of the rated steam load in these boilers. Bottom blow refers to the required regular blow down from the boiler mud drums to remove sludge and suspended solids.

Type D: It is the most flexible design. They have a single steam drum and a single mud drum, vertically aligned. The boiler tubes extend to one side of each drum. Generally have more tube surface exposed to the radiant heat than other designs.

Type O: Have a single steam drum and a single mud drum. The drums are directly aligned vertically with each other, and have a roughly symmetrical arrangement of riser tubes. Circulation is more easily controlled, and the larger mud drum design renders the boilers less prone to starvation due to flow blockage, although burner alignment and other factors can impact circulation.

Different Configurations of a Water Tube Boiler

Bent tube or Stirling boiler

A further development of the water-tube boiler is the bent tube or Stirling boiler. Again this operates on the principle of the temperature and density of water, but utilises four drums in the following configuration. Cooler feedwater enters the left upper drum, where it falls due to greater density, towards the lower, or water drum. The water within the water drum, and the connecting pipes to the other two upper drums, are heated, and the steam bubbles produced rise into the upper drums where the steam is then taken off. The bent tube or Stirling boiler allows for a large surface heat transfer area, as well as promoting natural water circulation.

Cross drum boiler

The cross drum boiler is a variant of the longitudinal drum boiler in that the drum is placed cross ways to the heat source as shown in Figure 3.3.6. The cross drum operates on the same principle as the longitudinal drum except that it achieves a more uniform temperature across the drum. However it does risk damage due to faulty circulation at high steam loads; if the upper tubes become dry, they can overheat and eventually fail. The cross drum boiler also has the added advantage of being able to serve a larger number of inclined tubes due to its cross ways position.

Longitudinal drum boiler

The longitudinal drum boiler was the original type of water-tube boiler that operated on the thermo-siphon principle (see Figure 3.3.5).Cooler feedwater is fed into a drum, which is placed longitudinally above the heat source. The cooler water falls down a rear circulation header into several inclined heated tubes. As the water temperature increases as it passes up through the inclined tubes, it boils and its density decreases, therefore circulating hot water and steam up the inclined tubes into the front circulation header which feeds back to the drum. In the drum, the steam bubbles separate from the water and the steam can be taken off. Typical capacities for longitudinal drum boilers range from 2 250 kg/h to 36 000 kg/h.

Heat Transfer Mechanisms

The purpose of boiler is to generate either hot water or steam. The heat released by burning fuels (or the

waste heat in the gases) is to be transferred efficiently to the incoming water. In the boiler practice, the

heat is transferred in two modes:

by radiation

by convection.

The radiation heat transfer occurs because of both flame radiation and non luminous gas radiation. The

radiation heat transfer is governed by the 'inverse square law' and also the emissivity and temperature of

the radiation source and the boiler heating surface.

The convection heat transfer can be either due to natural convection or force convection.

The energy from the heat source may be extracted as either radiant or convection and conduction.

Heat transfer in the furnace This is an open area accommodating the flame(s) from the burner(s). If the flames were allowed to come into contact with the boiler tubes, serious erosion and finally tube failure would occur. The walls of the furnace section are lined with finned tubes called membrane panels, which are designed to absorb the radiant heat from the flame. Large boilers may have several tube banks (also called pendants) in series, in order to gain maximum energy from the hot gases.

Boiler Circulation & its Types

Boiler circulation:

The movement of water and steam within a steam generating unit is known as boiler circulation.

Types of circulation:

There are two types of water circulation mechanisms employed in boilers

Natural Circulation

Forced Circulation

Natural circulation:

Natural circulation is based on the physics principle of density difference, i.e. when water is heated, it become less dense this

means that for a given volume of water, hot water weighs less than cold water and steam weighs less than water. As a result

of this there is a natural circulation in the boiler with cold water forcing the hot water and steam to move upward through the

tubes.

.

Forced circulation: Forced circulation of water is carried out with the help of a boiler circulating pump. The pump takes suction from down

comers from steam drum and discharges the water to water drum from where it is distributed to the water walls. On

forced circulation units the boiler water circulating pumps are designed to ensure flow through the water wall tubes. This

reduces the possibility of hot spots and the resultant tube metal overheating problems. Natural circulation type boilers do not

use these pumps. The advantage of a controlled circulation boiler is the much faster allowable heat up rate and load change

rate.

Natural circulation water tube and fire tube boilers are widely used in the chemical process

industry. These are preferred to forced circulation boilers where a circulation pump ensures

flow of a steam/water mixture through the tubes. In addition to being an operating expense, a

pump failure can have serious consequences in such systems. The motive force driving the water

mixture through the tubes (water tube boilers) or over tubes (fire tube boilers) in natural-

circulation systems is the difference in density between cooler water in the downcomer circuits and

the steam/water mixture in the riser tubes. This flow must be adequate to cool the tubes and

prevent overheating.

Circulation ratio:

CR is defined as the ratio of the mass of steam/water mixture to steam generation. The mass of

the mixture flowing in the system is determined by balancing the thermal head available

with various system losses, including:

Friction and other losses in the downcomer piping, including bends.

Two -phase friction, acceleration and gravity losses in the heated riser tubes.

Friction and other losses in the external riser piping

Gravity loss in the riser piping

Losses in drum internals.

Circulation ratio (CR) by itself does not give a complete picture of the circulation system.

Natural-circulation boiling circuits are in successful operation with CRs ranging from 4 to 8 at

high steam pressures (1,500 to 2,100 psig) in large utility and industrial boilers.

In waste -heat boiler systems, CR may range from 15 to 50 at low steam pressures (1,000 to

200 psig). CR must be used in conjunction with heat flux, steam pressure, tube size,

orientation, roughness of tubes, water quality, etc., to understand the boiling process and its

reliability. Tube failures occur due to conditions known as departure from nucleate boiling

(DNB) when the actual heat flux in the boiling circuit exceeds a critical value known as

critical heat flux - a function of the variables mentioned above. When this occurs, the rate

of bubble formation is so high compared to the rate at which they are carried away by the

mixture that the tube is not cooled properly, resulting in overheating and failure.

Principle of natural circulation:

Boilers are designed with Economizer, Evaporator and superheater depending on the Design

parameters.

Economizers add sensible heat to water. The economizer water outlet temperature will be closer to

saturation temperature. The water is forced through the economizer by the boiler feed pumps.

Superheaters add heat to steam. That is the heat is added to steam leaving the Boiler steam drum /

Boiler shell. The steam passes through the superheater tubes by virtue of the boiler operating pressure.

Evaporators may be multi tubular shell, water wall tubes, Boiler bank tubes or Bed coils as in FBC boiler.

In evaporators the latent heat is added. The addition of heat is done at boiling temperature. The Flow of

water through the evaporator is not by the pump but by the fact called thermo siphon. The density of

the water, saturated or sub- cooled is higher as compared the water steam mixture in the heated

evaporator tubes. The circulation is absent once the boiler firing is stopped.

Natural circulation calculations:

The basic parameter for the boiler circulation calculation is the circulation ratio K which is equal to the

ratio by weight of the water fed to the heated tubes, Wʷ, to the steam generated Wˢ K= Wʷ/Wˢ

Natural circulations usually have the steam-water circulation system. The simplest form of this system

consists of a drum, headers, risers, and downcomers. Risers are arranged in the furnace and when heated,

the water in the risers evaporates, decreases in density, and tends to rise; downcomers are placed outside

the furnace and are unheated. Cooler and heavier water in them flows downwards. This makes a

circulation in the circuit.

From the figure,

For a steady flow:

ρᵈ gh - Δpᵈ=Σ ρʳhʳg + Δpʳ + Δpˢ

Where;

ρᵈ=density of the water/steam in the risers (kg/m³)

ρʳ=density of the water in the downcomers (kg/m³)

Δpᵈ=hydraulic resistanceof the downcomers (Pa)

Δpʳ= hydraulic resistance of the risers (Pa)

Δpˢ= hydraulic resistance of the steam-water separator in the drum (Pa)

If the left hand side of the eq. are set equal to the Yᵈ, which express the total pressure difference of the

downcomer, and the right hand side of the eq. equal to the Yʳ, which express the total pressure difference

of the risers, then at working point of a circuit with steady flow,

Yᵈ=Yʳ

The aim of the circulation calculation is to determine the the flow rates in the risers and to check

the reliability of the flow for the safe operation of the boiler circuit.

In eq. 2; Yᵈ and Yʳ both depend on the mass flow rate in the circuit (circulation flow rate) W, (kg/s), or

depend upon the inlet water velocity of the risers (circulation velocity) Vₒ, m/s.

W= ρʳ Vₒ Aʳ

Where;

Aʳ= flow area of the risers, m².

With an increase in the W or Vₒ, Δpᵈ increases; i.e; Yᵈ decreases while the Yʳ increases.

For a simplest circuit (all risers have geometrical

characteristics) circulation calculation can be

solved graph analytically as follows: First take

three values of Vₒ from which one may obtain

three corresponding circulation mass flow rates,

W, for establishing curves Yᵈ=f(w) and Yʳ - f(w);

the intersection of the two curves determine the

working point A of the circulation circuit. Fig

shown:

The actual quantity of the circulation flow rate,

W, or the circulation velocity, Vₒ, can be obtained

from the working point A as shown in the fig. for

establishing the curves Yᵈ - f(w) and Yʳ - f(w), Δpᵈ,

Δpʳ , ρm (density of the steam- water mixture)

have to be determined.

What if the circulation ratio is less than that

required minimum?

Tube deformation / leakage failures /

tube to fin weld failures take place. The failure

mode varies depending upon the flow, heat

input, tube size, boiler configuration, water

quality.

Wrinkles seen in tubes

Bulging of tubes

Wrinkle formation & subsequent circular

crack

Heavy water side scaling inside tubes.

Corrosion of tubes

Prolonged overheating & irregular cracks

on tubes

Sagging of tubes if orientation is horizontal

/ inclined

Tube to fin weld crack

Factors which affect Circulation

No. of downcomers, diameter , thickness, layout:

No. of downcomers are selected depending upon the heat duty of each section of evaporator tubes. Depending on the length of the distributing header, more downcomers would be necessary to avoid flow unbalance. It is desirable to keep the bends, branches to a minimum so that the pressure drop is less. The selection of downcomers is so done to keep the velocity less than 3 M/sec.

Heated down comers:

In some boilers the downcomers are subject to heat transfer, for e.g. rear section of boiler bank in Bi drum boilers. The circulation pattern in these boiler evaporator tubes is a function of heat transfer. In case of heated downcomers, burning of tubes may take place if the design is defective. There could be stagnation of water in some tubes depending on the heat pick up.

Downcomer location & entry arrangement inside the drum:

Depending on the Boiler configuration downcomers may be directly connected to steam drum or else to mud drum. One should ensure that the entry of sub-cooled water is smooth into the downcomer.

A down comer directly connected to steam drum is vulnerable to steam bubble entry into the downcomer. In such a case the circulation is affected. Instead of using big pipes, more no of smaller diameter pipe would avoid this. Vortex breaker would be necessary to avoid steam entry into the downcomer pipe.

In case a set of bank tubes are used for taking water to mud drum, one should ensure that the steam does not enter these tubes during water level fluctuation. Proper baffle plates would be necessary to avoid mix up of steam water mixture from risers section to downcomer section. Downcomers taken from mud drum are very safe. An obstruction in front of downcomer can cause the poor circulation in evaporator tubes.

Arrangement of evaporator tubes:

The circulation in each evaporator tube is dependent on how much it receives heat. If there is non- uniform heating among evaporator tubes, one can expect non-uniform flow. At times even flow reversal can take place. In some situations the water may become stagnated leading to water with high TDS or high pH. Localized corrosion of tubes would occur.

Improper operation of boiler:

Depending upon the boiler capacity there may be number of burners / compartments in a boiler. This is required in order to achieve the boiler turn down in an efficient way. In FBC boilers no of compartments are provided for turn down. Operating only certain compartments all the time would cause stagnation of water in unheated section of bed coils. The concentration dissolved solids; pH could be far different from the bulk water chemistry. This leads to corrosion of boiler tubes. Similarly, operating same burner would heat the evaporator tubes in non-uniform way leading to different water chemistry in unheated section of furnace tubes.

Feed pump operation:

In low-pressure boilers, (pressures below 21 kg/cm2 g), the feed pump on /off operation is usually linked to level switches in the steam drum. When the pump is in off mode, it is likely that the steam bubbles would enter the downcomer tubes and cause loss of circulation.

Arrangement of evaporative sections and the interconnection between sections:

In certain configuration of boilers it is possible to obtain better circulation by interconnecting a well- heated evaporator sections to poorly heated evaporator section. It would be necessary to separate the poorly heated section if it lies in parallel to well heated section. The downcomers & risers are to be arranged separately so that the reliable circulation can be ensured. This principle is called sectionalizing for reliable circulation. The inlet headers / outlet headers shall be partitioned for this purpose. However, it is desirable to arrange the evaporative surface in such a way that heat flux & heat duties in various circuits are more or less same. If tubes are inclined close to horizontal, the steam separation would take place leading to overheating of tubes.

No. of risers , pipe Inside diameter, bends, branches:

No of risers are so selected that the velocity inside the pipes would be 5 – 6 m/s. The no of risers are selected in such a way the flow unbalance is minimum. It is preferable to adopt long radius bends to keep the pressure drop to minimum. The no off bends, branches should be kept as minimum possible as these elements contribute for high-pressure drop.

Arrangement of risers in the drum:

The risers are arranged in such a way that the pressure drops is minimum. The baffles are spaced apart to keep the obstruction to flow is minimum. Instead of terminating the risers below the water level in the drum, it would be better to terminate above water level in the steam drum as it allows free entry.

Feed distributor inside the steam drum:

Feed distributor shall be arranged in such way that the sub-cooled water enters the downcomer section. This will ensure that the good hydrostatic head is available for circulation.

Drum Internals arrangement:

Drum internals such as baffles, cyclone separator also form part of the natural circulation circuit. The baffles are arranged in such a way the steam would rise easily to the steam space without much resistance. High-pressure drop in the drum internals will retard the flow through evaporator tubes.

Slagging of furnace tubes:

The design of the furnace shall be in such a way that the Slagging of the fuel ash is avoided. Slagging retards the heat transfer to tubes and thus the driving force for circulation will come down. At locations where the tubes are clean, this would lead to overheating of tubes. If unavoidable, soot blowers shall be so arranged that the uniform heat flux to evaporative sections be not hindered.

Critical heat flux, Allowable steam quality, recommended fluid velocity:

In the design of furnace, the heat flux should not be higher that a limit beyond which the tube will burn. Several correlations are available on this. In a circuit the steam produced divided by the mass flow would be the quality of steam produced in the circuit. The allowable steam quality has been found be dependent on the heat flux, mass velocity and the steam pressure. Even after ensuring that the heat flux and steam quality are safe, the entry velocity is important to avoid departure from nucleate boiling. For vertical rising circuit the velocity is in the range of 0.3 m/s to 1.5 m/s. for inclined circuit the velocity shall be in the range of 1.54 m/s to 3 m/s.

Block diagram for the boiler fuel oil system

Maintenance of the Water Tube Boiler

General maintenance

A well-planned maintenance program avoids unnecessary down time or costly repairs. It also

promotes safety and aids boiler code and local inspectors. An inspection schedule listing the

procedures should be established. It is recommended that boiler room log or record be

maintained, recording daily, weekly, monthly, and yearly maintenance activities. This provides a

valuable guide and aids in obtaining boiler availability factor to determine shutdown frequency,

economies, length of service, etc.

Even though the boiler has electrical and mechanical devices that make it automatic or semi-

automatic in operation, these devices require systematic and periodic maintenance. Any

"automatic" features do not relieve the operator from responsibility, but rather free him from

certain repetitive chores, providing him with time to devote to upkeep and maintenance.

Good housekeeping helps to maintain a professional boiler room appearance. Only trained and

authorized personnel should be permitted to operate, adjust, or repair the boiler and its related

equipment. The boiler room should be kept free of all material and equipment not necessary

for operation for the boiler.

Alertness in recognizing unusual noises, improper gauge readings, leaks, signs of overheating,

etc., can make the operator aware of developing malfunction and initiate prompt corrective

action that may prevent excessive repairs or unexpected down time. All piping connections to

the system and its accessories must be maintained leak-proof because even a minor leak, if

neglected, may soon become serious. This applies especially to the water gauge glass, water

level control, piping, valve packing, and manway gaskets. If serious leaks occur shut down the

boiler immediately and gradually reduce steam pressure. Do not attempt to make repairs while

the boiler is under pressure.

Shift Maintenance

Shift maintenance should include checking the boiler water level in the gauge glass and the

boiler steam pressure on the gauge. Operate the intermittent blowdown valve to remove any

accumulated solids in the mud drum. The valves on the water column and gauge glass should

be operated to make sure these connections are clear. Monitor water chemistry to adjust the

chemical feed treatment and continuous blowdown as required, remaining within water

treatment guidelines established by the Owner's water treatment consultant.

Daily maintenance

Daily Maintenance should include a check of the burner operation, including fuel pressure,

atomizing air or steam pressure, visual appearance, etc. Clean the observation ports during

periods of low fire or shutdown. Test the boiler level alarms and low water cutoff. Maintain a

daily schedule of sootblowing.

Monthly maintenance

Check the condition of the refractory for significant damage or cracking. Patch and repair the

refractory as required. Frequent wash coating of refractory surfaces is recommended. Use high

temperature bonding; air-dry type mortar diluted with water, to the consistency of light cream,

for this purpose. This will seal small cracks and prolong the life of the refractory. Any large

cracks should be cleaned out and filled with mortar.

Follow the recommendations of you authorized inspector pertaining to safety valve inspection

and testing. The frequency of testing, either by the use of the lifting lever or by raising the

steam pressure, should be based on the recommendation of your authorized inspector. Test

the boiler safety valves in accordance with the manufacturer's instructions to be absolutely

sure that the valves have not corroded shut. Failure of the relief valves in an overpressure

situation is disastrous.

Annual maintenance

Have the unit inspected and checked by a service representative from the manufacturer, if

possible. Clean both the heating and heated sides of the boiler. Remove all manway and

handhole covers. Open all bottom blowdown and drain valves. Hose the inside of the boiler

with clean water under high pressure. Use a hand scraper to remove accumulated sludge and

scale. Start near the top and work toward the bottom. After cleaning tube exteriors, inspect the

tube surfaces for signs of overheating, such as bulging, blackened surfaces in the tubes, etc.

Specific local conditions determine the use of "wet" or "dry" storage during shutdown periods.

If you are unsure of which procedure to follow, contact the Owner's water treatment

consultant or your local insurance company.

Replacement of flange, manway, and handhole gaskets:

Clean metal surfaces where cover plate bears against shell plate or ring.

Always use new gaskets. Apply graphite paste to gasket to prevent sticking and assure

tightness.

Use care in centering cover plate and gasket in shell opening. Draw bolts up firmly.

Yokes are designed for the positioning and holding of the covers only. Gasket sealing is

accomplished by the application of internal pressure.

Spare gaskets should be maintained in your inventory to minimize your downtime.

Annual inspection

Insurance regulations or local laws will require a periodic inspection of the boiler by an

Authorized Inspector. Sufficient notice is generally given to permit removal of the boiler from

service and preparation for inspection. This major inspection can often be used to accomplish

maintenance, replacements, or repairs that cannot easily be done at other times. This also

serves as a good basis for establishing a schedule for annual, monthly, or periodic maintenance

programs.

While this inspection pertains primarily to the waterside and fireside surfaces of the pressure

vessel, it provides the operator an excellent opportunity for detailed inspection and check of all

components of the boiler including piping, valves, pumps, gaskets , refractory, etc.

Comprehensive cleaning, spot painting or re-painting and the replacement of expendable items

should be planned for and taken care of during this time. Any major repairs or replacements

that may be required should also, if possible, be coordinated with this period of boiler

shutdown. Replacement spare parts, if not on hand, should be ordered sufficiently prior to this

shutdown.

Boiler operation and maintenance are closely tied together. Good operation includes

performing necessary daily and periodic maintenance. Low maintenance cost depends on good

daily operating control, given that the system and fuel are compatible.

Operating a steam generator — whether it is a low-, medium-, or high-pressure design — is a

complex undertaking. Important physical and chemical balances are necessary for safe and

efficient control.

Factors to achieve efficient operation of boiler

The primary duty of the boiler operator is to achieve optimum operating efficiency of the

equipment consistent with high reliability and low cost. The steam generator’s efficiency

depends on proper control of time, temperature, turbulence and oxygen.

Time and temperature

Before a boiler begins to achieve efficient operation, the technician must raise the furnace to

operating temperature. The fuel-burning rate must be maintained to produce the desired

number of pounds of steam per hour to run the stream of turbines — if generating electricity —

and supply steam for heat and process needs.

Turbulence

The turbulence in fossil-fuel boiler systems results from the combination of forced-draft fans

located in the fuel-supply section and the induced-draft fans located in the stack breeching. The

drafts introduced by these large-volume air handlers produce the turbulence necessary for

efficient operation. They also create a demand for emission controls, which are very important

to air-quality improvements that are being emphasized today and will only be more important

in the future.

The furnace and steam-generating boiler are made up of a setting, or support structure, a fuel-

handling and -supply system, a fuel-burning control system, space above the fuel for heat

transfer by radiation and convection, boiler tubes for conducting heat to the water, boilers for

steam generation and storage, air- and ash handling equipment, and many support systems,

such as condensers, pumps, deaerators. A boiler consumes a large amount of a facility's energy

budget. Even a small decrease in a boiler's efficiency can cause a sharp increase in energy costs.

Optimize air-to-fuel ratio

A boiler requires just the right amount of oxygen to ensure an appropriate air-to-fuel ratio. Air

consumes energy as it is heated. Thus, excess air/oxygen wastes energy, as heated air is

released up the stack. If air/oxygen is insufficient, not all fuel will burn. The unburned fuel will

move through the system, leaving behind soot. Additionally, too little air may cause a buildup

of carbon monoxide and smoke.

By analyzing flue gas, one can measure oxygen and stack gas temperature and calculate boiler

efficiency. Adjustments then can be made to optimize the level of excess air and the

temperature of incoming air.

To optimize air-to-fuel ratio, one can use a computer-based distributed control system, which

automatically controls a fuel burner to reduce oxygen levels as needed.

Optimize water treatment

Before being pumped into a boiler, feedwater is treated to remove dissolved oxygen and other

impurities that might cause corrosion or buildup of sediment, both of which reduce boiler

efficiency. Water treatment is performed on a water softening plant where different chemicals

are used to treat and purify the water especially sodium zeolide.

Minimize heat loss

To recover waste heat from a stack, install an economizer. Heat then can be directed to boiler

feedwater for preheating. Before installing an economizer, be sure a boiler system is cleaned

and tuned so that an accurate measurement of stack gas temperature can be taken. Additional

heat can be extracted from flue gas (below 300 F) using a condensing economizer. When a

condensing economizer is used, caution must be exercised because a reduction in flue gas

below the dew point will cause condensation, which can contain sulfuric or hydrochloric acid

because of the sulphur, hydrogen, and chlorine in the fuel. These acids can significantly corrode

the surfaces with which they come in contact.

Install a stack-temperature gauge

A stack-temperature gauge indicates the temperature of flue gas leaving a boiler. The lower the

temperature of flue gas, the more efficient is the system. A high stack temperature indicates

soot or scale may be building up in tubes or the baffling inside of the boiler may have

deteriorated or burned through, allowing gases to bypass heat-transfer surfaces. These

conditions generally develop slowly and unbeknownst to operators. Approximately 1 percent in

boiler thermal efficiency is lost per 40 F increases in stack temperature.

Recover condensate

Condensate drained from steam traps can be collected and used as boiler feedwater. This

reduces boiler operating costs and usually is more cost-effective than using fresh utility water.

Recovered condensate takes less fuel to convert into steam than fresh utility water does. The

temperature of recovered condensate is 160 F to 200 F, while the temperature of fresh utility

water usually does not exceed 80 F. The proper maintenance of steam traps throughout a

distribution system can maximize the amount of condensate returned to a boiler, minimizing

energy waste associated with feedwater heating.

Failure cause and prevention

The primary cause for boiler failure during operation is low water level. According to

authorities on boiler explosions, an estimated 75 percent of boiler failures are due to this cause.

The main cause for this high level of accidents is the assumption that boilers require little or no

attention because of the redundant, automatic controls they feature. The most common

reasons unit heaters fail include

Improper installation

Installation in a corrosive environment, and lack of maintenance.

Annual inspection and cleaning several months before the heating season is highly

recommended.

Water hammer

Steam and hot-water heaters often fail due to internal corrosion and water hammer.

Technicians can minimize corrosion by treating the makeup water with a filming amine, which

protects the tube walls, due to the formation of carbonic acid.

Technicians can control water hammer by using the right type and size of steam trap for

removing condensate from the heaters. They should check traps for proper operation and clean

steam-line filters annually. Long drip legs correctly installed in the condensate lines help to

keep a static head of condensate t o overcome pressure loss across condensate piping, strainers

and traps.

Technicians can remove the drip-leg caps annually for cleanout and inspection to determine the

amount of scale buildup occurring. They can install vacuum breakers between the heating units

and the trap if a control valve regulates the steam supply. This tactic prevents pressure in the

tubes from dropping below atmospheric pressure. Gas- and oil-fired heaters are subject to

internal corrosion due to atmospheric conditions. The only solution is to move them to a

location less vulnerable to corrosive substances. Over firing caused by drafts can occur, causing

the burners to fail prematurely. If technicians cannot eliminate the draft, adding outside air

might reduce the over firing problem.

Finally, technicians should clean the contactors and inspect them for oxidation and pitting,

replacing them if they look badly burned. The coil itself can crack and break from fatigue, due

to frequent cooling and heating. Technicians can make a temporary fix by reconnecting the

broken ends with a conducting fastener and washers, but they should replace the faulty coil

with the proper part as soon as possible.

Providing appropriate training and conducting operating-floor visits can help managers ensure

technicians follow these procedures and log all important events, including unsafe conditions,

operating problems, and equipment issues.

But without regular operation and maintenance controls, a series of automatic-control failures

can occur, preceding an explosion. First, the automatic feed device fails, causing the low-water

condition. Then, the low-water fuel cutout fails to sense the low-water condition and stop the

fuel supply. Third, the safety pop valve fails to actuate to relieve the pressure buildup. Although

all of these devices are automatic, they have a finite life span under the conditions in which

they operate. Mechanical wear, fatigue, corrosion and erosion take their toll.

Preventing failure

These four steps will ensure more reliable and energy-efficient boiler operations and prevent

failure.

First, match the best equipment available with the type of service and fuel required.

Second, verify proper operation, including all necessary controls and safety equipment,

by having the installation checked annually by the insurance company’s service

representative.

Third, specify as a part of the installation contract that the system is inspected by an

authorized insurance company or state or local inspector before acceptance. This step

ensures the installation meets all ordinances and that installers followed good practices.

Finally, provide operators with a log book for recording daily events and a preventive

maintenance program for regular, daily, weekly, monthly, semiannual, and annual

maintenance procedures. These procedures should include repair, replacement,

inspection, cleaning, and lubricating. Technicians should schedule these tests annually

and perform them periodically.

Key boiler safety features

Boilers have a variety of features designed to prevent accidents and keep them functioning at

optimal efficiency:

Safety valves

Safety valves are the primary safety feature on a boiler. Safety valves are designed to

relieve all of the pressure generated within a boiler if other systems fail. Every steam

and hot-water heating boiler must have at least one safety or safety relief valve of

sufficient relieving capacity to meet or exceed maximum burner output.

The ability of a safety valve to perform its intended function can be affected by several factors,

including internal corrosion and restricted flow.

Internal corrosion typically is the most common cause of "freezing" or binding of safety relief

valves. This generally is caused by slight leaking or "simmering" attributed to improper seating

of a valve disk and is a condition that must be corrected immediately. A boiler never should be

operated too close to a valve setting because the set pressure will cause the valve to leak

slightly, resulting in internal corrosion buildup that eventually will prevent the valve from

operating.

Water-level control and low-water fuel cut-off

These two devices perform two separate functions, but sometimes are combined into one unit.

It is important to ensure piping is open and free of scale or sludge buildup at all times. Cross

tees allow piping to be cleaned and inspected easily. Low-water fuel cutoffs should be checked

periodically for proper operation. Because this requires boiler water to be lowered to the

minimum safe operating level, extreme caution should be used.

In addition to periodic tests of a low-water device, the float chamber on a water-level control

and/or a low-water fuel cutoff should be flushed thoroughly to remove accumulated sediment.

At least once a year, water-level controls and low-water fuel-cutoff devices should be

disassembled, cleaned, and checked.

Water gauge glass

A water gauge glass enables an operator to observe and verify the actual level of water in a

steam boiler. If not properly cleaned and maintained, a gauge glass can appear to show a

sufficient level of water when a boiler actually is operating in a low-water condition. A stain or

coating sometimes develops on the inside of a gauge glass, where the gauge glass is in contact

with boiling water. This stain can give the appearance of water in the boiler, especially when

the gauge glass is completely full or empty of water.

If necessary, replace a gauge glass, even if the boiler must be shut down. That inconvenience is

nothing compared with the damage that can result from a boiler being operated without a

functioning gauge glass. The connection lines to a gauge glass can become clogged and show

normal water levels when water is low; thus, the piping connecting a gauge glass to a boiler

should be cleaned and inspected regularly to ensure it is clear.

A boiler's fuel system, particularly the burner, requires periodic cleaning and routine

maintenance. Failure to maintain equipment in good working order can result in high fuel costs,

the loss of heat transfer, or a boiler explosion.

Boilers logs may be the best method of ensuring boilers are maintained properly. Because a

boiler's operating conditions change slowly over time, a log is the best way to detect significant

changes that otherwise may go unnoticed. Maintenance and testing should be performed and

recorded in a log on a regular basis.

Factors influencing 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: 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 can lead to sulphur dew point corrosion. Stack temperatures greater than 200°C indicates potential for recovery of waste heat. It also indicates 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 economizer: 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. 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 preheating: Combustion air preheating is an alternative to feed water 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 preheats temperatures. 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 color 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: 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. 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. • Portable oxygen analyzers 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.

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. • 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 outputs. 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. 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, and 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. 13. 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 under-sized 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. Different losses:

Loss due to hydrogen in fuel (H2) Loss due to moisture in fuel (H2O) Loss due to moisture in air (H2O) Loss due to carbon monoxide (CO) Loss due to surface radiation, convection and other unaccounted.

Loss due to dry flue gas (sensible heat)

Boiler optimization and emission control

Boilers are the equipments used for heating water and producing steam. Boiler is thus energy

conservation equipment along with heat transfer duty. The thermal energy required for

transferring to water is obtained by burning various fuels. So, in combined cycle scheme it

accept hot flue from gas turbine and produce steam.

So in doing so many losses occur in boilers which reduces its efficiency so they must be

minimized for best optimization achievement of boiler.

Types of boiler losses:

Loss due to unburnt fuel

Loss due to partial combustion

Dry gas loss

Loss due to fuel moisture

Loss due to air moisture

Loss due to sensible heat of solid combustion residue

Loss due to radiation

So, for proper optimization these all losses should be avoided by changing modifications in

boiler design and boiler operating conditions.

To minimize emission and obtain optimal combustion in the boiler, key factors that must be

addressed include the availability of oxygen, time, temperature and turbulence. There is an

optimum ratio of temperature air and turbulence in boiler operation that minimizes organic

PM, NOx and VOCs emission in the flue gas will be minimized.

One of the key factors for better functioning is to use boiler designed for staged combustion

and gasification. Actually, separate burn chambers are provided in staged combustion. So, by

doing so excess air varies in different sections and chambers low temperature gasification helps

reduce soot formation by reducing fuel rich. High temperature zone in flame and reduce ash-

based partial formation.

To maximize benefits of staged combustion, Accurate automated process

controls are required to ensure operations at the appropriate air-to-fuel ratios required in each

of different zones.

To reduce the unburn carbon amount in boiler we should meet following parameters:

Coal fineness

Good combustion characterized by good mixing

Adequate air supply

Sufficient residence time.

A burner coal flow balancing system and a combustion turning system is provided in modern

technology. With these systems, operators can mange un burnt carbon without raising total

boiler excess O2 level or increasing NOx emission and sensible heating losses.

Boiler optimization:

To minimize emissions and optimize efficiency, process monitors, such as those that monitor

temperature, oxygen and carbon monoxide levels, can be installed and used with pre-defined

schemes to ensure optimum operating parameters. These systems allow automatic

adjustments of air-to-fuel ratios, redistribution of combustion air between the primary,

secondary and (possibly) tertiary combustion zones, and fuel feed rates for stable combustion.

Combustion efficiency:

Operating your boiler with an optimum amount of excess air will minimize heat loss up the

stack and improve combustion efficiency. Combustion efficiency is a measure of how effectively

the heat content of a fuel is transferred into usable heat. The stack temperature and flue gas

oxygen (or carbon dioxide) concentrations are primary indicators of combustion efficiency.

Given complete mixing, a precise or stoichiometric amount of air is required to completely

react with a given quantity of fuel. In practice, combustion conditions are never ideal, and

additional or “excess” air must be supplied to completely burn the fuel. The correct amount of

excess air is determined from analyzing flue gas oxygen or carbon dioxide concentrations.

Inadequate excess air results in unburned combustibles (fuel, soot, smoke, and carbon

monoxide) while too much results in heat lost due to the increased flue gas flow—thus lowering

the overall boiler fuel-to-steam efficiency.

Flue gas analyzers:

The percentage of oxygen in the flue gas can be measured by inexpensive gas- absorbing test

kits. More expensive hand held, computer-based analyzers display percent oxygen, stack gas

temperature, and boiler efficiency.

Oxygen trims systems:

When fuel composition is highly variable (such as refinery gas, hog fuel, or multi- fuel boilers),

or where steam flows are highly variable, an online oxygen analyzer should be considered. The

oxygen “trim” system provides feedback to the burner controls to automatically minimize

excess combustion air and optimize the air-to- fuel ratio.

Combustion of black liquor:

Combustion of black liquor in a recovery boiler has been optimized to change the ash

characteristics and rate of deposition to substantially improve the superheater steam

temperature performance over time. Modifications to the approach of spraying black liquor

into the furnace and distributing air demonstrate the importance of depositing the liquor char

on the bed and at the perimeter of the furnace. Optimum lower furnace operating condition

result in a stable bed and higher quality smelt.

Improvement of boiler efficiency

In order to make the boiler more efficient, it is necessary to reduce the boiler losses:-

1. Reducing loss due to unburnt fuel:

In the present day technology of gaseous fuel combustion, it is possible to completely remove

this loss. Most of the oil firing equipments would also ensure complete combustion of the oil. In

the case of solid fuels however, there is always a certain quantum of unburnt carbon found

along with the residual ash.

2. Reducing dry gas loss:

Dry gas loss is directly affected by the temperature of the outgoing flue gases, as well as the

excess air coefficient adopted. With modern combustion devices, it is possible to reduce the

excess air coefficient significantly. The recommended values of excess air coefficient for various

types of combustion systems are given in table 2. The reduction of flue gas outlet temperature

however, would require extra investment for additional surfaces in air pre heater. It should also

be remembered, that fuels containing sulphur should be dealt with carefully to avoid corrosion.

Corrosion (due to sulphur in fuel) can also be minimized by using special alloy steels for the

construction of last stage heat recovery surfaces. Thus the reduction of flue gas temperature

(to increase the efficiency) would be largely a tradeoff between initial capital cost and revenue

savings of fuel cost due to higher efficiency

3. Reducing loss due to fuel moisture:

It is practically not possible to bring down flue gas outlet temperature to a value below 100 C.

However, the loss due to sensible heat of super heating water vapors can be minimized. This

can be achieved by pre-drying the fuel with separate equipments. It would also be possible to

use boiler exhaust flue gas itself for pre-drying of fuels. This would be an especially attractive

proposal for high moisture fuels like lignite and biogases. Special fluidizers and agitators can be

successfully adopted in such pre-dryers. In the recent days, non-metallic air preheaters and

feedwater heaters have been developed to reduce outgoing flue gas temperature to values

below 100(C which would then improve boiler efficiency considerably.

4. Reducing loss due to radiation:

The 'Radiation Loss' is a misnomer. This loss is due to natural convection on the insulated

surface of the boiler. The general practice for insulation is, to design the insulated skin

temperature to be 20(C) above the ambient temperature. However, the insulation thickness

can be reduced or increased depending on the special site conditions. In the indoor type

boilers, there is reduced natural convection and hence can economically accommodate

relatively higher skin temperatures. The skin temperature of the insulated surfaces is also

governed by safety requirements.

Strategies to increase boiler net thermal efficiency

In this section, the strategies that should be applied to maximize net steam generation from a

recovery boiler are summarized and discussed, including

Maximizing the fired liquor solids concentration or percent solid

Maximizing steam temperature

Minimizing access air

Minimizing fouling

Minimizing sootblowing

Stabilizing steam flow

Minimizing auxiliary power use

Maximizing The Fired Liquor Solids Concentration

Maximizing the percent solids fired in a recovery boiler will reduce the thermal losses

for heating the water associated with the black liquor. This water exits the boiler as steam or

water vapour in the stack gases. The heat of vaporization of water and some sensible heat will

be lost up the stack. A typical recovery boiler will gain about 0.4%efficiency for each 1%

increase in the percent solids fired in the recovery boiler. An exact prediction of this change can

be obtained by using a recovery boiler thermal balance program, such as the TAPPI Short Form.

Using the example boiler and a 5% increase in percent solids, the annual value of the additional

high pressure steam is about 1,000,000/yr. the additional steam use in the

evaporator/concentrator, with a steam economy of 5, would be worth $125,000/yr. The net

value would thus be $875,000/yr.

The limitation in raising the fired solids concentration are a function of the evaporators

and concentrators used to concentrate the black liquor.

In the case of direct contact units, the use of dilution water on cascade or cyclone

evaporators should be avoided.

The percent solids to the black liquor oxidation system should be maximized given the

constraint of maintaining low residual sulfide levels in the black liquor. This will result in the

highest possible solids to the recovery boiler. A target of 68-69% would be good practice.

The percent solids target for a concentrator should be consistent with the capability of the unit to produce the high percent solids liquor while not requiring excessive boil outs. Depending on the equipment used, this could range from 68% to more than 80% solids.

Controls measurement of the percent solids out of the product evaporator should be used to help stabilize the high firing solids concentration. A continuous or concentrator can be made available using either the boiling point rise or a refractometer. Maximizing steam temperature

Higher steam temperatures are important as they result in additional power generation in the turbine. The main factor in determining steam temperature is the design of the recovery boiler superheater. All superheaters are designed for a maximum outlet temperature, which is a function of the materials used to construct the superheater.

In actual performance, many superheaters cannot maintain the design exit steam temperature throughout the annual operating period between maintenance shutdowns. This is usually due to insufficient superheater surface or excessive fouling of the superheater. Fouling is addressed in a following section.

In some cases, a superheater is controlled to less than the design temperature due to past problems with corrosion. Check with a turbine expert to see what this is costing you in terms of power generation. It may be that some improvements to the boiler operation, or changes in the materials of construction for the superheater, can be made to enable operation at a higher steam temperature.

The superheater outlet temperature can also be improved by taking the sootblower steam off after the primary or intermediate superheater rather than from the final superheater. This will also reduce the desuperheating required for the sootblower steam. Note though that it is better from an overall energy perspective to use a source steam header that is closer to the operating pressure of the sootblowers (300-450 psig normally). Most boilers produce steam at much high pressures, and use of this high pressure steam, pressure-reduced down to a pressure suitable for sootblower operation, eliminates an opportunity to generate electrical power.

While the steam temperature can usually be increased by raising the feedwater temperature, there are some exceptions. Determining the energy benefit requires a careful check of your mill’s energy balance to determine if this is a worthwhile approach. In general, this approach will be favored by higher electricity prices and lower fuel prices. The actual value of an increase in steam temperature is highly dependent on the steam cycle and fuels used to produce incremental steam; as a result, rules-of-thumb are of little use.

Minimizing excess air

Excess air is the amount of air that must be used above the theoretical requirements in order to complete combustion. Complete combustion can be defined based on carbon monoxide (CO) levels in the flue gases. In general, if the concentration of CO is less than 50 ppm, then combustion is essentially complete. On most recovery boilers with a modern air system design, this will require between 1.5 and 2.5% O2 or about 7.5 to 10% excess air. With older air systems, excess air requirements could be as high as 3.0% O2, or about 15% excess air.

There are two aspects to minimizing excess air: 1. setup of the air and liquor system so that it is most effective in burning the black liquor with a minimum amount of excess air; and 2. controlling the system so that it runs as close as possible to the minimum requirement at all times.

The setup of the air and liquor system will depend on the specific boiler. In general, it requires that burning be maximized in the lower furnace with high air pressures at the different air levels to promote mixing.

Excess air is best controlled by stabilizing the liquor input to the boiler. If the liquor heating value is stable, then control of the amount of fired dry solids can be effective. If heating values vary, then heat input control has been shown to be very effective. Consumed air type strategies are particularly effective in stabilizing air demands for the boiler. There are many qualified vendors of these types of systems.

There are two main benefits of minimizing excess air on boiler efficiency: stack thermal losses are reduced, and the temperature exiting the economizer will be reduced. For each 1.0% decrease in exit O2, the thermal efficiency of a recovery boiler will increase by 0.5-1.0%. Typically, application of supervisory control will result in a 1.5-2.0% reduction in the exit O2 versus manual control. Using the example boiler, an O2 reduction of 2% gives an annual savings of up to $750,000/yr.

You can use a boiler heat balance program to more accurately calculate the efficiency improvement, but it is necessary to estimate what the temperature decrease at the economizer outlet will be as this is generally an input parameter. There will be some uncertainty in this estimate. Another way of getting an estimate of the impact is to perform a trial on the boiler and then analyze the operating data. This could be done in a short trial of 3 to 4 hours duration. Hold the dry solids firing rate constant and adjust tertiary air frequently so that the outlet O2 varies over a good range (2%-5%), with each O2 target (2%, 3%, 4%, and 5%) being held for one hour. Then correlate steam flow with the excess O2 concentration and the economizer outlet gas temperature to estimate the impact on the boiler.

Your O2 target can usually be slightly lower (~0.5%) than the best achievable levels using frequent manual changes because a supervisory control system will add more stability than is possible with even frequent manual changes. The target O2 should produce a minimum of about 50 ppm CO; the maximum CO concentration would be based on the permitted level for the boiler.

Another way to decrease excess air at the stack is to minimize any infiltration air that enters the boiler through unused burner openings, around sootblowers, through bed camera openings and through casing leaks

Minimizing fouling

When a recovery boiler fouls, the thermal efficiency decreases. One way to observe this is to check the boiler efficiency when it first starts up and then compare this to the thermal efficiency just prior to a water wash at the same dry solids input. The decrease in thermal efficiency can be a few percent. It drops because all of the heat transfer surfaces become less effective as material deposits on the fireside of the boiler.

Some deposition is inevitable, but it can be minimized by a number of techniques: Minimizing the chloride concentration in the black liquor fired in the boiler. Effective use of sootblowers (more about this in the next section). Good air and liquor system operation that minimizes carryover of black liquor into the

upper furnace.

Area of the boiler most affected by a loss in thermal efficiency is the superheater. This is normally the biggest improvement by attention to the factors above. Improvements in generating bank and economizer thermal efficiency are more difficult to achieve and using frequent sootblower operations to achieve a small improvement in thermal efficiency is generally not worth the cost of the extra sootblowing steam. This assumption can be easily tested on a boiler by increasing sootblowing and observing the impact on thermal efficiency.

Minimizing sootblowing

Any steam used for sootblowing in a recovery boiler reduces the net production of steam from the boiler. Sootblowing is necessary in a recovery boiler in order to prevent excessive fouling and plugging of the boiler, but it is possible to reduce the amount of sootblowing steam used. A few techniques can be used: Examine each area of the boiler just prior to water washes to see where deposits build up.

If an area of the boiler has less deposit build up, then consider reducing the frequency of sootblowing in this

area. Examine your sootblower sequences. They should focus on the critical areas of the boiler,

where heavy Deposits are typically observed. Some areas of the boiler can use one-way sootblowing. This can save steam as cooling flow

is used when the Blower retracts from the boiler. Check for leaks in your sootblower system, such as poppet valves and drain valves.

Sootblowing steam use in excess of 6% of the steam generated can generally be considered excessive and should be addressed. Assuming the example boiler reduced sootblowing steam use from 9% to 6% of total steam production; this would result in an annual savings of $950,000 if high pressure steam was being used. Stabilizing steam flow

Recovery boilers are the lowest cost steam producer at a pulp mill. It is worthwhile to control these boilers so that steam generation is stabilized. If mill production is limited by the recovery boiler capacity, then the steam flow at which the boiler is stabilized would be as close to the steaming limit as possible. If the mill is not recovery limited, then the boiler steam flow would be stabilized to match the average throughput requirements.

When the steam flow from the recovery boiler is stabilized, the following benefits will

be seen: Easier control of excess air because air demands are proportional to steam demands. Well defined operating parameters would allow for optimization of such items as liquor

guns and air splits. Reduction in fuels used in other boilers due to dips in recovery boiler steam production.

Generally, the lower the variability in the “base loaded” portion of the steam generation, the lower the need for the use of high cost fuels to make up the variable portion of the steam generation.

Minimizing auxiliary power/steam use Some examples of reducing auxiliary power use include: Reducing the pressure set point of forced draft fans. Check to make sure the fan outlet

pressure is not higher than that required to distribute air at the required pressure to each air level.

Using variable speed motors in applications where power demand varies widely (i.e. for liquor nozzle pumps).

Some areas for auxiliary steam savings include:

Air heater steam if the steam temperature used in the first stage is too high. Generally low pressure steam (5 bar) should be used to first heat incoming air, then later stages can use medium pressure (10 bar) steam.

Liquor heating if the heat is lost via flashing before the boiler (common with atmospheric mix tanks). If a direct heater (steam injection) is being used, consider its replacement with an indirect liquor heater.

Excessive steam use on shatter jets. A water coil air heater can reduce outside steam requirements by up to20 tons/hr. Note

that this reduces high pressure steam generation which may exceed the savings in low pressure steam. Once again, a detailed energy balance is necessary to assess this at a particular mill;

New boilers are going in with finned tube (external water source), economizers after the electrostatic precipitator. This results in increased thermal efficiency for the boiler.

Some more measures of improvements

Analyze the existing air and fuel system Improve gas mixing and combustion effectiveness Lower excess air necessary for complete combustion Minimize particulate carryover and unburned fuel Minimize emissions of CO2, CO, TSR, and NOx Increase the range of operational conditions Optimize firing strategies for different loads/fuels Improve overall thermal efficiency

Increase the capacity of the boiler Improve the stability of the boiler Minimize the danger of bed blackouts Minimize the danger of waterwall tube failure Analyze and recommend choices of air and fuel system upgrades Provide valuable operational information for mill personnel

Benefits of Waste Heat Recovery

Benefits of ‘waste heat recovery’ can be broadly classified in two categories: Direct Benefits:

Recovery of waste heat has a direct effect on the efficiency of the process. This is reflected by reduction in the utility consumption & costs, and process cost. Indirect Benefits:

a) Reduction in pollution: A number of toxic combustible wastes such as carbon monoxide gas, sour gas, carbon black off gases, oil sludge, Acrylonitrile and other plastic chemicals etc, releasing to atmosphere if/when burnt in the incinerators serves dual purpose i.e. recovers heat and reduces the environmental pollution levels. b) Reduction in equipment sizes: Waste heat recovery reduces the fuel consumption, which leads to reduction in the flue gas produced. This results in reduction in equipment sizes of all flue gas handling equipments such as fans, stacks, ducts, burners, etc. c) Reduction in auxiliary energy consumption: Reduction in equipment sizes gives additional benefits in the form of reduction in auxiliary energy consumption like electricity for fans, pumps etc.

Boiler Tube Failure Assessment

Introduction:

Significant deformations and crack propulsions in the power utility boiler tubes are the leading cause of steam plant non-reliability. These boiler tubes are subjected to various failure mechanisms due to high temperature, stress and environmental hazards depending upon their design and functions. Stress-rupture failure initiated by creep process or sudden overheating, arise due to steam starvation or flue gas disruption.

The operation of the steam boiler is so complex that results in metal fatigue due to temperature cycling and pressure fluctuation as well as erosion and chemical depositions over the tube surfaces that cause severe corrosion. Thus, during their lifetime, it may be required for various reasons, to estimate and assess the remaining service life of the boiler tubes in order to avoid any unexpected collapse in running operation. The work shown in this paper will assist to determine various non destructive techniques to determine the hidden flaws in the tubes to estimate the remaining life of steam boilers. It will provide knowledge sharing through several case studies on the boiler tube failure detection and cure before time.

Structural Integrity’s approach to effectively manage high temperature high energy tubing systems is to employ a fully integrated, multidiscipline approach of running the plant. All the necessary technical disciplines are used to develop and implement a sequence of steps intended to help ensure safe and reliable operation of critical boiler operation. This technical paper will help answer three important questions that are fundamental to any critical setup, and effectively minimize the overall risk associated with high energy tubing at plant.

Structural Integrity’s approach to effectively manage high temperature high energy tubing systems is to employ a fully integrated, multidiscipline approach of running the plant. All the necessary technical disciplines are used to develop and implement a sequence of steps intended to help ensure safe and reliable operation of critical boiler operation. This technical article will help answer three important questions that are fundamental to any critical setup, and effectively minimize the overall risk associated with high energy tubing at plant. Where should we check the tubes???

How should we check the tubes???

After checking what should we do???

Where?? Structural Integrity of a boiler is based on, a semi-quantitative approach to selecting and prioritizing which tubes to evaluate. The analysis for their life assessment uses stress information, materials knowledge, inspection data, fabrication process information, and other readily accessible data. The output from the analysis provides a list of the system tubes in a rank ordering of the potential for damage and shows the tubes that are the highest contributors to overall risk. How?? Structural Integrity of a boiler demands advanced nondestructive evaluation techniques that are specifically designed to detect and quantify the damage mechanisms associated with high energy tubing systems. These techniques are capable of detecting damage at an early stage (as compared to traditional inspection methods), which allows for longer re-inspection intervals and extended time to develop corrective action plans.

What to do now?? Structural Integrity uses analytical tools including fracture mechanics, life consumption analysis and risk optimization to predict future serviceability and facilitate run/repair/replace decisions. It provides recommendations for re-inspections and repairs as necessary and can assist in the performance of the repair activities.

Boiler Tube Failure Reduction

Boiler tube failures are the number one cause of forced outages in power plants worldwide. Failures occur despite the fact that in almost all cases it is understood why they occur and how they can be prevented. The vast majority of these failures are repeat failures, because in all too many cases the response to a failure is to treat the symptoms and not the root cause. Once a boiler tube fails certain key questions must be answered: What is the damage mechanism responsible for the

failure? Does the damage extend to other tubes and, if so, to

how many and where? What has been the failure history? What were the conditions of operation at the time of

the failure? If the failure involves the water-touched surfaces,

what is the water treatment regime for the unit and have there been significant disruptions in that regime.

The condition assessment of un-failed tubing is also a key component to the failure reduction. Temperature, pressure, metallurgical condition (i.e., wall loss, swelling, microstructure, etc.), and mode of unit operation are all considered and analyzed. The boiler tube failure reduction and assessment includes the following:

A careful review of plant operating and water chemistry data A metallurgical examination of tubing samples Non-destructive inspection of the tubing in the area of interest Installation of thermocouples, strain gauges, or flow monitoring devices at selected

sites.

Boiler Tubing Life Assessment

The reliable operation of the power industry’s fossil-fired steam generators require critical pressure part components, particularly boiler tubing, to be properly maintained throughout the life of the unit and, when problems occur, that the appropriate corrective action be taken.

A boiler is a complex and critical piece of equipment and its reliability is crucial to the entire plant’s operation. Several components of boiler play a major role in contributing to its reliability and performance. Of these, boiler tubes are considered, the most vulnerable component to corrosion in steam generating units. The corrosion concerns and the failure mode of boiler tubes can sometimes be unique to a plant and the control of corrosion is made a challenging task due to several variables including the make-up water chemistry, contaminants in the return steam condensate and effectiveness of the treatment program. Therefore, periodic inspections, assessments and timely remedial actions are required to ensure safe and reliable operation. Boiler tubing assessments that characterize tube condition and predict future serviceability are

the cornerstone of boiler tube failure analysis. including evaluations of water wall tubes with

such waterside corrosion issues as hydrogen damage, caustic gouging, corrosion fatigue

cracking, and flow-accelerated corrosion; creep damage evaluations of super heater and re-

heater tubing operating at elevated temperatures; evaluations of super heater and re-heater

dissimilar metal welds for creep fatigue, oxide notching, and carbide coarsening; and

examination of hard-to-reach areas of low-temperature super-heater and re-heater sections for

internal wall loss due to corrosion pitting, or external wastage caused by soot blower erosion,

fly ash erosion, or abrasion.

Procedures for boiler tube failure analysis

At times, the cause of a failure cannot be readily determined, making it difficult to determine

the appropriate corrective action. A detailed examination of the failure and associated

operating data is usually helpful in identifying the mechanism of failure so that corrective action

may be taken.

Proper investigative procedures are needed for accurate metallurgical analyses of boiler tubes. Depending on the specific case, macroscopic examination combined with chemical analysis and Microscopic analysis of the metal may be needed to assess the primary failure mechanism.

When a failed tube section is removed from a boiler, care must be taken to prevent

contamination of deposits and damage to the failed zones. Also, the tube should be properly

labeled with its location and orientation.

Visual Examination

The first step in the lab investigation is a thorough visual

examination. Both the fireside and the waterside surfaces should

be inspected for failure or indications of imminent failure.

Photographic documentation of the as-received condition of tubing

can be used in the correlation and interpretation of data obtained during the investigation.

Particular attention should be paid to color and texture of deposits, fracture surface location

and morphology, and metal surface contour. A stereo microscope allows detailed examination

under low-power magnification.

Dimensional analysis of a failed tube is important. Calipers and point

micrometers are valuable tools that allow quantitative assessment of

failure characteristics such as bulging, wall thinning at a rupture lip,

and corrosion damage.

The extent of ductile expansion and/or oxide formation can provide

clues toward determining the

primary failure mechanism. External wall thinning from

fireside erosion or corrosion mechanisms can result in tube

ruptures which often mimic the appearance of overheating

damage. In those cases, dimensional analysis of adjacent

areas can help to determine whether or not significant

external wall thinning occurred prior to failure. A photograph

of a tube cross section taken immediately adjacent to a failure

site can assist in dimensional analysis and provide clear-cut

documentation.

The extent, orientation, and frequency of tube surface cracking can be helpful in pinpointing a

failure mechanism. While overheating damage typically causes longitudinal cracks, fatigue

damage commonly results in cracks that run transverse to the

tube axis. In particular, zones adjacent to welded supports

should be examined closely for cracks. Nondestructive testing

(e.g., magnetic particle or dye penetrate inspection) may be

necessary to identify and assess the extent of cracking.

When proper water chemistry guidelines are maintained, the

waterside surfaces of boiler tubes are coated with a thin protective layer of black magnetite.

Excessive waterside deposition can lead to higher-than-design metal temperatures and

eventual tube failure. Quantitative analysis of the internal tube surface commonly involves

determination of the deposit-weight density (DWD) value and deposit thickness. Interpretation

of these values can define the role of internal deposits in a failure mechanism. DWD values are

also used to determine whether or not chemical cleaning of boiler tubing is required. In

addition, the tube surface may be thoroughly cleaned by means of glass bead blasting during

DWD testing. This facilitates accurate assessment of waterside or fireside corrosion damage

(e.g., pitting, gouging) that may be hidden by deposits.

The presence of unusual deposition patterns on a waterside surface can be an indication that

non optimal circulation patterns exist in a boiler tube. For example, longitudinal tracking of

deposits in a horizontal roof tube may indicate steam blanketing conditions.

Steam blanketing, which results when conditions permit stratified flow of steam and water in a

given tube, can lead to accelerated corrosion damage (e.g., wall thinning and/or gouging) and

tube failure.

Chemical analysis

When excessive internal deposits are present in a tube, accurate chemical analyses can be used

to determine the source of the problem

and the steps necessary for correction.

Whenever possible, it is advisable to

collect a "bulk" composition, by

scraping and crimping the tube and

collecting a cross section of the

deposit for chemical analysis. Typically,

a loss-on-ignition (LOI) value is also

determined for the waterside deposit.

The LOI value, which represents the

Weight loss obtained after the deposit

is heated in a furnace, can be used to

diagnose contamination of the waterside

deposit by organic material.

In many cases, chemical analysis of a deposit from a specific area is desired. Scanning electron

microscope-energy dispersive spectroscopy (SEM-EDS) is a versatile technique that allows

inorganic chemical analysis on a microscopic scale. SEM-EDS analyses are shown in Figures 14-

12 and 14-13. For example, SEM-EDS can be useful in the following determinations:

Differences in deposit composition between corroded and non corroded areas on a tube

surface.

The extent to which under-deposit concentration of boiler salts on heat transfer

surfaces is promoting corrosion damage.

Elemental differences between visually different tube surface deposits

Elemental mapping(analysis of deposits)

Inorganic analyses through SEM-EDS can also be performed on ground and polished cross

sections of a tube covered with thick layers of

waterside deposit. This testing is called elemental

mapping and is particularly valuable when the

deposits are multilayered. Similar to the

examination of rings on a tree, cross-sectional

analysis of boiler deposits can identify periods

when there have been upsets in water chemistry,

and thereby provides data to help determine

exactly how and when deposits formed. With

elemental mapping, the spatial distribution of

elements in a deposit cross section is represented

by color-coded dot maps. Separate elements of

interest can be represented by individual maps, or selected combinations of elements can be

represented on composite maps.

A scanning electron microscope (SEM) can also be utilized to analyze the topography of surface

deposits and/or morphology of fracture surfaces. Fractography is particularly helpful in

classifying a failure mode. For example, microscopic features of a fracture surface can reveal

whether the steel failed in a brittle or ductile manner, whether cracks propagated through

grains or along grain boundaries, and whether or not fatigue (cyclic stress) was the primary

cause of failure. In addition, SEM-EDS testing can be used to identify the involvement of a

specific ion or compound in a failure mechanism, through a combination of fracture surface

analysis and chemical analysis.

Alloy Analysis

Most water-bearing tubes used in boiler construction are fabricated from low-carbon steel.

However, steam-bearing (superheater and reheater) tubes

are commonly fabricated from low-alloy steel containing

differing levels of chromium and molybdenum. Chromium

and molybdenum increase the oxidation and creep

resistance of the steel. For accurate assessment of metal

overheating, it is important to have a portion of the tube

analyzed for alloy chemistry. Alloy analysis can also

confirm that the tubing is within specifications. In isolated

instances, initial installation of the wrong alloy type or tube

repairs using the wrong grade of steel can occur. In these cases, chemical analysis of the steel

can be used to determine the cause of premature failure.

At times, it is necessary to estimate the mechanical properties of boiler components. Most

often, this involves hardness measurement, which can be used to estimate the tensile strength

of the steel. This is particularly useful in documenting the deterioration of mechanical

properties that occurs during metal overheating. Usually, a Rockwell hardness tester is used;

however, it is sometimes advantageous to use a micro-hardness tester. For example, micro-

hardness measurements can be used to obtain a hardness profile across a welded zone to

assess the potential for brittle cracking in the heat-affected zone of a weld.

Metallography

Microstructural analysis of a metal component is probably the most important tool in

conducting a failure analysis investigation. This testing, called metallography, is useful in

determining the following:

whether a tube failed from short-term or long-term overheating damage

whether cracks initiated on a waterside or fireside surface

Whether cracks were caused by creep damage, corrosion fatigue, or stress-corrosion cracking

(SCC)

Whether tube failure resulted from hydrogen damage or internal corrosion gouging Proper

sample orientation and preparation are critical aspects of micro structural analysis. After

careful selection, metal specimens are cut with a power hacksaw or

an abrasive cut-off wheel and mounted in a mold with resin or

plastic. After mounting, the samples are subjected to a series of

grinding and polishing steps. The goal is to obtain a flat, scratch-

free surface of metal in the zone of interest. After processing, a

suitable etchant is applied to the polished metal surface to reveal

micro structural constituents (grain boundaries, distribution and

morphology of iron carbides, etc.)

Finite element analysis

Structural Integrity performs thermal transient, linear elastic, elastic plastic, and inelastic creep stress analysis for engineering design, root cause analysis, and life assessment of plant equipment. Typical components evaluated include piping systems, boiler headers and drums, valves, turbine

steam chests, casings, and rotors. Dynamic analysis of piping systems and other components is performed to evaluate water/steam hammer and other dynamic events. FE modeling of welding processes is performed to evaluate residual stresses due to weld overlay and other repairs.

CFD Analysis

3D modeling and analysis of internal/external flow in boilers, (heat recovery steam generators) HRSGs, and piping systems. Evaluations are performed using COSMOS FloWork and ANSYS CFX.

Fracture Mechanics

Critical flaw size, Leak before Break (LBB) and crack growth evaluations for fatigue, corrosion-fatigue, stress corrosion, creep, and creep-fatigue are performed for serviceability assessment of flawed components. Evaluations are performed per API 579 / ASME FFS-1 and other industry standards.

Boiler Safety Analysis

The most significant factor of heating system that provides comfort to the numerous homes

and apartments are efficient boilers. Regular servicing and maintenance will keep boiler repairs

to a minimum and also a simple boiler service can keep at bay complete breakdown or boiler or

even fickle generation of fatal gases. Most of us think that the money spends on boiler services

is not an essential one but professionals recommend to service your boiler for every twelve

months and if you are a landlord then it will be a legal requirement for every property you let

out. Here are some ways to be aware of the fact what can you do in between servicing to

ensure your boiler is as safe and efficient as possible.

When water is converted to steam it expands in volume over 1,000 times and travels down the

steam pipes at over 100 kilometer/hr. Because of this steam is a great way of moving energy

and heat around a site from a central boiler house to where it is needed, but without the right

boiler feed water treatment, a steam-raising plant will suffer from scale formation and

corrosion. At best, this increases energy costs and can lead to poor quality steam, reduced

efficiency, shorter plant life and an operation which is unreliable. At worst, it can lead to

catastrophic failure and loss of life. While variations in standards may exist in different

countries, stringent legal, testing, training and certification is applied to try to minimize or

prevent such occurrences. Failure modes include:

Over pressurization of the boiler

Insufficient water In the boiler causing overheating and vessel failure

Pressure vessel failure of the boiler due to inadequate construction or maintenance.

However, if we take the proper safety measures, we can be sure that our boiler and central

heating system will not only be more efficient, but also safer.

Annual safety check

Carbon monoxide

Keep your boiler healthy

Annual safety check

If you own your own home and are responsible for ensuring that your boiler is running properly

then you also need to make sure that you have it serviced once a year.

Some boiler cover plans will include your annual safety check, but if you’re not insured, or this

is not included in your cover, you will need to contact a registered engineer to look over your

boiler. You should never attempt to do it yourself.

Making sure your annual service is carried out not only ensures that your boiler is safe and

running efficiently, but also reduces the chance of a breakdown - and the costly callout and

repair fees that go hand-in-hand with central heating emergencies.

Carbon monoxide

Carbon monoxide (CO) is a colorless, odorless gas that can be given off by faulty gas appliances

and it can be fatal. So it’s vital that you know how to spot the symptoms of both a faulty

appliance, and the first signs of CO poisoning.

CO poisoning can occur via a shared flue or chimney, or even from a neighbor’s appliance and

early symptoms include tiredness, headaches, nausea and chest or stomach pains. It can often

be confused with flu, and children and the elderly will be affected quicker, but if you experience

any of these symptoms while using a gas appliance, you need urgent medical attention.

There are also a number of ways that you can check your appliances. These include looking at

the flame; if it’s bright blue, it’s healthy; if it’s yellowy orange, carbon monoxide could be

present. Also, pilot lights that frequently blow out; brownish-yellow stains around the appliance

or heavy condensation in the room where the appliance is installed are also indicators that you

need to get your appliance professionally checked as soon as possible. If you are worried about

CO leaks, you can install an alarm.

Need for carbon monoxide alarm

Many of us won't consider having smoke alarm in your home as we are not aware of the evil

effects of carbon monoxide poisoning. Carbon monoxide is a colorless, odorless and tasteless

gas and it is equally a toxic gas to both animals and human beings. It offers adverse effects that

may result in death by asphyxiation which is preceded by headaches, vomiting, vertigo and flu

like symptoms. Low level exposure can lead to depression, confusion and memory loss.

Instead of suffering from all those health effects it is advisable to purchase carbon monoxide

alarm as it is very cheap and it will be a great solution to protect your family and tenants from

carbon monoxide poisoning. As this alarm can detect the carbon monoxide leakage and gives

you the early warning of leaks from your boiler and also you can assure peace of mind in

between boiler servicing.

Make use of the boiler even if there is no need

Sometimes in summer you may not required heating but it is always better to put your heating

on for 10 minutes once a month as it will create costly problems when the boiler is not

operating over few months. Months of inactivity lead to moving parts seizing up and the pumps

being clogged with grit. On the other hand it had to be put on at least for a few hours over the

winter while chilly temperatures can cause water to freeze in your pipes which in turn causes

the water to expand and crack the pipes.

Replace with new one

An old boiler will cost you more in the long run not just for repairs but also in energy bills. With

an "A" efficiency rating, any new boiler can save your energy bills and if your boiler is old (more

than 10-15 years) it is better to replace it with new one so that you can save you as much as

40% on your annual heating bill.

Keep your boiler healthy

Taking out boiler insurance will not only ensure that your boiler stays in good condition, it also

offers peace of mind against the high costs of emergency repairs.

Keep it clean

Like other house hold items which require occasional clean you also required to clean your boiler regularly. The efficiency of the boiler will be affected if any dust or dirt gets blocked inside it and so make sure to give it wipe down and once an over with the duster between each boiler servicing.

Boiler Safety Measures

Measures taken to reduce the hazards ensuring the safe and reliable work Conditioning

monitoring of the boiler by using NDT Techniques like inspection of deposits in tubes of

different sections, hardness testing, Dye penetrate and ultrasonic testing of weld joints.

Destructive testing of sample tubes during overhaul of boiler.( tensile test )

Regular monitoring of tube thickness, tube scanning and advance techniques like LFED (Low

frequency Electrodynamics Device.)

Ensuring proper protection by periodic checks by simulating or relevant procedures.( At the

end of the outage simulating scenarios / faults & checking MFT and checking healthy

working of protection.)

Hydro testing of boiler once in a year

Controls for boiler in service

Permissive for boiler purging prior to light up.( By using FD&ID fans to clear all explosive

mixture if any)

Flame scanners-for detecting the flames of the burners.( Sensing the flame by UV

sensors)

Furnace draft control to avoid explosion / implosion of boiler / ducting’s.

Various other controls for monitoring feed flow, combustion control etc

Regular housekeeping reports and checks.

Hydrostatic Testing and Repairs

Hydrostatic testing a pressure vessel or non-pressure vessel such as a fuel tank is done using water as a fluid and pumping it in under pressure to a predetermined level. This is a safe method of finding leaks and is a requirement of the ASME code. A hydrostatic test is required when a new boiler is built before and after stress relieving (heat treating) of all the welded joints. The ASME code requires a hydrostatic test 150 percent of the designed working pressure. The method of doing this test is to fill the boiler or pressure vessel with water until all the air is removed. Then there is a need to install a gauge, valve to release the pressure and a fitting to pump more water into the vessel. The release valve should be at the highest place on the tank or boiler. The pressure should not be just pumped in all at once but brought up to its pressure in stages. On a boiler that a test of 800 PSI is to be performed, the pressure should be brought up at 200 Lb increments and let set for twenty minutes. Then, release the entrenched air and continue to the next level. A satisfactory test should hold its test pressure for a good hour without dropping more than 10 psi.

Fuel tanks have a requirement of 5 psi. The ASME code can be checked for the testing requirement of most types of vessels. Usually systems such as economizers, superheaters, exhaust feed water heaters, and piping systems are tested separately so as to remove entrenched air and isolate any leaks or failures. After a boiler has been built and stamped, routine testing is performed at a lower level as required by the inspecting authority. This test is normally performed at 125 % of working pressure. All fittings and plumbing are removed. The outer jacket and insulation is also removed, all welded joints exposed, plugs and fittings are added for the test. The big question; what if I have a leak? If the inspecting authority determines the boiler shell and all plates are in good condition and the leak is in a weld, then the weld can be ground out and re-welded. Now the problem, this weld needs to be heat-treated and stress relived As a result of the welding processes used to join metals together, the base materials near the weldment, the deposited weld metal, and in particular, the heat-affected zones transform through various metallurgical phases. Depending upon the chemistry of the metals in these areas hardening occurs in various degrees dependant mainly upon carbon content adjacent to the weld metal deposit where the highest stresses due to melting and solidification result. Stress relieving is designed to relieve these imposed stresses by reducing the hardness and increasing ductility thus reducing the danger of further cracking. Controlled cooling down to 800F or lower is also very important as higher carbon steels are subject to surface cracking if cooled too quickly. The temperature of the heat treatment is normally held for at least one hour. Normal low carbon steels of most boilers are 0.35 or lower. The temperature range can be anywhere between 900F to 1200F. Someone specializing in this area should be consulted. Superheaters and components of high carbon and nickel and chrome require temperatures as high as 1350F. Ceramic insulation and thermostatic controls are used to control the level of heat. Waterside inspection of drums and headers

Whenever a boiler is opened for cleaning and overhaul, the internal surfaces of the drums and headers should be carefully inspected for evidence of cracking. Particular attention must be given to steam drum manhole knuckles, knuckles at corners of drum heads, corners of cross boxes and headers, superheater header vent nozzles, and handhole openings. Any defect found must be recorded in the boiler water treatment log and in the maintenance log. These defects should also be reported to the maintenance office so that appropriate repair action can be taken. Hydrostatic tests

Boilers are tested hydrostatically for several different purposes. In each case, it is important to understand why a test is being made and to use—but not to exceed—the test pressure specified for that particular purpose. In general, most hydrostatic tests are made at one of three test pressures: boiler design pressure, 125% of design pressure, or 150% of design pressure. Other test pressures may be authorized for certain purposes. For example, a test pressure of 150 psi is required for the hydrostatic test given before a boiler undergoes chemical cleaning. The hydrostatic test at design pressure is required upon the

completion of each general overhaul, cleaning, or repair that affects the boiler or its parts and at any other time when it is considered necessary to test the boiler for leakage. The purpose of the hydrostatic test at design pressure is to prove the tightness of all valves, gaskets, flanged joints, rolled joints, welded joints, and boiler fittings. The test at 125% of design pressure is required after the renewal of pressure parts, after chemical cleaning of the boiler, after minor welding repairs to manhole and handhole seats, and after repairs to tube sheets, such as the correction of gouges and out-of-roundness. The “renewal of pressure parts” includes all tube renewals, rolled or welded, except downcomers and superheater support tubes The test at 150% of design pressure is required after welding repairs to headers and drums, including tube sheet cracks and nozzle repairs, after drain and vent nipple repairs, and after renewal or rewelding of superheater support tubes and downcomers. The hydrostatic test at150% of design pressure is basically a test for strength. This test may be (but is not necessarily) required at the 5-year inspection and test. Before making a hydrostatic test, rinse out the boiler with freshwater. Using at least 50-psipressure, play the hose onto all surfaces of the steam drum, the tubes, the nipples, and the headers. Examine the boiler carefully for loose scale, dirt, and other deposits. Be sure that no tools or other objects are left in the boiler. Remake all joints, being sure that the gaskets and the seating surfaces are clean. Replace the handhole and manhole plates and close up the boiler. Gag all safety valves. Boiler safety valves must never, under any circumstances, be lifted by hydrostatic pressure. When gagging the safety valves, do not set up on the gag too tightly or you may bend the valve stems. As a rule, the gags should be set up only hand tight. Close all connections on the boiler except to the air vents, the pressure gauges, and the valves of the line through which water is to be pumped to the boiler. Be sure the steam-stop valves are completely closed and that there will be no leakage of water through them. After all preparations have been made, use the feed pump to fill the boiler completely. Successful, reliable operation of steam generation equipment requires the application of the best available methods to prevent scale and corrosion. When equipment failures do occur, it is important that the cause of the problem be correctly identified so that proper corrective steps can be taken to prevent a recurrence. An incorrect diagnosis of a failure can lead to improper corrective measures; thus, problems continue.

There are times when the reasons for failures are obscure. In these instances, considerable investigation may be required to uncover the causes. However, in most cases the problem area displays certain specific, telltale signs. When these characteristics are properly interpreted, the cause of a problem and the remedy become quite evident.

Deaerator cracking

In numerous deaerators, cracks have developed at welds and heat-affected zones near the welds. The cracking most commonly occurs at the head-to-shell weld below the water level in the storage compartment. However, it may also occur above the water level and at longitudinal welds. Because cracks can develop to the point of equipment failure, they represent a potential safety hazard requiring periodic equipment inspection and, when warranted, repair or

replacement. Wet fluorescent magnetic particle testing is recommended for identification of cracks.

The mechanism of most deaerator cracking has been identified as environmentally assisted fatigue cracking. Although the exact causes are not known, steps can be taken to minimize the potential for cracking (e.g., stress-relieving of welds and minimization of thermal and mechanical stress during operation). In addition, water chemistry should be designed to minimize corrosion.

Feedwater line erosion

High-velocity water and especially water/steam mixtures cause erosion in feedwater systems. The most commonly encountered erosion problems occur at the hairpin bends in steaming economizers. Here, the mixture of steam and water thins the elbows, leaving a characteristic reverse horseshoe imprint.

Similar problems can be encountered in feedwater lines where high velocities create the familiar thinning pattern. These problems can occur even at moderate average flow velocities when a sequence of bends causes a significant increase in local velocity.

In order to mitigate erosion problems, it is helpful to maintain water chemistry conditions that form the most tenacious oxide layer. However, the problems cannot be completely resolved without design or operational changes.

Economizer tubes

Water tube economizers are often subject to the serious damage of oxygen pitting. The most severe damage occurs at the economizer inlet and, when present, at the tube welds seams. Where economizers are installed, effective deaerating heater operation is absolutely essential. The application of a fast-acting oxygen scavenger, such as catalyzed sodium sulfite, also helps protect this vital part of the boiler.

While oxygen pitting is the most common form of waterside corrosion that causes economizer tube failures, caustic soda has occasionally accumulated under deposits and caused caustic gouging. Usually, this type of attack develops in an area of an economizer where steam generation is taking place beneath a deposit and free caustic soda is present in the feedwater. The best solution to this problem is improved treatment that will eliminate the deposition.

Other common causes of economizer failure include fatigue cracking at the rolled tube ends and fireside corrosion caused by the condensation of acid from the boiler flue gas.

Failures due to overheating

When tube failures occur due to overheating and plastic flow (conditions commonly associated with deposits), the cause is usually identified by the deposits which remain, as shown in Figure 14-2. An accurate analysis of the deposits indicates the source of the problem and the steps needed for correction. Metallographic analyses are useful, at times, in confirming whether a short- or long-term exposure to overheating conditions existed prior to failure. Such analyses

are helpful also when metal quality or manufacturing defects are suspected, although these factors are significant only in isolated instances.

When tube failures occur due to overheating, a careful examination of the failed tube section reveals whether the failure is due to rapid escalation in tube wall temperature or a long-term, gradual build up of deposit. When conditions cause a rapid elevation in metal temperature to 1600°F or above, plastic flow conditions are reached and a violent rupture occurs. Ruptures characterized by thin, sharp edges are identified as "thin-lipped" bursts.

Violent bursts of the thin-lipped variety occur when water circulation in the tube is interrupted by blockage or by circulation failure caused by low water levels. In some steam drum designs, water level is extremely critical because the baffling may isolate a generating section of the boiler when the steam drum water level falls below a certain point.

Thin-lipped bursts also occur in superheater tubes when steam flow is insufficient, when deposits restrict flow, or when tubes are blocked by water due to a rapid firing rate during boiler start-up.

Interruptions in flow do not always result in rapid failure. Depending on the metal temperature reached, the tube can be damaged by corrosive or thinning mechanisms over a long period of time before bulges or blisters or outright failures develop. In such instances, a metallurgical examination in addition to an examination of the contributing mechanical factors can be helpful in identifying the source of the problem.

A long-term scaling condition which will lead to a tube leak is usually indicated by a wrinkled, bulged external surface and a final thick-lipped fissure or opening. This appearance is indicative of long-term creep failure created by repetitive scale formation, causing overheating and swelling of the tube surface in the form of a bulge or blister. The scale, in such instances, tends to crack off; water contacts the metal and cools it until further scaling repeats the process. The iron oxide coating on the external surface cracks during the process giving rise to the characteristic longitudinal creep cracks.

Failures due to Corrosion

Stress corrosion cracking

Various corrosion mechanisms contribute to boiler tube failure. Stress corrosion may result in either inter-crystalline cracking of carbon steel. It is caused by a combination of metal stress and the presence of a corrosive. A metallurgical examination of the failed area is required to confirm the specific type of cracking. Once this is determined, proper corrective action can be taken.

Caustic embrittlement

Caustic embrittlement, a specific form of stress corrosion, results in the inter-crystalline cracking of steel. Inter-crystalline cracking results only when all of the following are present: specific conditions of stress, a mechanism for concentration such as leakage, and free NaOH in the boiler water. Therefore, boiler tubes usually fail from caustic embrittlement at points where tubes are rolled into sheets, drums, or headers.

The possibility of embrittlement may not be ignored even when the boiler is of an all-welded design. Cracked welds or tube-end leakage can provide the mechanism by which drum metal may be adversely affected. When free caustic is present, embrittlement is possible.

An embrittlement detector may be used to determine whether or not boiler water has embrittling tendencies. The device, illustrated in Figure 14-4, was developed by the United States Bureau of Mines. If boiler water possesses embrittling characteristics, steps must be taken to protect the boiler from embrittlement-related failure.

Sodium nitrate is the standard treatment for inhibiting embrittlement in boilers operating at low pressures. The ratios of sodium nitrate to sodium hydroxide in the boiler water recommended by the Bureau of Mines depend on the boiler operating pressure. These ratios are as follows:

Pressure, psi NaNO3 /NaOH Ratio

Up to 250 0.20

Up to 400 0.25

Up to 1000 0.40-0.50

The formula for calculating the sodium nitrate/sodium hydroxide ratio in the boiler water is:

NaNO3

=

ppm nitrate (as NO3 -)

NaOH ppm M alkalinity - ppm phosphate (as CaCO3 ) (as PO4 3-)

At pressures above 900 psig, coordinated phosphate/pH control is the usual internal treatment. When properly administered, this treatment method precludes the development of high concentrations of caustic, eliminating the potential for caustic embrittlement.

Fatigue and Corrosion Fatigue

Transgranular cracking primarily due to cyclic stress is the most common form of cracking encountered in industrial boilers. In order to determine the cause of a transgranular failure, it is necessary to study both the design and the operating conditions of the boiler. Straight tube, shell-and-tube waste heat boilers frequently develop tube and tube sheet failures due to the imposition of unequal stresses. A primary cause of this is the uneven distribution of hot gases across the face of the tube sheet. The tubes involved tend to come loose, creating leakage problems. Even when the tubes are securely welded, imposed stresses can cause transverse cracking of the tubes.

Any design feature that allows steam pockets to form within a unit can cause cyclic overheating and quenching. This can lead to transverse cracking of tubes and, occasionally, shells. Such cracking always appears in the area of greatest stress and results in cracks.

Some inter-crystalline cracking may develop in this type of failure whether or not free NaOH is present. However, the predominant type of cracking is across the grain structure of the metal. Because it is mechanically induced, the cracking occurs irrespective of boiler water chemical concentrations. The cracks are often accompanied by a number of pits adjacent to or in line with the cracking- another specific indicator of the mechanical stresses imposed. Any corrosives present contribute to the formation of the pits. The normal reaction between iron and water is sufficient to cause pitting at breaks in the thin oxide film formed on freshly exposed surfaces under stress.

Stress-induced corrosion

Certain portions of the boiler can be very susceptible to corrosion as a result of stress from mechanical forces applied during the manufacturing and fabrication processes. Damage is commonly visible in stressed components, such as rolled tube ends, threaded bolts, and cyclone separators. However, corrosion can also occur at weld attachments throughout the boiler (see Figure 14-5) and can remain undetected until failure occurs. Regular inspection for evidence of corrosion, particularly in the wind box area of Kraft recovery boilers, is recommended because of the potential for an explosion caused by a tube leak.

The potential for stress-induced corrosion can be reduced if the following factors are minimized: stresses developed in the boiler components, the number of thermal cycles, and the number of boiler chemical cleanings. In addition, it is necessary to maintain proper water chemistry control during operation and to provide protection from corrosion during shutdowns.

Dissolved oxygen corrosion

Dissolved oxygen corrosion is a constant threat to feedwater heater, economizer, and boiler tube integrity. As deposit control treatment methods have improved, the need for effective control of oxygen has become increasingly important.

The first serious emphasis on oxygen control began when phosphate-based treatments were introduced to replace the soda ash treatments common before that time. The dense, hard calcium carbonate scale which developed with the soda ash treatments protected tubes and

drums from serious oxygen corrosion. With the application of phosphate treatment, the tube and drum surfaces were cleaner. Therefore, more of the surface area was exposed to corrosives in the water. This spurred the use of improved open feedwater heaters to remove most of the oxygen prior to the entrance of water into the boiler. Today, most plants are equipped with efficiently operated deaerating heaters. The use of oxygen scavengers, such as catalyzed sodium sulphite, hydrazine, and organic scavengers, is also standard practice.

The use of chelant treatments and demineralised water has improved the cleanliness of boiler heat transfer surfaces to such an extent that essentially bare-metal conditions are common. Only a thin, protective, magnetic oxide film remains in such instances. As a result, oxygen control has become even more essential today. The use of catalyzed sulphite, where applicable, is a standard recommendation in chelant applications.

The control of downtime corrosion has become increasingly important in recent years to prevent or inhibit pitting failures. Often, cold water that has not been deaerated is used for rapid cooling or start-up of a boiler. This is a risky operating practice, usually chosen for economical reasons. Severe pitting can occur in such instances, especially in boilers that have been maintained in a deposit-free condition. Therefore, it is usually more economical to maintain clean heat transfer surfaces and eliminate the use of cold water containing dissolved oxygen during cool-down and start-up periods. This practice can result in fuel savings and improved boiler reliability.

Chelant corrosion

During the early years of chelant use, nearly all internal boiler corrosion problems were labeled "chelant corrosion." However, other corrosives such as oxygen, carbon dioxide, caustic, acid, copper plating, and water are still common causes of boiler corrosion. In addition, mechanical conditions leading to caustic embrittlement, film boiling, and steam blanketing are even more prevalent today than ever, as a result of increasing heat transfer rates and the more compact design of steam generators. Chelant corrosion, or chelant attack, has some specific characteristics, and develops only under certain conditions.

Chelant corrosion of boiler metal occurs only when excess concentration of the sodium salt is maintained over a period of time. The attack is of a dissolving or thinning type-not pitting-and is concentrated in areas of stress within the boiler. It causes thinning of rolled tube ends, threaded members, baffle edges, and similar parts of stressed, unrelieved areas. Normally, annealed tubes and drum surfaces are not attacked. When tube thinning occurs in a chelant-treated boiler, evidence of steam blanketing and/or film boiling is sometimes present. In such instances, failure occurs regardless of the type of internal treatment used.

Pitting is often thought to be a result of chelant attack. However, pitting of carbon steel boiler tubes is almost always due to the presence of uncontrolled oxygen or acid. Infrequently, copper plating (usually the result of an improper acid cleaning operation) may lead to pitting problems.

Caustic attack

Caustic attack (or caustic corrosion), as differentiated from caustic embrittlement, is encountered in boilers with dematerialized water and most often occurs in phosphate-treated boilers where tube deposits form, particularly at high heat input or poor circulation areas. Deposits of a porous nature allow boiler water to permeate the deposits, causing a continuous buildup of boiler water solids between the metal and the deposits.

Because caustic soda does not crystallize under such circumstances, caustic concentration in the trapped liquid can reach 10,000 ppm or more. Complex caustic-ferrite compounds are formed when the caustic dissolves the protective film of magnetic oxide. Water in contact with iron attempts to restore the protective film of magnetite (Fe3O4). As long as the high caustic concentrations remain, this destructive process causes a continuous loss of metal.

The thinning caused by caustic attack assumes irregular patterns and is often referred to acoustic gouging. When deposits are removed from the tube surface during examination, the characteristic gouges are very evident, along with the white salts deposit which usually outlines the edges of the original deposition area. The whitish deposit is sodium carbonate, the residue of caustic soda reacting with carbon dioxide in the air.

Inspections of boilers with caustic attack often show excessive accumulations of magnetic oxide in low flow areas of drums and headers. This is caused by the flaking off, during operation, of deposits under which the complex caustic-ferrite material has formed. When contacted and diluted by boiler water, this unstable complex immediately reverts to free caustic and magnetic oxide. The suspended and released magnetic oxide moves to and accumulates in low flow or high heat flux areas of the boiler.

While caustic attack is sometimes referred to as caustic pitting, the attack physically appears as irregular gouging or thinning and should not be confused with the concentrated, localized pit penetration representative of oxygen or acid attack.

Steam blanketing

A number of conditions permit stratified flow of steam and water in a given tube, which usually occurs in a low heat input zone of the boiler. This problem is influenced by the angle of the affected tubes, along with the actual load maintained on the boiler. Stratification occurs when, for any reason, velocity is not sufficient to maintain turbulence or thorough mixing of water and steam during passage through the tubes. Stratification most commonly occurs in sloped tubes located away from the radiant heat zone of the boiler, where heat input is low and positive circulation in the tubes may be lacking.

Examination of the affected tubes usually reveals a prominent water line with general thinning in the top area of the tube or crown. In rare instances, the bottom of the tube is thinned. When the boiler water contains caustic, high concentrations accumulate and lead to caustic corrosion and gouging under the deposits that accumulate at the water line.

In certain instances, stratification may occur together with input of heat to the top or crown of the tube. This creates a high degree of superheat in the steam blanket. Direct reaction of steam

with the hot steel develops if the metal temperature reaches 750°F or higher. Corrosion of the steel will proceed under such circumstances whether or not caustic is present. When there is doubt about the exact cause, a metallographic analysis will show if abnormal temperature excursions contributed to the problem. Deposits usually found under such circumstances are composed primarily of magnetic iron oxide (Fe3O4). Hydrogen is also formed as a result of the reaction and is released with the steam.

A somewhat unusual problem related to circulation and heat input problems has been encountered in roof tubes. These tubes are usually designed to pick up heat on the bottom side only. Problems generally develop when the tubes sag or break away from the roof, causing exposure of the entire surface of the tube to the hot gases. The overheating that usually develops, along with the internal pressure, causes a gradual enlargement of the tube, sometimes quite uniformly. Failure occurs when the expanded tube can no longer withstand the combined effects of the thermal stress and internal pressure.

Superheater tubes often show the same swelling or enlargement effect. In such instances, steam flow has been restricted for some reason, leading to overheating and eventually to failure.

Acidic attack

Acid attack of boiler tubes and drums is usually in the form of general thinning of all surfaces. This results in a visually irregular surface appearance, as shown in Figure 14-8. Smooth surfaces appear at areas of flow where the attack has been intensified. In severe occurrences, other components, such as baffling, nuts and bolts, and other stressed areas, may be badly damaged or destroyed, leaving no doubt as to the source of the problem.

Severe instances of acid attack can usually be traced to either an unsatisfactory acid cleaning operation or process contamination. Some industrial plants encounter periodic returned condensate contamination, which eliminates boiler water alkalinity. Occasionally, regeneration acid from an ion exchange process is discharged accidentally into the boiler feedwater system. Cooling water contamination of condensate can depress boiler water pH and cause severe deposition and pitting in areas of high heat flux. Damage can be quite severe if immediate steps are not taken to neutralize the acid.

In the case of industrial process contamination, it is possible for organic contaminants to decompose under boiler temperature and pressure to form organic acids. Sugar is an excellent example of an organic which, when returned in a large quantity, can cause rapid loss of boiler water alkalinity and reduce pH of the boiler water to 4.3 and lower. Most sugar refining plants maintain standby pumping systems, to add caustic soda to neutralize these acids as quickly as possible.

Corrosion due to copper

Pitting of boiler drums and tube banks has been encountered due to metallic copper deposits, formed during acid cleaning procedures which do not completely compensate for the amount of copper oxides in the original deposits. Dissolved copper may be plated out on freshly cleaned

steel surfaces, eventually establishing anodic corrosion areas and forming pits very similar in form and appearance to those caused by oxygen.

In such instances, metallic copper plating is quite evident. In most cases, it is localized in certain tube banks, giving rise to random pitting in those particular areas. Whenever deposits are found containing large quantities of copper or its oxide, special precautions are required to prevent the plating out of copper during cleaning operations.

Copper deposits and temperatures over 1600°F can cause liquid metal embrittlement. Weld repair of a tube containing copper deposits leads to the failure.

Specification of our Project, Biogas Boiler

Boiler parts:

Economizer, Steam Drum, Mud Drum, Grate, Burner(s) , Headers , Air Preheater, FD Fan, ID

Fan, Super Heater, Furnace Area Tubes, Baffles, Evaporation Tubes, Secondary Air Fan and

Chimney.

Steam and Mud drum:

Diameter= 250mm, Length= 915mm

Fuel consumption:

0.55 cubic meter biogas per hour

Total steam generation capacity= 9.5304 kg/hr

Pressure= 10 bar

Dimensions (size) = (1792×1700×1000) mm

Weight = 85-90 kg

2D Drawings, Designed on Autocad

3D MODEL, Designed on Pro E

Complete Fabricated Model

Calculation of the Surface Area of the Boiler

Boiler: Inner Length = 360+50+40 = 450 mm Area= (3.4)*(19)(450)/(106) = 0.0268 m2 Outer Length= 400+60+50 = 510 mm Area = (3.14)(19)(510)/(106) = 0.03 m2 Total Area = Inner area + Outer area = 0.05685 m2

Economizer: Total Length= (188x4) + (330x2) + (50x5) = 1662 mm Are = (1662)*(3.14)(19)/(106) = 0.1 m2

Air Pre-heater: Length = (400)*(14) = 5600 mm Area = (5600)*(3.14)*(19)/(106) = 0.03 m2

Side Panel: Length = 750 mm Diameter = 19 mm Area = (3.14)*(19)*(750)/(106) = 0.045 m2

Area of Both side panels = (0.045)*2 = 0.09 m2

Front Header: Length = 415+585= 1000 mm Area = (3.14)(19)(1000)/(106) = 0.06 m2

Rear Header: Length = 740+162+100= 1002 mm Area = (3.14)*(19)*(1002)/(106) = 0.06 m2

Total furnace area = 0.09+0.06+0.06 = 0.21 m2

Total heating area = 0.05685+0.21 = 0.26685 m2

Recommended that If heating area is 28 m2, capacity is 1 ton/hr Therefore, 1 m2= 1/28 0.26685 m2 = (1/28)(0.26685) = 9.5304 Kg/hr

Metallurgy of Boiler

Following grades are used in boiler parts manufacturing. These are mentioned below according to

international material designation systems.

Ss-304

Ss-316

Ss-321

Inlet and outlet pipes: 316 L is used preferably due to its corrosion resistance

Reinforcement rings: If internal then material should be especially corrosion resistant like the internal

lining but if external then sometime A106 with additional welding characteristics may be used.

Tubes: They should be highly thermal resistance as they have to bear much higher temperatures. These

are made from 25:22:2 but mostly with INCOLOY 800 & INCOLOY 800 H and 23 - 23 NIUBIUM.

PART NAME RATIOS

Shell A 516 Gr.60 (if lining is used)

Heads A 516 Gr.70(if lining is used)

Weep holes 25:22:2

Steam drum SS-347 / SS-309

Tray supporting Ring 25:22:2

Lining material inside the

casing A 240 TP 316 L Modified 25:22:2

Inlet and outlet pipes 316 L

Tubes 25:22:2 & 23 - 23 NIUBIUM

PART NAME CODE

Centric Reducer

A213

Tubes A210

Steam Drum A213

Mud Drum A210

Super Heater A213

In Tie Group (Boiler manufacturers and suppliers in Lahore), following materials are mostly used.

A 210 is used for low temperature

while A213 for higher temperature.

If we ponder upon the basics of the below bottom diagram, it will be helpful for us to understand the

true meaning of the classification of stainless steel which has the property to resist corrosion but every

composition has its own characteristics according to the composition present in it .

Tubes A210

Centric reducer A213

STEAM DRUMS A213

MUD DRUM A210

SUPERHEATER A213

SS – 30418 Cr – 8 Ni

SS - 316

SS - 317

ADD Mo (2%)

FOR PITTING RESISTANCE

ADD MORE Mo (4%)

FOR PITTING RESISTANCE

ADD Nb + Ta

TO REDUCE SENSITIZATION

SS - 347

ADD Ti

TO REDUCE SENSITIZATIONSS - 321

LOWER C

SS - 317L

SS - 316L

SS - 304L

ADD Cr & NiSTRENGTH & CORROSION RESIST.

SS – 310SS - 309

REDUCE NiTO REDUCE AUSTENITIC STRUCTURE

DUPLEX STEEL

NO Ni

FERRITICSTEEL

INCREASE CLOWER Cr

MARTENSITICSTEEL

Design Analysis of Biogas Plant

Introduction

Decaying biomass and animal wastes are broken down naturally to elementary nutrients and

soil humus by decomposer organisms, fungi and bacteria. The processes are favored by wet,

warm and dark conditions. The final stages are accomplished by many different species of

bacteria classified as either aerobic or anaerobic.

What is biogas?

Biogas originates from bacteria in the process of bio-degradation of organic material under anaerobic (without air) conditions. The natural generation of biogas is an important part of the biogeochemical carbon cycle. Methanogens (methane producing bacteria) are the last link in a chain of micro-organisms which degrade organic material and return the decomposition products to the environment. In this process biogas is generated, a source of renewable energy. The methane content and hence the calorific value is higher the longer the digestion process. The methane content falls to as little as 50% if retention time is short. If the methane content is considerably below 50 %, biogas is no longer combustible. The first gas from a newly filled biogas plant contains too little methane. The methane content depends on the digestion temperature. Low digestion temperatures give high methane content, but less gas is then produced.

Properties & Composition and of biogas

Like those of any pure gas, the characteristic properties of biogas are pressure and temperature-dependent. They are also affected by the moisture content. The factors of main interest are:

change in volume as a function of temperature and pressure, change in calorific value as a function of temperature, pressure and water-vapor

content, and Change in water-vapor content as a function of temperature and pressure.

The calorific value of biogas is about 6 kWh/m3 - this corresponds to about half a liter of diesel oil. The net calorific value depends on the efficiency of the burners or appliances. Methane is the valuable component under the aspect of using biogas as a fuel.

Chemical composition

Different sources of production lead to different specific compositions. The presence of H2S,

CO2 and water make biogas very corrosive and require the use of adapted materials. The

composition of a gas issued from a digester depends on the substrate of its organic matter load,

and the feeding rate of the digester.

Components Household

waste

Wastewater

treatment plants

sludge

Agricultural

wastes Waste of agrifood industry

CH4 % vol 50-60 60-75 60-75 68

CO2 % vol 38-34 33-19 33-19 26

N2 % vol 5-0 1-0 1-0 -

O2 % vol 1-0 < 0,5 < 0,5 -

H2O % vol 6 (à 40 ° C) 6 (à 40 ° C) 6 (à 40 ° C) 6 (à 40 ° C)

Total % vol 100 100 100 100

H2S mg/m3 100 – 900 1000 – 4000 3000 – 10 000 400

NH3 mg/m3 - - 50 - 100 -

Physical characteristics

According to its composition, biogas presents characteristics interesting to compare with

natural gas and propane. Biogas is a gas appreciably lighter than air; it produces twice as fewer

calories by combustion with equal volume of natural gas.

Types of gas Biogas 1

Household waste

Biogas 2

Agrifood industry Natural gas

Density(kg/m3) 0.93 0.85 0.57

Biogas Plant & its Components

Types of Biogas Plants

The three main types of simple biogas plants are:

Continuous plant

Continuous plants are fed and emptied continuously. They empty automatically through the overflow whenever new material is filled in. Therefore, the substrate must be fluid and homogeneous. Continuous plants are suitable for rural households as the necessary work fits well into the daily routine. Gas production is constant.

Batch plant

Batch type biogas plants are appropriate where daily supplies of raw waste materials are

difficult to be obtained. A batch loaded digester is filled to capacity sealed and given sufficient

retention time in the digester. After completion of the digestion, the residue is emptied and

filled again. Gas production is uneven because bacterial digestion starts slowly, peaks and then

tapers off with growing consumption of volatile solids

A Biogas Plant consists of the following components:

1. Gas Holder

It is an airproof steel container, which cuts off air to the digester and collects the gas thus generated. The top part of a plant (the gas space) must be gas-tight. Concrete, masonry and cement rendering are not gas-tight. The gas space must therefore be painted with a gas-tight layer (e.g. ’Water-proofer’, Latex or synthetic paints). A possibility to reduce the risk of cracking of the gas-holder consists in the construction of a weak-ring in the masonry of the digester. This "ring" is a flexible joint between the lower (water-proof) and the upper (gas-proof) part of the hemispherical structure. It prevents cracks that develop due to the hydrostatic pressure in the lower parts to move into the upper parts of the gas-holder.

2. Mixing pit

In the mixing pit, the substrate is diluted with water and agitated to yield homogeneous slurry.

3. Inlet and Outlet:

The inlet (feed) and outlet (discharge) pipes lead straight into the digester at a steep angle. Both the inlet pipe and the outlet pipe must be freely accessible and straight, so that a rod can

be pushed through to eliminate obstructions. The inlet pipe ends higher than the outlet pipe in the digester in order to promote more uniform through flow.

4. Fermentation Tank(Digester):

It can be best described as a cylindrical or cube-shaped tanker which is waterproof and comes with as inlet into which the raw-materials are introduced in the form of liquid.

Balloon Digester Plant Floating-drum Digester Plant Fixed dome Digester Plant

Design Analysis of Continuous Fixed Dome Biogas Plant

As a biogas unit is an expensive investment, it should not be erected as a temporary set-up. Therefore, determining siting criteria for the stable and the biogas plant are the important initial steps of planning.

Selection of design of the plant Typical design criteria are:

Climate

Temperature

Soil conditions

Substrate for digester

Building material

Design Parameters At this point it is important to note that much of the design details will be refined through

greater experience and empirical data. The following instructions are only a suggestion of

design techniques brought together from a number of internet articles.

Here, we propose a design for a fixed dome biogas plant keeping in mind various design

parameters according to GTZ* for the production of required biogas cum/day.

Digester (including gas holder)

The size of the digester largely depends on the amount of waste to be added. Digester shape

should enable a minimum surface area to volume ratio to be reached to reduce heat loss and

construction costs. Hemispherical digesters with a conical floor often work best (camartec

design). To calculate the required digester volume (VD) use Equation 1 below

VD = Vs x RT (Eq. 1)

Where:

VD = Volume of the digester (m3)

Vs = Volume of slurry added per day (m3/day)

RT = Retention time required (days)

It is important to know the average waste excreted by living organisms per day e.g a cow

produce 10kg dung per day, so by multiplying by the no. of animals available and retention time

(time to keep the slurry inside the digester), we can calculate the digester volume according to

our requirement.

Deutsche Gesellschaft für Technische Zusammenarbeit (GTZ) GmbH

The volume of the gas holder VG depends on the relative rates of gas production and

consumption. To calculate the daily gas production (G) Equation 2

G = Vs x Gy (Eq. 2)

Where:

G = Daily gas production rate (m3/day)

Gy = Gas yield per kg of excreta per day (m3/kg/day)

The gas holder must be designed to cover the peak consumption rate. Say there is a time, when

max. gas consumption (VG1) and may be sometime, no gas is consumed(VG2) but the process

of digestion would continuously occur. The larger of the two volumes should be used to specify

the gas holder volume with an additional 20% safety margin. The following equations should be

used to calculate VG1 and VG2:

VG1 = Gcmax x Tcmax (Eq. 4)

VG2 = G x Tczero (Eq. 5)

Where:

VG1 = Gas holder volume 1 (m3)

VG2 = Gas holder volume 2 (m3)

Gcmax = Maximum rate of gas consumption (m3/day)

Tcmax = Maximum time of gas consumption (days)

G = Daily gas production rate (m3/day)

Tczero = Maximum time of zero gas consumption (days)

The final gas holder volume can then be calculated using the largest of VG1 and VG2 with

Equation 6 below:

VG = VGmax + (VGmax x 0.2) (Eq. 6)

According to GTZ (from experience) the ratio of digester volume to gas holder volume (i.e.

VD:VG ) usually lies in the range 3:1 to 10:1.

Since the hemispherical design of the fixed-dome plant combines the digester volume (VD) with

the gas holder volume (VG) the total volume of the hemispherical dome (VH) can then be

calculated:

VH = VD + VG (Eq. 7)

The final part of the calculation is to determine the required radius (r) of the hemisphere. This

can be done using Equation 8:

r=[3Vh/2]1/3 (Eq. 8)

Any calculated values are only be taken as an estimation – there are so many variables in the

inputs (HRT, waste addition rate, gas consumption rate, climate, etc) that the value should be

used with caution.

Calculation of the Biogas Plant

Requirement of fuel to run our designed boiler is 0.55 m3 of biogas per hour. This gives us a daily value

of 13.2 m3 of biogas (Per day consumption of biogas = G = 0.55×24= 13.2 m3/day). This shows that we

have to produce 13.2 m3 of biogas to fulfill the requirement of the equipment. Now, how much quantity of slurry is needed to produce that much cubic meter of biogas? 1m3of slurry will produce 35 m3 of biogas

Applying unitary method:

1 m3of biogas will be produced by 1/35 m3 of slurry

13.2 m3of biogas will be produced by 13.2/35 m3 of slurry, hence 0.4 m3 slurry is required to produce

13.2 m3 of biogas.

Calculations of volume of digester

VD= Volume of Digester (m3)

SD= daily slurry required (m3/day)

RT= Retention time (days)

VD=SD × RT

VD=0.4*85= 34 m3

(Say RT=85 days, for mesophillic digestion retention time is taken in a range of 100-20 days & the

temperature required for the process is 20 )

Vs = Active slurry volume in digester

Vs =2*G

Where; G=gas production rate m3/day=13.2 m3/day

=2*13.2= 26.4 m3

H= Height of cylindrical portion of the digester up to top edge of inlet/outlet opening

H=

H=2 m.

D= Diameter of the digester

VD=

→ D=4.6m

d= Slurry displacement inside digester

d=

=0.3 m

h= slurry displacement in the inlet/outlet tank

h=0.85-d

h=0.55 m

1. b= breath of inlet/ outlet tank

b=

b= 1.8 m

l= length of inlet/outlet tank

l=1.5×b

=2.7 m

dh= height of the dome

p=0.75 D2=15.87 m

q=-0.6

= –2.3 m

R=

= 150 m

A=

=2.37 m

B=

=-2.23 m

Hence, dh=A+B= 0.139 m

Displacement tank

There are a number of different options for the design (size, shape, etc) of the displacement

tank. The tank could be a fully buried hemispherical structure (much the same as but smaller

than the digester), a simple columnar tank or a large open drying bed. Available materials,

workforce skill level, safety and space are factors which need assessing before choosing a

design. The primary functions of the displacement tank are to provide a buffer for the pressure

of the gas inside the digester and to allow digested slurry to be removed.

The main parameters of the design are volume of tank and height of slurry overflow. The

required size largely depends on the fluctuation in gas volume/pressure over time (e.g. 1 day).

If the gas volume fluctuates a large amount then a large tank is required to prevent too much

slurry being lost through the overflow during times of high gas pressure (which will cause a low

pressure of the next batch/collection of gas). If the gas volume hardly fluctuates at all (e.g. rates

of gas production/use are the same) then in theory a displacement tank may not be needed at

all (this is unlikely).

According to GTZ the volume of the displacement tank should be roughly equal to that of the

gas holder however there is a lot of variance between designs since the shape of the

displacement tank can vary so much (from a simple self-contained tank with an overflow to a

large drying bed structure).

Design check-list

The slurry overflow outlet must be higher than the slurry bed/slurry distribution channel

(to prevent backwash into the digester).

The digester inlet must be at least 0.3m higher than the slurry overflow outlet.

The gas outlet must be situated as close to the top of the gas holder as possible and at

least 0.1m higher than the slurry overflow outlet (to prevent clogging with scum).

The generator should be located away from trees (where roots can interfere with the

structure) and 30m from water supplies (to avoid possible contamination).

The generator should not be built on top-of or be situated beneath a throughway for

heavy machinery.

The outlet pipe/channel of the digester is fully accessible from the manhole of the

displacement tank to enable unblocking.

Construction (Fixed-Demo Generator)

Well skilled masons (ideally those experienced in biogas generator construction) are required to

carry out the construction work since quality of construction is of paramount importance to the

efficiency of the generator.

Throughout the construction section, we have considered;

Concrete mixes will be specified using the ratio cement: sand: aggregate.

Mortar/plaster mixes will be specified using the ratio cement: lime: sand.

Digester (including gas holder)

“A digester is a huge vessel where chemical or biological reactions are carried out. These are

used in different types of process industries.”

For biogas production, digester can be aerobic or anaerobic.

Aerobic decomposition involves oxygen while anaerobic don’t.

Aerobic decomposition (fermentation) will produce carbon dioxide, ammonia and some other gases in small quantities, heat in large quantities and a final product that can be used as a fertilizer. Anaerobic decomposition will produce methane, carbon dioxide, some hydrogen and other gases in traces, very little heat and a final product with a higher nitrogen content than is produced by aerobic fermentation.

Field Extrusion

Before any construction goes underway a reference line (running along the ground (or at a

known height) above the intended site from inlet to outlet ideally) must be erected. This will be

used throughout the construction to measure depths of essential features of the generator to

ensure that it is horizontal (using spirit/hose pipe level) and very well pegged in. Make a mark

of this level on any permanent structure nearby also. Check the design checklist to ensure

heights/depths of the various inlets/outlets are known.

Excavation of the area must be conducted to ensure the digester is totally buried with the neck

protruding above ground level. The depth of the floor (and foundation ring), the radius of the

hemisphere and the height of the neck should be taken into account. Stone or sand packing

may be required on the digester floor area if the soil is soft. A peg/large nail should be driven

deep into the centre of the digester floor area to act as a centre point for the entire digester –

ensure the height is correct according to the reference line. This will be used with a radius

stick/string (length of hemisphere radius (r)) to build the hemisphere and preserve its shape. A

foundation ring (centered on the digester radius) should be dug around the circumference of

the digester and filled early in the day with a strong concrete (1:2:4).

Construction

In the wet concrete the first row of bricks for the digester wall should be laid (using the radius

stick/string to set the radius).

Bricks should be soaked in water and laid on a 1cm thick bed of cement plaster/mortar

(1:0.25:4) to create the digester walls. As they are laid ensure as best as possible to angle the

brick so that the top surface lies at the same angle as the radius stick/string (this will lead to a

uniform hemispherical shape). A nail can be driven through radius stick to provide a

perpendicular square for the bricks to be place against. Vertical joints between the bricks

should be ‘squeezed’ and offset.

After the first few rows of bricks have been laid the first 2 or 3 rows of bricks should be

reinforced with lean concrete (1:3:9) from the outside. The concrete floor of the digester can

also be laid. A 3cm cement screed/mortar (1:0.25:4) may suffice in the case of laterite or

volcanic soil. In the case of unstable soils or high water table a 30cm thick layer of rocks

covered by 5-10cm of concrete should be applied beneath the cement screed. A flat or slightly

bowled digester floor can be constructed (bowled design is helpful for the collection of solid

and better stress distribution). Concrete can be placed in the inside of the digester where the

wall meets the floor to create a smooth radius preventing solid build up and to enable easy

cleaning.

Inlet and outlet pipes/channels must be laid within the brick layers (any knocking through of

holes will weaken the structure) and should be situated opposite each other. Pipes should be of

substantial diameter (20-30cm) to prevent clogging and should be held in place securely with a

collar of cement plaster/mortar (1:0.25:4) on the inside and outside of the wall. Alternatively

the outlet can be built as a stepped channel. The angle of the inlet pipe should be as high as

possible to prevent blocking whilst ensuring that any inlet tank is not constructed above the

digester itself.

The opening of the outlet pipe/channel starts low down in the generator so as to only remove

well digested slurry. It should not be placed too close to the floor however since blocking of the

pipe may occur – any solids in the slurry will collect on the floor. From the digester wall the

outlet pipe/channel continues to the floor of the displacement tank. When the displacement

tank is built access straight down the outlet pipe/channel should be kept clear to enable

unblocking with a long pole. The height at which the inlet pipe protrudes into the digester

defines the slurry holding volume (VD) and the gas holding volume (VG) (below and above the

inlet respectively). The height (h) of the inlet from the digester floor can be approximated by

h=0.6r.

After the inlet/outlet pipes have been laid the outside of the digester walls should be plastered.

Only sieved and washed river sand should be used for the cement plaster/mortar mix in the

ratio 1:0.25:4. The 2cm thick layer of plaster should be left until completely dry (1 day) before

soil (in compacted layers 30cm thick) can be used to back fill up to the current level of brick

work.

Maintenance Tasks

Daily Activities

Cleaning/unblocking of latrine(s) – water with no added detergents should be used to

clean the pipes regularly (detergents can kill the methane producing bacteria). Soap

water, from time to time, can be tolerated.

Agitate the digester contents.

Check the appearance and odour of the digested slurry – if the slurry is not fully

digested and odour free (to an extent) a reduction in rate of waste addition may be

required to increase the HRT or the solid: liquid ratio of the waste may require

adjusting. If the pH of the slurry drops this can be remedied by the addition of lime or

cow dung.

Weekly/Monthly activities:

Clean and inspect the gas system and appliances – check for leaks in piping with soapy

water. Ensure appliances are working correctly (with efficient flames, etc) and

thoroughly cleaned.

Inspect the water trap (if present) and empty excess water (if tap style trap is used).

Inspect the water bath in the digester neck – for gas leaks through the clay and water

levels.

Clean the displacement tank – to prevent solids build up and thus restriction of slurry.

The slurry overflow pipe/channel should be kept clear and checked regularly. The

overflow should direct slurry away from the outlet effectively.

Unblocking of inlet and outlet pipes.

Annual activities (should be conducted by experienced biogas engineers)

Remove solid sludge from digester depending on solid sludge build-up. An assessment

should be made as to the level of solid sludge collected in the bottom of the generator

(test the substrate with a pole/dipstick and test consistency of the overflow slurry). If

the amount of solid sludge is deemed too high (blockages are common, overflow slurry

does not flow well, etc) then the digester should be emptied. The frequency of emptying

depends on size of the digester, quality of inlet waste, diet, generator design, etc and

can vary greatly between generators (some generators are designed not to be emptied

before 5 years of use). Any sludge removed can be dried or composted and used as

fertilizer as detailed in Table 7.

Clean the displacement tank.

Pressure tests the gas valves and fittings.

Safety Analysis

Biogas is combustible and explosive. A number of safety measures must be taken and clear

education and warning as to the dangers must be given.

Safety factors to consider include:

Location – the generator should not be housed underneath or within any other

permanent structure

Biogas piping system should be protected, clear and obvious (whether underground or

above ground)

Careful installation and regular inspection is mandatory

Regular inspection of gas appliances

Good ventilation of rooms containing gas appliances without pilot lights

Installation of safety stop valves (at the plant and on each appliance) and venting valves

(at the plant)

Educational factors to consider include:

Users must be aware of the dangerous nature of biogas when formed in the explosive

mix of Oxygen (air) and biogas

Always close the gas and safety valves of each appliance properly and after each use

Close the generators safety valves over night or when the generator is unattended

Quick detection of gas leaks by watching for the conspicuous odor of unburned biogas.

Global Environmental Benefits of Biogas Technology

The greenhouse effect is caused by gases in the atmosphere (mainly carbon dioxide, CO2) which allow the sun’s short wave radiation to reach the earth surface while they absorb, to a large degree, the long wave heat radiation from the earth’s surface and from the atmosphere. Due to the "natural greenhouse effect" of the earth’s atmosphere the average temperature on earth is 15°C and not minus 18°C.

The increase of the so called greenhouse gases which also include methane, ozone, nitrous oxide, etc. cause a rise of the earth's temperature. The World Bank Group expects a rise in sea levels until the year 2050 of up to 50 cm. Flooding, erosion of the coasts, stalinization of ground water and loss of land etc.

Until now, instruments to reduce the greenhouse effect considered primarily the reduction of CO2-emissions, due to their high proportion in the atmosphere. Though other greenhouse gases appear to be only a small portion of the atmosphere, they cause much more harm to the climate.

Methane is not only the second most important greenhouse gas (it contributes with 20% to the effect while carbon dioxide causes 62%), it has also a 25 times higher global warming potential compared with carbon dioxide in a time horizon of 100 years. The Bio gas plant effectively reduces the amount of methane directly released into the atmosphere, by trapping it and facilitating its use as a green fuel. After burning, methane only releases harmless gases in air. Given below are the figures relating to this:

With anaerobic digestion, a renewable source of energy is captured, which has an

important climatic twin effect:

1. The use of renewable energy reduces the CO2-emissions through a reduction of the

demand for fossil fuels.

2. At the same time, by capturing uncontrolled methane emissions, the second most

important greenhouse gas is reduced:

1m3 cattle manure = 22.5 m3 biogas = 146 kWh gross = 36 kg CO2 Emission

Health benefits of biogas technology Biogas can have significant health benefits. It reduces water pollution by using feedstock that would end up in rivers and lakes. It reduces the annoyance caused by odor from manure.

According to the Integrated Environmental Impact Analysis carried out by BSP** has revealed that problems like respiratory illness, eye infection, asthma and lung problems have decreased after installing a biogas plant. (Tables 1 & 2)

The following are the principal organisms killed in biogas plants:

Typhoid Paratyphoid, Cholera and dysentery bacteria (in one or two weeks), Hookworm and bilharzia (in three weeks). Tapeworm and roundworm die completely when the fermented slurry is dried in

the sun. Table: Health benefits of biogas

Disease Problems in the past (HHs)* Present status of HHs

Yes No I m p r o v e d Remained

same

Eye Infection 72 18 69 3

Cases of burning 29 71 28 1

Lung problem 38 62 33 5

Respiratory problems

42 58 34 8

Asthma 11 89 9 2

Dizziness/headache 27 93 16 11

Intestinal;/diarrhea 58 42 14 44

*HHs = households

Source: Biogas Users’ Survey 2000, BSP**

Table: Health benefits of biogas

Disease 20 80

Cough 53 47

Headache 33 3 67

Nausea 5 95

Chest pain 15 1 85

Lethargy 11 89

Respiratory disease 41 59

Malaria 8 2 92

Typhoid 10 90

Total (%) 22 1 77

Source: Biogas Users’ Survey,1999 ,BSP**

Preservation of forest

Smaller agricultural units can additionally reduce the use of forest resources for

household energy purposes and thus slow down deforestation, soil degradation and

resulting natural catastrophes like flooding or desertification.

1 m3 biogas = 5.5 kg fire wood = 11 kg CO2

Reduction in fossil fuel demand

Biogas provides an excellent source of energy that is helpful to the environment. It can

successfully replace the consumption of fossil fuels like coal, LPG, petroleum etc. These fossil

fuels are not environmental friendly as they produce a lot of pollutants like COX, SOX, and NOX

etc. The use of biogas creates a green environment.

By Production of Fertilizers The production of biogas is a method to treat organic waste from industry and

household in an environmentally friendly way, where the residuals are reused in

the farmlands as good quality fertilizers.

Project Safety and Design Analysis

Design considerations: Feed water characteristics. The type and reliability of external

treatment. Boiler type. Boiler pressure and heat flux. Steam load and variations in load. Steam purity requirements. Feed, testing, and control needs or

restrictions. Economic considerations. Boiler room layout and number of boilers.

Factors influencing efficiency of boiler: Stack Temperature Feed Water Preheating using Economizer Combustion Air Preheating Incomplete Combustion Excess Air Control Radiation and Convection Heat Loss Automatic Blow down Reduction of Scaling and Soot Losses Reduction of Steam Pressure Effect of Boiler Loading on Efficiency

Recovery boiler net thermal efficiency: Maximizing the fired liquor solids

concentration or percent solid Maximizing steam temperature

Minimizing access air Minimizing fouling

Minimizing soot blowing Stabilizing steam flow

Minimizing auxiliary power use

Achieving efficiency: Optimize air-to-fuel ratio. Optimize water treatment. Clean heat-transfer surfaces Minimize heat loss Recover condensate Install a stack-temperature gauge

Causes of a Boiler failure: Feedwater line erosion Deaerator cracking Economizer tubes Stress Corrosion Cracking Failures due to overheating Caustic embrittlement Steam Blanketing Fatigue and Corrosion Fatigue Acidic Attack Superheated Tubes Boiler Design Problems

Techniques for failure analysis: Visual examination Magnetic particle inspection Ultrasonic inspection Chemical analysis Finite element analysis CFD analysis NDT Inspection Water Treatment Analysis

Boiler safety feature: Safety valves. Water gauge glass

Water-level control and low-water fuel

cutoff. Annual safety check Carbon monoxide alarm

Factors affecting boiler circulations: No. of down comers, diameter , thickness,

layout Down comer location Feed pump operation: No. of risers , pipe Inside diameter,

bends, branches Arrangement of risers in the drum

Hydrostatic testing and repairs Regular monitoring of tube thickness

Maintenance of boiler: General Maintenance Shift Maintenance Daily Maintenance Monthly Maintenance Annual maintenance

Boiler layouts: Type A Type D Type O

The names are derived from the general shapes of

the tube and drum arrangements.

Environmental impacts: Green energy solution Reduces fossil fuel consumption Better hygiene conditions

A good way to decompose off organic matter

Effects of retention time: Long retention times help saving

energy. Retention time for mesophillic digestion at a temperature of 20-350 C is almost 60 to 100 days. Payback period: Usual payback period for this type of biogas plant is one to two years.

Conclusions:

This project is an attempt to create awareness and providing a viable solution to the soaring energy

crisis prevailing in Pakistan. Boilers are very integral part of many industries and if we are able to

operate them with multiple fuels then this can create a revolution in countries like Pakistan where

industry is suffering a lot due to energy shortage.

Rizwan Ali Bsc. Mechanical Engineering Student

Assistant Manager Thermodynamics Section

ASME UET Lahore, Pakistan rizwanali976@gmail.com

+92-300-4094863

Books:

The Stirling Water Tube Boiler

Publishers: The Babcock & Wilcox Company

Packaged Commercial Water tube Boiler Publishers: American Boiler Manufacturers Association, Inc.

BOILER ENGINEERING DESIGN GUIDELINE By Aprilia Jaya Publishers: KLM Technology Group Malaysia

Boiler Tubes Facts Publishers: Boiler Tube Company of America BOILER, METALLURGY, MATERIALS & HEAT TREATMENT By Rakesh Kumar Singh

Websites:

http://www.aesieap0910.org/upload/File/PDF/4-

Technical%20Sessions/TS15/TS1501/TS1501_FP.pdf

http://www.corrosionlab.com/failure-analysis.htm

http://www.poweronline.com/product.mvc/Boiler-Tube-Life-Assessment-0001

http://www.csircmc.res.in/Boiler%20tube%20assessment%2021.pdf

http://www.sciencedirect.com/science/article/pii/S1350630708001271

http://www.matcoinc.com/home/publications/123-technical-publication-failure-

analysis-and-investigation-methods-for-boile

http://www.gewater.com/handbook/boiler_water_systems/ch_14_systemfailure

.jsp

http://www.structint.com/what-we-do/fossil-plant-services/engineering-

services/boiler-integrity-management/boiler-tubing-assessments

http://www.babcock.com/library/pdf/E1013153.pdf

http://www.structint.com/files/public/fossil-plant-services/FPS-Overview.pdf

http://www.scribd.com/mjorion/d/56700845-NDT-for-Boilers

http://www.em-ea.org/Guide%20Books/book-2/2.2%20Boilers.pdf

http://www.poweronline.com/product.mvc/Boiler-Tube-Life-Assessment-0001