Legislation and Codes for Power Engineers
Learning Outcome
When you complete this learning material, you will be able to:
Explain the purpose of, general content of, and interaction with, the legislation and codes that
pertain to the design and operation of boilers and related equipment.
Learning Objectives
You will specifically be able to complete the following tasks:
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Explain the purpose and the legislated authority of the “Boilers Branch” jurisdictions in
Canada. Recognize the naming conventions of the various jurisdictions and explain how
power engineers interact with their own jurisdiction.
Describe the general content of a typical “Boiler and Pressure Vessel Act” and its associated
“Regulations”.
Explain the adoption of codes and standards by jurisdictions in Canada and identify the
main standards that have been adopted with respect to boilers and pressure equipment.
Explain the purpose and scope of the National Board of Boiler Inspectors (NBBI).
Describe the general procedure and regulations that must be followed in order to construct,
or install, and place into service.
Describe the scope and general content of the CSA B51 Code for the construction and
inspection of boiler and pressure vessels.
Describe the scope and general content of the CSA B52 Mechanical Refrigeration Code.
Explain the scope of the ASME and state the purpose and general content of the following
sections of the following sections of the ASME Codes: Section I, IV, V, VI, VII, VIII, IX.
Objective One
When you complete this objective you will be able to…
Explain the purpose and the legislated authority of the “Boilers Branch” jurisdictions in Canada.
Recognize the naming conventions of the various jurisdictions and explain how power engineers
interact with their own jurisdiction.
Learning Material
BOILER AND PRESSURE VESSELS LEGISLATION IN CANADA
Safety of life and property are the primary purposes behind legislation for the design, manufacture,
installation, construction, maintenance, repair, inspection, and operation of boilers and pressure
vessels. All Canadian provinces and territories have passed laws, rules, and regulations to achieve
these.
Power Engineers require a working knowledge of the legislation that is directed at the equipment
that they are responsible for and for their own level of certification in the province or territory that
they work in. They should also be familiar with the codes that have been adopted by their
jurisdiction, namely:
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The Canadian Standards Association (CSA).
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The American Society of Mechanical Engineers (ASME).
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The National Board of Boiler and Pressure Vessel Inspectors (NBBI).
The legislation responsible for boilers and pressure vessels in the different provinces and territories
may vary, but all have the same intent and objective, that is, the safety of life and property.
Through the use of adopted codes such as the CSA B51, CSA B52, and sections of the ASME codes,
there is much common ground between the provinces and territories in the design, construction,
installation, operation, inspection, testing, and repair of boilers, pressure vessels, and related
equipment such as pressure piping systems and fittings.
Governments are responsible for passing legislation and a minister will have the responsibility for
this legislation, but the actual day to day duties of seeing that the legislation is carried out will be
delegated to some specific government or independent not-for-profit body. Regulations under the
acts are more specific and it is the regulations that are directed at boilers and pressure vessels that
the power engineer must be familiar with. Rules and standards that have been adopted by
provincial and territorial legislation also become part of the law. Therefore, the power engineer must
also be familiar with these adopted rules and standards.
For additional information on titles, levels of certification, classification of plants, and the
relationship between these levels of certification and plant classifications, refer to the respective
acts and regulations, for your jurisdiction. Most jurisdictions have a syllabus that prospective
candidates, for certification at each level, may obtain for guidance when studying for examinations.
In addition to the theory, there is also a practical component that must be met in order to write
examination papers, at each level of certification.
Provinces and territories have made revisions in their regulations for the certification of Power
Engineers, from other Canadian provinces and territories. This is to allow them to obtain an
equivalent certification, without examination, as long as the eligibility requirements for the original
class of certification is equal to the certification requirements in the new province or territory. The
information, in the following section, will identify the naming convention of each province and
territory.
BRITISH COLUMBIA
Under the Ministry of Community, Aboriginal and Women’s Services, the Boiler and Pressure Vessel
Safety Program is responsible for the administration of the Power Engineers and Boiler and Pressure
Vessels Safety Act.
ALBERTA
The Alberta Boilers Safety Association (ABSA) is one of nine Technical Councils, within the Safety
Codes Council, and is responsible for the administration of the legislation for boilers and pressure
vessels. The Safety Codes Council is a not-for-profit, non-government, statutory corporation and is
responsible to the Minister of Municipal Affairs.
SASKATCHEWAN
The Department of Municipal Affairs and Housing, Safety Division, is mandated to provide public
protection and administers boiler and pressure vessel safety.
MANITOBA
The Mechanical & Engineering Branch, part of the Manitoba Department of Labour and the
Workplace Safety and Health Division, is responsible for steam and pressure plants.
ONTARIO
The Technical Standards and Safety Authority (TSSA), an independent, not-for-profit organization,
is responsible for Boilers and Pressure Vessels and Operating Engineers, under the Technical
Standards & Safety Act.
QUEBEC
The Minister of Labour is responsible for the application of the Acts and Regulations respecting
boilers and pressure vessels.
NEW BRUNSWICK
The New Brunswick Safety Code Services is the responsibility of the Department of Public Safety
and is responsible for the administration and enforcement of legislation, affecting boilers and
pressure vessels.
NOVA SCOTIA
The Public Safety Division, of the Environment and Labour Department, is responsible for
administering acts and regulations regarding boilers and pressure vessels.
PRINCE EDWARD ISLAND
The Planning and Inspection Services Division of the Department of Community Services and
Attorney General, is responsible for boiler and pressure vessel systems.
NEWFOUNDLAND
The Department of Government Services and Lands is responsible for the administration of the
Public Safety Act and Boiler, Pressure Vessel and Compressed Gas Regulations.
YUKON TERRITORIES
The Public Safety Branch of the Department of Community and Transportation Services is
responsible for the administration of the legislation, for boilers and pressure vessels.
NORTHWEST TERRITORIES
Boilers and pressure vessels are the responsibility of the Electrical/Mechanical Inspections section of
the Public Works and Services Department of the Government of the Northwest Territories.
NUNAVUT
The Safety Division, of the Department of Public Works and Services, administers boiler and
pressure vessel legislation.
POWER ENGINEERS
Chief Power Engineer
The chief power engineer is the person who holds a certificate of competency, allowing him/her to
perform the duties of a chief power engineer. The classification of the certificate of competency,
required for this role of chief power engineer, is dependent on the kilowatt rating of the power
plant. The chief power engineer is the person responsible for the supervision of the other power
engineers and the safe, and efficient, operation of the plant.
Shift Engineer
The shift engineer is a person who holds a certificate of competency, allowing him/her to perform
the duties of the shift engineer. The classification of the certificate of competency, required for this
role of shift engineer, is dependent on the kilowatt rating of the power plant. The shift engineer has
charge of a shift in a power plant, under the supervision of the chief power engineer.
Assistant Shift Engineer
The assistant shift engineer is a person who holds a certificate of competency, allowing him/her to
perform the duties of the assistant shift engineer. The classification of the certificate of competency,
required for this role of assistant shift engineer, is dependent on the kilowatt rating of the power
plant. The role of this position is to assist the shift engineer in supervising all aspects of the
operation of a power plant.
Assistant Engineer
The assistant engineer is a person who holds a certificate of competency, allowing him/her to
perform the duties of the assistant engineer. The classification of the certificate of competency,
required for this role of assistant engineer, is dependent on the kilowatt rating of the power plant.
The role of this position is to take charge of a section of a power plant, under the supervision of a
shift engineer.
Objective Two
When you complete this objective you will be able to…
Describe the general content of a typical “Boiler and Pressure Vessel Act” and its associated
“Regulations”.
Learning Material
INTRODUCTION
Every power engineer should obtain copies of the relevant acts and regulations for boilers, pressure
vessels, and operators for his or her respective province or territory. By having a working
knowledge of this legislation, they will be able to ensure their plant meets the legal requirements,
for the jurisdiction. The Boiler and Pressure Vessel Act may have different names:
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Public Safety Act
Steam Boiler and Pressure Vessel Act
Technical Standards & Safety Act
The Steam and Pressure Plants Act
Safety Codes Act
Power Engineers and Boiler and Pressure Vessels Act
The intent is the preservation of life and property by ensuring the best in design, construction,
installation, inspection, operation, repairs, alteration, and supervision of boilers, pressure vessels,
and pressure piping systems. Acts are often more general, in nature, and are written to cover more
than boilers, pressure vessels and their operators. Often the names of the regulations under the Act
will be more descriptive as to what or whom they apply to, such as Design, Construction and
Installation of Boilers and Pressure Vessels, Engineers’ Regulations, and Pressure Welders’
Regulations. The following information provides an insight to the contents that may be found in a
typical Boiler and Pressure Vessels Act and its associated regulations.
BOILER AND PRESSURE VESSELS ACT
Definitions
The Act begins by defining various terms that are used in the Act, and Regulations, under the Act.
Some of the terms defined are: boiler, certificate of competency, certificate of inspection, fittings,
inspector, power plant, pressure plant and pressure vessel.
Exceptions
Equipment, to which the Act and the regulations do not apply, is listed. Examples include:
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Boilers below a minimum power rating.
Pressure vessels of less than a certain internal diameter and operating below a given
pressure.
Refrigeration systems of less than a minimum capacity.
Any boiler, pressure vessel, or pressure piping system that does not constitute a sufficient
hazard to require it to be subjected to the Act.
Design and Construction
This section deals with the approval and registration of designs of boilers and pressure vessels to be
constructed within the jurisdiction or brought into the jurisdiction. It also covers the need for
approval for changes in design and also deals with unsafe and obsolete designs.
Fittings
All fittings constructed and used within the jurisdiction, must be registered in accordance with the
regulations. Registrations of fittings brought into the jurisdiction and changes to fittings are dealt
with as well as unsafe or obsolete fittings.
Boiler and Pressure Vessel Identification
This section states that before an inspector issues the first certificate of inspection for any boiler and
pressure vessel, he or she must make sure that the boiler or pressure vessel is stamped with the
jurisdiction's identification number.
Construction, Installation and Sale of Boilers, Pressure Vessels and Fittings
This section covers the restrictions in regard to the construction, sale or disposal, and installation of
boilers, pressure vessels, fittings and pressure piping systems.
Inspections
This section lists the rules regarding inspections, orders issued by an inspector, the powers of an
inspector and the responsibilities of the owner or person in charge of the equipment in regard to
assisting an inspector. The certificate of inspection is described in this section, as well as the
responsibilities of the owner or person in charge, for the retaining and displaying of this certificate.
Accidents and Investigations
The procedure to be followed by the owner or person in charge, in the event of an accident
concerning the boiler, pressure vessel or power plant, is detailed here. It is also noted that such an
accident may be investigated by the chief inspector or other persons directed by him or her, to do
so. Regulations and Offences This part of the Act states that the governing body of the jurisdiction
may make regulations in regard to boilers, pressure vessels, power plants and fittings concerning
the registration of design, construction, testing, installation, inspection, operation and repair. Many
other types of regulations, which the governing body may make, are also listed in this section
including rules concerning certificates of competency. This section states that contravening any
provision of the Act is an offence and the penalty for doing so, may be a fine or imprisonment.
DESIGN, CONSTRUCTION AND INSTALLATION REGULATION
The following information will give an insight to a regulation that may be a part of a typical Boiler
and Pressure Vessels Act.
Exemptions
The various types of equipment, which are exempted from the provisions of the Act, are listed.
Adoption of Codes
To save duplication, it is simpler and more economical for each province, or territory, to adopt
existing codes. Representatives, from each province and territory, are part of the committees that
develop and modify these codes. Examples are the CSA and ASME Codes.
Registration and Approval of Designs and Welding Procedures
The details of the drawings and specifications, required for approval of a design of a boiler or
pressure vessel, are listed. These must be submitted to the chief inspector, in triplicate, and bear
the signature of the owner of the design or the manufacturer of the boiler. A similar listing is given
for the requirements for the approval of a pressure piping system. The method of approving and
registering a design of a boiler, pressure vessel or pressure piping system, by an inspector, is
described. In order to obtain approval for changes to a design, it is likewise necessary to submit
drawings and specifications, to the chief inspector. Similarly, when a boiler, pressure vessel, fitting
or pressure piping system is to be constructed, altered or repaired by welding, the welding
procedure specifications and procedure qualification records must be submitted, in triplicate, for
approval and registration.
Registration of Fittings
If a fitting is to be constructed for use in the jurisdiction, or purchased elsewhere, application must
be made to the chief inspector, for registration. The drawings, information and procedure necessary
to obtain this registration, are listed.
Boiler and Pressure Vessel Fees
The fees necessary to register a design, welding procedure or fitting are discussed here. Also, shop
inspection fees, initial inspection fees and annual fees for boilers and pressure vessels, are
identified.
Construction and Inspections
The requirements relating to the construction of a boiler or pressure vessel, within the jurisdiction,
are discussed. These deal with submission of drawings and specifications, quality control programs
during construction and manufacturers data reports.
Inspection
This section deals with the inspection of boilers, pressure vessels and pressure piping systems.
Fees
This section lists the fees for operating boilers, pressure vessels, pressure piping systems, and heat
exchangers.
ENGINEERS REGULATIONS
These regulations state the minimum qualifications necessary to obtain each class of power
engineer certification.
Definitions
The roles of chief steam engineer, shift engineer, assistant engineer, assistant shift engineer,
fireman and building operator are defined.
Certificates of Competency
Rules regarding the issuing and posting of Certificates of Competency, by the chief inspector are
defined. The issuance of temporary certificates of competency is discussed in regard to conditions
requiring a temporary certificate and how it is applied for, as well as, the duration of such
certificates.
Qualifications and Examinations
In order to obtain a certificate of competency, a person must pass an examination set by the
jurisdiction issuing the certificate. In order to qualify to take this examination, the candidate must
fulfill certain conditions, with regard to previous working experience and educational requirements.
The candidate must be the holder of a certificate of competency one grade lower than that which he
or she is applying for. Other information given in this section deal with examination pass marks,
credits which may be granted in lieu of operating experience, credits which may be granted to a
holder of a Power Engineering Diploma issued by an educational institute, as well as credits for
other technical courses. Another part of this section deals with the issuing of equivalent certificates
of competency to persons from other jurisdictions.
Application and Conduct of Examinations
The procedure for submitting applications for examinations is documented as well as the type of
references required certifying a candidate's experience, ability and conduct.
Examination and Certificate Fees
The fees for writing the various certificates of competency examinations are listed, as well as the
fees for remarking examination papers. Other fees listed include those for temporary and duplicate
certificates.
PRESSURE WELDERS' REGULATIONS
The regulations define terms such as performance qualification card, pressure welder, and pressure
welding.
Classification of Certificates
The various certificates for pressure welders are listed, as well as what each certification allows the
holder to perform.
Qualifications and Examinations
In order to obtain a Pressure Welder's Certificate of Competency, a person must pass an
examination set by the jurisdiction issuing the certificate. In order to qualify to take this
examination, the candidate must fulfill certain conditions, in regard to previous experience as a
welder.
Conduct of Examinations
The use of codebooks and calculators during an examination is noted and also the penalty if there is
a misconduct of the rules.
Performance Qualification Tests
In a performance qualification test, the candidate is required to weld test coupons. The inspector
will supervise this.
Miscellaneous
Among the topics covered in this section are rules regarding identification of pressure welds and
duplicate certificates of competency.
Fees
The fees for certificate of competency examinations are listed. Fees for duplicate certificates of
competency, duplicate performance qualification cards and special examination fees are also listed.
Objective Three
When you complete this objective you will be able to…
Explain the adoption of codes and standards by jurisdictions in Canada and identify the main
standards that have been adopted with respect to boilers and pressure equipment.
Learning Material
ADOPTION OF CODES AND STANDARDS
All of the provinces and territories of Canada have established laws, rules and regulations relating to
the construction, installation, inspection and operation of boilers and pressure vessels, to ensure
public safety. Various codes and standards, covered in the next section, have been used in the
development of these laws, rules and regulations.
The following is a list of Codes, Rules, and Standards that have been adopted by the provinces and
territories of Canada. Though most of these have been adopted by each Canadian jurisdiction, there
are some differences and it will be necessary for you to consult the exact list of adoptions, for your
specific jurisdiction. It will state whether all, or a part of the code, has been adopted and if the
appendix is to be considered mandatory. Your jurisdictional regulations will also inform you as to
the edition of adopted code.
Canadian Standards Association (CSA) Standards
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CSA B51 – Boiler, Pressure Vessel, and Pressure Piping Code
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CSA B52 – Mechanical Refrigeration Code
American Society of Mechanical Engineers (ASME) Codes
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Section
Section
Section
Section
Section
Section
Section
I – Rules For Construction of Power Boilers
IV – Rules For Construction of Heating Boilers
V – Nondestructive Examination
VI – Recommended Rules for the Care and Operation of Heating Boilers
VII – Recommended Guidelines For The Care of Power Boilers
VIII – Rules for Construction of Pressure Vessels
IX – Welding and Brazing Qualifications Procedures
American National Standards Institute (ANSI)/ ASME Codes
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B31.1 – Power Piping Systems
B31.3 – Chemical Plant and Petroleum Refinery Piping
B31.5 – Refrigeration Piping
American Petroleum Institute
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API 510 – Pressure Vessel Inspection Code
API 570 – Piping Inspection Code, Inspection, Repair, Alteration and Rerating of In-Service
Piping Systems
API RP 572 – Inspection of Pressure Vessels
Objective Four
When you complete this objective you will be able to…
Explain the purpose and scope of the National Board of Boiler Inspectors (NBBI).
Learning Material
INTRODUCTION
Boiler explosions, in the late 1800s and the early 1900s, were common. In the five-year period,
1898 to 1903, 1,299 people were killed in the United States by 1,600 boiler explosions. A
catastrophic boiler explosion in a shoe factory in Brockton, Massachusetts, in 1905, killed 58 people,
injured 117, and caused property damage of a quarter of a million dollars. This accident, together
with another half-million dollar accident, resulted in enactment of the first legal code of rules for the
construction of steam boilers by the Commonwealth of Massachusetts.
Other states and a number of cities, where boiler explosions had occurred, also recognized that
many explosions could have been prevented by the safe and proper design, construction,
installation, and inspection of boilers. As a result, safety rules and regulations for boilers were
formulated by many states and cities. Often the rules of one regulatory body conflicted with those of
other states or cities.
This lack of uniformity of laws resulted in an unmanageable situation. Materials and methods of
construction considered safe in one jurisdiction were not permitted in another. It was difficult for
both the user, who may have wanted to move a boiler from a facility in one jurisdiction another,
and the manufacturer, who had to build boilers complying to several different specifications, making
it difficult to keep stock. The problem of inspection for use of a boiler out of the state or city of
manufacture presented serious difficulties. Therefore, in 1919, several chief inspectors of various
jurisdictions organized the National Board of Boiler and Pressure Vessel Inspectors to establish
uniform qualifications for inspectors and acceptance of standard code requirements.
THE NATIONAL BOARD OF BOILER AND PRESSURE VESSEL INSPECTORS (NBBI)
The National Board of Boiler and Pressure Vessel Inspectors (NBBI) was created, in 1919, as an
organization to promote uniformity in the qualifications of those named by the jurisdictions, as
authorized inspectors. This board is a nonpolitical, nonprofit technical body that promotes boiler and
pressure vessel safety through the enforcement of codes and standards developed by the American
Society of Mechanical Engineers (ASME). By setting standards for qualifications, experience and
knowledge of inspectors, the NBBI helps ensure uniformity of compliance to the ASME codes.
Its membership is composed of the Chief Inspectors of all the jurisdictions in the United States and
Canada that have adopted at least one section of the ASME Boiler and Pressure Vessel Code.
The NBBI also sets guidelines and standards for which the Authorized Inspectors can qualify as a
commissioned National Board Inspector. Commissioned National Board Inspectors are qualified in
the fabrication, installation and maintenance of boilers and pressure vessels. They are required to
possess qualifications as set by the NBBI and to pass an exam, prepared and administrated by the
NBBI.
Some of the main objectives of this National Board are to:
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Promote uniform enforcement of boiler and pressure vessels laws and rules.
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Secure uniform approval of specific design and structural details of boilers and pressure
vessels, as well as accessories and devices instrumental to the safe operation of such
vessels.
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Code numbers are “stamped” into the vessel constructed in accordance with the
requirements of said code.
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Code and registration numbers are metal “stamped” into the vessel proper.
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Provide one standard of qualification and examinations for inspectors who are to enforce
the requirements of said code.
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Administer the uniform rules and regulations that affect safety for the public and property.
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Make information and statistics available to members, inspectors and other interested
parties.
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Promote testing facilities for safety relief valves or other boiler and pressure vessel
components and dissemination of such test results.
Today, all Canadian provinces and most of the states in the United States, require boilers and
pressure vessels to be inspected during fabrication by an inspector holding a National Board
commission. The boilers or vessels are “stamped” with a National Board standard number.
Equipment fabricated under a NBBI qualified inspector, and stamped accordingly, is accepted by all
jurisdictions as being constructed in compliance with the ASME code. This allows free movement of
boilers and pressure vessels across jurisdictions, without the need for additional testing or
inspection.
Qualified and authorized boiler and pressure vessel manufacturers must be registered with the
National Board. In addition, two data sheets on each vessel must be filed with the National Board.
The board retains one copy and the other is sent to the administrative authority of the province,
territory, state or city in which the vessel is to be used. As a result, it is possible for an authorized
shop to build a boiler or pressure vessel that will be accepted anywhere in North America, after it
has been inspected by a National Board Commission inspector.
The National Board of Boiler and Pressure Vessel Inspectors have set out three requirements that
must be met to permit a boiler/pressure vessel to be registered:
1. It must be constructed using an acceptable code.
2. The manufacturer must have a quality assurance program.
3. A third party must inspect the boiler.
All three of these requirements must be completed to standards satisfactory to the National Board
of Boiler and Pressure Vessel Inspectors.
Objective Five
When you complete this objective you will be able to…
Describe the general procedure and regulations that must be followed in order to construct, install,
and place a new boiler or pressure vessel into service, in Canada.
Learning Material
NEW BOILER OR PRESSURE VESSEL CONSTRUCTION
The initial step in the construction, installation, or placement of a new boiler or pressure vessel into
service is to contact the regulating authority for that province, or territory. Legislation from each of
these jurisdictions sets out the specific requirements. CSA Code, B51, which has been adopted by
the jurisdictions in Canada, lays out the procedure to be followed in the construction of a new boiler.
Information on the construction of a boiler, or pressure vessel, is identified in the following sections
of CSA B51.
Registration of Design
The drawings, specifications and calculations of designs for all boilers, pressure vessels, piping and
fittings, must be submitted to the regulatory authority. If the boiler or pressure vessel is to be
manufactured outside of Canada, then the name of the authorized inspection agency that will be
used to inspect the boiler or pressure vessel must also be submitted to the regulatory authority. The
designs must be accepted, and registered, before construction can be started.
Once a design has been registered, other boilers can be built using the same design, as long as
there are not any changes in construction and there have been no changes in any of the applicable
regulations, codes, or standards that apply to the registered design.
Canadian Registration Number (CRN)
When a province or territory registers a boiler or pressure vessel design, the design will be given a
Canadian Registration Number. To identify this province or territory that first registered the design,
a number or letter will be placed after a decimal point. If the boiler or pressure vessel design is
registered in other provinces, then a number or letter representing that province or territory will
follow the number or letter where it was first registered. The numbering of the provinces for the
CRN starts with British Columbia, which is given the number one, and the numbers increase for
each province as they move eastward. Letters are used to show registration in each of the
territories. The following identifications are used:
1 British Columbia 7 New Brunswick
2 Alberta 8 Nova Scotia
3 Saskatchewan 9 Prince Edward Island
4 Manitoba 0 Newfoundland
5 Ontario T Northwest Territories
6 Quebec Y Yukon
An example of a Canadian Registration Number would be CRN 290.469Y. The design, first registered
in Manitoba, was given the registration number 290 and registered as CRN 290.4. Then it was
registered in Quebec and given the number CRN 290.46. It was subsequently registered in Prince
Edward Island, and given the number CRN 290.469. The last registration was in the Yukon
Territory, so it was given the number 290.469Y.
Registration of Welding and Brazing Procedures
All the welding and brazing procedures are to be registered with the regulatory authority of the
province, or territory, where the welding or brazing will be performed.
Submission of Manufacturer’s Data Report
Upon completion of the construction of a boiler or pressure vessel, a manufacturer’s data report,
signed by the manufacturer and countersigned by an authorized inspector, must be sent to the
province or territory where it is to be installed.
Fabrication Inspection
A provincial boiler inspector carries out shop inspections, during the fabrication of boilers or
pressure vessels. If the boiler or pressure vessel has been constructed outside of Canada, an
authorized inspection agency may carry out the inspection.
Quality Control Program
Manufacturers must present a satisfactory quality control system to the regulatory authority, where
the boiler is registered. Quality control programs must be submitted every five years. A
manufacturer who has a Certificate of Authorization issued by the ASME is considered to have a
satisfactory quality control system.
Stamping
All boilers and pressure vessels must be stamped with an ASME code symbol, or other acceptable
stamping, by the jurisdiction where the boiler or pressure vessel is to be installed.
Nameplates
The stamping on the nameplate of a boiler or pressure vessel must be according to the ASME Code.
Before any boiler or pressure vessel can be placed into service it must be stamped with a provincial
identification number and have an inspection/certification permit issued. In Alberta, the letter “A”, in
a circle, precedes the provincial identification number.
NEW BOILER OR PRESSURE VESSEL INSTALLATION AND STARTUP
The installation and startup of a new boiler is explained in the ASME Section VII, Boiler & Pressure
Vessel Code, Subsection C2 “Boiler Operation”. This section deals with the following topics:
Operator Training
The safe and reliable operation of any boiler or pressure vessel is dependent upon the skill and
knowledge of the operator. Good operating skill implies that he/she must be familiar with the
equipment and have sufficient training and experience.
Preparation For Operation
This section deals with the development of checklists for the water side, fire side and the external
components of the boiler. Chemical cleaning of the boiler internals and hydrostatic testing of the
pressure components are in this section.
Starting Up
This section explains the practices that should be followed in establishing a safe operating steam
drum water level. It explains the initial light off of the boiler and the recommended warm up period
to allow for the heat up of the boiler and refractory. It also identifies precautions that should be
followed in bringing the boiler on line with other units.
On Line Operation
This section deals with the topics of feedwater treatment; the results of high and low water
conditions and boiler water blowdown.
Objective Six
When you complete this objective you will be able to…
Describe the scope and general content of the CSA B51 Code for the construction and inspection of
boiler and pressure vessels.
Learning Material
INTRODUCTION
The Canadian Standards Association is a not-for-profit, independent, private sector organization
that serves the public, business, and governments by developing standards.
A CSA committee for boilers and pressure vessels produces the B-51, Boiler, Pressure Vessel, and
Pressure Piping Code. This committee works closely with the National Board of Boiler and Pressure
Vessel Inspectors and the ASME Boiler and Pressure Vessel Code Committees. This code is a
recommended standard.
The committee consists of representatives from the following:
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Provincial and territorial government departments.
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Boiler and pressure vessel manufacturers.
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Boiler insurance companies.
The purpose of the Boiler, Pressure Vessel, and Pressure Piping Code, CSA B-51, is to promote
safety and uniformity in the design, construction, installation, operation, testing, and repair of
boilers, pressure vessels, and related equipment. This code is made up of the following sections:
Sections of the Code
Scope
The type of equipment to which the code applies is listed, as well as the exceptions.
Definitions
This section lists and defines the various terms and abbreviations, as used in the Code.
Reference Publications
This section outlines the other CSA Standards, and standards from the American National Standards
Institute, American Society of Mechanical Engineers, American Petroleum Institute, American
Society for Testing and Materials, Canadian Gas Association, Compressed Gas Association, Canadian
General Standards Board, Underwriters’ Laboratory of Canada and the International Organization for
Standardization, that are used and made reference to, in this Code.
General Administrative Requirements
This section deals with the registration of designs, registration of fittings, Canadian Registration
Numbers, registration of welding and brazing procedures, welding and brazing qualifications,
submission of the manufacturer’s data report, quality control program, manufacturing in Canada,
and in other countries, nondestructive examination, and piping and fittings.
Identification
This section identifies information that must appear on the nameplates of every boiler, pressure
vessel, safety valve, relief valve and rupture disc. It also makes reference to any alteration that is
made to a boiler or pressure vessel, and an additional nameplate is to be attached next to the
original nameplate.
Boilers and Related Components
This section identifies the standards used in the design, construction, installation, inspection,
testing, and repair, along with water gauges, low water cut off, fusible plugs, boiler installation,
inspection openings, outlet dampers, blowoff tanks, and cast iron steam and hot water boilers.
Pressure Vessels
This section identifies pressure vessels and their installation, including pressure vessel inspection
openings. This section also shows the design of cushion tanks, blow-off vessels, and the installation
of air receivers.
Piping and Fittings
This section identifies piping and fittings and lists the codes and standards that must be used. These
standards include ANSI/ASME standards B31.1, for Power Piping and the B31.3, for Process Piping.
Refrigeration Equipment
This section explains refrigeration equipment and refers to CSA B52 for the standard to be met in
the design, construction, installation, inspection, testing, and repair of refrigeration equipment.
Pressure Coils
This section identifies the requirements for the designing of pressure coils in petroleum and
chemical plant fired heaters.
Repairs and Alterations
This section outlines the standards that must be followed when completing repairs to existing pieces
of pressure equipment.
Tables
This section consists of tables, which identify the following:
•
Categories of fittings.
•
Minimum dimensions of blowoff vessels.
•
Minimum dimensions of blowoff vessels for coil-tube boilers.
Appendices
This section consists of various appendices indicating the following:
•
Development of quality assurance programs for defect prevention and in-service reliability.
•
Guidelines for safety/relief valve repair organizations.
•
Samples of manufacturer’s data report forms for miniature pressure vessels, pressure
vessels, water tube boilers, fired process heaters, piping systems; statutory declaration for
the registration of fittings; installation report for cast-iron sectional boilers, and
repair/alteration report for boilers and pressure vessels.
Objective Seven
When you complete this objective you will be able to…
Describe the scope and general content of the CSA B52 Mechanical Refrigeration Code.
Learning Material
INTRODUCTION
The Technical Committee on Mechanical Refrigeration produced the CSA B-52, Mechanical
Refrigeration Code. This committee is made up of representatives from the following:
•
Provincial and territorial government departments
•
Professional engineers associations.
•
Refrigerating and air conditioning institutes.
This code has two main purposes:
•
To provide for the safe design, construction, installation, operation and repair of
refrigerating and air conditioning equipment and systems, and related equipment.
•
To promote uniform requirements among the provinces and territories.
The B-52, Mechanical Refrigeration Code, is not law in any province or territory until it has been
officially adopted by a jurisdiction.
Sections Of The Code
Scope
The equipment to which this code applies and the equipment to which this code does not apply, are
generally described.
Definitions
Terms and equipment relating to refrigeration and air conditioning equipment are defined.
Occupancy Classification
The various classifications of buildings and occupancies are listed and described with examples of
each classification given.
Refrigerating System Classification
Refrigerating systems are classified according to the method used for extracting heat. Each
classification is described and sketches are given to assist in these descriptions.
Refrigerant Classification
The various refrigerants used are listed and divided into three groups according to their toxicity or
flammability. Group 1 refrigerants are the least toxic, or flammable, while Group 3 refrigerants are
the most toxic, or flammable.
Requirements for Occupancies Other Than Industrial
Rules regarding the type or group of refrigerant permitted in the various types of occupancies are
given. Maximum permissible quantities of the refrigerant groups, for the different types of
refrigeration systems are listed.
Requirements for Industrial Occupancies
Restrictions regarding the quantity and kind of refrigerant used are given and rules regarding
ignition sources when flammable refrigerants are used are listed. Requirements related to
machinery rooms are noted.
Design and Construction of Equipment
The following topics are covered in this section:
•
•
•
•
•
•
Drawings and specifications.
Materials.
Design pressures.
Refrigerant pressure vessels.
Piping, valves, fittings and related parts.
Other components, service provisions, factory tests and test pressures.
Pressure Limiting Devices
This section shows where these devices are required and their setting.
Pressure Relief Protection
Pressure relief devices and rupture members are covered in this section with rules given regarding
method of connection, materials used, setting, marking, and types of vessels to be protected. Other
rules cover: required capacity, discharge from pressure relief devices, and devices for positive
displacement compressors. Tables are given for the length of discharge piping required.
Installation Requirements
Included in this section are: water supply and discharge connections, electrical wiring, gas devices,
air duct systems, location of refrigerant piping and machinery room requirements. Part of this
section relates to emergency discharge of the refrigerant with detailed rules given regarding
emergency valves, piping, location and installation.
Field Tests
Rules regarding the testing of refrigerant systems after install before operation are listed.
General Requirements
Listed here are rules regarding signs, charging and discharging of refrigerant systems, storage of
refrigerants, breathing masks or helmets, maintenance, posting of instructions and exits from cold
storage rooms.
Drawings
Rules relating to the submission of drawings, use of standard draw details required in drawings is
discussed.
Objective Eight
When you complete this objective you will be able to…
Explain the scope of the ASME and state the purpose and general content of the following sections
of the ASME Codes: Section I, IV, V, VI, VII, VIII, IX.
Learning Material
SCOPE
The American Society of Mechanical Engineers, (ASME), founded in 1880, is a professional-technical
society with a membership of over 115,000 practicing engineers and associated scientists. Its
purpose is to develop and disseminate technical information, promote high standards of engineering
design and education, encourage personal and professional development, foster high ethical
conduct, and provide creative solutions for technical problems.
In 1911, ASME set up the Boiler and Pressure Vessel Committee to formulate standard rules for the
construction of steam boilers and other pressure vessels. Prior to 1911, other organizations had
attempted to write rules but did not have the broad membership and support, which the ASME had.
This broad membership was necessary to develop rules suitable for acceptance by manufacturers,
users, regulatory authorities and the public. The ASME had the knowledge and diversity of interest
needed for the task.
The function of the Boiler and Pressure Vessel Committee is to establish rules of safety covering the
design, fabrication, and inspection during construction of boilers and pressure vessels, and to
interpret these rules when questions arise. In formulating the rules, the committee considers the
needs of the users, manufacturers, and inspectors of pressure vessels.
The objective of the rules is to provide reasonably certain protection of life and property and to
provide a margin for deterioration in service, which will allow this protection to continue for an
acceptable period of time. Advancements in design of materials and the evidence of experience are
recognized. These rules have been adopted or accepted in varying degrees by all the Canadian
provinces and territories.
Note that the ASME does not approve, certify, rate, or endorse any item, construction, proprietary
device, or activity. The ASME does not act as a consultant on engineering problems or general
application of the Code.
ASME CODES
Section I – Rules For Construction of Power Boilers
This section includes the rules and general requirements for all methods of construction of power,
electric and miniature boilers and high temperature water boilers used in stationary service. It also
includes power boilers used in locomotive, portable and traction service. The rules of this Section
are applicable to boilers in which steam or other vapor is generated at a pressure, more than 103
kPa, and high temperature water boilers intended for operation pressures, exceeding 120°C.
Superheaters, economizers, and other pressure parts connected directly to the boiler, without
intervening valves, are considered as part of the scope of this section.
Section IV - Rules For Construction of Heating Boilers
The rules of this section of the code covers minimum safety requirements for the design,
fabrication, installation and inspection of steam generating boilers and, hot water boilers intended
for low pressure service that are directly fired by oil, gas, electricity, or coal.
It also contains appendices, which cover approval of new material, methods of checking safety valve
and safety relief valve capacity, definitions relating to boiler design and welding, and quality control
systems.
Section V - Nondestructive Examination
This section contains requirements and methods for nondestructive examination, which are
referenced and required by other code sections. This also includes manufacturer's examination
responsibilities, duties of authorized inspectors and requirements for qualification of personnel,
inspection and examination.
Examination methods are intended to detect surface and internal imperfections in materials welds
and fabricated parts and components. A glossary of related terms is also included.
Section VI - Recommended Rules For The Care and Operation of Heating Boilers
This section covers the latest specifications, terminology, and basic fundamentals related to steel
and cast iron boilers and limited to the operating ranges of Section IV, Heating Boilers. It also
includes guidelines for associated controls and automatic fuel burning equipment.
Various illustrations show typical examples of available equipment. This section also includes a
glossary of terms commonly associated with boilers, controls, and fuel burning equipment.
Section VII - Recommended Guidelines For The Care of Power Boilers
This code contains rules, which have been compiled to assist operators of power boilers in
maintaining their plants in a safe condition. These rules apply to the boiler proper and to the pipe
connections up to and including the valve, or valves, required by the ASME code. Rules are also
given covering auxiliary equipment.
Section VIII - Rules for Construction of Pressure Vessels
Division I
This division covers the minimum safety requirements applicable to the construction, design,
fabrication and certification of pressure vessels under either internal or external pressure for
operation to pressures exceeding 103kPa, and to vessels having an inside diameter, width, height,
or cross section diagonal, exceeding 152mm. Such pressure vessels may be fired or unfired.
Specific requirements apply to several classes of material used in pressure vessel construction and
fabrication, methods such as welded, forged and brazed construction. This also covers the stamping
and coding and contains both mandatory and non-mandatory appendices detailing examination and
inspection.
Division 2 – Alternative Rules
This division covers the minimum safety requirements applicable to construction, design, fabrication
and certification of pressure vessels, which are used to operate at either internal or external
pressures greater than 103kPa. This pressure may be obtained from an external source or by the
application of heat from a direct or indirect source, or any combination thereof.
These rules provide an alternative to the minimum construction requirements for the design,
fabrication, inspection and certification of pressure vessels within the scope of Division 1.
Division 2 rules cover only vessels to be installed in a fixed location for a specific service where
operation and maintenance control is retained during the useful life of the vessel by the user who
prepares, the design specifications.
Division 3 – Alternative Rules For Construction of High Pressure Vessels
The rules of this division constitute requirements for the design, construction, inspection and
overpressure protection of pressure vessels with design pressures generally above 69mPa.
Section IX - Welding and Brazing Qualifications Procedures
This section covers the rules relating to the qualification of welding and brazing procedures, as
required by other code sections. This section also covers rules relating to the qualification and requalification of welders, brazers, and welding and brazing operators in order that they may perform
welding, or brazing, as required by other code sections, in the manufacture of boiler components. It
includes a special section of welding and brazing data covering variables, p-numbers, specimens,
forms and definitions.
Objective One
When you complete this objective you will be able to…
Given the tube material specification numbers, and other necessary parameters, use the formulae in
PG-27.2.1 to calculate either the minimum required wall thickness or the maximum allowable
working pressure for a boiler tube.
Learning Material
SYMBOLS USED IN THE FORMULAE OF PG-27
The symbols in the formulae to be used in this module are found in Paragraph PG-27.3 and are
defined as follows. It is extremely important that the correct units be applied when performing the
calculations:
t
= minimum required thickness (millimetres, mm). (Also see PG-27.4, Note 7)
P
= maximum allowable working pressure (megapascals, MPa). (Note - this refers to
gauge pressure)
D = outside diameter of cylinder (millimetres, mm)
R
= inside radius of cylinder (millimetres, mm)
E
= efficiency of longitudinal welded joints or of ligaments between openings,
whichever is lower. The values allowed for ‘E’ are listed in PG-27.4, Note 1.
This is a factor that has no units, (for example, the value of ‘E’ for seamless
cylinders is 1.00)
S
= maximum allowable stress value, at the operating temperature of the metal, as
listed in the Table PG-23.1, (megapascals, MPa). See PG-27.4, Note 2. The
tables are located in an Appendix near the back of the Code. (For example, the
max. allow. working stress for SA-192, at 400°C, is 73 MPa)
C
= minimum allowance for threading and structural stability, (millimetres, mm). See
PG-27.4, Note 3
e
= thickness factor for expanded tube ends (millimetres, mm). See PG-27.4, Note 4
y
= a temperature coefficient: This factor has no units and has a value between 0.4
and 0.7. The values allowed for y are listed in PG-27.4, Note 6, (for example, for
ferritic steel at 550°C, the value of ‘y’ is 0.7)
BOILER TUBE CALCULATIONS
To calculate the required minimum wall thickness or the maximum allowable working
pressure of ferrous boiler tubing, up to and including 127 mm O.D., the following formulae, as
given in PG-27.2.1, are used:
Example 1 (to find tube wall thickness):
Calculate the minimum required wall thickness of a superheater tube. The tube is 76 mm O.D. and
is connected to a header by strength welding. The maximum allowable working pressure is 4150
kPa gauge and the average tube temperature is 400°C. The tube material is alloy steel with
specification SA-213-T11.
Solution:
*Note: This 103 MPa value for S is found in Table PG-23.1. First locate the specification number,
SA-213 T11, in the left column under the headings “Spec. Number” and “Grade or Class” (page 96
of extract). Then scan across the table to the “400” column under “For Metal Temperatures Not
Exceeding°C” The corresponding value is 103 MPa.
Now, complete the calculation by substituting all factors into the formula:
Information concerning the type of material used and the construction of the tube can be found in
PG-9. The student should check PG-6 and PG-9 before starting calculations. The information in
these sections will direct the student to the correct section of Table PG-23.1 by indicating if the
metal is carbon steel, low alloy steel, or high alloy steel. PG-6 deals with steel plate, PG-9.1 deals
with boiler tubes or pressure containing parts, PG-9.2 deals with all superheater parts. These
sections will also help to correctly select the values for E and e (as per PG-27, Note 1 and Note 6).
Note: This value for the thickness of the tube is exclusive of manufacturer’s tolerances. (See PG16.5)
Example 2 (to find maximum allowable working pressure):
Calculate the maximum allowable working pressure, in kPa, for a watertube boiler tube, which is
73.5 mm O.D. and has a minimum wall thickness of 4.71 mm. The tube is strength-welded into
place in the boiler and is located in the furnace area of the boiler. Tube material is carbon steel, SA192, with a mean wall temperature of 280°C.
Solution:
*Note: This 79 MPa value for ‘S’ is found in Table PG-23.1. First, note that PG-27.4 states “tube
temperature will not be taken as less than 370°C when absorbing heat”. Since this tube is in the
furnace, it is absorbing heat. Now, find SA-192 in the table and scan across to find the temperature.
You’ll notice that there is no column for 370°C, so take the next higher temperature, which is
375°C. Use the value of 79 MPa from this column.
Note: In general, when a temperature given in a problem does not appear in Table PG-23.1, select
the next higher temperature from the table.
Now, substitute the values of all factors into the formula:
In both Example 1 and Example 2, the tubes were strength-welded into place. In this case the value
of ‘e’ is zero. In calculations involving tubes expanded into place, the appropriate value of ‘e’ would
be converted to mm and inserted into the formula. (See PG-27.4, Note 4)
Self-Test Problems
1. Calculate the minimum required wall thickness of a boiler tube, which is strengthwelded to a header. The maximum allowable working pressure is 4450 kPa, and the mean
wall temperature is 370°C. The tube material is SA-192 and the outside diameter is 50
mm.
(Ans. 62 mm)
2. Calculate the maximum allowable working pressure for a watertube boiler tube 76 mm
O.D. and 3.25 mm minimum thickness, which is strength-welded to the drum. Tube
material is SA-192 and the tube temperature does not exceed 370°C.
(Ans. 6.2 MPa)
Objective Two
When you complete this objective you will be able to…
Given the material specification, construction method, and other necessary parameters, use the
formulae in PG-27.2.2 to determine the required thickness and or maximum working pressure for
boiler drums, headers, or piping.
Learning Material
PIPING, DRUM and HEADER CALCULATIONS
PG-27.2.2 (see page 3 of the Extract) gives the formulae that are used to calculate the required
minimum thickness or the maximum allowable working pressure of ferrous piping, drums,
and headers. The size of each component may be stated as the outside diameter or as the inside
radius. The formulae that are applied differ in each case, and are as follows:
To find the minimum thickness
To find the maximum working pressure
Example 3 (to find the required thickness of a boiler drum):
Calculate the minimum required thickness, in mm, of a welded boiler drum having an inside
diameter of 1.5 m. The drum welds are finished flush with the surface of the plate. The drum plate
is carbon steel, SA-516-65, and the metal temperature will not exceed 250°C. The maximum
allowable working pressure is 4500 kPa gauge. The efficiency of the ligaments between the tube
holes is 0.5.
Solution:
The inside diameter is given and therefore the formula from PG-27.2.2, for inside radius can be
used can be used:
Example 4 (to find the maximum working pressure of a boiler drum):
Calculate the maximum allowable working pressure for a welded drum if the plates are 25 mm thick
and of material SA-299. The inside diameter of the drum is 988 mm and the joint efficiency is
100%. Assume the steam temperature will not exceed 400°C.
Solution:
The inside diameter is given and therefore the formula from PG-27.2.2, for inside radius, can be
used;
given that:
t = 25 mm
R = D/2 = 494.0 mm
E = 1.0 (PG-27.4, Note 3)
from Codes: C = 0 (from PG-27.4, Note 3)
S = 108 MPa (Table PG-23.1 for SA-299 at 400°C)
y = 0.4 (PG-27.4, Note 6, temperature less than 400°C)
substituting these values into the equation:
Example 5 (to find the required thickness of a header):
Calculate the required thickness, in mm, of a superheater outlet header, operating at 500°C and
having a maximum allowable working pressure of 17 MPa. The header material is SA-335-P7 and
the outside diameter is 457.2 mm.
Solution:
The outside diameter is given and therefore the formula from PG-27.2.2, for outside diameter
should be used:
given that: P = 17.0 MPa
D = 457.2 mm
from Codes: C = 0 (from PG-27.4, Note 3)
S = 63 MPa (Table PG-23.1 for SA-335-P7 at 500°C)
y = 0.5 (PG-27.4, Note 6)
E = 1.0 (PG-27.4 Note 1)
substituting these values into the equation:
Example 6 (to find the required thickness of a high-pressure boiler pipe):
Calculate the minimum thickness required for a seamless steel feedwater pipe of material
SA-209, grade T1. The outside diameter of the pipe is 323.85 mm and the operating pressure and
temperature are 5200 kPa and 500°C respectively. The pipe is plain-ended. Assume that the
material is an austenitic steel.
Note: Plain-end pipe is that which does not have its wall thickness reduced when joined to another
pipe. For example, pipe lengths welded together rather than joined by threading are classed as
plain-end pipes.
Solution:
The outside diameter is given and therefore the formula from PG-27.2.2, for outside diameter
should be used:
given that:
P = 5.2 MPa
D = 323.85 mm
from Codes:
C = 0 (from PG-27.4, Note 3; 4 inch nominal and larger)
S = 69 MPa (Table PG-23.1 for SA-209-T1, at 500°C)
y = 0.4 (PG-27.4, Note 6; austenitic steel at 500°C)
E = 1.0 (PG-27.4 Note 1; seamless pipe as per PG-9.1)
substituting these values into the equation:
Note on Manufacturer’s Tolerance:
The calculated thickness in Example 6 does not include the manufacturer’s tolerance. Since the
manufacturing process does not produce absolutely uniform wall thickness, an allowance is added,
which is called the manufacturing tolerance. This is usually done by increasing the minimum
required thickness, as calculated in the formula, by 12.5%.
Example 7 (for minimum thickness of steam piping):
Calculate the required minimum thickness (in mm) of steam piping which will carry steam at a
pressure of 4300 kPa gauge and a temperature of 370°C. The piping is plain-end, 273.05 mm O.D.;
the material is low alloy steel, SA-335 P11. A manufacturers tolerance of 12.5% must be added to
the pipe.
Solution:
The outside diameter is given and therefore the formula from PG-27.2.2, for outside diameter
should be used:
given that:
P = 4.3 MPa
D = 273.05 mm
from Codes:
C = 0 (from PG-27.4, Note 3)
S = 103 MPa (Table PG-23.1 for SA-335-P11, at 370°C)
y = 0.4 (PG-27.4, Note 6; ferritic steel at 475°C)
E = 1.0 (PG-27.4 Note 1)
substituting these values into the equation:
multiply by 1.125 to add the manufacturers tolerance of 12.5%:
t = 5.61 x 1.125 = 6.31 mm (Ans.)
Self-Test Problems
3. Calculate the minimum required plate thickness of a welded boiler drum having an
inside radius of 935 mm and a maximum design working pressure of 9020 kPa. The plate
material is SA-516 grade 70 and metal temperature does not exceed 320°C. Weld
reinforcement on the longitudinal joints has been removed flush with the surface of the
plate.
(Ans. 72.96 mm)
4. Calculate the minimum thickness required for a welded steel pipe of material SA-209
grade T1b, plain end. The outside diameter of the pipe is 273.05 mm and the operating
pressure and temperature are 2000 kPa and 400°C, respectively.
(Ans. 53 mm)
5. A steam header between the boiler and first stop valve is to be fabricated of 152.4 mm
NPS pipe. The material specification is SA-369 FPA seamless pipe. The operating
pressure will be 8440 kPa at 420°C. The pipe will be joined by full penetration welds and
will be fully radiographed. Calculate the minimum thickness of the pipe wall if the
manufacturer’s tolerance is 12.5%.
(Ans. 12.04 mm)
6. A boiler drum is made of SA-515-70 steel and has a ligament efficiency of 0.66. If the
steam temperature is 280°C and the inside diameter of the drum is 1.6 m, what will the
maximum operating pressure be, in kPa?
(Ans. 6500 kPa)
Objective Three
When you complete this objective you will be able to…
Given the required specifications and operating conditions, use formula PG-29.1 to calculate the
required thickness of a seamless, unstayed dished head.
Learning Material
DISHED HEAD CALCULATIONS
The following Paragraphs from PG-29 must be considered when performing calculations on dished
heads.
•
Paragraph PG-29.1 states that the thickness of a blank, unstayed dished head with the
pressure on the concave side, when it is a segment of a sphere, shall be calculated by the
following formula:
The symbols in this formula are defined as follows:
t = minimum thickness of plates (mm)
P = maximum allowable working pressure (MPa)
L = radius (mm) to which the head is dished, measured on the concave side mm
S = maximum allowable working stress (MPa), using values Table PG-23.1
E = efficiency of the weakest joint used in forming the head (not including the joint that joins the
head to the shell) to the shell)
PW-12, Joint Efficiency Factors, states that for welded joints an efficiency of 1.0 (that is, 100%)
may be used provided all weld reinforcement on the joint is removed substantially flush with the
surface of the plate. Otherwise a joint efficiency not to exceed 90% shall be used. Seamless heads
have an efficiency of 100%.
•
Paragraph PG-29.2 states: “The radius to which the head is dished shall be not greater
than the outside diameter of the flanged portion of the head.” If two different portions of
the head are dished to different radii, then the longer radius shall be used as the value of
‘L’ in the formula.
•
Paragraph PG-29.3 states that when a head, dished to a segment of a sphere, has a
flanged-in manhole or access opening that exceeds 152 mm in any dimension, then its
thickness must be 15%, or 3.2 mm, whichever is greater, more than the thickness of a
blank unstayed head as calculated by the formula in PG-29.1.
Note: This would apply to a manhole such as is found on the end of a boiler drum.
•
Paragraph PG-29.6 states that no head, except a full-hemispherical head, shall be of
lesser thickness than required for a seamless shell of the same diameter.
•
Paragraph PG-29.5 states that in the case of a dished head with a flanged-in manhole, if
the dish radius ‘L’ is less than 80% of the diameter of the shell to which the head is
attached, then, when calculating the thickness by:
the value of ‘L’ must be made equal to 80% of the shell diameter. In addition, the thickness thus
calculated must be increased by the greater of 15% or 3.2 mm (PG-29.3) to compensate for the
flanged-in manhole. This method of calculation will give the minimum thickness for any form of
head having a flanged-in manhole.
Example 8:
Calculate the thickness of a seamless, unstayed dished head with pressure on the concave side,
having a flanged-in manhole 280 mm by 380 mm. The head has a diameter of 1235 mm and is a
segment of a sphere with a dish radius of 1016 mm. The maximum allowable working pressure is
1380 kPa, the material is SA-285 C and the metal temperature does not exceed 204°C.
Solution:
Since the head has a flanged-in manhole, the first thing to check: Is the radius of the dish at least
80% of the diameter of the shell, per
PG-29.5?
1016/1235 = 0.823 = 82.3 %
This is greater than 80%, so the value of L in the formula will be 1016 mm.
Use the formula from PG-29.1:
given that:
P = 1.380 MPa
L = 1016 mm (radius of the curvature of the sphere)
from Codes:
S = 95 MPa (Table PG-23.1 for SA-285, at 204°C)
substituting these values into the equation:
This would be the thickness of a blank head, that is a head with no manhole.
In this case there is a manhole and it exceeds the 152 mm allowed by PG-29.3. Therefore, the
thickness must be increased by 15% or by 3.2 mm whichever is greater.
15% of 15.37 mm = 0.15 x 15.37 = 2.306 mm
But this is less than 3.2 mm, so the thickness must be increased by 3.2 mm.
Therefore, the required thickness is:
15.37 mm + 3.2 mm = 18.57 mm (Ans.)
Example 9:
Calculate the thickness of a seamless, blank unstayed dished head having pressure on the concave
side. The head has a diameter of 1067 mm and is a segment of a sphere with a dish radius of 915
mm. The maximum allowable working pressure is 2068 kPa and the material is SA-285 A. The metal
temperature does not exceed 250°C.
Solution:
Since the head does not contain a manhole, PG 29.5 does not apply.
Using the formula from PG-29.1:
given that:
P = 2.068 MPa
L = 915 mm (radius of the curvature of the sphere)
from Codes:
S = 78 MPa (Table PG-23.1 for SA-285, at 250°C)
E = 1.0 (for seamless heads)
substituting these values into the equation:
From PG-29.6, the head in this example must be as thick as, or thicker than, a seamless shell of the
same diameter. Therefore, before we can confirm that the calculated thickness of 25.57 mm is
adequate, we must determine the shell thickness.
Calculate the shell thickness using the appropriate formula from PG-27.2.2
where:
C=0
y = 0.4
Since 25.27 is greater than 14.00 mm, the head thickness of 25.27 mm, as calculated before, is
adequate.
Example 10:
Calculate the thickness of the head in Example 9 if it has a flanged-in manhole.
Solution:
Since the head now contains a manhole, the first thing to check is conformance to PG 29.5.
L = 915 mm,
D = 1067 mm
and L/D = 915/1067 = 0.857 = 85.7%
This is greater than the 80% so our calculation for “t” in example 8 does not have to be modified,
i.e. t = 25.27 mm
According to PG-29.3, this thickness must be increased by the greater of 3.2 mm or 15%.
25.27 mm x 0.15 = 3.79 mm
Since this is greater than 3.2 mm, increase the thickness by 3.79 mm:
Head thickness
= 25.27 mm + 3.79 mm
= 29.06 mm (Ans.)
Self–Test Problems
7. Calculate the thickness required for a dished seamless head, which is attached to a
boiler having a shell diameter of 1200 mm. The head has a flanged-in manhole with one
dimension equal to 160 mm. The head is a segment of a sphere with a dished radius of
1120 mm. The head material is SA-285 Grade C, the maximum allowable working
pressure is 1930 kPa and the steam temperature does not exceed 260°C.
(Ans. 23.52 mm)
8. Calculate the thickness of a seamless blank unstayed dished head having pressure on
the concave side. The head has a diameter of 830 mm and is a segment of a sphere with
a dish radius of 615 mm. The maximum allowable working pressure is 1650 kPa, the
material is SA-299 and the metal temperature does not exceed 200°C.
(Ans. 8.13 mm)
Objective Four
When you complete this objective you will be able to…
Given the required specifications and operating conditions, use formulae in paragraphs PG-29.11
and PG-29.12 to calculate the required thickness of an unstayed, full-hemispherical head.
Learning Material
HEMISPHERICAL HEAD CALCULATIONS
When a boiler head is in the form of a complete hemi-sphere, termed “full-hemispherical”, the
requirements of Paragraph PG-29.11 apply. This paragraph states that the minimum required
thickness for a blank, unstayed, full-hemispherical head with the pressure on the concave side shall
be calculated by one the following two formulae:
Formula 1 is normally used. However, formula 2 may be used if the head exceeds 13 mm thickness
and is used for shells or headers that are designed according to PG-27.2.2, and if the head is
attached by fusion welding or is integrally formed on a seamless shell.
•
Paragraph PG-29.12 states if a flanged-in manhole, meeting code requirements, is placed
in a full-hemispherical head, then the thickness of the head is calculated using the same
formula as for a head dished to the segment of a sphere (per PG-29.1), with a dish radius
equal to 80% of the shell diameter and with the added thickness for the manhole. That is,
the following formula is used, where the value of ‘L’ in the formula is 80% of the diameter
of the shell.
Example 11:
Calculate the minimum required thickness, in mm, for a blank, unstayed, full-hemispherical head,
with the pressure on the concave side. The head is fabricated from seamless material and is double
butt welded to the shell. All reinforcement is removed and fully radiographed. The radius to which
the head is dished is 700 mm, maximum allowable working pressure is 4000 kPa, and the head
material (SA-285 C) will not reach a temperature greater than 340°C
Solution:
Use the formula from PG-29.11:
given that:
P = 4.0 MPa
L = 700 mm (radius of the curvature of the head)
from Codes:
S = 95 MPa (Table PG-23.1 for SA-285, at 340°C)
E = 1.0
substituting these values into the equation:
Example 12:
A seamless, welded, full-hemispherical head is welded to a boiler shell that has an inside diameter
of 1100 mm. Maximum working pressure is 3500 kPa, the material is SA-226, and operating
temperature is 300°C. The head has a flanged in manhole that meets code requirements. Calculate
the minimum required thickness for the head.
Solution:
Use the formula from PG-29.1: (per PG-29.12)
given that:
P = 3.5 MPa
from codes: S = 81 MPa (Table PG-23.1 for SA-226, at 300°C)
E = 1.0
L = 880 mm (80% of 1100 mm per PG-29.1)
substituting these values into the equation:
From PG-29.3, due to the manhole, this thickness calculation must be increased by the greater of
15% or 3.2 mm.
39.61 mm x 0.15 = 5.94 mm
Since this is greater than 3.2 mm, the thickness must be increased by this amount:
t = 39.61 mm + 5.94 mm
= 45.55 mm (Ans.)
Self–Test Problems
9. Calculate the minimum required thickness for an unstayed full-hemispherical head
with the pressure on the concave side if the head has the following specifications:
Inside diameter = 1.0 m
Pressure = 1500 kPa
Temperature = 285°C
Plate specification is SA-285 C
The head is fabricated from seamless material and is double butt welded to the shell. All weld
reinforcement is removed and has a flanged-in manhole that complies with the code.
(Ans. 16.36 mm)
10. What is the minimum required thickness for a blank, full-hemispherical head if the material of
construction is SA-515-65, operating temperature is 425°C, pressure is 1800 kPa, and the head is
dished to a radius of 870 mm?
(Ans. 46.17 mm)
Objective Five
When you complete this objective you will be able to…
Given the design and the steam generation capacity of a boiler, use information in paragraphs PG67 to PG-71 to calculate the minimum relieving capacity of the boiler safety or relief valve.
Learning Material
PG-67 – PG-72: SAFETY VALVES (and Safety Relief Valves)
Paragraphs PG-67 to PG-72 of ASME Code, Section 1, deal with safety valves and safety relief
valves. In particular, these sections cover the following topics:
•
PG-67 Boiler Safety Valve Requirements: the types and numbers of safety valves
required on the various types of boiler (that is, the boiler proper)
•
PG-68 Superheater Safety Valve Requirements: locations and capacities of
superheater and reheater safety valves
•
PG-69 Testing: rules for the testing of safety valve capacities by manufacturers
•
PG-70 Capacity: methods and requirements for relieving capacity of safety valves
•
PG-71 Mounting: required methods for attaching safety valves to boilers
•
PG-72 Operation: guidelines for the operating ranges of safety valve popping and
blowdown pressures
SAMPLE EXCERPTS RE SAFETY VALVES
The code requirements for safety and safety relief valves contain some very specific and technical
data The requirements differ significantly between different types of boilers, with special references
being made to specific types of boilers, such as electric, waste heat, once-through, hightemperature water boilers, and organic fluid vaporizer generators.
All rules cannot be covered here, and the student should at least review the sections to understand
where the special mentions are made. However, the following are a sample of some of the rules,
with respect to power boilers. Each sample is only a partial quote of its respective paragraph and
the student is advised to read the entire paragraph in the Extract or in the Code itself.
•
PG-67.1: “Each boiler shall have at least one safety valve or safety relief valve and if it has
more than 46.4 m2 of bare tube water-heating surface …….it shall have two or more safety
valves or safety relief valves…”
•
PG-67.2: “The safety valve capacity for each boiler shall be such that the safety valve, or
valves, will discharge all the steam that can be generated by the boiler without allowing the
pressure to rise more than 6% above the highest pressure at which any valve is set and in
no case more than 6% above the maximum allowable working pressure. The safety valve
capacity shall in compliance with PG-70 but shall not be less than the maximum designed
steaming capacity as determined by the manufacturer..”
•
PG-8.2: “The discharge capacity of the safety valve, or valves, on an attached superheater
may be included in determining the number and size of safety valves for the boiler ……….
provided the discharge capacity of the safety valve, or valves, on the boiler, as distinct from
the superheater, is at least 75% of the aggregate valve capacity required.”
•
PG-68.4: “Every reheater shall have one or more safety valves ……. The capacity of
reheater safety valves shall not be included in the required relieving capacity for the boiler
and superheater.”
•
PG-69.1: “Capacity test data reports for the initial certification of each valve model, type,
and size, signed by the manufacturer and authorized observer witnessing tests, shall be
submitted to the National Board of Boiler and Pressure vessel Inspectors for certification.”
•
PG-69.2: [paraphrased] (for a particular safety valve design). Tests shall be made (by the
manufacturer) to determine the lift, popping, and blowdown pressures and capacities ……..
A coefficient (of discharge) shall be established as follows:
The average K from the tests will be taken as the coefficient of design and shall be used for
determining the relieving capacity of all sizes and pressures of the design, in the following formula:
For flat seat valves:
W = (0.00525 x p D L P x K) x 0.90
where:
W = mass of steam/h (kg)
D = seat diameter (mm)
L = lift at 103% of set pressure (mm)
P = (1.03 x set gauge pressure) + 100 (kPa abs)
K = average coefficient of discharge
Note: There are other formulae for 45 deg seats and for nozzle-type safety valves.
PG-70: CAPACITY
PG-70.1 states that “the minimum safety valve or safety relief valve relieving capacity (for other
than electric boilers, waste heat boilers, organic fluid vaporizer generators, and forced-flow steam
generators with no fixed steam and water line) shall be determined on the basis of the kilograms of
steam generated per hour per square metre of boiler heating surface and waterwall heating surface
as given in the Table PG-70.”
Table PG-70 is as follows:
TABLE PG-70
MINIMUM KILOGRAMS OF STEAM PER HOUR PER SQUARE METRE OF
SURFACE
Boiler
heating
surface:
Hand fired
Stoker Fired
Oil, gas, or
pulverized
fuel fired
Waterwall
heating
surface:
Hand fired
Stoker fired
Oil, gas, or
pulverized
fuel fired
Firetube
Boilers
Watertube Boilers
25
35
30
40
40
49
40
49
40
59
69
79
PG-70.1 also states that “the minimum safety valve or safety relief valve relieving capacity for
electric boilers shall be 1.6 kg/h/kW input.
Example 13:
A stoker-fired firetube boiler has 62 m2 of heating surface. How much steam must the safety valve
on this boiler be capable of discharging per hour?
Solution:
From Table PG-70, a stoker-fired firetube boiler must have a safety valve that capacity of 35 kg/h
per metre of heating surface.
therefore:
Capacity
= heating surface (m2) x 35 kg/h/m2
(kg/h)
= 62 m2 x 35 kg/h/m2
= 2170 kg/h (Ans.)
Example 14:
A watertube boiler is gas-fired and has 65 m2 of boiler heating surface, plus 85 m2 of waterwall
surface. What is the minimum required relieving capacity for all the safety valves?
Solution:
From PG-70, a gas fired watertube boiler must have safety valve capacity of 49 kg/h for each m2 of
boiler surface, plus 79 kg/h for each m2 of waterwall surface.
Therefore:
Total
capacity
= capacity for boiler +
capacity for waterwalls
= (65m2x 49 kg/h/m2) +
(85m2 x 79 kg/h/m2)
= 3185 kg/h + 6715 kg/h
= 9900 kg/h (Ans.)
Example 15:
A watertube boiler, equipped with a superheater, has two safety valves on the steam drum and one
safety valve on the superheater. The boiler is fired on pulverized coal and has 70 m2 of boiler
surface, 95 m2 of waterwall surface, and 20 m2 of superheater surface. What is the minimum
combined relieving capacity permitted for the steam drum safety valves?
Solution:
From PG-70, a pulverized-fired watertube boiler must have a safety valve capacity of 49 kg/h for
each m2 of boiler surface, plus 79 kg/h for each m2 of waterwall surface.
Therefore:
Total
= capacity for boiler + capacity
capacityfor waterwalls
= (70 m2 x 49 kg/h/m2) + (95 m2
x 79 kg/h/m2)
= 3430 kg/h + 7505 kg/h
= 10935 kg/h
But, from PG-68.2, the boiler safety valves must have a minimum of 75% of the total capacity. So:
Min. capacity = 10935 kg/h x
of boiler
.75
valves
= 8201 kg/h
(Ans.)
Please note: Superheater area is NOT included in heating surface for capacity calculations
Fuels, Combustion, Flue Gas Analysis
Learning Outcome
When you complete this learning material, you will be able to:
Explain the properties and combustion of common fuels and the analysis of combustion flue gas
Learning Objectives
You will specifically be able to complete the following tasks:
1.
Explain/define complete combustion, incomplete combustion, combustion products, and
write balanced combustion equations
2. Explain the purpose and benefits of excess air and calculate the theoretical and excess air
required for the complete combustion of a given fuel.
3. Explain proximate analysis, ultimate analysis, and heating value of a fuel and describe the
use of calorimetry to determine calorific value.
4. Given the ultimate analysis of a fuel, use Dulong’s Formula to calculate the heating value of
the fuel.
5. Describe the properties, classifications and combustion characteristics of coal.
6. Describe the properties, classifications and combustion characteristics of fuel oil.
7. Describe the properties and combustion characteristics of natural gas.
8. Explain the use and combustion characteristics of non-fossil fuels, including biomass, wood
wastes, solid municipal wastes, coke, oil emulsions.
9. Explain the analysis of flue gas for the measurement of O2, CO, and CO2 in relation to
combustion efficiency. Describe typical, automatic flue gas analyzers.
10. Explain the formation, monitoring and control of nitrogen oxides (NOx), sulphur dioxide,
and particulates
Objective One
When you complete this objective you will be able to…
Explain/define complete combustion, incomplete combustion, combustion products, and write
balanced combustion equations.
Learning Material
COMBUSTION
Combustion is the chemical union of the combustible elements of a fuel and the oxygen in the air, at
a rate that produces useful heat energy. Air is a mixture of oxygen, nitrogen and small amounts of
water vapor, carbon dioxide and other gases. The principal combustible elements are carbon and
hydrogen, often combined as hydrocarbons. During combustion, they combine with oxygen to form
carbon dioxide and water. Small quantities of sulphur are often present in fuels and since sulphur is
combustible, it increases the heating value of the fuel. However, the corrosive and toxic nature of
sulphur compounds makes its presence undesirable.
The composition of dry atmospheric air is as follows:
Nitrogen
Oxygen
Other gases
% by volume
78.09%
20.95%
0.96%
% by mass
76.85%
23.15%
—
Perfect Combustion
Perfect combustion would occur when exactly the theoretically correct amount of air necessary was
supplied and the combustibles were all completely burned. This is impossible in any commercial
furnace because of the difficulty of contacting between the O2 and the combustibles in the presence
of large quantities of diluting gases. The products of perfect combustion would be CO2, SO2, H2O, N2
and ash.
Complete Combustion
Complete combustion occurs when all of the combustibles in the fuel are completely burned, but
more air than the minimum theoretically required is used (excess air). This is attainable in any
boiler furnace that is properly designed for the fuel being used and the load being carried. The
resulting stack gases will contain CO2, SO2, H2O, O2, N2 and ash.
There will be an increase in N2, above the value calculated for perfect combustion due to the
nitrogen supplied with the excess O2.
Complete combustion is attained with the following conditions:
•
Sufficient air must be admitted and some portion of this air must be admitted over and
close to the surface of the fire.
•
The temperature must be high enough to ignite the combustible gases given off.
•
The air must have a turbulent flow within the furnace to ensure that O2 contacts all the
combustibles present.
•
The gases must be in the hot zone for sufficient time for combustion to proceed to
completion.
Complete Combustion Equations
The following equations represent the combining of the carbon, hydrogen and sulphur combustible
elements, with oxygen, during complete combustion.
1. Carbon + produces Carbon Dioxide
Oxygen
C + O2 produces CO2
Hydrogen
2.
+
produces Water Vapor
Oxygen
2H2+ O2 produces 2H2O
Sulphur
3.
+
produces Sulphur Dioxide
Oxygen
S + O2 produces SO2
The nitrogen, being a non-combustible element, does not combine with oxygen, but passes through
the furnace unchanged, except for an increase in its temperature.
Incomplete Combustion
Incomplete combustion occurs when some of the C, CO and H2 pass to the stack. The stack gas will
consist of CO2, SO2, H2O, N2, CO, H2, C (carbon as soot), probably CH4 or other hydrocarbons and
may or may not contain free O2.
Incomplete Combustion Equations
If any of the requirements for complete combustion are missing, then the combustible elements will
not combine completely with oxygen. The following equations represent the incomplete combining
of the oxygen and the combustibles.
Carbon +
1 Insufficient
Oxygen
C + ½ O2
Hydrogen +
2 Insufficient
Oxygen
2H2 + ½ O2
produces Carbon Monoxide
--->
CO
produces Water Vapour + Free Hydrogen
--->
H2O + H2
The formation of the free hydrogen is undesirable because it is a combustible
element, which if not burned, will represent a waste of fuel.
3
Sulphur +
Insufficient
produces Sulphur Dioxide + Free Sulphur
Oxygen
2S + O2
--->
SO2 + S
Similarly, the formation of free sulphur is undesirable as it
represents a waste of fuel. The sulphur in a fuel is considered an
impurity although it is a combustible element; it tends to produce
corrosive acids in the presence of water.
Objective Two
When you complete this objective you will be able to…
Explain the purpose and benefits of excess air and calculate the theoretical and excess air required
for the complete combustions of a given fuel.
Learning Material
EXCESS AIR
Air is composed of a mixture of oxygen and nitrogen in the proportion of 23.15 parts of oxygen to
76.85 parts of nitrogen, by mass.
The oxygen required for complete combustion must be obtained from the air supplied to the
furnace. The amount of air required to supply, just enough oxygen for complete combustion is
called the “theoretical air”. However, in actual practice, it is necessary to supply more than this
theoretical amount of air in order to make sure that all particles of fuel come in contact with
oxygen.
The amount of air in excess of the theoretical air is called “excess air” and is usually expressed as
a percentage of the theoretical air. For example, if the theoretical amount of air required for the
complete combustion of 1 kg of a coal is 12 kg and the actual amount of air used in the furnace is
18 kg, per kg of coal, then the excess air = 18 - 12 = 6 kg. Expressed as a percentage, this would
be 6/12 x 100 = 50%.
The percent of excess air required depends on the fuel, the method of firing, the burner and furnace
design and the load on the boiler. Natural gas requires the least excess air and coal, the most. The
excess air is added to ensure that all of the fuel comes in contact with oxygen and that complete
combustion takes place.
Examples of required excess air, at the furnace outlet, are:
•
•
•
•
Natural gas 5 - 10 %
Oil 5 - 15 %
Coal (pulverized) 15 - 30%
Coal (stoker fired) 25 - 50%
It is desirable to reduce the amount of excess air supplied to the furnace as much as possible as the
air is heated to a high temperature in the furnace and carries a large amount of heat out through
the stack. In addition, the power required for forced draft and induced draft fans will decrease with
decreased air supplied. If the excess air is reduced too much, then there will be the possibility of
incomplete combustion occurring with formation of carbon monoxide and free hydrogen.
The efficiency of the boiler depends to some extent on the efficiency of the combustion. This
efficiency can be maximized when the boiler has a flue gas analyzer enabling the operator to
minimize excess air, while still maintaining complete combustion.
Designing the boiler, furnace and firing equipment for efficient combustion is the responsibility of
the manufacturer. Operating the equipment to obtain complete combustion, with the minimum of
excess air, is the responsibility of the operator.
Effect of Incorrect Excess Air
Too much air reduces the furnace temperature and so reduces combustion efficiency and may cause
solid carbon to be cooled and deposited as soot. The extra oxygen and nitrogen, leaving the stack at
an elevated temperature will further reduce efficiency since they carry off sensible heat. Too much
excess air may result in a pulsating flame and a flame that is pulled too far away from the burner.
Temperatures at the back of the furnace or further along the flue gas path may be elevated due to
increased velocities of the flue gas resulting in less time for heat transfer.
Too little air results in incomplete combustion. Results may include deposits of unburned solid
carbon as soot; the production of CO. When CO is present in the flue gas there are generally also
other combustible components. The furnace temperature is not necessarily increased because less
heat is liberated from the fuel. The flame may appear smoky and the flue gas leaving the stack may
be gray or black. Efficiency is reduced due to energy that has not been released by combustion.
Calculation Of Theoretical Air
Mass of Air for Combustion
The amount of air required to supply a specific quantity of oxygen must be calculated for a
combustion process. Since dry air is 23.15% oxygen by mass, each kilogram of air contains 0.2315
kg of oxygen. A simple proportion calculation:
Therefore, 4.32 kg of air will contain 1 kg of oxygen.
Formula for Required Air
Often fuels being burned are a mixture of combustibles. An analysis of the fuel gives the
percentage, by mass, of each ingredient or element in the fuel. Using basic combustion equations,
the number of kilograms of air required for each combustible element can be determined and
totaled to obtain the total required oxygen. The three combustible elements in any fuel are carbon,
hydrogen and sulphur.
The kilomole is defined as that quantity of a substance that has a mass in kilograms, equal to its
molecular mass. For example, the molecular or molar mass of water is 12. Therefore, a kilomole of
water is an amount of water having a mass of 12 kg. (See NPE3-1-12 for more detail.)
Carbon
Hydrogen
Sulphur
Thus, for 1 kg sulphur, 1 kg O2 is required. As calculated the air required to supply 1 kg of O2is 4.32
kg (Page 6).
These results of the carbon, hydrogen and sulphur formulas can be combined to give the following
formula:
Air required for 1 kg fuel = 11.52 x %C + 34.56 x %H2 + 4.32 x %S
When the analysis of the fuel indicates that it contains oxygen, it is assumed that the oxygen is
found as part of the water contained in the fuel. This means that some of the hydrogen in the fuel is
bound to water and is not available for combustion. The mass of hydrogen must be reduced in the
formula. Since the mass ratio of oxygen to hydrogen is 8/1 (that is, one kg of hydrogen requires 8
kg of oxygen to form H2O) the amount of hydrogen is reduced to
This changes the formula for theoretical air required to:
The previous calculations are all based on the equations for the complete combustion of carbon,
hydrogen and sulphur. It must be remembered that incomplete combustion of carbon to carbon
monoxide is possible and should be avoided, as carbon monoxide is a combustible and toxic gas.
Theoretical Air Required
Given the following analysis of coal, calculate the theoretical amount of air required:
Note that ash and nitrogen are incombustible. Using the formula derived for theoretical air required:
Each kilogram of fuel burned will require a theoretical air supply of 10.21 kg.
Calculation of Excess Air
Since in the operation of a boiler, theoretical conditions are never attained, it is important that the
foregoing calculations be tied in with practical conditions.
The mass of air theoretically required for the combustion of one kg of dry coal is (from the above
tabulation) 10.21 kg. For each 20% in excess of this amount (that is, each 2.042 kg above 10.21)
there will appear in the products of combustion:
2.042 x 0.2315 = 0.4727 kg O2
2.042 x 0.7685 = 1.5693 kg N2
Objective Three
When you complete this objective you will be able to…
Explain proximate analysis, ultimate analysis, and heating value of a fuel and describe the use of
calorimetry to determine calorific value. Explain higher and lower calorific values.
Learning Material
FUEL ANALYSIS
It is necessary to analyze a fuel to determine its constituents, as these determine the fuels burning
characteristics, the amount of air that will be required for combustion, and the heating value of the
fuel. Two methods of analysis are used, the proximate analysis and the ultimate analysis.
Proximate Analysis
This analysis is performed on a solid fuel like coal to determine the percentages of moisture, volatile
material, fixed carbon and ash. This will indicate the behavior of the fuel in the furnace, to some
extent, and will suggest the best method of firing the fuel.
The procedure is to take three weighed samples, one for each part of the analysis. The first sample
is dried for one hour in an oven, at 105°C, and then weighed again. The percentage of moisture will
be the loss of mass divided by the original mass of the sample, and the result, times 100.
The second sample is heated for seven minutes in a covered oxygen free container, to 954°C. The
loss of mass represents both moisture and volatile material, and the percentage of volatile material
is obtained by subtracting the percentage of moisture, determined earlier.
The third sample is heated for two hours, at 760°C, to achieve complete combustion. The residue is
the ash content.
The percentage of fixed carbon is taken to be the difference between 100 and the sum of the ash,
volatile material and moisture percentages.
An example of a proximate analysis is:
Fixed
carbon
Volatile
matter
Moisture
Ash
57.43%
34.67%
2.71%
5.19%
Ultimate Analysis
The proximate analysis is sufficient for the determination of the burning qualities of a fuel, but a
more detailed analysis is required for combustion calculations. This detailed analysis, called the
ultimate analysis, determines the elements present, such as carbon, nitrogen, oxygen, hydrogen
and sulphur, by chemical methods. This must be done, in a laboratory, by a qualified chemist.
The ultimate analysis of the same coal used in the proximate analysis is:
Carbon 79.71%
Hydrogen5.29%
Sulphur 1.26%
Oxygen 7.13%
Nitrogen 1.42%
Ash
5.19%
Since the proximate and ultimate analyses are based on mass percentage, the ash content will be
the same, for both. The carbon content, in the ultimate analysis, is both the fixed carbon and the
carbon, in the volatile material. Therefore, the carbon percentage, in the ultimate analysis, is
greater than in the proximate analysis.
The analyses may be expressed in several ways:
a) As received, or as fired
b) Dry or moisture free
c) Moisture and ash free
In method (a), the constituents are listed as found in the fuel as received, or as fired in the furnace.
The moisture content is included in the hydrogen and oxygen content.
In method (b), the mass of the moisture is removed and the constituents are listed as a percentage
of the remaining mass of fuel.
In method (c), both the mass of the moisture and ash are removed and the constituents are listed
as a percentage of the remaining mass of fuel.
Heating Value
When a unit amount of a fuel is burned completely, the heat, produced by this combustion, is called
the heating value or calorific value of the fuel. It is expressed as kJ/kg, for solid and liquid fuels,
and kJ/m3, for gaseous fuels. In the case of a gaseous fuel, the cubic metres are measured at
standard conditions of 16°C and 101.3 kPa.
Two methods are used to determine the heating value of a fuel:
•
By calculation, based on the ultimate analysis of the fuel.
•
By burning a sample of the fuel and measuring the heat produced, in an instrument, called
a calorimeter.
The first method is based upon the knowledge that, when burned:
•
1 kg of carbon will produce 33 890 kJ
•
1 kg of hydrogen will produce 143 900 kJ
•
1 kg of sulphur will produce 9 290 kJ
These values having been obtained by experimentation. Therefore, if the amount of carbon,
hydrogen and sulphur contained in the fuel is known from the ultimate analysis, then the heating
value, of the fuel, can be calculated.
In the second method, where a calorimeter is used, a measured mass of a solid or liquid fuel or a
measured volume of a gaseous fuel is burned in the presence of sufficient air to ensure complete
combustion. The heat produced is absorbed by a measured amount of water contained in a jacket
around the fuel container. The temperature rise of the water is measured and, in this way, the
amount of heat produced is determined. The outside of the calorimeter is insulated to prevent the
escape of heat to the surrounding atmosphere.
Calorimetry
Calorimetry is an experimental procedure that measures the amount of energy (heat) transferred,
in order to determine the thermal properties of a substance. The instrument, used for this
measurement, is a calorimeter and the most common type, for the determination of heating values,
is the ‘oxygen-bomb’ calorimeter.
The calorimeter, as shown in Figs. 1 to 4, consists of:
•
The bomb in which the fuel sample is burned.
•
The bucket, holding a measured amount of water and the bomb.
•
The jacket, protecting the bucket from variations in room temperature and drafts.
•
The thermometer, usually 60 cm long and graduated from 19°C to 35°C, in 0.02°C
increments.
Figure 1
Parts of a Bomb Calorimeter
Figure 2
Bomb of a Bomb Calorimeter
Figure 3
Assembled Calorimeter
Figure 4
Cross-Section of a Bomb Calorimeter
Procedure
The fuel sample, approximately 1 gm and weighed to four decimal
places, is placed in a crucible in the bomb with an ignition wire
placed just above the sample. The bomb is closed and charged
with oxygen to a pressure of 2000 to 2500 kPa. The bomb is placed
in the bucket and a measured mass of water, generally 2 kg, is
poured into the bucket. The calorimeter cover, with the mixer and
thermometer, is put on and the mixer started. When the
temperature has stabilized, usually after about 5 minutes, power is
applied to the ignition wire and an explosive combustion occurs.
The heat, produced by the combustion of the fuel, is transferred to
the water, causing a rise in temperature. The rise, in temperature,
is applied to the formula supplied with the instrument, and the
value, so calculated, is the higher calorific value (kJ/kg), as the
heat from any water vapor in the bomb is transferred to the outside
water bucket and the water remains as a liquid, inside the bomb.
Higher and Lower Calorific Value
The calorific values, determined through the use of calorimetry or
by Dulong’s formula, are called the higher heating or calorific
values. These higher heating values include the latent heat of the
water vapor in the products of combustion. The use of Dulong’s
formula will be explained in the next objective. They represent the
total energy released by the complete combustion of a unit
quantity of fuel.
In actual boiler operation, the water vapor in the combustion gas
leaving the boiler is not cooled below the dew point. Therefore, the
latent heat is not available to make steam. Subtracting the latent
heat, from the higher calorific value, gives the lower calorific value.
This reduction of the heating value, in kJ/kg of fuel, is equal to the
total mass of water vapor per kilogram of fuel, (moisture in the fuel
plus vapor formed by combustion of hydrogen in the fuel),
multiplied by the latent heat of evaporation.
Objective Four
When you complete this objective you will be able to…
Given the ultimate analysis of a fuel, use Dulong’s Formula to calculate the heating value of the
fuel.
Learning Material
HEATING VALUE
The calorific, or heating value of fuel, can be calculated using the results of the ultimate analysis of
the fuel. From the fuel analysis, the percentages of combustibles (carbon, hydrogen and sulphur)
are known. Since the heat of combustion of these elements is known, it is quite easy to calculate
the calorific value of fuels. Table 2 shows the heat of combustion for carbon, hydrogen and sulphur.
Example 1:
Calculate the heating value of a fuel with the following ultimate analysis:
Solution:
The chemical heating value of a fuel is calculated using Dulong’s Formula. It is:
Where C, H, and S represent the mass of carbon, hydrogen, and sulphur respectively per kilogram
of fuel. The result is in MJ per kg of fuel.
Using the analysis given in example 1, the calorific value, by Dulong’s formula, is:
Objective Five
When you complete this objective you will be able to…
Describe the properties, classifications and combustion characteristics of coal.
Learning Material
COAL CLASSIFICATIONS
The American Society for Testing and Materials, ASTM, classifies coal into four main groups, with
several sub classifications (see Table 1). The four main groups are:
•
•
•
•
Anthracite
Bituminous
Sub-bituminous
Lignite
Anthracite
Anthracite coal is hard, dense, very brittle and shiny black with no layering. It has a high
percentage of fixed carbon and a low percentage of volatile matter, mostly methane (CH4).
Anthracites include a variety of slow burning fuels, merging into graphite at one end of the
classification and, into bituminous coal, at the other end. Most anthracite coals have a lower heating
value than the highest grade of bituminous coal.
Anthracite coal is expensive, has a high ignition temperature and burns slowly. This makes it an
unsuitable fuel for utility boilers.
Semi-anthracites are dark gray and distinctly granular. They have lower percentages of fixed carbon
and higher percentages of volatile matter. The lower fixed carbon content makes them burn, faster,
and the higher volatile matter content lowers the ignition temperature. This increases the stability of
the ignition.
Bituminous
Bituminous coals form the largest group. The name derives from their tendency to produce a sticky,
cohesive mass, when heated. The carbon content is lower than that of anthracite, but the volatile
matter content is higher. The composition of the volatile matter is more complex than in anthracite
and the calorific value is higher.
Bituminous coals burn easily, especially when pulverized. They are not well suited for use with
stokers as they bake on the surface of the coal bed, prevent an even air supply, and cause
unburned fuel losses.
Low volatile bituminous coal is grayish black and granular. High volatile coal is distinctly laminar in
structure with thin layers of shiny black coal alternating with dull, charcoal-like layers. Medium
volatile coal is in transition from the high volatile to the low volatile coal. They have the
characteristics of both, as some are granular, soft and easily crumble while others have a faint
indication of a layered structure.
Sub-Bituminous
These coals are black in colour and have high moisture content. They disintegrate when exposed to
air and are difficult to store. When burning, they do not cake but burn freely. Due to their high
moisture content, they are not usually shipped for power plant use.
Lignite
Lignite coals are dark brown, with a laminar structure, often with remnants of woody fibers,
present. The name comes from the Latin “lignum”, meaning wood. Freshly mined lignite is tough
but not hard, and on exposure to air, it loses moisture rapidly and crumbles. Even when it appears
quite dry, the moisture content of lignite may be as high as 30%. Due to its high moisture content
and low heating value, it is not economical to transport lignite over long distances. As lignite is
found close to the surface, it is easy to strip mine and is used extensively in nearby thermal power
stations.
Table 1 provides an overview of the main classes of coal and their sub groups. Since this is an ASTM
standard, the calorific values are given in US Customary units. To convert Btu/lb to kJ/kg, multiply
Btu/lb by 2.326. For example, Bituminous 3, has a calorific value of 32 564 kJ/kg (14,000 Btu/lb x
2.326).
Table 1
Classification of Coals by Rank
Typical Coals
Table 2 shows the constituent percentages of some typical coals.
District Fixed Volatile Moisture Ash Heat
Value Carbon (kJ/kg)
Table 2
Constituent Percentages of Coals
Objective Six
When you complete this objective you will be able to…
Describe the properties, classifications, and combustion characteristics of fuel oil.
Learning Material
FUEL OIL
Crude petroleum is sometimes burned, but it usually contains lighter gasoline fractions, which lower
the flash point and, therefore, presents a fire hazard. Limited fractional distillation, or topping,
removes the lighter gasolines and produces a safe fuel oil.
The term fuel oil covers a wide range of petroleum products from crude petroleum through to a light
fraction similar to kerosene, or gas oil, and to a heavy residue, after distilling off the gases, gasoline
and some of the kerosene. Referring to Table 3, specifications have been established for several
grades of fuel oil. Fuel oil, used for steam generation, is petroleum or a liquid residue remaining
after the more volatile petroleum constituents have been removed.
Mainly, the temperature of their distillation range specifies grades No. 1 and 2, sometimes called
light and medium domestic fuel oil. Grade No. 6, heavy industrial fuel oil or Bunker C oil, is specified
mainly by viscosity. The specific gravities of Grades No. 4, 5 and 6 are not specified, as they will
vary with the source of the crude petroleum and the extent of the refining process. Despite the
great number of chemical compounds found in fuel oils, the analyses of these oils are fairly
constant.
Specific Gravity
Specific gravity is the ratio between the mass of a volume of oil, at 15°C, and the mass of an equal
volume of water, at 15°C. The common designation is SpGr 15/15°C and is expressed as a decimal,
to four places. It is generally measured with a hydrometer.
Heating Value
The heating value of fuel oil, expressed as kJ/kg, varies inversely with the specific gravity. This is
due to the fact that the hydrogen content increases as the oil becomes lighter. It ranges from 42
566 kJ/kg to 45 350 kJ/kg.
Table 3 gives some typical properties for fuel oils.
Table 3
Typical Analyses and Properties of Fuel Oils
Viscosity
Viscosity is defined as the resistance to flow. It can be measured in a viscosimeter and is expressed
in units of Saybolt Universal viscosity. The viscosity is the time, in seconds, for 60 cm3 of oil to run
through a standard size orifice, at 38°C.
Viscosity of fuel oil decreases as the temperature increases and becomes nearly constant, above
120°C. Therefore, when fuel oil is heated to reduce the viscosity to allow proper atomization, there
is little to be gained by heating the oil above this 120°C. It is also desirable to operate in the
viscosity range where temperature variations have least effect as burners operate most efficiently
with oil of constant viscosity.
Flash Point
The flash point, of a fuel oil, is the lowest temperature at which sufficient vapor is present to form a
momentary flash, when a flame is brought near the oil.
Fire Point
The fire point, of a fuel oil, is the lowest temperature at which continuous combustion is possible.
Pour Point
The pour point, of a fuel oil, is the lowest temperature at which oil will flow.
Combustion of Oil
Oil can be vaporized into the gases of its component hydrocarbons if the temperature is sufficiently
high. This is seldom the case in the short time available in the combustion chamber. In practice, the
oil is atomized, by the use of steam, air, or mechanically, into extremely small portions. This is to
present more surface for collecting heat and thereby, promoting vaporization. The majority of oil
burners produce a white flame that indicates some solid carbon is burning separately.
Objective Seven
When you complete this objective you will be able to…
Describe the properties and combustion characteristics of natural gas.
Learning Material
NATURAL GAS
Of all the fossil fuels, natural gas is the most desirable for steam generation purposes. It is free of
ash and mixes readily, with air, to give complete combustion with low amounts of excess air.
Raw natural gas may be ‘sweet’ gas or ‘sour’ gas. ‘Sweet’ gas is free of hydrogen sulphide and is
sometimes used directly for boiler operation. Apart from this exception, natural gas is refined before
use.
Natural gas, from a well, is a mixture of the following gases:
•
•
•
•
•
•
•
•
Methane (CH4)
Ethane (C2H6)
Propane (C3H8)
Butane (C4H10)
Hydrogen sulphide (H2S)
Nitrogen (N2)
Carbon dioxide (CO2)
Traces of other gases
A typical analysis of sour natural gas is listed below with the values as volume percentages.
In the refined gas, only the hydrocarbons are left and the N2, CO2, H2S and any moisture are
removed. Products, such as ethane (C2H6), propane (C3H8) and butane (C4H10), are removed and
sold separately. The remaining natural gas, which is used for combustion, is greater than 95%
methane (CH4).
Refined natural gas is colorless and odorless. An odorant, usually a mercaptan, is added for
purposes of detecting a natural gas leak. A proper natural gas flame will be blue with a yellow tip,
and is highly explosive, when mixed with the correct proportion of air.
The advantages of natural gas firing are:
•
A storage facility is not required
•
As it is clean burning, no ash is produced to leave deposits on the heating surfaces
•
Stack emissions are relatively clean as the flue gas contains essentially only N2, CO2, and
H2O
•
It can be easily mixed with air
•
It does not require any extensive handling equipment in the plant
•
It is easy to control
The disadvantages of natural gas firing are:
•
The hydrogen content in the gas decreases the efficiency of combustion (i.e. heat available
to transfer energy to the boiler) as each kilogram of hydrogen produces 9 kg of H2O
(water). This leaves the boiler as superheated water vapor with an approximate loss of
2800 kJ/kg of water or 2800 x 9 = 25 900 kJ/kg hydrogen burned. This is evident on a cold
day as the visible water vapour exiting the stack.
•
It is usually more expensive than the solid and liquid fuels.
•
Its use involves the use of long large diameter pipelines for transmission to the plant.
•
The heating value of natural gas will vary according to its constituents and, expressed in
terms of mass, will generally run from 46 420 to 55 700 kJ/kg. However, it is more usual to
rate the heating value for a gas in terms of volume. Natural gas usually has a value of
about 37 250 kJ/m3, at a standard temperature and pressure of 16°C and 101.3 kPa.
Objective Eight
When you complete this objective you will be able to…
Explain the use and combustion characteristics of biomass fuels, including wood wastes and solid
municipal wastes, coke and, oil emulsions.
Learning Material
BIOMASS FUELS
Biomass fuels are any fuel sources that are, or were, alive. Specific examples include grass, leaves,
vines, coffee grounds and other waste products from the food industry. These products have always
been used as a source of fuel, but only recently, has there been sufficient pressure to develop
commercial systems for their utilization. Increased costs of fossil fuels, shortages of landfills,
advances in technology and the use of co-generation systems have made biomass fuels viable as
alternative sources of heat and electricity.
The heat and electricity, produced by the combustion of biomass products, is generally utilized by
the production facility producing the waste products. Facilities, that do not require all of the energy
released by the combustion of biomass, have the ability to sell the excess electricity produced.
Municipal wastes generally contain large amounts of biomass material that may be suitable for use
as a fuel. The biomass fuels may be fired alone or in combination with gas, oil or coal.
Wood Wastes
The wood industry produces large amounts of bark, sawdust, wood chips, and sludge from clarifier
equipment. These products may be utilized to produce steam for process heating requirements or
for the production of electricity for internal use, or sale. Wood products with moisture contents as
high as 65% may produce stable combustion in water-cooled furnaces. Preheated combustion air is
utilized to reduce the time required to dry the fuel, prior to ignition. Air entering above the grate or
burner area, is utilized to ensure that the volatile gases produced are completely burned. The
heating value of dry wood bark is about 20 000 kJ/kg.
Solid Municipal Wastes
Solid municipal wastes over the last several decades have changed dramatically due to conservation
programs and changes in the manner in which foods are packaged. The heating value of the waste
is increasing and the moisture content is decreasing. The heating value of municipal waste varies
from approximately 6 000 kJ/kg to 15 000 kJ/kg, depending on the moisture content (20% to 35%)
and the combustible compounds (15% to 35%).
There are two general methods of burning municipal wastes. One method involves the removal of
large non-combustibles such as metal and appliances, with the rest of the waste products pushed
onto stoker grates. The ash and other non-combustibles, enters an ash pit for reclamation or
disposal. Another method involves the preparation of the fuel prior to entering the furnace area,
with recyclable products removed and the combustibles sorted and delivered to the furnace.
Coke
Petroleum cracking produces heavy residuals that may be suitable as fuel. The heavy residuals are
heated in a reactor producing a solid mass (coke). The coke is pulverized and burned on a grate in a
Cyclone furnace, or on a fluidized bed. Regardless of the firing method, coke generally requires a
supplemental fuel for ignition and proper combustion. Coke has a heating value of about 35 000
kJ/kg.
Oil Emulsions
Very small droplets of oil are suspended in water and are prevented from coming together, through
the use of chemicals. The oil emulsions can be used as a fuel having similar properties and handling
characteristics, to fuel oil. Bitumen oil emulsions are finding use as a fuel in areas where heavy oils
are extracted with large amounts of water.
Firing
Each of the above fuels has their own unique firing problems and methods. The determination of the
type of firing method will depend on the particular fuel that is being used. Corrosion of furnace parts
and the removal of particulate material must be addressed, for each particular fuel. The use of
biomass produces less sulphur dioxide and nitrogen oxides, than fossil fuels.
Objective Nine
When you complete this objective you will be able to…
Explain the analysis of flue gas for the measurement of O2, CO, and CO2 in relation to combustion
efficiency. Describe typical automatic flue gas analyzers.
Learning Material
FLUE GAS ANALYSIS
When an analysis of the flue gas is made, the volume percentages of CO2, O2 and CO are
determined. While the flue gas may also contain some SO2 and water vapor, the percentages of
these are not normally obtained. The SO2 content is so small that it may be neglected and the water
vapor does not provide a guide for combustion efficiency.
If a fuel composed entirely of pure carbon were burned completely with no excess air, then the part
of the air that combined with the carbon would be the oxygen that makes up 21% of the air
volume. The volume of CO2 formed by the combining of the oxygen with the carbon, will be equal to
the volume of the oxygen, which it has replaced and will therefore be 21% of the flue gas. The
other 79% by volume of the flue gas will be nitrogen.
If excess air is used in the burning of the carbon, then the nitrogen percentage in the flue gas will
increase. In addition there will be a percentage of O2 present because of the excess air providing
more O2 than is needed, to combine with the carbon. As a result, the CO2 percentage will decrease.
If a fuel consisting of hydrogen and carbon is burned completely without excess air, there will be
H2O from the combustion of the hydrogen as well as CO2 in the flue gas. As a result, the CO2
percentage will be reduced. The higher the percentage of hydrogen in the fuel, the lower will be the
percentage of CO2, in the flue gas.
The maximum CO2 content of flue gas for various fuels are, as follows:
•
•
•
For coal, approximately 19%
For oil, approximately 15.5%
For natural gas, approximately 12%
These figures are for combustion with no excess air. If excess air is used, as it would be in actual
practice, the above percentages will be reduced in accordance with the amount of excess air. For
example, coal burned with 50% excess air will give a percentage of CO2, in the flue gas, of
approximately 12%.
Automatic Gas Analyzers
There are numerous devices for analyzing the flue gases leaving a boiler furnace. These devices are
usually arranged to continuously draw a sample of flue gas from the stack, analyze it and record the
results of the analysis on a chart. Some types only determine the CO2 content of the sample, while
others are designed to analyze the O2 component. Another type analyzes the flue gas sample for O2
and combustibles, such as CO and H2.
Fig. 5 illustrates the arrangement of an automatic gas analyzer that determines both the O2 and
combustible content of the flue gas. Referring to Fig. 5, the sample of the flue gas is withdrawn
from the boiler and supplied to the analyzer, under pressure, by a water operated aspirator or
injector. Two pressure regulating valves; placed in series, control the pressure of the sample. These
regulating devices consist of free floating valves that float on the gas stream and, if the gas sample
pressure increases, then these valves will rise and allow some of the gas to escape to atmosphere.
Conversely, if the gas sample pressure drops, then the valves will lower and reduce the escape of
the gas to the atmosphere. In this way, the gas sample pressure is maintained at a constant value,
which is determined by the weight of the valves.
After passing through the pressure regulating valves, a portion of the gas sample is bled off through
the oxygen analyzer sample orifice to the oxygen analyzer cell. Another portion of the sample is
bled off through the combustibles analyzer sample orifice to the combustibles analyzer cell. After
passing through the oxygen sample orifice, this portion of the gas sample is mixed with hydrogen
supplied from a storage cylinder. This mixture of sample gas and hydrogen now passes into the
oxygen analyzing cell, which contains two platinum filaments. Enough electrical current is passing
through these filaments to cause them to glow. One of these filaments is called the “measuring
filament” and the gas mixture has free access to it. The other filament is called the “compensating
filament” and only a small amount of the gas mixture can contact it.
Figure 5
Automatic Gas Analyzer
When the mixture of sample gas and hydrogen comes in contact with the hot filaments, the
hydrogen, in the mixture, will begin to burn. The amount of combustion and, therefore, the amount
of heat produced from this combustion, will depend upon the amount of oxygen contained in the
flue gas sample, as this is the only oxygen available to combine with the hydrogen.
The measuring filament will be heated by this combustion, to a greater extent than the
compensating filament, as the measuring filament is exposed to a greater amount of the burning
gas. The electrical resistance, of the measuring filament, will be increased to a greater extent than
that of the compensating filament, due to this heating. The change, in electrical resistance, is
measured automatically and is proportional to the oxygen percentage, in the gas sample. This
percentage is then indicated on a recorder.
The portion of the gas sample that passes through the combustibles orifice mixes with compressed
air, which is supplied at a regulated pressure from a compressed air source. The mixture of sample
gas and air then enters the combustibles analyzing cell which, like the oxygen analyzing cell,
contains two platinum filaments, one a measuring filament and the other a compensating filament.
This mixture has free access to the measuring filament while the compensating filament comes in
contact with only a small amount of the mixture.
If any combustibles are present in the gas sample, they will combine with the oxygen from the
compressed air, and burn. The heat produced, will increase the resistance of the measuring filament
to a greater extent than that of the compensating filament. This change will be proportional to the
combustibles percentage in the sample. This percentage can then be indicated on a recorder.
The block, containing the analyzing cells, is maintained at a constant temperature by means of a
thermostatically controlled heater element. Pressure sensitive alarms are used on the sample gas
inlet line and on the compressed air inlet line, to indicate failure of the supply of either one.
Objective Ten
When you complete this objective you will be able to…
Explain the formation, monitoring and control of nitrogen oxides (NOx), sulphur dioxide and,
particulates
Learning Material
NITROGEN OXIDES
Formation
Nitrogen oxides, generally called NOx, are composed primarily of nitrogen monoxide (NO) and
nitrogen dioxide (NO2). The majority of the NOx formed, greater than 90%, is nitrogen monoxide
(NO). However the calculations for concentrations are normally expressed as nitrogen dioxide
(NO2). The nitrogen may originate from atmospheric air, in which case the products are known as
“thermal NOx”. The nitrogen may also be an organically bound component of fuels such as oils and
coals, in which case the products are known as “fuel NOx”.
The amount of NOx formed, is dependant on the:
•
•
•
•
Temperature
Time for reaction
Mixing
Amounts of nitrogen, and oxygen, available
Thermal NOx is rapidly formed when the combustion temperatures exceed approximately 1500°C,
and is the predominate product when burning natural gas or other low nitrogen content fuels.
Fuel NOx is dependant on the fuel nitrogen content and the volatility of the fuel, and is the
predominate product, up to 85%, when burning fuels high in organically bound nitrogen.
Control
The amount of NOx formed, can be controlled by:
•
•
Restricting the amount of excess air used in combustion
Reducing the temperature in the combustion zone
Two-stage combustion supplies less air than that theoretically required for complete combustion at
the burners. Additional overfire air is supplied above the main combustion area to complete the
combustion process. Reburning, an NOx reducing strategy, involves staging of both the air and the
fuel in the combustion process. Flue gas recirculation for the reduction of thermal NOx, involves the
recirculation of a percentage of the flue gas back to the burner. The control of NOx in the
combustion process, involves specific design of burners and furnaces. These burners and furnaces
are discussed in another module. NOx control after the combustion zone, may be through the use
of:
•
•
Non-catalytic process
Catalytic process
Non-Catalytic Process
An example of the non-catalytic removal of NOx as shown in Fig. 6, is the addition of ammonia to
the flue gas. This system consists of the storage and handling equipment for mixing the chemical
with the carrier (compressed air, steam or water) and the injection equipment. The liquid ammonia
is fed to a vaporizer where it is vaporized into a gaseous state. It is mixed with the carrier and fed
to the injection unit. This gaseous mixture is then injected into the flue gas stream. It combines
with the nitrogen oxides, in the temperature region of 750°C – 1100°C, and water vapour is
formed.
The main component is the injection system and consists of nozzles located at various elevations in
the furnace walls to match the expected flue gas operating temperatures. The number and location
of the nozzles are established by the supplier and are based on obtaining good reagent distribution
within the flue gas.
Figure 6
Non-Catalytic Removal of NOx System
The non-catalytic removal of NOx is generally restricted to smaller units, using fuels with low
nitrogen content. The addition of these chemicals may result in other undesirable products leaving
the stack or with corrosion and fouling of equipment.
Catalytic Process
With the catalytic system, the highly efficient removal of NOx is achieved through the addition of
ammonia in the presence of a catalyst. This is the most effective method of reducing NOx
emissions, especially where high removal efficiencies, 70 to 90%, are required. The effective
temperature range is between 250°C and 450°C. The catalyst used may be base metals, such as
titanium oxide, or Zeolites such as aluminosilicate. Precious metals such as platinum can also be
used.
The NOx reduction takes place as the flue gas passes through the catalyst chamber. Before entering
the catalyst, ammonia is injected into and mixed with the flue gas, as shown in Fig. 7. Once the
mixture enters the catalyst, the NOx reactions with the ammonia (NH3) are shown, as
follows:
Figure 7
Catalytic Removal of NOx System
SULPHUR DIOXIDE
Formation
Sulphur dioxide is formed when fuels containing sulphur are used in the combustion process.
When this gaseous SO2 combines with liquid water, it forms a dilute aqueous solution of sulphurous
acid ((H2SO3).
Sulphurous acid can easily oxidize in the atmosphere to form sulphuric acid (H2SO4). Dilute
sulphuric acid is the major component of acid rain.
Control
The control of sulphur dioxide is best achieved by burning fuels with no sulphur content, such as
natural gas, certain oils and selected coals. Selecting a low or zero sulphur content fuel in the
design stage or retrofitting a plant to burn these fuels may be a practical consideration. However,
economic considerations may make this alternative too expensive.
Certain combustion modifications such as the use of a fluidized bed of limestone, will not only
reduce nitrous oxides but will also significantly reduce sulphur dioxide emissions by the combination
of sulphur dioxide with the limestone.
Another control strategy for dealing with sulphur dioxide is the injection of a calcium sorbent
material into the flue gas stream, at an optimum temperature. The sorbent material reacts with the
sulphur dioxide. Examples of calcium sorbents include lime (CaO) and hydrated lime (Ca(OH)2). A
typical reaction is, as follows:
Wet and dry scrubbing involves the injection of slurry made up of water and a sorbent material such
as those stated above. The waste products formed are either wet or dry, depending on the style of
the reactor vessel used. The wet products may be removed for the recovery of usable products. The
dry products formed must be removed by particulate control equipment.
PARTICULATES
Formation
Other than natural gas, all fossil and most biomass fuels contain varying quantities of ash. Some of
the ash produced will drop to the bottom of the furnace and can be removed. The remaining ash is
called flyash and is carried out of the furnace with the flue gas. The amount of particulate matter
produced will depend on the fuel used and the firing method. Coals can have an ash content ranging
from 5% to 30%.
The amount of fly-ash leaving with the flue gas varies with the method of firing, as per the
following:
•
•
•
•
Pulverized coal - up to 90% of the ash content
Cyclone furnace - up to 40% of the ash content
Stoker firing - up to 40% of the ash content
Fluidized bed furnaces - all of the ash traveling out of the furnace
The composition of the fly-ash includes but is not limited to oxides of silicon, titanium, iron,
aluminum, magnesium, calcium, potassium, sodium, and sulphur.
Control
Cyclone separators produce a centrifugal force on the particulate matter to effectively remove larger
particles from the flue gas. For very fine particulate matter, the efficiency of a cyclone type
separator may drop to 90%.
Fabric filters or bag houses, will allow the flue gas to pass through while collecting the particulate
matter. Bag house filters have the disadvantage of requiring high fan power. However they can be
greater than 99% efficient in the removal of particulate matter.
Electrostatic precipitators negatively charge the particles using high voltage DC charging plates. The
particles collect on grounded plates and are then removed. Electrostatic precipitators have an
efficiency of greater than 95%.
Monitoring
Continuous monitoring of emissions has been developed to meet the increasing regulation
requirement for all types of industrial plants. Continuous monitoring analyzers may be of three
different types:
a) Extraction type analyzers, used where the monitoring equipment is close to the sample point
b) Dilution - extraction type analyzers, use a carrier such as instrument air to distribute a dilute
sample to an analyzer that is a long distance from the flue gas sample
c) In-situ analyzers, directly located in the flue gas path
Generally the analyzers consist of a measuring cell and a reference cell. The instruments are zeroed
and the span adjusted using air or a standard calibration gas. The voltages across the measuring
and reference cells are measured and compared, to determine the composition of the flue gas.
Specific cells are used to analyze each substance being measured.
One method of measuring nitrous oxides is by injecting ozone into the sample. The ozone reacts
with the NOx generating a light that is measured by a photocell. A second method is by using a light
detector to measure the concentration of a specific constituent, after infrared light is passed through
a measurement filter.
Particulate matter can be measured through the use of an in situ transmissometer analyzer, as
shown in Fig. 8. A transmissometer is an instrument for measuring the transmission of light through
a fluid (as the atmosphere). Passing a light through the flue gas and using a mirror to reflect the
light back to a measuring instrument can measure particulate matter. The quantity of light returned
is proportional to the particle matter and aerosols in the flue gas.
Figure 8
In-Situ Transmissometer Analyzer
Piping Design, Connections, Support
Learning Outcome
When you complete this learning material, you will be able to:
Discuss the codes, designs, specifications, and connections for ferrous, non-ferrous and non-metallic
piping and explain expansion and support devices common to piping systems.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
Identify and explain the general scope of the CSA, ASME, ANSI, ASTM codes and standards
with respect to piping and pipe fittings. Differentiate between power piping (code B31.1)
and pressure piping (code B31.3).
2. Explain methods of pipe manufacture; size specifications and service ratings, and the
material specifications and applications for ferrous pipe.
3. Given operating conditions, and using pipe specifications and PG-27.2.2 of AMSE Section 1,
determine the size of pipe required for a particular installation.
4. Explain the materials, code specifications and applications of common, non-ferrous metal
piping.
5. Describe screwed, welded, and flanged methods of pipe connection and identify the fittings
used for each method.
6. Describe the construction, designs, and materials of flange gaskets and explain the
confined, semi-confined, and unconfined flange styles.
7. Explain the materials, construction and approved applications of common, non-metallic
pipe.
8. Explain the effects of temperature on piping; explain the mechanisms and the dangers of
expansion in piping systems, including attached equipment.
9. State the purpose and explain the designs, locations and applications of simple and offset
U-bend expansion bends.
10. Describe designs, locations, care and maintenance of slip, corrugated, bellows, hinged,
universal, pressure-balanced, and externally pressurized expansion joints.
11. Describe design, location, operation of pipe support components, including hangers, roller
stands, variable spring hangers, constant load hangers, anchors, and guides.
Objective One
When you complete this objective you will be able to…
Identify and explain the general scope of the CSA, ASME, ANSI, ASTM codes and standards with
respect to piping and pipe fittings. Differentiate between power piping (code B31.1) and process
piping (code B31.3).
Learning Material
REGULATIONS GOVERNING THE DESIGN, CONSTRUCTION AND INSTALLATION OF
BOILERS AND PRESSURE VESSELS
In Canada, the federal government and all of the provincial jurisdictions and territories have Boilers
and Pressure Vessels Acts or their equivalents. This is also true of most American states and large
American cities.
The Canadian jurisdictions have all adopted CSA B51 via the use of Regulations as allowed by their
Acts. CSA B51 references the ASME (American Society of Mechanical Engineers), ANSI (American
National Standards Institute), and other codes and standards. Thus, by simply adopting CSA B51,
the ASME and ANSI Codes are used in Canada.
Most of the provincial jurisdictions, American states and large American cities, and much of the
developed world have adopted all of the ASME standards, and use them as references for a
standard of performance or quality control.
CSA B51 establishes that every boiler, pressure vessel, safety valve, relief valve, safety relief valve
and rupture disc shall be stamped with either an ASME Code Symbol Stamp, or other stamping
acceptable to the regulatory authority.
ASME controls the quality of shops, which they approve by issuing code symbols (which ASME
retains ownership of), by issuing Certificates of Authorization, and by controlling advertising, which
makes reference to the ASME codes. ASME-approved shops undergo regular intensive inspections
by inspectors employed by ASME.
Any new boiler, pressure vessel or fitting going into service must have a Canadian Registration
Number (CRN), that is issued by the province in which it is to be installed, and it must be fabricated
in an ASME shop if not made in Canada. If it is fabricated in Canada it, must be fabricated by an
ASME or other shop acceptable to the regulatory authority.
Non-code shops are those that fabricate storage tanks, water heaters, etc., for use in areas not
included in the scope of the Act, codes, or standards. These vessels are not made to conform to
ASME or CSA standards and are not inspected by authorized inspectors.
Adoption of Codes
The Codes that have been adopted as regulations and are of particular interest to power engineers
are:
i) Canadian Standards Association (CSA)
CSA B51 - Boiler, Pressure Vessel, and Pressure Piping Code
CSA B52 - Mechanical Refrigeration Code
ii) American Society of Mechanical Engineers (ASME)
ASME Section I - Rules for Construction of Power Boilers
ASME Section II - Materials
ASME Section IV - Rules for Construction of Heating Boilers
ASME Section V - Nondestructive Examination
ASME Section VI - Recommended Rules for the Care and Operation of Heating
Boilers
ASME Section VII - Recommended Guidelines for the Care of Power Boilers
ASME Section VIII - Rules for Construction of Pressure Vessels
ASME Section IX - Welding and Brazing Qualifications
iii) ASME Pressure Piping Codes
B.31.1 - Power Piping
B.31.3 - Chemical Plant and Petroleum Refinery Piping
B.31.4 - Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas,
Anhydrous Ammonia, and Alcohols
B.31.5 - Refrigeration Piping
Canadian Standards Association
The Canadian Standards Association has formulated and published many standards, which relate to
power engineering equipment. These standards are recommendations only and do not have the
force of law until adopted officially by a jurisdiction
CSA B51 - Boiler, Pressure Vessel, and Pressure Piping Code
This code is produced by a CSA boilers and pressure vessels committee. This committee consists of
representatives from the provincial and territorial government departments, representatives from
boiler and pressure vessel manufacturers and representatives from boiler insurance companies. The
committee, therefore, is well qualified to make rules and regulations regarding boiler and pressure
vessel construction and inspection.
CSA B51 states that all fittings shall be designed, constructed, inspected and tested as specified in
the relevant ASME Code and to ANSI standards. This code has two purposes: first, to provide for
the safe design, construction, installation, operation, inspection, testing and repair of boilers and
pressure vessels and Pressure Piping; and second, to promote uniform requirements among the
jurisdictions. Pressure Piping is a broad classification (used in CSA- B-51) covering all subclassifications such as Power Piping as covered in B31.1 and Process Piping as covered in B-31.3.
General Requirements
In this section are listed the various standards which have been adopted by this code and these
include other codes such as the ASME and the American National Standards Institute (ANSI). It is
pointed out, however, that when any rule of this code is at variance with the other listed standards
then the rules of this code, CSA B51, shall govern.
ASME Codes
ASME references standards and methods set out by other bodies, such as ANSI and ASTM. A list of
all referenced standards in a particular ASME Code can be found in the Appendix section of the
Code.
ASME Boiler and Pressure Vessel Code Section I
This code applies to the Boiler proper and the boiler “external piping”. Super heaters, economizers
and other pressure parts connected directly to the boiler without intervening valves are considered
as parts of the boiler proper. Boiler external piping is that which begins where the boiler proper
terminates and which extends up to and including the valve or valves required by this code. The
exact rules for the code scope are given in ASME Section I PG-58.
B31.1 Power Piping sets boiler piping rules for: materials, design, fabrication, construction, and
testing. There are two classifications of Boiler piping covered in B31.1. They are:
•
•
Boiler External Piping. This is the piping that begins where the boiler proper leaves off.
Examples are piping between the boiler and the first stoop valve on the main steam line,
and piping located between the mud drum and the first blow-down valve.
Non-Boiler External Piping. This is the steam system piping that is not covered in the Boiler
External Piping category. An example is the plant steam distribution piping.
B-31.3 Process Piping sets the rules for Pressure or Process Piping in the rest of the plant that is
not covered in B-31.1 or ASME Section I. In general B31.1 is connected to ASME Section I (Power
Boilers), and B.31.3 is connected to ASME Section VIII (Pressure Vessels).
ANSI (American National Standards Institute) does not itself develop standards. It facilitates
development by consensus of qualified groups. These groups develop national and international
standards. A common ANSI standard used for piping is ANSI B16.5 Steel Pipe Flanges and Flanged
Fittings.
ASTM is a voluntary organization for developing international standards. ASME uses ASTM
standards for such things as material specifications.
Design Registration
The designs of piping systems with volume over 0.5 cubic metres (18 cubic feet) have to be
registered. If the design is satisfactory a piping number is stamped on the drawing. For example,
PP-455-E-03-P is stamped on the drawing. PP designates pressure piping. The number 455
identifies the particular owner of the plant. The E indicates that the plant is in the Edmonton
Inspection District. The number 03 indicates that this is the third plant in the district owned by
company 455. The last letter identifies the type of plant: P = petroleum gathering, C = chemical, R
= refrigeration, and so on.
Quality Control
Quality Control programs are required to manufacture, repair or modify a boiler, pressure vessel,
piping, fired heater pressure coil or fitting. The QC program consists of a written description of the
way the organization will perform the work.
This description provides guidance to company staff involved in construction to ensure that all Code
and Branch requirements are met during construction. The program also prevents costly mistakes
such as the construction of a pressure system using the wrong material.
After the Quality Control Manual has been reviewed and if the organization with the QC system has
demonstrated to a Boilers Branch Inspector that they are following the QC program, they are
authorized, for a period of three years, to construct the work described. The Boilers Branch provides
the authorized organization with a Certificate describing the work they are authorized to perform.
One copy of the organization’s QC manual is stamped with a Boilers Branch acceptance stamp on
the Statement of Authority page.
Any owner hiring an organization to construct or repair pressure vessels or piping should verify that
the contractor has a valid QC program for the scope of work by asking for a copy of the contractor’s
registered QC manual.
Objective Two
When you complete this objective you will be able to…
Explain methods of pipe manufacture, size specifications and service ratings, and the material
specifications and applications for ferrous pipe.
Learning Material
METHODS OF PIPE MANUFACTURE
Pipe is either welded or seamless. If the pipe is welded, the welding may be done by the electric
fusion method, the electric resistance method, or the double submerged-arc method.
In the electric fusion method, also known as the furnace butt weld method, flat plate having the
proper width and thickness and having been heated in an electric furnace to the proper welding
temperature is shaped by forming rolls into a tube-like form. The edges of the plates are then
squeezed together in order to fuse them. The formed pipe then passes through a series of rolls to
give it its final dimensions.
In the electric resistance method, the flat plate is formed cold into a tube shape by rollers and then
it passes between welding electrodes which make contact with the pipe on either side of the joint.
The welding current passes between the electrodes through the pipe joint where resistance of the
pipe metal to the current flow produces sufficient heat to fuse the joint edges together.
In the double submerged-arc method, also known as the automatically welded method, flat plate is
formed into a tube shape and placed in an automatic welder with the inside backed by a watercooled copper shoe. Two electrodes are used which are not in actual contact with the pipe. The
welding current passes from one electrode through a powdered flux and across the pipe joint to the
other electrode. A welding rod placed just above the pipe joint is thereby melted and deposited in
the groove of the pipe joint. The pipe is then welded in a similar manner on the inside. Seamless
pipe can be produced by: piercing and rolling, cupping and drawing, extrusion, or by the forgingboring-turning method.
The piercing and rolling method involves forcing a heated billet of steel over a piercing mandrel by
means of rolls. The hollow billet then passes over further mandrels and through further rolls to
obtain the correct outside diameter and wall thickness. With this method, the billet must be of high
quality forged metal because of the pulling and tearing action of the initial rolls.
In the cupping and drawing method, a forged billet at about 1260°C is formed into a thick-walled
cup by means of a mandrel or ram. The still red-hot cup is then forced by a long mandrel through a
series of dies progressively smaller in diameter, and then leaves the last die as a long tube closed at
the front end. This closed end is then removed.
With the extrusion method, a hot billet is forced by a ram into the space between a die and a closely
centered mandrel. In this way the billet leaves the die as a tube or pipe. Both the billet and the
mandrel are wrapped with glass, which melts and provides lubrication for the process.
The forging-boring-turning method is used for large high temperature – high-pressure pipe that
cannot be produced in ordinary commercial pipe mills. The large billet or ingot from which the pipe
will be made is heated and then forged into a solid round bar. The bar, after controlled cooling and
heat treatment, is rough-bored to the approximate inside diameter. The outside is then turned down
and then the inside is given a finish-boring to achieve the desired smooth inside diameter.
Commercial Pipe Sizes
Commercial pipe is made in standard sizes each having several different wall thickness or weights.
Up to and including 300 mm pipe the size is expressed as nominal (approximate) inside diameter.
Above 300 mm the size is given as the actual outside diameter.
For example, if a pipe was designated as 152 mm size this would mean that it has a nominal or
approximate inside diameter of 152 mm. The outside diameter is 168.3 mm and this is a constant
value no matter what the wall thickness is. The actual inside diameter of the pipe will depend upon
its wall thickness. For a standard wall thickness the actual inside diameter of 152 mm pipe is 154.1
mm. For an extra strong wall thickness the actual inside diameter is 146 mm.
There are two systems used to designate the various wall thicknesses of different sizes of pipe. The
older method lists pipe as standard (S), extra strong (XS) and double extra strong (XXS). The
newer method, which is superseding the older method, uses schedule numbers to designate wall
thickness. These numbers are: 10, 20, 30, 40, 60, 80, 100, 120, 140 and 160. In most sizes of
pipe, schedule 40 corresponds to standard and schedule 80 corresponds to extra strong.
Applications of Ferrous Pipe
The most frequently used materials for power piping systems are: low carbon steels, alloy steels
and austenitic stainless steels. Table PG-23.1 in the ASME Code Section I lists the allowable stress
values for these materials for various temperatures up to 815°C.
Low carbon steel is the lowest priced steel and it is used extensively for steam, water, fuel oil and
compressed air piping for temperatures below 400°C. Above 400°C, it is not recommended as
graphitization may occur within the pipe material at these elevated temperatures. Graphitization is
the breaking down of part of the material into iron and graphite, and failure of the material will
occur along lines where there is a concentration of graphite. The vast majority of piping in power
plants is low carbon steel. It is used everywhere except where corrosion or high temperatures are a
problem.
Pipe made from low carbon steel may be seamless, electric resistance welded or butt-welded.
Specification numbers of some examples of low carbon steel pipe as listed in Table PG-23.1 are: SA53B, SA-106B and SA-135A.
Alloy Steels such as the chrome-molybdenum types are used for temperatures above 400°C, for
example in steam generator outlet piping at 540°C or more. The use of some types of low
chromium alloys, where graphitization can be a problem, is limited to 525°C. low chromium alloys
are very common materials for boiler superheater and reheater tubing and outlet piping.
Alloy steel pipe may be seamless or welded and some examples as listed in Table PG-23.1 are: SA213T12, SA-335P11 and SA-423-2.
Austenitic stainless steels are a special class of high alloy steels, which contain 18% chromium
and from 8 to 12% nickel. They are highly resistant to corrosion and maintain adequate high
strength at high temperatures. This piping is available as seamless or welded pipe and some
specification numbers as listed in Table PG-23.1 are: SA-312TP304, SA-376TP304, SA-430FP304
and SA-249TP304. Applications would include once-through boiler tubes or high temperature
furnace tubes.
Table 1 lists some materials commonly used for piping together with comments regarding their use
and method of manufacture.
Table 1
Piping Materials
Objective Three
When you complete this objective you will be able to…
Given operating conditions, and using pipe specifications and PG-27.2.2 of AMSE Section 1,
determine the size of pipe required for a particular installation.
Learning Material
STRENGTH OF PIPING
The strength of a pipe will depend upon its wall thickness, the material from which it is made and
the temperature to which it is subjected. In order to determine the minimum wall thickness
necessary for boiler piping in order for it to withstand a certain pressure and temperature, the
following formula from the ASME Power Boilers Code paragraph PG-27.2.2 is used. This formula is
for ferrous-piping and it is the same formula as used to determine the thickness of boiler drums and
headers.
Example 1:
Calculate the minimum thickness required for a seamless steel pipe of material SA-209 grade T1.
The outside diameter of the pipe is 323.85 mm and the operating pressure and temperature are
5200 kPa and 500°C respectively. The pipe is plain ended. Assume that the material is austenitic
steel.
Note: Plain end pipe is that which does not have its wall thickness reduced when joined to another
pipe. For example, pipe lengths welded together rather than joined by threading are classed as plain
end pipes.
When:
t = maximum required thickness, mm
P = maximum allowable working pressure, MPa
D = outside diameter of cylinder, mm
C = maximum allowable for threading and structural stability, mm (PG-27.4, note 3)
S = maximum allowable stress value at the operating temperature of the metal,
MPa PG-23 (ASME SECTION II tables 1A and 1B in 2001 Edition Codes)
E = efficiency, value given in PG-27.4, Note 1
y = temperature coefficient, as given inPG-27.4, Note 6
P = 5.2 MPa, as given
D = 323.85 mm, outside diameter as given
C = 0, PG-27.4, Note 3 (101.6 mm nominal and larger)
S = stress value at 500°C for SA-209-T1, see PG-9.1
= 69 MPa, from Table PG-23.1 (SECTION II tables 1A and 1B in 2001 Edition Codes)
E = 1.0 see PG-27.4, Note 1, seamless pipe as per PG-9.1
y = 0.4 see PG-27.4, Note 6 (austenitic steel, 500°C)
Then:
This thickness is exclusive of the manufacturer’s tolerance. As the manufacturing process does not
produce absolutely uniform wall thickness, an allowance is made which is called the manufacturing
tolerance. This usually is done by increasing the minimum required thickness, as calculated in the
formula, by 12.5%.
Therefore:
t = 11.85 x 1.125
= 13.33 mm (Ans.)
Therefore, the pipe wall thickness required is 13.33 mm. See PG-16.5 and PG-27.4, Note 7.
Table 2 lists the dimensions and the mass, in kilograms per metre, of different sizes of steel pipe
with varying wall thickness.
From Table 2 it can be seen that the wall thickness of 13.33 mm for a pipe with an outside diameter
of 323.85 mm lies between schedule 40 (10.31 mm) and schedule 60 (14.27 mm). Therefore
schedule 60 pipe would be used.
Table 2
Dimensions and Masses of Steel Pipe
Upper figures in each square denote wall thickness in mm
and lower figures denote mass per metre in kilograms
Self Test Problems
Calculate the minimum thickness required for a seamless steel pipe of material SA-312
Grade TP347H. The outside diameter of the pipe is 323.85 mm and the operating
pressure and temperature is 5200 kPa and 500°C respectively. The pipe is plain ended.
(Stress value S can be found in Table 1).
(Ans. 9.2012 mm)
Objective Four
When you complete this objective you will be able to…
Explain the materials, code specifications and applications of common, non-ferrous metal piping.
Learning Material
OTHER MATERIALS
Metals other than steel, which may be used in power plant piping, are cast iron and nonferrous
materials such as copper and brass. These materials, however, are limited by the code in regard to
pressure and temperature. According to the ASME Code Section I, cast iron can be used for steam
pressures up to 1725 kPa providing the steam temperature does not exceed 230°C, but in no case
can be used for boiler blow-off connections.
Cast iron should not be used where shock loading may occur.
The ASME Code Section I also specifies that nonferrous pipe or tubes shall not be used for blow-off
piping or for any other service where the temperature exceeds 210°C. In cases where the use of
nonferrous materials is allowed, there is a possibility of galvanic corrosion occurring when these
materials are used in conjunction with steel or other metals.
Nonferrous Metals
Nonferrous metals are those containing very little or no iron, such as red brass, admiralty brass,
aluminum brass, copper silicon and copper nickel alloys. These are highly resistant to corrosion and
are used for special power plant applications. They are more expensive than the ferrous materials.
The ASME code B31.1 (105.3) 1limits the use of nonferrous pipe (copper and brass) for water and
steam service, to pressures not exceeding 1750 kPa, and to design temperatures not exceeding
208°C.
Copper and brass for air service may be used as per the allowable stresses of the stress tables. The
tables are found in ASME Section II Part B –Nonferrous Material Specifications
Brass
85% Cu - 15% Zn
Brass is an alloy of copper and zinc. With a high copper content, it is called red brass, and with a
lower copper content, it is called yellow brass. Copper contents vary from 65% to 85%. Connections
can be threaded, brazed, soldered, or flanged.
Brass for utility piping systems shall conform to ASTM B 43 specifications. Brass is commonly used
in water lines, fuel piping, lube-oil and compressed air coolers.
Admiralty Brass
71% Cu - 28% Zn - 1% Sn
Used in evaporators, condensate and air coolers. Stress tables are found in ASME SECTION II – Part
B Nonferrous Material Specifications (tables 1A and 1B in the 2001 Edition Codes).
Aluminum Brass
78% Cu - 20% Zn - 2% Al
This material is gradually replacing admiralty because of better resistance to seawater corrosion. .
Stress tables are found in ASME SECTION II – Part B Nonferrous Material Specifications (tables 1A
and 1B in the 2001 Edition Codes).
Copper Silicon Alloys 95.8% Cu - 1.1% Mn - 3.1% Si
Widely used in sewage and water treating plants. Stress tables are found in ASME SECTION II –
Part B Nonferrous Material Specifications (tables 1A and 1B in the 2001 Edition Codes).
Cupro Nickel Alloys
8.4% Cu - 10 Ni% - 0.4% Mn - 1. 2% Fe
These are harder and more resistant to cracking compared to any other type of copper alloy.
Copper tubing may be used for steam tracing of product lines and for instrument air lines providing
the tubes will not be subjected to corrosive atmospheres (sulphur, ammonia, etc.). Stress tables are
found in ASME SECTION II – Part B Nonferrous Material Specifications (tables 1A and 1B in the 2001
Edition Codes).
Cast Iron -Section I – Power Boilers states that cast iron shall not be used for nozzles or flanges
attached directly to the boiler for any pressure or temperature. (PG-8.2.1)
Grey Cast Iron - In PG-8.2.2 it is stated that grey cast iron (SA-278) may be used for boiler and
superheater connections under pressure such as pipe fittings, water columns, valves and their
bonnets for pressures up to 1720 kPa provided the steam temperature does not exceed 232°C.
Cast Nodular Iron – As designated in PG-8.3, nodular cast iron (SA-395) may be used for boiler
and superheater connections under pressure. Such uses would be for pipe fittings, water columns,
and valves and their bonnets. It is limited to pressures of 2410 kPa and 232°C.
Objective Five
When you complete this objective you will be able to…
Describe screwed, welded, and flanged methods of pipe connection and identify the fittings used for
each method.
Learning Material
METHODS OF CONNECTING PIPE
There are three general methods used to join or connect lengths of pressure piping. Each of these
methods has certain advantages and disadvantages and each method will be discussed in the
following sections. The methods are:
•
•
•
By the use of threaded pipe and screwed connections
By the use of flanges fastened to the pipe ends and bolted together and,
By the use of welded joints.
Screwed Connections
With this method, threads are cut on each end of the pipe and screwed fittings such as unions,
couplings, elbows, etc., are used to join the lengths. This method is generally used for pipe sizes
less than 100 mm for low and moderate pressures. It has the advantage that the piping can be
easily disassembled or assembled. However the threaded connections are subject to leakage and
the strength of the pipe is reduced when threads are cut in the pipe wall. Fig. 1 illustrates various
screwed fittings which may be used when fabricating a pipe system,
The fittings are threaded to conform to American standard pipe threads and unless otherwise
specified, right-hand threads are used. Cast iron, malleable iron, cast steel; forged steel and brass
may be used as material for fittings depending upon the service they are to be used for.
As in the case of pipe, there are several weights of fittings made which are designed for pipe of a
corresponding weight. However, instead of schedule numbers as with pipe, the fittings are
designated as to the pressure for which they are suited. Often two service ratings are used, one for
steam service and one for cold water, oil, or gas, non-shock service.
For example, a malleable iron fitting may have a rating of 1000 kPa for saturated steam and a
rating of 2000 kPa for cold water, oil or gas, non-shock. Similarly, a cast iron fitting may have a
rating of 850 kPa for saturated steam and a rating of 1200 kPa for cold water, oil or gas, non-shock.
The letter S marks steam service fittings. Water is WO and oil or gas service is denoted by the letter
G.
Figure 1
Threaded Pipe Fittings
Steel fittings are rated as to the maximum pressure at a certain maximum temperature for which
they are suited. For example, a certain fitting rated at 13 500 kPa at 35°C might only be rated at
1600 kPa at 535°C, The manufacturer's service tables must be consulted when deciding upon which
fitting to use.
Pipe Threading
When making up a piping system with screwed connections, it is necessary to cut the pipe into the
required lengths and then thread the ends onto which the fittings will be screwed. The pipe is
supplied from the manufacturer in standard lengths and may be cut to the required length by
means of a pipe cutter. The type of cutter usually employed consists of a cutting wheel and
adjustable guiding rollers as illustrated in Fig. 2.
When pipe is cut with a wheel and roller cutter a burr is left on the inside of the pipe and a shoulder
is formed on the outside of the pipe. The external shoulder may be removed by filing and the
internal burr is removed with a special tool known as a pipe reamer, which is illustrated in Fig. 3.
Figure 2
Figure 3
Pipe Cutter
Pipe Reamer
It is extremely important that the internal burr be removed completely otherwise it will tend to
catch foreign material passing through the pipe and an obstruction will be formed, and piping
system capacity will be reduced.
After the pipe has been cut to the proper length, reamed, and the external shoulder removed, the
threads are now cut on the pipe ends. The threads are cut by means of a set of cutters known as
dies, which are held in a frame known as a stock. These may be moved around the pipe by means
of a hand driven ratchet lever or else a power driven machine is used to turn the pipe while the dies
are held stationary. The ratchet type dies are shown in Fig. 4.
Figure 4
Ratchet Pipe Dies (Ridge Tool Co.)
The dies should be well lubricated with oil while the threads are being cut and should be thoroughly
cleaned after use. Before screwing the fittings on the threaded pipe the threads must also be
thoroughly cleaned and a small amount of lubricant or "pipe dope" used on the pipe threads. The
dope should not be used on the fitting threads otherwise the excess may be squeezed into the pipe
and washed through the system when it is put into service.
Flanged Connections
This method uses flanges at the pipe ends, which are bolted together, face to face, usually with a
gasket between the two faces. Flanged connections are suitable for moderate pressures and are
frequently used on low-pressure lines larger than 150 mm. They have the advantage over welded
connections of permitting disassembly and are usually more convenient to assemble and
disassemble than the screwed connections. Also, flanged connections are stronger and more suited
for high pressure than are screwed connections. They are, however, subject to leakage if not
properly lined up and installed with suitable gaskets.
There are three general types of pipe flanges used and these are classified according to the method
of attaching to the pipe end. These types are the screwed flange, the welded flange and the loose or
lapped flange.
Screwed Flange
The inside of the screwed flange is threaded and the flange is screwed onto the threaded pipe as
shown in Fig. 5. The companion flange is attached in the same way to the connecting pipe.
Threaded flanges are widely used because no welding equipment is required for assembly. However,
this type of a joint may develop leaks along the threaded portion and they have a further
disadvantage in that the pipe wall thickness is reduced and therefore weakened by the threading
process.
Figure 5
Threaded Flange
Welded Flange
In the welded flange, as illustrated in Fig. 6, the flange is made with a welding neck as an integral
part. This neck is butt welded to the pipe and distortion of the flange due to the welding heat is
prevented by the fact that the weld is away from the immediate area of the flange face. The long
tapered hub reinforces the flange, permits stress-relieving and x-raying. These advantages make
welded neck flanges particularly suitable for severe service involving high pressure, extreme
temperature or hazardous service.
Another method of attaching a flange to a pipe by welding is shown in Fig. 7. The socket- welded
flanges are used for moderate services, particularly in the smaller sizes, because of ease of fit up
and alignment.
Figure 6
Figure 7
Welded Neck Flange
Socket Welded Flange
Fig. 8 shows a slip-on welded flange and this type is popular for normal service conditions because
of the ease of fit up and alignment and the greater tolerance permissible in cutting the pipe to
length.
The lapped or loose flange is shown in Fig. 9. In this type a lapped and machined stub with flange
slipped on is welded to the pipe. The pipe to be connected is similarly lapped and has a loose
companion flange. A gasket is used between the two lapped faces of the pipes. The ability of the
flange to rotate simplifies assembly and alignment of bolting on systems requiring frequent
dismantling.
Figure 8 Slip-On Welded Flange
Figure 9 Lap Joint Flange
With the exception of the lapped flange connection, in all the other flanged connections the faces of
the flanges butt together. These faces are made with various designs, which attempt to reduce the
possibility of leakage. Three common arrangements are: the raised face design, the male and
female design and the tongue and groove design. These are illustrated in Fig.10.
Figure 10
Raised Face
Male and Female
Tongue and Groove
The raised face type has a raised portion 1.5 to 6 mm high on each of the mating flanges. The male
and female type has a recess in one flange and a corresponding raised portion on the other flange.
The tongue and groove type has a groove machined into the face of one flange into which the
tongue of the mating flange fits. It has been found that the raised face type is the most suitable for
high pressure and is the most easily disassembled.
Other facing designs, which are used, include the plain straight-faced flanges, which have an
entirely straight or level face. Ring joint flanges have grooves machined in each flange face for a
special gasket.
Welded Connections
In this method, the pipe lengths are welded directly to one another and directly to any valves or
fittings that may be required. The use of these welded joints for piping has several advantages over
the use of screwed connections or flanged connections:
•
•
The possibility of leakage is removed with the elimination of screwed or flanged joints.
The weight of the piping system is reduced due to the elimination of connecting flanges or
fittings.
•
The cost of material and the need for maintenance are reduced with the elimination of
flanges and fittings.
•
The piping looks neater and is easier to insulate with the elimination of bulky flanges and
fittings
•
Welded joints give more flexibility to the piping design as the pipes may be joined at
practically any angle.
The main disadvantage of using welded joints for piping is the necessity of obtaining a skilled welder
whenever a connection is to be made. Piping of 50 mm size and smaller when welded is usually
socket welded. The couplings, valves and other fittings have a recessed portion into which the pipe
fits and the weld is made around the socket edge. Fig. 11 shows various types of socket welded
fittings and Fig. 12 illustrates how a pipe is fitted in and welded to the fitting.
Figure 11
Socket Welding Fittings
Figure 12
Socket Welding Elbows
For larger sizes of pipe the pipe ends are butt welded together or butt welded to valves or fittings.
When this method is used, the edges of the pipes or fittings are beveled so as to form a groove for
depositing of the weld metal. Backing or back up rings which fit inside the pipe at the weld are used
to aid in the lining up of the pipe and also to prevent weld metal from protruding down inside the
pipe.
Illustrated in Fig.13 are several butt-welding fittings with the beveled edges visible. Fig. 14
illustrates the use of a backing ring. The dimension T is the thickness of the pipe wall and the gap G
is the distance the pipe ends are apart.
Depending upon the pipe material and thickness, preheating before welding and stress relieving
after welding may be required. Both the welding procedures and the welders should be qualified in
accordance to the boiler or piping codes. When required, the welds may be inspected by
radiography and tested by means of a hydrostatic test.
Figure 13
Butt Welding Fittings
Figure 14
Butt Weld Groove with Backing Ring
Identification Of Fittings
In order to insure that valves, fittings, flanges, and unions are of the proper strength and material
for the particular service for which they are used, it is necessary that they be clearly marked or
identified.
ALL FITTINGS NOT PROPERLY OR CLEARLY IDENTIFIED SHOULD BE REJECTED.
All markings, which shall be legible, must indicate the following minimum requirements:
1. Manufacturer’s name or trademark.
2. Service designation, for example, pressure-temperature rating for which the fittings is
designated.
3. Material designation, for example, steel, cast, malleable or ductile iron, and ASTM No.
The above markings are listed according to the degree of importance, however, for cast and ductile
iron fittings (2) and (3) will be reversed in order since the material identification is more important
than the service designation.
The following is a partial list of material markings with their abbreviation symbol or identification
system:
-Malleable Iron - “MI”
-Cast Iron - not required for gray cast iron
-Ductile (Nodular) Cast Iron - “Ductile” or “DI”
-Carbon Steel - “Steel” or ASTM Specification No. and Grade
-Alloy Steel - Grade Identification symbol and steel or ASTM No.
The following is a list of service symbols that may be encountered:
A, to signify Air O, to signify Oil
G, to signify Gas S, to signify Steam
L, to signify Liquid W, to signify Water
Objective Six
When you complete this objective you will be able to…
Describe the construction, designs, and materials of flange gaskets and explain the confined, semiconfined, and unconfined flange styles.
Learning Material
FLANGE FACES
Gaskets fit between mating surfaces or flanges. It is these flanges that provide the sealing surfaces
and the means of bolting the surface together. Flanges are described briefly here because of their
relationship with gaskets. Flange faces fall into three main groups: unconfined, semi-confined, and
confined.
Unconfined
Unconfined flange faces as those used for machine case joints and large circular joints.
Often the gasket in a flat-faced flange extends to the outside edge of the flange. In these cases,
holes have to be punched in the gasket to permit the installation of the bolts. For this reason flatfaced flanges are sometimes called full-faced flanges. Unconfined flat-faced and raised-face flanges
are shown in Fig. 15.
Figure 15
Unconfined Flange Faces
Semi-Confined
Semi-confined flange faces are designed for circular shapes where the gasket is located accurately
by the flange. Several types of semi-confined flange faces are shown in Fig. 16.
Figure 16
Semi-Confined (Male-Female) Flange Faces
Confined
Confined flange faces are used for circular flanges, with narrow gaskets located in grooves. These
flange configurations are used for high-pressure applications. Fig. 17 shows a groove-to-flat flange
face and a tongue-and-groove flange face.
Figure 17
Confined Flange Faces
Fig. 18 shows a confined flange configuration for a ring type joint, commonly known as an RTJ, with
an oval, solid metal, heavy cross-section type gasket. These gaskets are used for high-pressure
applications.
Figure 18
Confined Flange, Ring-Type Faces
The RTJ gaskets are machined, from various types of metal, into rings (see Fig. 19). These rings
have different cross-sectional areas (see Fig. 20) depending upon application and manufacturer.
Figure 19
RTJ Oval, Solid Metal, Heavy Cross-Section
Gasket
Figure 20
Cross Sections of Various Heavy Metal RTJs
Flange Surface Markings
It is desirable to have some roughness (tool markings) on most flange surfaces to help grip the
gasket and prevent it from creeping under internal pressure. These tool marks should run the same
way as the lay of the gasket; that is, a circular gasket should have circular tool marks in the flange
face.
There are two types of tool marks (ridges) on flanges:
•
•
Concentric - where the ridges and hollows are in concentric rings around the flange face.
Phonographic - where one continuous groove spirals around many times until it reaches the
opposite edge of the flange (similar to a phonograph record).
In theory, concentric is more desirable because each tool mark is a separate, closed ring, thereby
reducing leakage paths. In practice, phonographic rings seem to work just as well. Care should be
taken to prevent scratches or dents that run cross-grain to these ridges, as a leakage channel could
be established.
Metallic Gaskets
Generally gaskets can be classified into two categories: metallic and nonmetallic. Metal gaskets may
be of the solid metal, heavy cross-section type, as used in RTJs, or they may have flat cross
sections for use in other flanges. Fig. 21 shows a solid, flat metal gasket and a serrated, flat metal
gasket.
Figure 21
Metal Gaskets
Where more conformability is needed in the gasket to compensate for flange imperfections, a
corrugated metal gasket may be used. Fig. 22 shows a corrugated metal gasket and a similar
gasket filled with asbestos cord. The asbestos cord gasket may be found in steam applications up to
4000 kPa.
Figure 22
Corrugated Metal Gaskets
Metal-jacketed gaskets, with soft fillers, such as Teflon, better service some flanges. Fig. 23 shows
some of the common profiles.
Figure 23
Metal Jacket Soft Filled Gaskets
Another type of metallic gasket is the spiral wound gasket. In this type of gasket, a V-shaped metal
strip is wound like a roll of tape. A layer of asbestos or other material is also wound in, separating
the metal strips.
When the gasket is compressed in a flange, the V-shaped metal acts like a spring to give some
resilience to the gasket. The spiral metal gasket may have a compression-limiting ring inside or
outside, or both, depending on the application. Fig. 24 shows a spiral wound gasket cross-section
with inside and outside compression limiting rings.
Figure 24
Spiral Wound Gasket
Nonmetallic Gaskets
The more common nonmetallic gasket materials used in lower pressure applications come in
different forms. Some come precut to fit intricate internal sealing requirements, such as the gasket
for an automatic transmission. Some materials come in rolls for the user to make a gasket for a
particular application. Some material comes in sheets of different sizes and thickness.
The nonmetallic gasket materials are made from a wide variety of sources, including cellulose and
other natural fires, asbestos, rubber, cork, neoprene, and polymers. They may be woven into cloth,
held together with binder material, or reinforced with a metal mesh or stranded core. Some have a
woven fiber core, such as nylon, with a layer of rubber or neoprene applied to each side.
Some nonmetallic gasket material is made using a similar process to making paper. Fibers, fillers,
and binders are mixed in slurry and deposited on a screen drum. The mat is drawn off the rotating
drum and sent through rollers and dried. The material may be further sprayed, dipped, laminated,
or coated with various resins and then cured.
Another method is to make a thicker mix of fibers (some include asbestos), binders, and fillers into
a “putty”, which is compressed between rollers and deposited on the larger steam heated roller until
the proper thickness is achieved. The material is then removed and cut into sheets of various sizes.
Further treatment may include treating the surface of the material with a release agent (such as
graphite or molybdenum disulphide) so that the gasket can be easily removed when a flange joint is
taken apart.
Other gasket materials are made from cork (the bark of the cork tree). The bark is granulated and
mixed with binders and resins and formed into blocks from which sheets of materials are cut. Cork
and rubber combinations are also made. The rubber addition holds the material together better.
Cork gaskets are used for low-pressure oil and water applications.
Rubber gaskets have a wide range of application, since rubber is flexible and elastic, thus affording
good sealing characteristics even when flange faces are quite rough. The makeup of the rubber can
be modified with various polymers to meet specific requirements. Rubber can be reinforced with
fiber or metal gauze to prevent creeping, or to add strength to the gasket. The common “Red
Rubber” gasket is used for air, low-pressure steam, hot and cold water.
Polytetrafluoroethylene (PTFE), commonly known as Teflon, is used in gaskets by itself or in
combination with other materials. Its high resistance to chemical attack and its non-stick
characteristics make PTFE a valuable material for certain applications, including cryogenic service.
PTFE has an upper temperature limit of about 260°C (500°F).
For high temperature service, flexible graphite gasket material is used. In a non-oxidizing
application, graphite gaskets are effective up to 3000°C (5400°F).
The application determines what type and thickness of gasket material should be used.
Consideration should be given to:
1. The fluid in the process.
2. The temperature and pressure the process is likely to reach.
3. How much bolt force is on the gasket.
4. How much will the gasket cost - not all gaskets have to be expensive, but an inexpensive gasket
that fails could be a costly maintenance activity.
Gasket suppliers are able to recommend the proper gasket for a given application. If any confusion
exists, the supplier should be consulted.
Objective Seven
When you complete this objective you will be able to…
Explain the materials, construction and approved applications of common, non-metallic pipe.
Learning Material
NON-METALLIC PIPING
Most plants contain some non-metallic piping. The most common type is manufactured form plastic.
The major advantage of plastic is its resistance to corrosive materials and its ease of installation.
Power Piping as governed by B31.1-105.1. B31.1 (1998 Edition) states that plastic may be used for
water and nonflammable liquids where experience or tests have demonstrated that the plastic pipe
is suitable for the service conditions. The pressure and temperature conditions also have to be
within the manufacturers limits. Plastic materials are limited to 1000 kPa and 60°C, for water
service. For other services, pressure and temperature limits shall be based on the hazards involved,
but in no application shall they exceed 1000 kPa and 60°C. Appendix III of B31.1 also has nonmandatory rules or guidelines for the use of plastic pipe.
There are two broad classifications of plastic piping materials. They are Thermoplastics and
Thermosets. Thermoplastics will soften when heated, allowing for shaping and forming. Thermosets
will not soften when heated. They will start to decompose if heated too high.
THERMOPLASTICS
PVC (Polyvinyl chloride)
PVC is one of the strongest and most widely used plastic pipes. Pipe is available in schedule 40 and
80 and in diameters up to 150mm. It is used in pressure and non-pressure systems and is approved
for potable water applications. It is strong and corrosion resistant, but is not resistant to solvents.
CPVC (Chlorinated Polyvinyl Chloride)
CPVC is a chemical modification of PVC. CPVC has two chlorine atoms for two carbon atoms. PVC
has one chlorine atom for two carbon atoms. It is good for higher temperatures than PVC, the upper
limit being about 90°C. The sizes and other properties of CPVC are very similar to PVC.
PE (Polyethylene Pipe)
Polyethylene pipe is probably the best-known polyolefin. It is tough, ductile, and flexible. It is also
rated for potable water service, and may also be used for underground fuel gas distribution piping.
It is also used for gravity and pressurized drainage systems. Its disadvantages are the lowest
mechanical strength of all the plastic pipes, and only a moderate resistance to chemicals.
PP (Polypropylene)
PP is resistant to sulfur compounds and can withstand corrosive environments. Of the plastic pipes,
it is the most resistant to organic solvents. It is only slightly less rigid than PVC Piping. The common
uses are pure water services and laboratory drainage systems. It is available in schedule 40 and 80,
and up to 300 mm in diameter.
ABS (Acrylonitrile Butadiene Styrene)
It is slightly more rigid than PVC, but has the lowest solvent resistance of all the plastic pipes. The
upper temperature limit for ABS is 80°C. ABS is available in schedules 40 and 80 and in diameters
up to 300 mm. Common applications are potable water systems and pressurized liquid lines for salt
water, or crude oil.
PB (Polybutylene)
PB is a polyolefin and is slightly less stiff than regular types of PE. It has more strength than PE. It
is resistant to soaps, most acids, and bases, and popular solvents are lower temperatures. It is used
mainly for water and to some extent for chemical waste lines.
THERMOSETS
Resin Pipe (RTR)
Reinforced Thermosetting Resin (RTR) is a class of composite pipe that consists of a resin reinforced
with a fiber. The fiber is usually imbedded in the resin. There are four resin types that are normally
used. They are epoxy, polyester, vinyl ester, and furans. The most common reinforcement material
is fiberglass. RTR can also be used in buried flammable and combustible liquid service.
Resin pipes have excellent corrosion resistant properties and can handle temperatures to 140°C.
Reinforced thermosetting resin pipe may be used in similar services to plastic piping. It is very
strong yet has a lightweight.
When choosing a plastic piping material it is necessary to know the physical characteristics of the
material, as well as the chemical resistance of the material. Table 3 lists the physical properties of
common plastic piping materials. Table 4 is a table of chemical resistance of plastic piping materials.
Table 3
Physical Properties of Common Plastic Piping Materials
Table 4
Chemical Resistance of Plastic Piping Materials
Flexible Non-Metallic Pipe or Tubing
A flexible non-metallic pipe or tubing arrangement may be used in applications where:
•
•
Satisfactory service experience exists
The pressure and temperature conditions are within the manufacturers recommended limits
Flexible tubing and small-bore piping is being used for applications such as for instrumentation
tubing or for water and steam piping to sample coolers. Its advantages are its ease of installation
and being able to bend it through tight openings.
Reinforced Concrete Pipe
Reinforced concrete pipe may be used in water service for temperatures up to 65°C. It is
manufactured from reinforced or non-reinforced concrete. Applications include; gravity drainage
systems, and pressurized water service. Sizes of concrete pipe range from 10.16 cm to 91.44 cm.
Reinforced concrete pipe is available in sizes up to 365.76 cm. It is usually used for non-potable
process or cooling water service.
Objective Eight
When you complete this objective you will be able to…
Explain the effects of temperature on piping; explain the mechanisms and the dangers of expansion
in piping systems, including attached equipment
Learning Material
EXPANSION OF PIPING
Expansion control in pipelines, which carry hot or cold fluids, or which are exposed to large
variations in ambient temperature, can be a major problem. As the metal temperature of the pipe
increases or decreases, its length also varies due to thermal expansion or contraction. Therefore,
unless provision is made for these changes in length, excessive stresses will be induced in the
piping. Large forces will be transmitted through the system to anchors and connected equipment.
Several different methods are available for controlling pipeline expansion. Two of the most common
are expansion bends and expansion joints.
A pipeline will expand and contract due to alternate heating and cooling. When a pipe is out of
service it is at the ambient temperature, possibly 20°C. However, when the pipeline is in service it
will be at the temperature of the fluid, which it is conveying. In the case of a line carrying highpressure superheated steam, the temperature may be as high as 500°C or more. The change in
length of the pipe due to the change from out-of-service temperature to in-service temperature may
be calculated by considering the coefficient of linear expansion of the pipe material and the length
of the pipe. This change in length will be equal to the original length times the coefficient of linear
expansion times the change in temperature.
For example, a steam line 150 m long is installed in a plant at an ambient temperature of 20°C.
When in service the line will carry steam at 580°C. How much will the line increase in length when
put into service?
The coefficient of linear expansion of steel is 1.1x 10-5/°C.
Change in length = original length x coefficient of linear expansion x change in temperature
= 150m x 1.1 x 10-5/°C x (580 - 20)°C = 0.924 m
As this example illustrates, the expansion of certain pipelines can be a considerable amount and
provision must be made for this movement otherwise excessive stress will be exerted on piping,
supports and connected equipment. In addition, the piping must be securely anchored at the proper
points. It is very important when commissioning a piping system to be aware of the piping
expansion. A very close watch must be kept on piping anchors and expansion joints. Piping without
the proper room to expand can distort and come in contact with other pipes. In extreme cases
piping can crack and spring leaks. This is very dangerous as the contents of the pipe are released.
Piping is usually disconnected from major pieces of equipment such as turbines, when they are
being inspected or overhauled. After the turbine has been aligned, the piping is reattached. The
alignment is often rechecked to insure that the piping has not changed any of the alignment
settings. The equipment must not have forces of piping expansion exerted on it. The piping
supports, expansion joints and hangers must support the piping forces.
Objective Nine
When you complete this objective you will be able to…
State the purpose and explain the designs, locations and applications of simple and offset U-bend
expansion bends.
Learning Material
EXPANSION BENDS
There are two methods in common use for providing for expansion in pipelines. One method
involves the use of expansion bends and the other the use of expansion-joints. With this method,
the pipe is fabricated with special bends and the increase in the length of pipe due to expansion is
taken up by flexing or springing of the bends. Fig. 25 shows some typical shapes of expansion
bends.
Figure 25
Expansion Bends
The use of expansion bends is usually preferred for high-pressure work as there is no maintenance
involved and little likelihood of leaks developing. However, expansion bends require a large amount
of extra space and add to pressure losses due to the extra amount of pipe through which the fluid
has to pass. Fig. 26 A is of a typical expansion loop in a run of pipe.
These loops are common on pipe racks with long runs of pipe. Fig. 26 B, C, D illustrates locations
where expansion loops can be added to runs of piping. Each example illustrates a run of pipe with
no extra expansion provision next to a run with extra expansion loops.
Objective Ten
When you complete this objective you will be able to…
Describe designs, locations, care and maintenance of slip, corrugated, bellows, hinged, universal,
pressure-balanced, and externally pressurized expansion joints.
Learning Material
SLIP EXPANSION JOINT
Two types of expansion joints in general use are the slip expansion joint and the corrugated
expansion joint. The slip expansion joint, which is illustrated in Fig. 27, features a slip pipe, which is
welded to an adjoining pipe. The slip pipe fits into the main body of the joint, which is fastened to
the end of the other adjoining pipe. When the pipeline expands, the slip pipe moves within the joint
body. To prevent leakage between the slip pipe and the joint body, packing is used around the
outside of the slip pipe and the slip pipe moves within the packing.
In the joint illustrated, the packing consists of two sections of asbestos packing separated by a
section of plastic packing. Additional plastic packing may be added while the joint is in service by
means of a packing plunger. Grease fittings are used to provide lubrication.
Figure 27
Slip Expansion Joint
Slip expansion joints are simple and rugged and are capable of handling a large amount of
expansion. Their space requirements are a minimum and they produce little pressure drop and heat
loss. However, they must be located where the packing can be given attention. Also, problems may
arise if the joint is poorly aligned or if it becomes corroded and therefore the joint should be
installed and maintained according to manufacturer’s instructions. The proper packing must be used
and this should be lubricated two or three times a year unless self –lubricating packing is used.
CORRUGATED EXPANSION JOINT
This type of expansion joint consists of a flexible corrugated section, which is able to absorb a
certain amount of endwise movement of the pipe.
Figure 28
Low Pressure Corrugated Expansion Joint
A simple design suitable for only low pressures is illustrated in Fig. 28 and is available with either
flanges or welding ends. For higher pressures the corrugated joint uses control or reinforcing rings
which surround the corrugations as illustrated in Fig. 29.
Figure 29
Reinforced Corrugated Expansion Joint
Figure 30
Bellows Type Corrugated Expansion Joint
The bellows type corrugated expansion joint shown in Fig. 30 is suitable for pressures up to 2070
kPa. It is equipped with an internal safety sleeve having a limit stop to prevent undue extension or
compression. Also, as this sleeve is closely fitted it will prevent excessive leakage if failure of the
bellows section occurs. This type may be supplied with or without anchor bases.
Corrugated expansion joints, as with the slip type, have the advantages of requiring less space and
producing less pressure drop and heat loss than the expansion bends or loops. In addition, they do
not require maintenance as in the case of the slip type. However, the amount of movement
provided by the bellows or corrugations is less than can be provided by the slip expansion joint. Also
they are vulnerable to condensate corrosion during shutdown periods, as the condensate will not
drain effectively from them. Figure 31 illustrates the various different designs of bellows or
corrugations.
Figure 31
Types of Bellows Courtesy of U.S Bellows Inc.
Figure 32
Pressure Balanced Expansion Joint
Fig. 32 is a complicated design of expansion joint – a pressure balanced expansion joint. It has rods
to restrict movement or pressure thrust. It can be self-supporting, and is used where structural
supports are not available, and expansion provisions are still required. An example would be high
above ground level between two pressure vessels, where no supports are available.
Courtesy of U.S Bellows Inc.
Figure 33
Externally Pressurized Expansion Joint
The externally pressurized expansion joint in Fig. 33 is suitable for higher-pressure service. This is
possible because the bellows has the line pressure on the internal and external surfaces. There is an
outer casing or pipe, which contains the pressure of the fluid in the pipe.
Objective Eleven
When you complete this objective you will be able to…
Describe design, location, operation of pipe support components, including hangers, roller stands,
variable spring hangers, constant load hangers, anchors, and guides.
Learning Material
PIPING SUPPORTS
Piping must be supported in such a way as to prevent its weight from being carried by the
equipment to which it is attached. The supports used must prevent excessive sagging of the pipe
and at the same time must allow free movement of the pipe due to expansion and contraction.
However, unlike a pipe guide, the pipe support does not control the direction of the pipe movement.
The supporting arrangement must be designed to carry the weight of the pipe, valves, fittings and
insulation, plus the weight of the fluid contained within the pipe. Fig. 34 illustrates two types of
adjustable pipe hangers, which can be suspended from overhead beams.
The roller stands in Fig. 35 may be bolted to brackets, structural supports, floors, etc. Vertical
adjustment of the pipe position in the case of the adjustable stand may be obtained by means of
four adjustment screws, which raise or lower the roller upon which the pipe rests. These roller type
supports also act as guides as they also keep the pipes from moving sideways.
Figure 34
Adjustable Pipe Hangers
Strap and Roller Type
Figure 35
Roller Stands
In the case of a horizontal pipe, which may be subjected to vertical movement by the action of
some other part of the piping system, the rigid type hangers or supports in Fig. 34 and Fig. 35 are
not suitable. In this situation, variable spring hangers are used which permit the pipe to move up or
down without disturbing the load distribution. Fig. 36 shows the variable spring type of hanger.
Figure 36
Variable Spring Hanger
If the amount of vertical movement of the supported pipe is large, then a constant support hanger
as shown in Fig. 37 is used. This type features a coiled helical spring, which is arranged to move as
the pipe moves and thus maintains a constant supporting force on the spring. Roller bearings with
sealed-in lubrication are used to reduce friction between the moving parts of the hanger.
The constant support hanger is factory adjusted and tested to support the specified load throughout
a definite range of travel. The spring compression can be adjusted in the field to give a plus or
minus 10% variation in the load setting.
Figure 37
Constant Support Hanger
Piping Anchors and Guides
Anchors are important in any piping system but there are some special considerations necessary
when expansion joints are used. No expansion joint will operate properly unless the pipeline is
securely anchored. In addition, the pipeline must have enough guides or supports to prevent
buckling or bowing of the pipe.
When guides are installed near an expansion joint they will hold the pipe in the proper position for
best operation of the joint. With the slip type joint, this will prevent misalignment of the sleeve in
the joint. With the bellows type joint, the guides prevent excessive stress on the bellows, which
would result from misalignment of the pipe. Fig. 38 shows a pipe guide and a slide. The pipe slide
supports the piping and allows for movement with expansion. Details of a pipe slide are shown in
Fig. 39. It allows for movement of the pipe both laterally and axially.
Figure 38
Pipe Guide and Slide
Figure 39
Pipe Slide Details
(Courtesy of Pipe Supports Limited)
A pipe alignment guide is a form of sleeve or framework, fastened to some rigid part of the
installation, which permits the pipe to move freely in one direction only, along the axis of the pipe.
It should allow sufficient clearance between the fixed and moving parts to give proper guidance
without excessive friction.
Anchors, in general, are installed to stabilize the piping at certain points, such as valves or other
equipment, junctions of two or more pipes, and terminal points. With expansion joints, anchors
serve to divide the system into sections, so that each expansion joint absorbs only the expansion of
its own section. Fig. 40 shows typical welded-in piping anchors.
If only one expansion joint is used in the pipe- line it should be placed in the middle of the line if it
is not fitted with an anchor and the line should be anchored at each end. If the single joint is fitted
with an anchor then it should be placed at the end of the line. When several expansion joints are
used in a piping system, the pipe may be anchored midway between the joints or else at the joints
themselves if they are fitted with anchor bases.
Figure 40
Typical Piping Anchors
Steam Traps, Water Hammer, Insulation
Learning Outcome
When you complete this learning material, you will be able to:
Explain the designs and operation of steam trap systems, the causes and prevention of water
hammer, and the designs and applications of pipe insulation.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
Explain the dynamics, design, and components of steam/condensate return systems for
steam lines and condensing vessels. Explain roles and locations of separators and traps.
2. Describe the design, operation and application of ball float, inverted bucket, thermostatic,
bi-metallic, impulse, controlled disc, and liquid expansion steam traps.
3. Explain the selection, sizing and capacity of steam traps and explain the factors that
determine efficient trap operation
4. Explain the procedures for commissioning, testing, and maintenance of steam traps.
5. Explain and compare condensate-induced and flow-induced water hammer in steam and
condensate lines. Explain the typical velocities, pressures and damage that can be created
in steam/condensate lines due to water hammer.
6. Describe specific trap and condensate return arrangements that are designed to prevent
water hammer in steam and condensate lines.
7. State precautions that must be observed to prevent water hammer and describe a typical
steam system start-up procedure that will prevent water hammer.
8. State the purposes of insulation for piping and process equipment and explain the
properties required for a good insulating material.
9. Identify the most common industrial insulating materials, describe the composition and
characteristics of each, and explain in what service each would be used.
10. Describe common methods for applying insulation to piping and equipment, including wrap
and clad, blanket, insulated covers and boxes. Explain the care of insulation and cladding
and the importance of maintaining good condition.
Objective One
When you complete this objective you will be able to…
Explain the dynamics, design, and components of steam/condensate return systems for steam lines
and condensing vessels. Explain roles and locations of separators and traps.
Learning Material
STEAM/CONDENSATE RETURN SYSTEMS
In the case of steam piping, it is necessary to constantly remove any condensate present from the
lines. If this is not done, the condensate will be carried along with the steam and may produce
water hammer and possible rupture of pipes or fittings. In addition, the admission of moisture
carrying steam to turbines, or engines, is undesirable.
In the case of steam heat exchangers, it is important that all condensate be completely removed
from the exchanger shell. Failure to provide complete condensate removal will lead to possible
water hammer and poor temperature control. The system must also remove air and carbon dioxide
from the pipelines, and exchangers, otherwise pitting and corrosion will occur.
Drain lines and traps must be provided at all points where condensate can accumulate, such as:
•
•
•
•
Upstream of the connection to a steam riser
At the ends of steam header mains
Ahead of expansion joints and bends
Inlets to steam valves and regulators
The condensate return system must be capable of handling the condensate load under normal
operating conditions, without causing excessive backpressure on the traps. Various devices are used
to remove condensate and moisture from the lines.
Fig. 1 shows a typical steam/condensate return system. In this system, the steam supply from the
boiler enters the steam separator, where entrained moisture, is removed. The steam then continues
on in the header and enters the expansion loop. Due to a change in the steam flow, traps are
provided on the inlet and outlet of the expansion loop to remove any condensate. These
condensates, as well as the returns from the utility system, all go into a condensate return tank.
The condensate is then pumped back into the boiler feedwater system.
Figure 1
Steam/Condensate Return System
Steam Separators
Steam separators, sometimes called steam purifiers, are installed in the steam lines to remove
moisture droplets and other suspended impurities from the steam. To accomplish this, the separator
either causes the steam to suddenly change its direction of flow or it imparts a whirling motion to
the steam. Both methods cause the moisture to be thrown out of the steam stream.
The separators, as shown in Fig. 2, use baffles, which cause the steam flow to suddenly change
direction. The moisture particles thus removed collect at the bottom and pass out through a drain
opening to a trap that will discharge it to the condensate return system.
Figure 2
Baffle Type Steam Separators
The separator, shown in Fig. 3, uses centrifugal baffles to give the steam a whirling motion. The
moisture particles are thrown out to the inside wall of the separator and pass to the drain. The
purified steam passes through secondary baffles to the separator outlet. These secondary baffles
are used to reduce the whirling motion of the leaving steam. The condensate, collected by the
steam separators, is drained off by means of a trap.
Figure 3
Centrifugal Type Steam Separators
Steam Traps
A steam trap is a device, which is used to discharge the water of condensation from steam lines,
separators, and other equipment without permitting steam to escape. The method by which the trap
performs this function varies with the particular design of trap. However, no matter what principle
of operation is involved, all traps should provide the following:
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Long life and dependable service
Resistance of trap parts to corrosion
Efficient venting of air and carbon dioxide
Ability to operate against the back pressure which will be present in the return line
Ability to operate satisfactorily in the presence of scale or sediment
Objective Two
When you complete this objective you will be able to…
Describe the design, operation and application of ball float, inverted bucket, thermostatic, bimetallic, impulse, controlled disc, and liquid expansion steam traps.
Learning Material
BALL FLOAT STEAM TRAP
Fig. 4 shows a sectional view of a ball float trap. As condensate flows into the trap, the stainless
steel float will rise and eventually open the discharge valve, allowing a flow of condensate to the
discharge outlet. Air and other gases, such as CO2, will escape to the discharge through the
thermostatic vent. When steam reaches the trap, it will surround the thermostatic vent bellows
causing the bellows to expand and close the vent, thus preventing the discharge of steam. In
addition, when the condensate level in the trap drops to a certain point, the float-operated valve will
close and prevent the escape of steam.
The float trap will work equally well whether the condensate load is light or heavy, and its operation
is not affected by steam pressure changes. It will not become air-locked on a start-up situation, as
it readily discharges the air immediately.
A ball float trap can be damaged due to water hammer and the bellows air vent is not suitable for
use with superheated steam. This type of trap will freeze, and is not suitable for outdoor use.
Figure 4
Ball Float Trap
Inverted Bucket Trap
An inverted bucket trap is shown in Fig. 5. Initially, the bucket hangs down holding the discharge
valve open. Condensate enters the trap and flows under the bottom edge of the bucket to fill the
trap body. The condensate will then flow out through the open discharge valve to the outlet. Any
steam that enters the trap will collect at the top of the inverted bucket giving it buoyancy and
causing it to rise, which will close the discharge valve. Air and CO2 gas collects at the top of the
inverted bucket and will pass through the vent at the top of the bucket to the upper part of the trap
body.
Some steam will also pass through this vent but will condense in the cooler environment near the
top of the trap. As more condensate enters the trap and as the steam, within the inverted bucket
condenses, the bucket will sink and again open the discharge valve. The accumulated air and CO2
will discharge first and then the condensate will discharge until more steam enters the bucket to
once again close the discharge valve.
The inverted bucket trap is simple in construction and easy to dismantle for inspection and cleaning.
It can be used for draining superheated steam lines and is better able to withstand water hammer
than is the ball float trap. This type of trap will not rapidly discharge air and can become air-locked,
which can be a serious problem in start-up situations. Like the ball float trap, it is liable to freeze if
exposed to low ambient temperatures.
Figure 5
Inverted Bucket Trap
Thermostatic Traps
Thermostatic traps operate on the temperature difference between the live steam and condensate.
Fig. 6 shows a cutaway view of a thermostatic trap. A corrugated bellows “A” is filled with a volatile
liquid, such as alcohol. “B” is a metal shield surrounding the element, and “C” is the discharge
valve. When steam enters the trap and surrounds the bellows, the alcohol will vaporize and expand
the bellows by its vapor pressure. As the bellows expands, it closes the trap outlet valve. When the
steam condenses and the condensate cools, the vapor, inside the bellows, condenses. The bellows
contracts and then opens the discharge valve.
This trap is small and can handle large amounts of condensate, and discharge large amounts of air,
on start-up. Another advantage is that it is self-draining, and therefore will not freeze. A
disadvantage of this trap is that the corrugated element is susceptible to damage from water
hammer and corrosion. It also cannot be used with superheated steam, as the high temperature will
create excessive pressure with the corrugated bellows.
Figure 6
Thermostatic Trap
Bi-Metallic
The bimetallic steam trap, as shown in Fig. 7, consists of bimetal strips of dissimilar metals welded
together, which deflect, when heated. As the condensate passes through the trap, its temperature
will increase deflecting the bimetal strip so that the valve can modulate the condensate flow through
the trap. When the trap is filled with steam, the bimetal strip will deflect enough to fully close off
the valve.
The bi-metallic trap is only used in special applications as the movement of the metal strips is slight
and the valve tends not to close tightly.
Figure 7
Bi-Metallic Steam Trap
(Courtesy of Spirax Sarco Limited)
Impulse
This type of trap employs the heat energy in the steam and condensate to control its operation. This
design, as shown in Fig. 8, consists of a piston type valve working within a control cylinder. When
cool condensate enters the trap, the pressure of the condensate acting upon the piston disc will lift
the valve to the open position, thus allowing the condensate to escape through the outlet orifice. A
portion of the condensate, however, instead of escaping through the outlet orifice, passes up past
the piston disc into the upper part of the control cylinder and then down through a small hole drilled
through the center of the piston valve to the outlet.
If the condensate entering the trap is at steam temperature, then the part entering the upper
section of the control cylinder will flash into steam as the section is at a lower pressure (outlet
pressure). The large volume of steam resulting will plug or choke the small hole through the center
of the valve and pressure will build up above the piston disc, thus forcing the valve into the shut
position.
Figure 8
Impulse Trap
Fig. 9 is a cutaway view of the impulse trap showing the control cylinder K and the valve L.
Figure 9
Impulse Trap – Cutaway View
Controlled Disc
In a controlled disc trap, as illustrated in Fig.10, condensate and air entering the trap pass through
the heating chamber, around the control chamber and through the inlet orifice. This flow lifts the
disc off the inlet orifice and the condensate and air pass to the outlet passages. When steam enters
the disc, its increased flow velocity across the face of the disc reduces the pressure in this area. The
pressure in the control chamber, above the disc, forces the disc against the orifice thus shutting off
the trap. The steam in the control chamber gradually bleeds off around the disc and the trap will
open once again. It will then discharge any condensate and close once again in the presence of
steam.
Figure 10
Controlled Disc Trap
(Armstrong Machine Works)
Fig. 11 shows the internal construction of a controlled disc trap. These traps have only one moving
part, the disc. They are suited for superheated steam and water hammer and vibration does not
affect the operation of the trap. The disadvantage of this type of trap is that it has a low condensing
capacity and will not operate at low pressures or with high backpressures.
Figure 11
Controlled Disc Trap Construction
(Armstrong Machine Works)
Note that the impulse trap and the controlled disc trap are two examples of “Thermodynamic” type
steam traps, because they utilize the velocity of the steam in their operation.
Liquid Expansion
The liquid expansion steam trap uses a thermostatic element or tube, which is filled with a special
oil, to control the opening or closing of the trap discharge valve.
Referring to Fig. 12, the operation of the trap is as follows. At the start-up of the system, the trap
discharge valve is wide open, allowing a flow of air and condensate from the system. When hotter
condensate or steam enters the trap, the liquid within the tube will expand and push the plunger
along, closing the valve by means of the plunger rod. When the condensate cools, the tube will
contract, the plunger will move back and open the valve, allowing the condensate to escape.
The sealing bellows acts as a packless gland to prevent leakage of liquid from the tube. The trap is
protected from the effects of water hammer or over-expansion, by the relief spring. The adjustment
screw allows the trap to be adjusted to discharge the condensate, at a desired temperature.
The advantages of this type of trap are that it can be used outside, as it will not freeze and they can
be used with superheated steam.
The disadvantages are that the tube is liable to corrode if the condensate contains corrosive
substances. In order to get enough movement of the valve, the rod has to be quite long (about one
meter in length).
Figure 12
Liquid Expansion Steam Trap
Objective Three
When you complete this objective you will be able to…
Explain the selection, sizing and capacity of steam traps and explain the factors that determine
efficient trap operation.
Learning Material
TRAP SELECTION
Selecting the correct trap for a specific application is critical to ensure all condensate will be
removed from the steam lines and the condensing vessels. The selection of the correct trap is
dependent on a number of variables. These variables are:
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Condensate capacity, under start-up conditions
Condensate capacity, under normal operating conditions
Condensate temperature the trap will have to handle
Steam header temperature
Pressure differential across the trap, under normal operating conditions
The location of the trap, whether inside or outside a building where it could freeze
Trap Sizing
In order to determine the correct size of the trap for an application, it is necessary to calculate the
condensate load to be removed by the trap, per hour. In the case of a trap used to drain a steam
main, the greatest rate of steam condensation will occur during the warming up period when the
pipeline is being brought up to its operating temperature. After this temperature has been reached,
the only condensation being produced will be by normal radiation losses from the pipe.
If the warm-up is done automatically, the trap must be sized to handle the large amount of
condensate produced during this warm-up period. However, if the initial heavy condensate load is
manually removed by using low point drains, the trap only needs to be sized to handle the
condensate produced by radiation losses occurring after the warm-up period, when the drains are
shut.
When choosing a trap for a particular service, it is usual to increase the calculated condensate load
in order to provide a safety factor. This is to ensure that the trap will have sufficient capacity in the
event that a change in operating conditions, such as a drop in line pressure, occurs.
Trap Flow Calculations
Automatic Warm-Up
The warming-up load is calculated by means of the following formula:
Where:
C = amount of condensate in kg
0.494 = specific heat of steel pipe
M = total mass of pipe in kg
t2 = final temperature of pipe °C
t1 = initial temperature of pipe °C
L = latent heat of steam at final temperature kJ/kg
The warming-up load “C” is divided by the number of minutes required for the warm-up and then
multiplied by 60, to give the load in kg/h.
Example 1:
Find the warm-up load in kg/h in warming up 30 m of 203.2 mm, Schedule 40 steel pipe to a
working pressure of 1350 kPa in a warm-up time of 10 minutes. Initial temperature of the pipe is
l0°C. Table 1 lists the dimensions and the mass per meter of different sizes of steel pipe with
varying wall thickness.
Table 1
Dimensions and Masses of Steel Pipe
Referring to Table 1, the upper figures in each square denote wall thickness in mm and the lower
figures denote mass per meter, in kilograms.
Solution:
Where:
M = 42.20 kg/m x 30 m (Table 1)
t2 = 193°C (Steam Tables) approx.
t1 = l0°C (Given)
L = 1967 kJ/kg approx. (Steam Tables)
In order to accomplish this warm up in 10 minutes, the condensate rate /h would be:
When choosing a trap for a particular service it is usual to increase the calculated condensate load
in order to provide a safety factor. This is to ensure that the trap will have ample capacity in the
event of a change in operating conditions such as a drop in pressure in the line. In Example 1, the
safety factor is not necessary if the capacity of the trap chosen is such that it can discharge 349
kg/h. at a warm up pressure of just above 0 kPa. As the pressure rises in the pipeline, the trap
capacity will automatically increase. The 349 kg/h is the warm up load and it is much greater than
the load the trap will have to handle after the system is up to operating temperature.
Manual Warm Up
In this case, as mentioned previously, the trap has only to handle the condensate produced by
radiation loss during the normal operation as the large amount of condensate produced during the
warm up is discharged by means of manually opening the low point drains.
The amount of condensate produced by radiation can be determined from Table 2, which lists
amounts for various pipe sizes.
Table 2
Condensate Load
Table 2 can be used to find the condensate load due to radiation for the pipeline in Example 1,
which is 203 mm diameter size and operates at 1344 kPa (abs) or 1241 kPa (gauge). Table 2 shows
that the kilograms of condensate per hour for 203 mm pipe at 1241 kPa are 0.98 kg for each metre
of pipe. As the pipe is 30 m long, then the condensate load is:
0.98 x 30 = 29.4 kg/h, at 1241 kPa
If the trap is installed between the boiler and the end of the steam main, a safety factor of 2 should
be allowed and the selected trap capacity would be:
29.4 x 2 = 58.8 kg/h, at 1241 kPa
If the trap is installed at the end of the main header, a safety factor of 3 should be allowed and the
selected trap capacity would be:
29.4 x 3 = 88.2 kg/h, at 1241 kPa
The condensate load for normal radiation losses can be calculated by the following formula, if a
table, such as Table 2, is not available.
Where:
C = Condensate, in kg/h
A = External area of pipe, in m2
U = Heat loss from uninsulated pipe, kJ/m2/°C temp. difference/h
t1 = Steam temperature °C
t2 = Air temperature °C
L = Latent heat of steam at operating pressure
E = 1.0 - efficiency of insulation
Example 2:
Find the condensate load due to radiation in 30 m of 203.2 mm steel pipe, operating at 1344 kPa
(abs) and covered with 75% efficient insulation.
Given that U = 63.34 kJ/m2/°C and the ambient temperature is 21°C.
Solution:
This amount must be increased by the appropriate safety factor of 2 or 3 depending upon the trap
location as explained previously.
Trap Capacity
The pressure differential of a trap is the difference in pressure between the pressure at the trap
inlet and the pressure at the trap outlet. For example, if the trap is removing condensate from a
main steam header operating at a pressure of 690 kPa and if the trap is discharging against
atmospheric pressure, then the pressure differential is 690 kPa. If, however, the same trap is
discharging against a backpressure of 70 kPa, then the pressure differential is 620 kPa.
The smaller the pressure differential between the trap inlet and outlet, the smaller is the trap
capacity. The greater the pressure differential, the greater will be the trap capacity.
Trap capacity also depends upon the size of the discharge orifice of the trap and the temperature of
the condensate. The larger the discharge orifice, the greater will be the trap capacity and vice
versa. The higher the temperature of the condensate, the smaller the capacity of the trap because
the high temperature condensate will generate flash steam, which will tend to partially choke the
discharge orifice.
Steam Trap Efficiency
The proper installation of a steam trap is important in order for it to operate efficiently.
Some of the important considerations regarding trap installations are listed below:
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The trap must be of the correct capacity and pressure rating, for the job
The trap should be installed in an accessible location close to and below the drip point
Check directional markings on the trap to make sure it is not installed backwards
Unions and shut-off valves should be installed on either side of the trap and in addition a
strainer, test valve, and a bypass valve are recommended, as shown in Fig. 13
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Do not use piping smaller then the size of the trap connections
Inlet lines to the trap should be pitched towards the trap
If a group of traps drain into a common return header, a check valve should be installed
between the trap and the return header
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Use self-draining traps on installations subject to freezing temperatures
Have a separate trap for each piece of equipment, as short-circuiting will occur if a single
trap drains more than one unit
Figure 13
Piping for Inverted Open Float Steam Trap
(Crane Limited)
Objective Four
When you complete this objective you will be able to…
Explain the procedures for commissioning, testing, and maintenance of steam traps.
Learning Material
STEAM TRAP COMMISSIONING
The piping arrangement for the installation of an inverted open float steam trap is shown in Fig. 13.
When commissioning a new steam trap, the following steps should be followed:
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Blow the main steam header, at full line pressure, through the use of low point drains to
remove any rust, scale, etc
Make sure the globe valve on the bypass line and the trap inlet gate valve are both closed
Remove the steam trap and install a pipe cap on the line below the sediment separator
Fully open the trap inlet gate valve
Partially open the sediment separator blowoff valve until a good volume of steam issues
from the valve
Close the trap inlet gate valve
Remove the cap and blowoff valve on the sediment separator and clean the internal screen
Put the screen in the sediment separator cap and reinstall
Reinstall the steam trap
Make sure the gate valve on the outlet line, is closed
Crack open the trap inlet gate valve, and allow condensate to fill the trap
Open the outlet gate valve
Testing
In order to determine whether or not a trap is working properly, it must be tested. The most
positive method of testing is to observe the discharge from the trap by means of a test valve, as
shown in Fig. 13. By opening the test valve and observing the discharge, it can be seen whether the
trap closes off tightly, blows live steam, discharges continuously or does not discharge at all.
Other methods of testing are by determining:
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The temperature, before and after the trap, by the use of thermometers or pyrometers. If
the trap is operating properly, the temperature on the exit will be cooler due to the
condensing of the steam into water
The pressure, before and after the trap, by means of pressure gauges
The operation of the trap through the use of a listening device, such as a stethoscope
Maintenance
In addition to regular testing, traps should be dismantled, for inspection, at least once a year.
During this inspection, the following tasks should be completed:
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The trap body and operating parts should be examined for corrosion, erosion, mechanical
wear, etc
All internal parts should be cleaned and worn valves, seats, levers etc., should be replaced,
as should cracked buckets, floats or bellows
•
All gasket seating surfaces should be thoroughly cleaned and new gaskets used on
reassembly
In addition to the inspection of the traps, all strainers should be
cleaned and inspected regularly. A record log or card should be
kept for each trap showing dates and details of inspection, repair
and replacement.
Objective Five
When you complete this objective you will be able to…
Explain and compare condensate-induced and flow-induced water hammer in steam and condensate
lines. Explain the typical velocities, pressures and damage that can be created in steam/condensate
lines due to water hammer.
Learning Material
INTRODUCTION
Water hammer is the term used to describe the pressure surges or banging noises that are created
inside pipes carrying water, steam, or other liquids or liquid vapour mixtures.
Condensate Induced Water Hammer
When steam is introduced into a cold pipe, when a steam pipe is cooled suddenly, or when flow in a
steam pipe is very slow and normal cooling occurs, the steam reverting to water forms condensate.
If the condensate can be removed from the pipe as fast as it is being formed, there will not be any
problem with water hammer occurring. However, there are not always drains located at all the
points where condensate may form.
Tests have been conducted in transparent piping, and observations indicate that water hammer
occurs when a bubble of steam has become enclosed by cooler condensate. Steam in the bubble
transfers heat to the surrounding water and then reverts to condensate. This rapid condensation
leaves a low pressure void and condensate rushes in to fill the void. In other words, the steam
bubble implodes with the result that the inrushing water from one side of the bubble, is met by
inrushing water from the opposite side of the bubble. This causes a bang, or shock wave, generated
by a collision of the masses in motion. Fig. 14 illustrates the progressive collapse of a steam bubble.
Figure 14
Collapsing Steam Bubble
Some of the factors that determine the magnitude of the shock are:
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The temperature differential between the steam and the cooler condensate
The diameter of the pipe
The amount of condensate in the pipe
Very cold water can cool steam quickly and reference to a steam table will indicate that vapour
pressures could be lowered to almost zero absolute pressure.
Higher steam pressures applied to the system serve to increase the pressure differential driving the
water into the collapsing void, with greater ferocity. Shattered pipe fittings, broken mains or
damaged equipment are visible evidence of the violent results of uncontrolled water hammer.
Fig. 15 shows how a steam trap failure, or trying to bring on a steam main faster than the trap can
remove the condensate, could cause water hammer to occur.
Figure 15
Ripples on Condensate Form into Collapsing Bubbles
As shown in Fig. 15, steam entering from the left overruns the cold condensate. The steam can
displace any air existing above the condensate so that if a bubble is formed, there is no air in the
collapsing bubble to cushion the impact. As the velocity of the steam increases, it causes ripples to
form on top of the water. These ripples come in contact with the top of the pipe and steam
chambers are formed. For this reason, multiple shock waves are produced. In small piping, such as
in a steam heating radiator, repeated banging is common. When the thermostat calls for steam to
be admitted to the radiator, intense banging may begin. As steam progresses through the radiator,
residual condensate is warmed and the banging becomes less violent.
Water hammer will also be produced if steam is admitted to a pipe, which contains some water or
condensate. The steam on passing above the surface of the water will raise up behind it a mass of
water and thus a pocket of steam will be formed. This steam will rapidly condense due to contact
with the water and a vacuum will be formed in the pocket. The water rushing into this vacuum will
produce condensate-induced water hammer.
In the situation illustrated in Fig. 16, steam is flowing through the main line but the branch line is
shut off and has filled with condensate up to the shut-off valve. In Fig. 16 (1), the drain valve
located just before the branch line shut-off has been opened and condensate is draining from the
branch line. Fig. 16 (2) and 16 (3) show the steam flowing into the branch line as the condensate
drains away. Fig. 16 (4) shows the steam beginning to displace the condensate in the upper portion
of the shut-off valve and, in Fig. 16 (5), a pocket of steam has become trapped in the upper portion
of the valve. This steam rapidly condenses, forming a vacuum into which the remaining condensate
is driven with great force by the steam pressure behind it, as shown in Fig. 16 (6).
This situation can result in the disastrous rupture of valves and fittings, and loss of lives. It must be
stressed, therefore, that before admitting steam to any piping system, all water or condensate must
be positively removed from all parts of the system. Traps, which are fitted to main lines, branch
lines and separators for drainage purposes must be installed with bypass lines around them, which
may be opened to ensure positive drainage. The force of the condensate rushing into the void
caused by the collapsing steam pocket can cause a pressure surge in excess of 300 000 kPa.
Figure 16
Water Hammer
Flow Induced Water Hammer
When a valve is closed too quickly in a pipeline through which water is flowing, the immediate result
is a decrease in the water velocity and an increase in pressure, at the valve. This increase in
pressure may be sufficient to rupture the valve. If not, then a wave of pressure will travel back
through the pipe to the reservoir or main and then back again to the closed valve. This cycle will
repeat itself at regular intervals, producing a series of shocks within the pipe. The pressure
pulsations will gradually decrease in magnitude due to the friction in the pipe but, when they are at
their greatest, they may be enough to rupture fittings or valves.
Another situation that can produce flow induced water hammer is the sudden stopping of a motor
driven centrifugal pump due to a power interruption or "trip out.” When this happens, the water in
the pump discharge line will stop and then reverse direction. Subsequent rapid closing of the check
valve at the pump will cause water hammer.
Steam flow induced water hammer occurs when condensate builds up in the steam line until the
flow of steam is so restricted that the steam will pick up a slug of condensate and carries it down
the line. This slug of condensate is now traveling at the speed of the steam, which can be as high as
several hundred km/hr., until it reaches a bend in the pipe or a closed valve. At this point, it will hit
the bend in the pipe or the closed valve and stops suddenly, with disastrous results. The resulting
pressure surge from this type of water hammer can be as high as several thousand kPa. Pressure
surges from steam flow induced water hammer are not as high as the pressure surges from
condensate-induced water hammer. Condensate induced water hammer can produce pressure
surges 10 to 100 times greater then those caused by steam flow induced water hammer.
Objective Six
When you complete this objective you will be able to…
Describe specific trap and condensate return arrangements that are designed to prevent water
hammer in steam and condensate lines.
Learning Material
TRAP ARRANGEMENTS
Water hammer in steam lines is normally caused by the accumulation of condensate. The proper
installation of traps to prevent water hammer includes the following:
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Steam lines must be properly pitched toward a drip trap station. Drip trap stations must be
installed ahead of any risers, expansion joints, bends, at the end of steam mains and every
90 to 150 metres along the steam piping
Drip traps must be installed ahead of all stem regulator valves to prevent the accumulation
of condensate when the valve is in the closed position
Each drainage point must be equipped with a drip pocket, free flow drain valve, and a trap
Gate valves in the lines must not be installed with their stems below the horizontal because
the valve bonnets would act as pockets for the condensate to gather in
“Y” strainers installed in steam lines should have the screen and dirt pocket mounted
horizontally to prevent condensate from collecting in the screen area and being carried
along in slugs, into the steam flow
All equipment using a modulating steam regulator on the steam supply must provide
gravity condensate drainage from the steam traps
Condensate Return Arrangements
Steam pockets, forming and imploding, is the major cause of water hammer, in condensate lines.
Frequently, the cause is a rise, or lift, in the discharge line from a trap or a high-pressure trap
discharging into a low temperature wet return line. This lift is shown in Fig. 17.
The proper design of the trap and condensate return system is critical in preventing water hammer
in a condensate system. The best way to avoid water hammer in a condensate return line is to have
the traps drain into a gravity return line. Properly sized return lines allow condensate to flow along
the bottom and flash steam to flow in the top of the pipe. The top portion also allows efficient air
venting during start up.
If a lift is used, then the most common type of trap used is the Inverted Bucket Trap as the open
bucket design can handle moderate water hammer. If at all possible, avoid lifts in the trap discharge
lines.
Figure 17
Trap Line Lift
In some systems where the temperature from one condensate stream is much cooler than another
stream, a small steam heat exchanger is used to heat up the cooler condensate. Fig. 18 illustrates a
gravity drain system. The condensate drains into a condensate collection tank, which is vented to
atmosphere via a loop seal. The condensate in the tank is pumped out to the return system.
Figure 18
Condensate Steam Heater
Objective Seven
When you complete this objective you will be able to…
State precautions that must be observed to prevent water hammer and describe a typical steam
system start-up procedure that will prevent water hammer.
Learning Material
PRECAUTIONS
Before warming up a steam line, there are several precautions you should take to ensure that the
line is completely drained of condensate.
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Make sure that the line is completely blocked in at both ends
Slowly open each low point drain on the steam line. Be sure the drain lines are free and
clear of any blockage
Check that each trap is in service
Ensure all condensate has been drained from the pressurized side of the steam supply valve
Steam System Startup
The following describes a typical startup of a steam system.
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All low point drain valves must be opened wide. These are usually located upstream of all
the trap stations and the supply to steam turbines inlet valves
Crack open the bypass around the main header steam admission valve, if so equipped. You
should hear steam entering the header
If a bypass is not installed, crack open the main header steam admission valve
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Check each low point drain for the presence of condensate
If there is not any condensate coming from the drains, increase the opening of the main
header steam admission bypass valve
Listen for the sounds of any water hammer taking place. If there is any, reduce the flow of
steam into the header
Close the low point drain valves when there is dry steam issuing from them
Continue opening the main header steam admission bypass valve to pressurize the header
Once the bypass is wide open and there is not any rise in steam header pressure, crack
open the main header steam admission valve. Close the bypass valve
Continue opening the main header valve, as the steam pressure rises
Check that each trap is working properly, to prevent an unexpected build-up of condensate
in the steam line.
Objective Eight
When you complete this objective you will be able to…
State the purposes of insulation for piping and process equipment and explain the properties
required for a good insulating material.
Learning Material
PURPOSES OF INSULATION
Most power plant piping systems are used to convey substances that are at temperatures much
higher than that of the surrounding air. Examples would include the main steam piping and
feedwater piping. In order to reduce the amount of heat lost to the surrounding air from the hot
substance, the piping is covered with insulation. The insulation not only retains the heat in the hot
lines, but also prevents the temperature inside the power plant building from becoming
uncomfortably high. In addition, insulation of hot pipe lines will prevent injury to personnel due to
contact with the bare surfaces of the pipe.
In the case of piping that carries substances at a lower temperature than that of the surrounding
air, insulating the piping will prevent sweating of the pipe and consequent dripping and corrosion.
Insulating Material Properties
A material, suitable for use as insulation, should have the following properties:
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High insulating value
Long life
Vermin proof
Non-corrosive
Ability to retain its shape and insulating value, when wet
Ease of application and installation
An insulating material may be defined as one that transmits heat poorly. It has been found that
substances having a large number of microscopic air pockets dispersed throughout the material
make the most efficient insulators. This is due to the extremely small air spaces restricting the
formation of convection currents and that air, itself, is a poor conductor of heat.
Thermal Conductivity
The coefficient of thermal conductivity (l) of a material is a measure of the amount of heat that will
be transmitted through this material. Therefore, the lower the value of “l” for a material, the better
will be its insulating ability.
Heat energy always flows from a higher to a lower temperature level. The heat energy is
transmitted from the hot to the cold zone by impact between adjacent molecules and convection
currents, so that a continuous flow of energy occurs as long as a temperature gradient exists.
It has been found by experiments that the quantity of heat transmitted, per unit of time, by
conduction is directly proportional to the cross-sectional area of a body and the temperature
gradient, and is inversely proportional to the length of the path. Thus, heat transmission by
conduction through a body, can be expressed as a formula:
Where
Q = heat transferred, in joules
l = thermal conductivity or coefficient of heat transfer in or
A = cross sectional area of path, in m2
t = time, in seconds
ΔT = temperature difference between surfaces, in °C
d = thickness of layer, in m
Most insulation has “l” values between 0.004 and 0.012 W/m°C. The “l” value for any one material
will vary according to the temperature to which it is exposed. For example, a material having a “l”
value of 0.004 at 150°C may have a “l” value of 0.008 at 500°C.
Objective Nine
When you complete this objective you will be able to…
Identify the most common industrial insulating materials, describe the composition and
characteristics of each, and explain in what service each would be used.
Learning Material
PIPE INSULATION MATERIALS
Calcium Silicate
Calcium silicate is a granular insulation made of lime and silica, reinforced with organic and
inorganic fibers and molded into rigid forms. Service temperature range covered is 38°C to 650°C.
Its flexibility strength is good. Calcium silicate is water absorbent, but it can be dried out without
deterioration. The material is noncombustible and is used primarily on hot piping and surfaces.
Metal jacketing is field applied. Its “l” value is 0.055, at 93.3°C.
Glass Fiber
This is glass that has been processed into fibers and then formed into pipe covering sections, which
are suitable for temperatures up to 454°C. It is noncombustible and is water absorbent. Its “l” value
is 0.032, at 23.9°C.
Mineral Fiber (Rock And Slag Wool)
Rock and/or slag fibers are bonded together with a heat resistant binder to produce mineral fiber or
wool available in loose blanket, board, pipe insulation, and molded shapes. Upper temperature limit
can reach 1040°C. The material has a practically neutral pH, is noncombustible, and has good
sound control qualities. Its “l” value is 0.040, at 93.3°C.
Expanded Silica, Or Perlite
Perlite is made from an inert siliceous volcanic rock, combined with water. Heating, causing the
water to vaporize and its volume to expand, expands the rock. This creates a cellular structure of
minute air cells surrounded by vitrified product. Added binders resist moisture penetration and
inorganic fibers reinforce the structure. The material has low shrinkage and high resistance to
corrosion. Perlite is noncombustible and operates in the intermediate and high temperature ranges.
The product is available in rigid pre-formed shapes and blocks. Its “l” value is 0.069, at 93.3°C.
Elastomeric
Foamed resins, combined with elastomers, produce a flexible cellular material. It is available in preformed shapes and sheets. Elastomeric insulations possess good cutting characteristics and low
water and vapor permeability. The upper temperature limit is 104ºC. Elastomeric insulation is cost
efficient for low temperature applications with no jacketing necessary. Resiliency is high.
Consideration should be made for fire retardancy of the material. Its “l” value is 0.040, at 23.9°C.
Foamed Plastic
Insulation produced from foaming plastic resins creates predominately closed-cellular rigid
materials. "l" values decline after initial use as the gas trapped within the cellular structure is
eventually replaced by air. Foamed plastics are light weight with excellent moisture resistance and
cutting characteristics. The chemical content varies with each manufacturer. It is available in preformed shapes and boards. Foamed plastics are generally used in the low and lower intermediate
service temperature range, -183°C to 150°C. Consideration should be made for fire retardancy of
the material. Its “l” value is 0.037, at 10°C.
Refractory Fiber
Refractory fiber insulations are mineral or ceramic fibers, including alumina and silica, bound with
extremely high temperature binders. The material is manufactured in blanket or rigid form. Thermal
shock resistance is high. Temperature limits reach 1650°C. The material is noncombustible. Its “l”
value is 0.123, at 538°C.
Insulating Cement
Insulating and finishing cements are a mixture of various insulating fibers and binders with water
and cement, to form a soft plastic mass for application on irregular surfaces. Insulation values are
moderate. Cements may be applied to high temperature surfaces. Temperature limits reach
1038°C. Finishing cements, or one-coat cements, are used in the lower intermediate range and as a
finish to other insulation applications. Its “l” value is 0.252, at 316°C.
Magnesia (85%)
This material is composed of magnesium carbonate with asbestos fiber. It is available in molded
form for pipe covering and is also supplied in powdered form to be mixed with water to form an
insulating cement, which is used to cover pipe fittings. Magnesia pipe covering is suitable for service
up to 320°C with “l” values from 0.35 to 0.42.
Reflective Metal Insulation
This is a fairly new type of insulation constructed of metal reflective sheets of stainless steel, spaced
and baffled to form isolated air chambers around the piping. The highly polished reflective sheets
reflect the heat and prevent loss due to radiation, yet absorbs little heat by conduction. This is used
for temperatures above 1040°C, with “l” values from 0.53 to 0.66.
Pipe Insulation Types
Piping insulation is normally fabricated in half-cylindrical sections for fitting over the pipe. It is held
together by metal wire or bands, and then covered with sheet metal, aluminum or galvanized steel.
Some typical examples of pipe insulating sections are shown in Fig. 19. Fig.19 (A) shows insulation
for small diameter pipe. It is split along its length and opens up to fit over the pipe. Fig.19 (B) and
(C) show the half-cylindrical sections of insulation for various larger size pipes.
Figure 19
Molded Pipe Insulation
Objective Ten
When you complete this objective you will be able to…
Describe common methods for applying insulation to piping and equipment, including wrap and
clad, blanket, insulated covers and boxes. Explain the care of insulation and cladding and the
importance of maintaining good condition.
Learning Material
WRAP AND CLAD
Sectional pipe covering is assembled over the pipe and bound with wire or light metal bands. A light
canvas or linen covering may be pasted down, cut to the correct size and then painted. Paint
provides a vapor barrier, protecting the pipe from corrosion and the insulation from getting wet, as
wet insulation loses its insulation value. This insulation is covered with aluminum or stainless steel,
the two types of metal cladding used in industry today. Cladding gives additional protection against
mechanical damage and weather elements. This type of insulation is used on long lengths of pipe
where there are no fittings or flanges.
The environment determines whether to use aluminum or stainless steel cladding. If metal cladding
is used in a chemical installation where there are caustic lines, the insulation is covered or wrapped
with stainless steel. This is done to prevent damage to the covering in the event of a leak or spill.
Molded Insulation
Molded insulation is available for standard size fittings. Figs. 20 and 21 illustrate the molded form
used for piping and piping fittings.
Figure 20
Installing Piping Insulation
(Courtesy of Owens Corning)
Figure 21
Pipe Elbow Insulation
Insulated Blankets
Insulating blankets are used in various applications. They are easy to install and remove for
maintenance. They are very convenient for use with expansion joints, valves, steam traps and other
odd shaped vessels, and they can be used in high temperature applications.
Insulated Covers
Insulated covers are used for odd size or shaped fittings, such as a valve, as shown in Fig. 22.
Figure 22
Insulated Cover
Insulated Boxes
Insulated boxes are used to cover valves, flanges, steam traps and condensate return stations.
Insulation Maintenance
The following are key points that will help to maintain the integrity and maximize the life of
insulation:
•
•
It must not get wet, as wet insulation loses its insulating ability
The insulation should not be cracked or broken, as this will greatly reduce its effectiveness
•
The cladding must not be removed from the insulation, as the cladding holds the insulation
in place, thereby protecting it from damage
•
Do not walk on the pipe and equipment, as this will damage the insulation
•
Be sure that all insulated boxes, covers and blankets are in place
•
Be sure that any damaged insulation is replaced as soon as possible; this prevents the loss
of heat and allows moisture in to promote corrosion to the piping
•
Replace any missing insulation as soon as possible as personnel working in the area could
be burned from the hot process fluids in the piping
Figure 23
Insulated Piping Systems
(Courtesy of Owens Corning)
Valves and Actuators
Learning Outcome
When you complete this learning material, you will be able to:
Describe the designs, configurations and operation of the common valve designs that are used in
power and process piping.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
Explain the factors that determine the suitability and applications of the major valve styles;
gate, globe, ball, plug, butterfly and needle.
2. Explain the factors that determine the selection of valve materials, and describe examples
of typical valve body and trim materials. How are common control valves identified?
3. Describe the configurations and applications for gate valves, including gate designs (solid,
split, flexible, sliding), stem configurations (rising, non-rising, outside screw-and-yoke,
inside screw), and bonnet designs (flanged, screwed, welded).
4. Describe the designs and applications of globe valves, including conventional disc,
composition disc, plug-type disc, and angle valves. Describe high-pressure plug-type
control valves.
5. Describe the designs, application and operation of single-seated and double-seated balance
valves. Explain caged trim for balanced control valves.
6. Describe the designs and applications of typical plug valve designs, including tapered and
cylindrical plug, four-way, eccentric, and jacketed.
7. Describe the designs and configurations for mixing and diverter valves.
8. Describe the designs and operation of diaphragm valves
9. Describe designs and operation of butterfly valves, including vertical, horizontal, swingthrough, lined, and high-performance.
10. Describe the design, application, and operation of gear, motor, air-diaphragm, and airpiston actuators for valves.
Objective One
When you complete this objective you will be able to…
Explain the factors that determine the suitability and applications of the major valve styles, namely
gate, globe, ball, plug, butterfly and needle.
Learning Material
FACTORS AFFECTING THE SUITABILITY AND APPLICATION OF VALVES
With the broad range of valve designs available to industry today, success of any fluid-handling
system depends greatly on proper valve application. Fluid properties, type of service and operating
conditions are factors that must be considered carefully for each and every valve selection.
Similarly, temperature and pressure can vary from one location to the next and the fluid itself may
change in character. If these variables are not taken into account during selection, money saved
initially in valve purchases, may be spent later doing repairs and valve replacement.
Fluid Properties
In valve selection an examination of the fluid to be handled is made to determine its properties and
characteristics. It includes the corrosive tendencies of the fluid and whether it contains any solids. If
the fluid starts as gas, will it liquefy or when it enters the line as a liquid, and will it later turn into a
vapor? The piping engineer considers all components in the fluid separately to ensure proper valve
selection for the system.
Valve Size
Valves are made in a full range of sizes to match the pipe and tubing in which they are placed. In
installations where pipe size has been purposely selected larger, the valve size must also be equally
designed. For example, a 75 mm valve would be selected for use in a 75 mm piping section. As a
rule of thumb, a valve that is smaller than the pipe should never be used. That is, a 75 mm valve
would not be put into a 100 mm pipeline. The effect would be to reduce fluid flow and increase
friction. It would be possible, however, to use a larger valve size in a given piping size but ordinarily
there is no reason for doing so.
Valve sizes are selected in accordance with the capacity needed and permissible fluid-friction losses.
Also, the type of fluid handled, turbulence, specific gravity, and viscosity must be considered.
Cavitation or other physical damage that valves frequently suffer may be caused by poor valve
sizing.
Valve size and material of construction go hand in hand. The larger the valve size selected, the
stronger the material that must be used. Brass valves for example, are common up to 50 mm size.
In larger valves, iron or steel is employed. More extreme services (higher temperatures and
pressures) demand steel valves forged up through the 50 mm size. Larger valves over 50 mm are
normally cast.
Valve Service
The type of valve needed is dictated by the job at hand. Simple shutoff or isolation usually calls for
a gate or similar on-off valve. When either manual or automatic modulating control is required, one
of many globe designs may be the best choice. To prevent flow reversal, one of the types of check
valve may be appropriate. A plug or ball type valve best handles fluids, which carry solids likely to
jam under the seat of a gate valve. The various types of valves are explained later in this module.
Fluid Friction Loss
Fluid friction loss and pressure drop are inherent losses that are responsible for a major portion of
the total energy loss in many fluid-handling systems.
In the past, designers simply had to live with the high friction loss caused by globe valves employed
in flow control. But recent development work has made great strides in reducing wide open losses
through many globe valve and check valve types. Manufacturers are constantly developing new
configurations to minimize these energy losses and reduce operating costs.
Generally, fluid-friction losses vary with smoothness of flow path. This is shown in Fig. 1, which
shows a standard globe valve and a low-loss globe valve design. In the standard valve, sharp
corners and abrupt changes in cross section create turbulence and increase in fluid-friction losses.
Figure 1
Fluid Friction Losses
In the special low-loss valve, there are carefully contoured internal water- ways to guide the flow
through the valve, while gradually altering cross section and velocity. Minimum turbulence results in
lower fluid-energy losses.
Fig. 2 illustrates the pressure loss through the most common valve types. The globe valve has the
most restriction to flow or pressure drop. The wide-open gate valve has the least pressure drop. The
butterfly valve also has a very small pressure drop compared to the other control valves, and is the
reason the butterfly control valve is becoming more and more popular. Some pressure drop is
necessary for flow control, however. The aim of designers is to have enough pressure-drop for
adequate flow control, with the least amount of pressure drop.
Figure 2
Head (Pressure) Loss of Common Valve Types
Pressure and Temperature
Pressure and temperature often vary widely within a given fluid-handling circuit, affecting valve
selection. The American Standard Association and other associations have set standards for
pressure-temperature relationships. Manufacturers rate their valves in accordance with the
standards. Designers commonly refer to these standards for applications within the pressuretemperature class required.
The pressure-temperature range of a valve is often different from that required in a piping system.
There may be, for example, a fluid in a process line operating at 4000 kPa and 260°C. The valves
required may not be necessarily of the 4000 kPa class. Instead, if valves of carbon steel are
selected and rated at 2000 kPa, a significant cost saving may be achieved. It is advisable therefore,
to consult the ASA standards or manufacturer’s tables in every valve application, since they
represent about 97 percent of all valves used in a typical plant.
Gate Valves
Three quarters of all valves employed in refineries, petrochemical, and gas processing plants are
gate valves. Gate valves offer flow with little turbulence and very little pressure drop. They are
adapted for services requiring isolation of equipment and are available in sizes from 10 mm to 2700
mm.
The gate valve, as illustrated in Fig. 3, consists of a gate-like disc, actuated by a screwed stem and
hand wheel, which moves up and down at right angles to the flow. In the closed position, the disc
seats against two faces to shut off flow. To retain the fluid from leaking around the valve stem, a
gland containing packing is used.
Figure 3
Gate Valve
Globe Valves
In a globe valve, as shown in Fig. 4, the flow of the fluid passing through it changes direction twice.
The disc and the seat are parallel to the main flow path, and the disc is moved toward, or away
from, the seat by means of a threaded stem.
Globe valves have the largest pressure drop or head loss of the valve types as shown in Fig. 2. They
are commonly found for throttling applications and for controlling fluid flow. Control valves are often
of the globe type.
Figure 4
Globe Valve, Plug Type Disc
Ball Valves
The ball valve has a spherical plug with a passage bored through it, as illustrated in Fig. 5, which
controls the fluid flow through the valve body. The basic type of ball valve requires a quarter turn
from the fully open to the fully closed position. The valve can be operated by means of a lever,
which also serves as an open or shut indicator, or by the use of an automatic or powered actuator.
The spherical plug not only gives precise control of the flow through the valve, but also gives a tight
shutoff when in the closed position. The valves are designed so that no internal lubrication is
required and the torque required to rotate the ball is negligible. The ball and stem are often
machined from one piece.
Figure 5
Ball Valve
For larger sizes and high-pressure ratings, the ball is constructed with a double stem and is
supported by bearings. This construction requires a seal for one end and a packing box for the
opposite end.
Ball valves are suitable for handling slurries and fluids with a high solid content, and for this reason
have found wide applications in the paper industry, chemical plants, and sewage treatment plants.
They are also used for quick closing isolation purposes. In instrumentation they are often used for
instrument air block valves.
Plug Valves
Fig. 6 illustrates a typical plug valve. It consists of a cylindrical or tapered plug, which fits snugly in
the valve housing. A nearly rectangular opening in the plug allows the fluid to pass through when
the opening is in line with the axis of the valve housing. By turning the lever attached to the stem of
the plug one quarter of a turn, the valve is completely closed. The tapered plug is secured in the
valve housing by the valve cover. A stuffing box is recessed in this cover where the packing is held
in place by a gland, thus preventing leakage along the stem.
Plug valves, also called cock or petcock valves, have gained acceptance because of their simplicity,
compactness and quick action. Although primarily an open-close valve, plug valves can be used for
flow control or throttling. In recent years, plug valves are increasingly favored in clear-liquid
systems, gas and air systems, and where space is a consideration. They are easy to operate, offer
positive closure, and can be automatically controlled. Plug valves are often used as quick opening
valves in gas supply lines, low-pressure steam and process lines.
Figure 6
Plug Valve
Butterfly Valves
A butterfly valve consists of the valve body, disc, shaft, and the necessary packing and bushings for
shaft support. The body is frequently a solid ring type, which is mounted between pipe flanges. The
disc is generally cast in one piece. Correct alignment of this valve is required to prevent binding of
the swing-through disc. The thickness of the disc is determined by the pressure drop across the
valve (throttling or closed position).
Butterfly valves come in sizes from 25 to 3800 mm and are designed for pressures up to 13 800 kPa
and temperatures up to 1100°C.
The flat disc can be rotated through 90° from the wide open to the fully closed position. The valve
shown in Fig. 7 is fitted with a lever for manual operation. A power actuator is required to position
the disc for bigger sizes because large pressure differentials can exist across the disc. The valve
shown in Fig. 8 has a motor operator, and can be manually or electrically operated.
Lug Body (a )
Wafer Body (b)
Figure 7
Butterfly Valves
(Courtesy of Dezurik Valves)
Figure 8
Power Operated Butterfly Valve
(Courtesy of Rockwell Manufacturing)
Butterfly valves are commonly used in thermal and hydroelectric power stations, oil and gas
processing industries, oil and gas transmission, and in water and sewage plants. Their advantages
are: relatively light weight, ease of operation, self-cleaning, and negligible pressure drop across the
valve when it is fully open.
Needle Valves
Needle valves allow precise flow control. Its name is derived from the sharp pointed disc and
matching seat. Fluid flow is controlled by the insertion depth of the point of the needle into the seat.
The stem threads are fine so that considerable movement of the hand wheel is required to increase
or decrease the opening through the seat. Usually, these valves have a reduced seat diameter in
relation to the pipe size.
An example of a needle valve is shown in Fig.9. Needle valves are commonly used for continuous
blow-down or chemical feed control services, as these applications require precise flow control.
Figure 9
Needle Valve
Objective Two
When you complete this objective you will be able to…
Explain the factors that determine the selection of valve materials, and describe examples of typical
valve materials, trim, and identification for common valve services.
Learning Material
MATERIALS OF CONSTRUCTION
Noticeable improvements in valve materials have been implemented in response to the demand to
meet increasingly severe operating conditions. Every manufacturer keeps pace with this progress to
simplify the problem of material selection and to prevent over design and waste of money.
The valve selection factors discussed are interrelated, but the importance of proper material
selection demands special attention, particularly when choosing valves for an energy system.
Economics plays an important role in the selection of valve materials. The corrosion resistant
materials like stainless steel, Monel, and titanium, are higher in cost than less corrosion resistant
materials such as carbon steel. The extra cost must be balanced off against less maintenance and
increased valve lifespan. Keeping a plant running can also be a factor. Having to shut down part or
all of a process to repair a valve can be extremely expensive. One day’s production may pay for
many valves. Therefore reliability is also a major concern.
Materials commonly employed for fluid-handling range from iron and bronze for low temperature,
low-pressure water service to sophisticated stainless steels for extreme pressure-temperature
steam conditions. In addition, many other metals and nonmetals are used to handle corrosive fluids
ranging from acetic acid to seawater.
When selecting valve materials, the valve body is considered separately from the trim (including
seats). This allows the optimum combination of materials for the valve. In control valves,
particularly where liquid velocities increase at the point of control, erosion can be the decisive factor
in trim selection. Seats and plugs take the beating here and, with solid-carrying liquids, the extra
cost of extremely hard materials usually pays. It is very common to have valves with carbon steel
bodies and stainless steel trim.
Cast-iron valve bodies in general can be used on water service up to temperatures of about 250°C,
brass valves up to about 300°C. At higher temperatures steel is a commonly selection. As
temperatures rise above 400°C, steel alloys such as the carbon-molybdenum, chrome-molybdenum
and chrome-nickel-molybdenum are used. For corrosive services stainless steel is the most popular.
Generally, in gate valves, the parts most severely worn are the discs and seats. Where erosion due
to velocity or solids is a problem, disc and seat materials are chosen for high surface hardness.
Where service dictates seats of different materials from the valve body, replaceable seats and disc
may cut the maintenance costs.
The valve trim refers to the valve disc and seat. The trim is the heart of any valve, as this is where
the flow control and the shutoff take place. Selection of proper materials for the trim is very
important.
For valve trim, brass is satisfactory up to about 300°C, but it is seldom used with steel valves
except in marine service. Stainless steel is a common valve trim material. Other more exotic
materials include Stellite, Hastelloy, Alloy 20, and Titanium.
Manufacturers recommendations must be followed closely. Variables effecting material selection
are: the process fluid and its temperature, and the pressure range that the system will operate in. If
the process fluid is very corrosive, as in dilute sulfuric acid service a lining material may have to be
selected separately from the valve material.
IDENTIFICATION OF VALVES
It is extremely important that the proper type of valve is used for a particular service. Serious
accidents have occurred when a valve of the wrong material has been installed in a piping system.
Therefore:
All valves must be properly identified as to the material of construction and the service conditions
for which they are designed.
All valves not properly or clearly identified should be rejected.
All markings shall be legible, the following basic information:
1. Manufacturer’s name or trademark.
2. Service designation, for example, pressure-temperature for which the fitting is designated.
3. Material designation, for example, steel or cast iron, and ASTM Number.
Objective Three
When you complete this objective you will be able to…
Describe the configurations and applications for gate valves, including gate designs (solid, split,
flexible, sliding), stem configurations (rising, non-rising, outside screw-and-yoke, inside screw), and
bonnet designs (flanged, screwed, welded).
Learning Material
GATE DESIGNS
The parts of a typical rising-stem gate valve were shown in Fig. 4. The stem rises out of the valve
as the valve is opened, and in this manner indicates the position of the gate. This type of valve has
an inside screwed stem and the packing is subjected to wear because of the up and down
movement and turning motion of the stem.
Figure 10
Gates for Gate Valves
Fig. 10 shows three types of gate valve closing elements or gates. The solid wedge design, on the
left, was the first invented. It is the simplest and most common type. The other two types have the
gate split vertically in the middle. This permits the wedged gate to adapt itself to small amounts of
distortion caused strain in the piping or seat wear.
The flexible wedge, in the center, is cut out between the two seats. The faces of the wedge that are
pressed against the two walls of the valve body seal the passageway. This flexibility is an advantage
when the valve has to be closed while it is being subjected to extremely high temperatures. The
body of the valve expands because of the heat. The gate then has less space, but it must be firmly
seated if it is to stop the flow. Because the gate has some “give”, excess stress on the valve spindle
is not required to close the gate.
The valve in Fig. 11 has a V-shaped insert. This type of valve would be used as a control valve. The
V-shaped opening has a different flow characteristic, usually more linear, than a standard round
shaped opening. The insert is designed to achieve the desired flow characteristics.
Figure 11
Sliding Gate Valve with V-Insert
Figure 12
High Pressure Parallel Sliding Gate
(Courtesy of Hopkinsons Valves and Controls)
Fig. 12 shows a parallel sliding gate design. In this design the gate is not a wedge. The sides of the
gate are parallel, and slide in and out to open or close the flow. This is a simple valve suited for on
– off operation and gives a tight shut off. In lower pressure models the gate can be thin. It is then
often referred to as a knife gate valve. Fig. 13 shows a knife gate type of valve.
Figure 13
Gate valve with Sliding Gate (Knife Gate)
(Courtesy of Dezurik Valves)
STEM CONFIGURATIONS
In the outside screw and yoke valve, shown in Fig. 14(a), the stem threads are outside of the valve,
and therefore, are not subject to extreme temperature changes with resulting galling. This valve is
well suited for steam and high temperature services and severe corrosive conditions. Most process
gate valves are specified with an outside screw and yoke because of the flow stream conditions
encountered.
Fig. 14(b) shows a valve that the handwheel and stem rise as the handwheel is turned. It has inside
or protected screw threads. This is an advantage as the treads stay lubricated and are not fouled by
atmospheric conditions such as dust. This type of valve may be used where there is ample room for
the handwheel to rise. There must be room for both the handwheel and the stem to rise fully
without striking any objects such as piping or steelwork.
In Fig. 14(c) rotation of the wheel operates the valve, but the stem does not come out of the
housing. The treads are inside the valve and protected. This type of gate valve is used where there
is low headroom or cramped space. No extra space is needed for the stem to rise to the open
position.
In Fig 14(d) the handwheel and stem turn together. The stem may be a rising or non-rising type. It
has outside screw threads. They are open to atmospheric conditions, and must be lubricated
periodically.
Fig. 14(e) shows a quick opening setup, where a lever moves the valve stem up and down. This
allows for quick opening of the valve. The lever must be long enough to supply the mechanical
advantage to lift the valve. There must be enough room to move the lever. The linkage is external
and must be kept lubricated. This type of valve stem configuration is not as common as the
handwheel designs. It is found more in lower pressure systems, where quick opening is an
advantage.
Figure 14
Gate Valve Stem Design
VALVE BONNET DESIGNS
Bonnet designs for gate valves are classified as to how they are attached to the valve. As shown in
Fig. 15, bonnets can be welded (union), flanged or threaded.
The welded type has the bonnet welded to the valve body. The welded type is leak-proof, but
repairs are difficult. The bonnet weld has to be removed before the valve can be repaired. After the
valve is repaired, the bonnet and valve are again welded together.
The flanged type consists of two flanges bolted together with a gasket forming the seal. This type is
good for repairs, but the flange is heavy and a possible source of leakage.
The treaded type has the bonnet and valve body threaded. They are screwed together. The
threaded variety needs room for the bonnet to be turned for removal. Usually the threaded type is
for lower pressures (where the piping has threaded joints), the bolted for medium pressures, and
the welded is for higher pressures.
Figure 15
Gate Valve Bonnet Designs
Objective Four
When you complete this objective you will be able to…
Describe the designs and applications of globe valves, including conventional disc, composition disc,
plug-type disc, and angle valves. Describe high-pressure plug-type control valves.
Learning Material
GLOBE VALVES
Globe valves are used for throttling and controlling fluid flow. With the exception of the composition
disc valve, this is a superior design for conditions requiring frequent operation and modulation of
flow.
The globe valve, compared to the gate valve, has a shorter stem travel, has relatively little wear
and is easier to repair. Globe valve design necessitates two changes in the direction of flow and this
causes resistance in liquid lines and pressure drop. Globe valves are installed so that the flow is up
through the seat ring and against the bottom of the disc. This prevents accumulation of dirt and
debris above the disc, which causes operating difficulties. Globe valves are best suited to clean
service. The piping should be cleaned out after maintenance, to prevent solids from damaging the
valves internals.
Bronze is used extensively in the construction of small size globe valves for low and high pressure
service. Also, iron body valves are made of two types of cast iron for light and medium metal
thickness. Steel valves, both cast and forged, are available in a variety of compositions. For more
severe service conditions, several types of stainless steels such as Monel, nickel, titanium, and other
alloys can be used.
Globe valves are selected based on the type of fluid and the degree of control required. Globe
valves are made in three basic disc types:
a. Conventional Disc
b. Composition Disc
c. Plug Type Disc
Conventional Disc
The conventional type disc is the earliest type of disc and seat construction and is made of a ball
shaped metal disc, which fits against a flat-surfaced seat in the body.
This type of globe valve is fairly cheap and popular in low-pressure service where severe throttling
is not required. Such a valve preferably should be used wide open or fully closed with little
modulation of flow since the short tapered disc is subject to severe erosion and wire drawing. The
seat and disc surfaces are easily reground if they are not badly damaged.
Composition Disc
The composition disc valve, Fig. 16, is an improvement over the ball type disc for many services,
but still is not suitable for throttling purposes. Various types of composition discs are available
making this type adaptable to many different services.
Figure 16
Globe Valve, Composition Disc
The flat disc is fabricated from various materials such as synthetics and asbestos suitable for cold or
hot water, steam, air, and petroleum products. This valve is easily and quickly repairable and
requires less power to seat tightly. Small particles or foreign matter are not likely to cause any
damage as they will likely imbed themselves in the relatively soft disc.
Plug Disc
The plug type globe valve, Fig. 17, is the best of the three types for throttling and hard service. The
disc is a long tapered metal plug seating into a cone that produces a wide seating surface. This
surface is not easily affected by foreign matter or by wire drawing and gives full flow when the valve
is wide open. The construction of this valve permits easy and quick replacement of seat and disc if
required.
Figure 17
Globe Valve, Plug Type Disc
Angle-Style Valves
Angle valves are nearly always single-ported. Single-ported means they have only one port and one
plug. They are commonly used in boiler feedwater and in heater drain service. In piping layouts
where space is limited, the valve can also serve as an elbow, as the inlet and outlet flanges are at
right angles.
Figure 18
Flanged Angle-Style Valve
(Courtesy of Valtek Inc.)
The valve shown in Fig. 18 is a control valve moved by a pneumatic actuator and has cage-style
construction. Cages are cylindrical guides, with machined flow ports, that surround the disc of some
globe valves. They are used to maintain uniform flow distribution around the disc, and to prevent
any side movement of the disc. This valve has flanged inlet and outlet connections. The bonnet is
bolted to the valve body.
HIGH PRESSURE PLUG TYPE CONTROL VALVES
High-pressure single-ported globe bodies, or plug type, as shown in Fig. 19, are often used in
production of oil and gas. This valve has a screw bonnet connection. The inlet and outlet piping
connections are also screwed. It has a long tapered plug, designed for throttling service. The stem
is connected to a pneumatic actuator.
Variations used include cage style trim, and bolted body/bonnet connection. Flanged and welded
versions are also common.
Figure 19
High Pressure Globe-Style Valve
(Courtesy Fisher Controls)
Objective Five
When you complete this objective you will be able to…
Describe the designs, application and operation of single-seated and double-seated balance valves.
Explain caged trim for balanced control valves.
Learning Material
BALANCE VALVES
Balance valves have nearly the same pressure on the top and bottom of the valve plug. This greatly
reduces the mechanical effort required to move the valve or to hold it in a steady position. Balanced
control valves are used extensively and are designed as single seated, or double seated.
Single Seated Balance Valves
The single seated balance valve, Fig. 20, has a valve plug that moves inside a removable cage,
which holds down a seating ring. When closed, the valve plug will rest on the seating ring and will
totally cover the ports in the cage. As the valve plug rises, a greater port area is allowed for
passage of fluid or gas, yet the pressure is equal above and below the valve plug. The plug has
passages or balance ports, which allow inlet pressure to pass to the top of the plug. As the bottom
and top of plug are under the same pressure, little effort is required to move the plug and stem.
Figure 20
Single Seated Balance Valve
(Courtesy of Valtek Inc.)
This type of single seated valve will provide about 37% more capacity or flow, than the standard
single seated globe valve of equivalent pipe size. Also, the cage provides more guiding area for the
valve plug than on other valves so that better valve closure is assured. Changing the shape of the
cage ports creates different flow characteristics. Valve maintenance time is reduced as the valve
plugs, cage, and valve seat can be removed for inspection by removing the bolts holding the valve
bonnet. On liquid and gas applications where a very tight shut-off or bubble-tight shutoff and low
friction are necessary, a seal is installed between the plug and the cage. Passages in the plug still
give balanced operation.
Double Seated Balance Valves
The double seated balance valve, as shown in Fig. 21, can pass up to twice as much fluid as a single
port valve. It generally divides the flow in half through two control ports. While the fluid velocity of
the top half tends to open the upper port, (force upward) the bottom half fluid velocity is closing the
lower port (force downward). This split of flow and port arrangement approaches a fluid balance
between the top and bottom forces for any valve position.
Figure 21
Double Seated Valve
Port size or area can be varied for finer balance. Size of port, between top and bottom, may also be
varied to provide for the same loading on the stem. In fact, the valve is not exactly balanced, as
one plug is smaller. The difference in sizes of the two plugs enables removal of the valve plug
during maintenance, as the smaller plug will pass through the larger valve seat opening.
Tight shut off is difficult to achieve with a double ported valve. When the temperature of the fluid
increases, the stem expands so both plugs do not seat simultaneously, thus causing some leakage
through the valve. In order to completely isolate line flow, hand operated isolating valves are placed
before and after the control valve.
A double seated valve will always require less power to operate than a single seated unbalanced
valve of the same size even though it usually has the larger port area. Double-seated valves are
more expensive to manufacture, than single seated valves.
Balanced Plug, Cage-Style Valve Bodies
A valve body with cage-style trim, balanced plug and soft seat, is shown in Fig. 22. It is single-
ported as only one seat ring is used. This type of valve has the advantages of a balanced valve plug
similar to a double-ported valve. Cage-style trim is used to provide valve plug guiding, seat ring
retention, and flow characterization. In addition, a sliding piston ring-type seal, placed between the
upper portion of the valve plug and the wall of the cage cylinder, virtually eliminates leakage of the
upstream high-pressure fluid into the lower pressure downstream system.
Figure 22
Valve with Cage-Style Trim, Balanced Plug, and Soft Seat
(Courtesy Fisher Controls)
In a balance plug design, downstream pressure acts on both the top and bottom of the valve plug,
thereby equalizing most of the forces. Referring to Fig. 22, the inlet pressure is transferred to the
top of the valve plug by a balancing port (thus the name balanced plug). Therefore the pressure at
the top and the bottom of the plug is the same.
The reduction of unbalanced forces permits operation of the valve with smaller actuators than those
necessary for conventional single-ported bodies. Fig. 23 shows valve parts. The plug fits inside the
cage, as a piston fits inside a cylinder.
The type of trim affects flow characteristics and noise reduction. For most available trim designs,
the standard direction of flow is in through the cage openings and down through the seat ring.
These valves are common in various material combinations, and are available in sizes up to 400
mm.
Figure 23
Cage Style Valve Parts
(Courtesy of Fisher Controls)
Objective Six
When you complete this objective you will be able to…
Describe the designs and applications of typical plug valve designs, including tapered and cylindrical
plug, four-way, eccentric, and jacketed.
Learning Material
PLUG VALVES
Plug Valves consist of a tapered or straight vertical cylinder inserted into a valve body. The cylinder
contains a horizontal opening. Rotating the cylinder opens and closes the opening, controlling the
flow. The plug valve is a quarter turn type of valve. Turning the cylinder one-quarter turn changes
the valve from fully open to fully closed.
Most plug valves have a tapered plug. The cross-sectional drawing in Fig. 24 shows a tapered plug
valve with a bolted packing gland. Tapered plugs have a tendency to jam in the tapered seat and
cause bad scoring if forced to turn. To eliminate this problem most plug valves are lubricated. The
lubricant is supplied through the center of the stem and is distributed through channels to the
seating surfaces. In many valves, the lubricant is also forced beneath the plug so it lifts slightly,
permitting easy operation. There are also lubricant sealing grooves that run vertically on the plug to
aid in sealing.
Figure 24
Plug Valve
Fig. 25 shows several designs of plug valves. The ends are constructed as screwed or flanged type,
and the glands can be either screwed or bolted. The screwed gland type has a packing gland and a
nut, which is turned to adjust the tightness of the packing. The bolted gland type has a packing
gland and a follower. Tightening or loosening the bolts, which fasten it to the valve body, adjusts
the follower.
The plug turns with the help of a wrench or is gear operated. If the packing is very loose, there will
be leakage around the shaft. If the packing gland is over tightened, the valve becomes hard to turn.
Figure 25
Plug Valves
The valves in Fig. 24 & 25 have fittings for a grease gun to pump lubricant into. Non- lubricated
plug valves are equipped with a flexible, smooth liner that eliminates the need for lubrication.
Fig. 26 illustrates three common plug sizes for plug valves. They are 100 percent or full port, 70
percent port and 40 percent port. The dotted line indicates the pipe opening and the unbroken lines
indicated the valve port opening. The percentage opening is plug opening area compared to the pipe
size on a percentage basis. The larger the port size is the larger the physical size of the valve.
Normally a 70 percent port opening is supplied. If zero pressure-drop is desirable a full port plug is
specified.
Figure 26
Plug Valve Port Designs
Multiport Valves
Plug valves may have one, two, three, or four ports. The various port designs of multiport plug
valves are shown in Fig. 27. The three way valves on the top row have plugs with L-shaped ports.
The diagram illustrates the three possible positions of the valve plug.
T-ported plug valves have ports in the plug in the shape of a T. The center row in Fig. 27 illustrates
the flow possibilities with the plug in various positions. These types of valves need clear markings to
show the operator what position the valve plug is in.
Fig. 27, on the bottom line, shows the operation of four-way plug valves. The plug has two separate
L-ports. Fig. 29 illustrates the external appearance of a four-way wrench operated plug valve.
A three-way plug valve is shown in Fig. 28. There are three flanges to attach to the external piping.
It has a manual handwheel and a gear operator to turn the valve.
Figure 27
Three-Way and Four-Way Valve Positions
Figure 28
Three-Way Plug Valve Worm and Gear Operated
Figure 29
Four-Way Plug Valve Wrench Operated
Eccentric Plug Valves
The eccentric plug valve, as shown in Fig. 30, is specially designed for severe rotary applications. It
features tight shutoff with globe style seating, and excellent resistance to abrasive wear. Eccentric
plug valves feature rotary action. They exhibit excellent throttling capabilities. They are used in a
wide range of control valve applications at temperatures up to 540°C.
Eccentric plug valves come in sizes up to 200 mm, in pressure ratings to ANSI 600. Both flanged
and flangeless body styles can be ordered in a variety of materials, and are usually less costly than
the conventional globe-style valves of equal capability.
Figure 30
Eccentric Plug Valves
(Courtesy Fisher Controls)
Jacketed Valves
Process conditions may require ball valves with full, partial, or bolt-on jackets. The jackets as shown
in Fig. 31, are used to apply heat to the valve. The heating fluid is piped to the valve jacket at a
controlled temperature. The process fluid therefore is prevented from freezing or forming solids in
the plug valve. Common heating media are low-pressure steam or glycol. The bolt-on style of jacket
is used for converting a valve with no jacket to a jacketed valve.
Figure 31
Jacketed Ball Valves
(Courtesy Dezurik Valves)
Objective Seven
When you complete this objective you will be able to…
Describe the designs and configurations for mixing and diverter valves.
Learning Material
MIXING VALVES
The mixing valve, Fig. 32, is a three-way valve. This valve is designed with two inlets and one
discharge for blending two fluids. Moving the valve stem varies the proportion of liquid or gas
entering each of the inlets. There is a continuous flow from the outlet regardless of the valve plug
position. When the plug is fully down, the bottom inlet is shut off. When the plug is fully raised, the
side inlet flow is shut off. Any intermediate position proportions the two inlet flows to meet the
operating needs.
Figure 32
Mixing Valve
DIVERTING VALVES
The diverting valve in Fig. 32 is a three-way valve, with one inlet and two outlets, which also can be
used in mixing applications, as shown in Fig. 34 - mixing. In mixing service, less force is required to
close the valve.
In diverting service (Fig. 34 Diverting – 2) the valve may maintain a constant level of fluid in a
vessel, but if the inlet flow is too high when the level is maximum, the excess input can be diverted
to another vessel. In this application more force is required for the initial opening, and combined
forces of the line fluid and diaphragm pressure may cause the valve to slam in either direction.
Another style of diverter valve is shown in Fig. 33. Its plugs are arranged above and below the
valve seats. Its operation is shown in Fig. 34 – diverting-1. The inlet pressure acts equally on both
valve plugs, reducing the force needed to move the valve stem. An unbalanced force will be
produced if one discharge line has a higher pressure than the other discharge line.
Figure 33
Diverting Valve
Figure 34
Schematic of Mixing and Diverting Valve Operation
Objective Eight
When you complete this objective you will be able to…
Describe the designs and operation of diaphragm valves
Learning Material
DIAPHRAGM VALVES
The diaphragm valve shown in Fig. 35 is an excellent valve for flow control service when handling
corrosive and toxic fluids. This valve is used extensively in raw water treatment plants, in sulfuric
acid applications, and generally in services where bubble-tight or drip-tight closure is mandatory.
Diaphragm valves have three basic parts: the valve body, the valve bonnet assembly, and the
flexible disc or diaphragm that is the closing element. The diaphragm serves as a partition that
separates the valve working parts (bonnet) from the fluid passageway. It is also a dynamic seating
element. The diaphragm is positioned in the valve body slightly above the opening the fluid passes
through. Pressing the diaphragm tightly against the body closes the valve.
The mechanism that moves the diaphragm is separated from the fluid and no packing material is
required as in conventional valves. This is an advantage because packing deteriorates and requires
periodic replacement. Another advantage is the bonnet assembly, can be removed for cleaning or
lubricating without shutting off the fluid in the line. Valve operation can be achieved with a valve
wheel, quick opening lever, or mechanical power systems.
Diaphragms are made of any of materials resistant to the particular fluids being transported. Rubber
base, neoprene, and polyethylene diaphragms are most common, but stainless steel is frequently
used to eliminate breakage. Diaphragm valve sizes range from 10 to 400 mm and are made with
screwed or flanged ends. Working pressure ranges up to 900 kPa in the small valves and to 350 kPa
in the larger sizes. Maximum temperature of fluids handled must be below the temperature limit for
the diaphragm material.
Figure 35
Diaphragm Valves
The diaphragm valve in Fig. 36 has a pneumatic operator (air operated) popular in water treatment.
It has a valve body and diaphragm made of corrosion resistant materials. Diaphragm valves may
have the body made of one material and the diaphragm made of another. For example, the valve
body may be carbon steel and the diaphragm made of rubber.
Figure 36
Diaphragm Valve with Pneumatic Actuator
Objective Nine
When you complete this objective you will be able to…
Describe designs and operation of butterfly valves, including vertical, horizontal, swing-through,
lined, and high-performance.
Learning Material
BUTTERFLY VALVES
The butterfly valve is often used as a final control element in air or large water piping systems. It
may be used in piping of 200 mm and larger as a shutoff or control valve. Butterfly valves are often
lined with a resilient material so the rotating disc seats tight when closed. They provide a bubble
tight seal with low operating torque. They operate by the wing-like action of the disc and when
open, the disc is parallel to the flow.
Butterfly valves fit into the piping in two ways: the two-flange or double ported type as in Fig. 37,
and the wafer type, Fig. 38. The double-ported type has a flanged body and the liner terminates
within the body. The small port works independently and can increase the control range
considerably at low flows.
The wafer type does not have flanges. It is installed by sliding it between two flanges in the piping.
It has a sealing surface, which matches up with the sealing surfaces of the piping flanges. The wafer
valve often has a molded-in seat for extra life and a better seal.
Butterfly valves are also classed as vertical or horizontal. This refers to their mounting position in
the piping. A vertical butterfly has its shaft in a vertical orientation when installed and a horizontal
butterfly has its shaft in a horizontal position. Fig. 38 is an example of a vertical butterfly and Fig.
39 is an example of a horizontal butterfly.
Figure 37
Two-Flange Butterfly Valve
(Courtesy Dezurik Valves)
Figure 38
Wafer Type Butterfly Valve, Gear Operated
Vertically Mounted
Large size butterfly valves need a mechanical aid to operate. Manual gear reducers, electric motors
or hydraulic cylinders are used. Mechanical actuators close the valve rapidly until it is almost
completely shut. The last part of the valve disc’s travel is more gradual to slowly relieve the
pressure in the system.
Butterfly valves do not require supports other than those required for the pipeline itself. They can
be used for flow in either direction and this feature is needed in plants that periodically reverse the
fluid flow. Butterfly valves are designed to handle pressures from 350-900 kPa. They are excellent
for throttling fluid flow, as well as for operation in a shut off capacity.
Swing-Through Butterfly Valves
Butterfly valves are divided into three subcategories: swing-through, lined, and high performance.
The most basic is the swing-through design, shown in Fig. 39. Rather like a stovepipe or fireplace
damper, but more sophisticated, this design has no seals. The disk swings close to, but clears the
body’s inner wall; therefore, they are handicapped by lack of tight shutoff. Mounting is flangeless,
lugged, or welded. Body pressure ratings go up to ANSI Class 2500 and they can be used in a wide
range of temperatures.
Figure 39
Swing-Through Butterfly Valve Horizontally Mounted
(Courtesy of Fisher Controls)
Lined Butterfly Valves
Lined butterfly valves feature an elastomer or fluoropolymer (TFE) lining that contacts the disk to
provide tight shutoff, as shown in Fig. 40. Since this seal depends on interference between the disk
and liner, these designs are more limited in pressure drop. Temperature ranges are also
considerably restricted due to elastomeric materials. An advantage of the liner is that the process
fluid never touches the metallic body. Therefore, this design is used with corrosive fluids.
Figure 40
Lined Butterfly Valve
(Courtesy of Fisher Controls)
High Performance Butterfly Valves
High performance butterfly valves have heavy shafts and discs. They have full rating bodies, and
sophisticated seals. This makes tight shutoff at high pressures possible. Referring to Fig. 41, the
eccentric shaft mounting allows the disc to swing clear of the seal to minimize wear and torque. The
offset discs employed allow uninterrupted sealing, and a seal ring that can be replaced without
removing the disc. These valves provide a combination of performance features, and are
lightweight, compared to globe valves used for the same pressure ratings.
Figure 41
Operation of High Performance Butterfly Valve
(Courtesy Dezurik Valves)
High performance butterfly valves come in sizes from 50 to 1800 mm, with flangeless or lugged
(flanged) connections, and carbon steel or stainless steel bodies. With their very tight shutoff,
heavy-duty construction, and tight linkages, these valves are suitable for as many process
applications as their sliding stem counterparts. Tight, metal-to-metal seals are possible with the
eccentric disc design. They can be used for tight shutoff in applications that are too hot for
elastomer-lined valves to handle. Fig. 42 illustrates a high performance butterfly valve.
Figure 42
High Performance Butterfly Valve
Objective Ten
When you complete this objective you will be able to…
Describe the design, application, and operation of gear, motor, air-diaphragm, and air-piston
actuators for valves.
Learning Material
GEAR OPERATORS
The most common mechanical or manual actuator or operator is the handwheel, which includes
many novel variations to operate the valve more easily. The simple handwheel may be attached
directly to the operating nut or stem to position the valve.
A common solution to the high torque required to operate larger valves is to equip the valve with a
gear system, as shown in Fig. 43. Gears provide a mechanical advantage permitting one person to
operate the valve, where two might otherwise be needed. However, the operating time to open or
shut the valve is increased and friction losses will occur in the gear train.
Figure 43
Gear Operated Valves
Electric Actuators
Electric actuators receive an electric signal to position the valve to the desired setting. These
devices may be solenoid or electric motor operated. The solenoid-operated valves are normally snap
acting and are frequently used in many automatic control systems. A solenoid is a coil of wire in the
shape of a doughnut. When a bar of iron is put inside an energized coil, it moves along the coil
because of the magnetic field that is created. If the plunger (iron bar) is fitted with a spring, it
returns to its starting point when the electrical current is turned off.
In a direct-operating valve, Fig. 44, the solenoid plunger is used in place of a valve stem and handwheel. The plunger is connected directly to the disc of a globe valve. As the solenoid coil is
energized or de-energized, the plunger rises or falls, opening or closing the valve.
Figure 44
Solenoid Operated Valve Internals
The valve in Fig. 45 is lever-operated and the moving power for the lever is a solenoid. This valve is
normally a closed valve. The solenoid is connected to a lever that moves the valve plug or closing
element.
Figure 45
Solenoid Operated Valve
Solenoid valves are employed in small size systems where on and off operation is required. They
are inexpensive to manufacture and are as reliable as their source of power. A common type of
solenoid valve used in fuel gas systems is the latching valve, often referred to as a Maxon valve as
shown in Fig. 46. It is manually latched to supply fuel to the boiler, when the boiler is running. It
trips to the closed position, when power to the electric circuit is interrupted, as in a trip situation
(fuel to the boiler is shut off).
Figure 46
Solenoid Type Latching Valves
(Courtesy of Maxon Valves)
Larger motorized valves as seen in Figs. 47 and 48 are equipped with a high-speed electric motor
and a system of reduction gears to position the valve. The gear train lowers the speed, thus
increasing the torque to get tight closure. This type of operator is excellent for frequently operated
valves and the motors used can be reversing or unidirectional types. Limit switches are provided to
open the motor circuit at the end of valve travel or when the motor has developed a high torque (as
when the valve is shut).
Figure 47
Power Operated Butterfly Valve
Figure 48
Electric Driven Worm and Gear Operator
(Courtesy of Fisher Controls)
Electrical valve operators are costly both in equipment and wiring costs, but their advantages are
numerous.
1. They can be set up for operation from several different locations – remotely operated.
2. Remote indicating devices can be installed to show the position of the valve at any operating
station.
3. Valve operating speeds (to close the valve) from two seconds for some units, to four minutes can
be reached.
4. Valves can be operated without personnel having to climb ladders or enter dangerous locations.
Air Diaphragm Actuators
Pneumatic actuators are widely used in the petroleum and chemical industries because they are
safe, simple and reliable. This type of valve operator translates an air signal into valve stem motion
by applying pressure to a diaphragm. The air pressure provides large amounts of force to give
positive action to the stem and overcome the spring action and packing friction. Although these
actuators can be used for on-off operation, they are more effective for modulating service.
There are two types of pneumatic actuators:
1. The diaphragm
2. The piston
The diaphragm type consists of a spring, which opposes the air pressure applied against the
diaphragm. Springless types of diaphragm actuators, in which controlled air pressure is applied to
either side of the diaphragm, are also used.
Figure 49
Diaphragm Actuator
(Courtesy of Dezurik Valves)
Spring Loaded Diaphragm Actuators
The spring-loaded diaphragm actuator, Fig. 49, has a diaphragm and a diaphragm plate connected
to an actuator stem. The diaphragm is enclosed in a case into which the air pressure from a
controller or positioner (control system) is applied. The spring force plus the unbalanced force on
the valve plug oppose the air pressure on the diaphragm. The spring repositions the actuator stem
and valve plug when the air pressure on the diaphragm decreases, until the force on the diaphragm,
due to the air pressure, is equal to the force exerted by the spring and valve plug.
The adjusting spring allows external setting or adjustment of the initial spring compression. The
spring force is adjusted so that the valve starts to open or close at the desired minimum pressure.
The diaphragm areas must be large enough so that sufficient force is created to overcome the
spring force and also the force on the valve plug. The actuator shown in Fig. 50 is called direct
acting or “air to close” operation. If system safety requires the opposite action, “air to open” or
failed closed, a reversed actuator is used and referred to as reverse acting. The actuator in Fig. 49
is air to open.
1. Diaphragm
Case
2. Diaphragm
3. Diaphragm
Plate
4. Actuator
Spring
5. Actuator
Stem
11. Travel
Indicator
Scale
6. Spring Seat
7. Spring Adjustor
8. Stem Connector
9. Yoke
10. Travel Indicator
Figure 50
Spring Loaded, Direct-Acting Diaphragm Actuator
(Fisher Governor Co.)
Air Loaded Diaphragm Actuators
Air loaded diaphragm actuators as in Fig. 51, have no springs and are often used in applications
requiring a valve positioner. Spring action is apt to be erratic and the force provided by the spring is
constant at any degree of compression. In this design, two air signal pressures control the valve
differentially. One side of the diaphragm is supplied with a constant air pressure, usually in the
order of 20 to 30 kPa, and air pressure (20 to 103 kPa) from the controller is applied to the opposite
side. This actuator is referred to as a preloaded type and has a large air dome on top of the
diaphragm replacing the spring.
Figure 51
Air Loaded Diaphragm Actuator
(Fisher Governor Co)
Air Piston Actuators
Pneumatic or hydraulic piston actuators shown in Fig. 52 are used when the force required in
moving a valve or a damper is higher than that which can be provided by a diaphragm actuator.
Figure 52
Pneumatic Piston Actuators
(Fisher Governor Co.)
No spring is required to absorb the force of the piston. Instead, the piston is double acting. When
fluid is admitted to one side of the piston, the fluid from the other side is allowed to pass out of the
cylinder.
Compared to diaphragm valves, higher air or hydraulic pressures can be applied to piston actuators.
The higher pressure means a smaller volume has to be displaced to and from the piston, thus
causing an increase in speed of response to a control signal. Piston actuators can also provide a
much greater stem movement than a diaphragm actuator. The stem movement is the distance
between open and closed.
For on-off positioning, the cylinder can be loaded and unloaded by a simple solenoid valve but when
it is necessary to position the valve plug at any intermediate position, a positioner is required as is
shown in the actuator on the left-hand side of Fig. 52.
Electrical Theory and DC Machines
Learning Outcome
When you complete this learning material, you will be able to:
Explain basic concepts in the production of electricity and the design, characteristics and operation
of DC generators and motors.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
5.
6.
7.
Explain the production of electron flow in a circuit and define circuit voltage, amperage and
resistance.
Explain electromagnetic induction and how it produces generator action and motor action.
Describe the design and operating principles of a DC generator or motor, clearly stating the
purposes of the armature, brushes, windings and poles.
Explain how back EMF, armature reaction, and torque are created and their influence on a
DC generator. Given the speed, flux, number of poles, and number of conductors, calculate
the back emf created in a DC generator.
Explain separate and self excitation and describe the voltage/load characteristics of shunt,
series and compound generators. State where the various types would be used. Explain
how excitation of a DC generator is controlled.
Explain the speed/load characteristics of shunt, series and compound DC motors; define
and calculate percent speed regulation and explain how speed is controlled in DC motors.
Explain DC motor torque characteristics and describe the starting mechanisms for DC
motors.
Objective One
When you complete this objective you will be able to…
Explain the production of electron flow in a circuit and define circuit voltage, amperage and
resistance.
Learning Material
CURRENT
All matter is composed of tiny particles called molecules. A molecule is the smallest identifiable
particle of a substance. Each molecule is made up of smaller particles called atoms the building
blocks of all matter.
Electricity can be explained by the nature of atoms and the manner in which they behave when
subjected to various forces and conditions. Fig. 1 portrays the structure of an atom. The center
consists of an arrangement of protons carrying a positive charge. Arranged in circles, or shells,
around the protons are negative charges called electrons.
Figure 1
The Atom
In Fig. 1 the outer ring has only one electron spinning in orbit. This valence or free electron is
loosely attracted to the mass of protons and is easily freed from the atom. A battery or generator
can force an electron to move, allowing an electron from an adjacent atom to rush in and take its
place. Such a movement of electrons along a conductor is called an electric current.
The movement of electrons cannot be maintained unless there is a continuous, unbroken path from
the current-producing device to the current-consuming device or load. A light bulb, an appliance, or
an electric motor are examples of electrical loads.
Not all substances possess a valence electron in the outer ring of their structure that can be made
to flow. Such substances do not have electron movement or current. They are called nonconductors,
or insulators and include rubber, glass, plastics, ceramics, and similar materials. Normally the
valence electrons wander erratically in all directions as illustrated by the arrows in Fig. 2.
Figure 2
Random Drift of Electrons
If an electrical supply such as a battery is connected to the ends of a metal conductor such as a
copper wire, as shown in Fig. 3, the free valence electrons are attracted by the positive (+) terminal
of the voltage supply and will flow out continuously from the negative terminal (-) into the circuit.
The movement or drift of electrons along a conductor is known as current flow.
Figure 3
Electron and Conventional Current Flow
Knowledge about electron flow in an electrical circuit is recent in origin. Before discovery of the
electron theory, current was believed to be the flow of positive charges from the positive terminal of
a voltage source, through the circuit and back to the negative terminal as shown in Fig. 4. This was
called Conventional Current Flow.
Note: In this course, the actual direction of current flow will not affect the theoretical studies, so
the Conventional Current Flow will be used.
Figure 4
Electrical Circuit
UNIT OF CURRENT -THE AMPERE
The number of electrons that pass a given point in one second determines the quantity of current
flowing in a wire. A coulomb is equal to the charge on 6.242 x 1018 electrons and this unit is used
for practical measurements.
Because a coulomb is a quantity of electricity, then a rate of flow of electricity may be specified in
coulombs per second. One coulomb flowing past any section of a conductor per second is termed
one ampere. The symbol for current is I. The flow of one ampere of electric current is shown
graphically in Fig. 5.
Figure 5
Electric Current
POTENTIAL DIFFERENCE AND ELECTROMOTIVE FORCE
In order to cause an electric current to flow between two points in an electric circuit there must be a
difference in electric pressure or potential. The unit of measurement of potential difference is the
volt. The potential difference required to cause a flow of one ampere through a resistance of one
ohm is one volt. The symbol used is E.
If two bodies have different amounts of charge a potential difference will exist between them. When
a conductor joins two points, which have a potential difference, a current flows along the conductor.
When the two charges become equalized the current flow will stop. Therefore if a current flow is to
be maintained the potential difference between the points must be maintained.
A device that can maintain a potential difference between two points and a current is flowing is said
to have an electromotive force (EMF). There are several ways in which an EMF may be developed. A
simple wet cell develops an EMF by chemical means, such as a lead acid battery. An electric
generator, in which conductors are moved through magnetic fields, develops an EMF by mechanical
means. Photovoltaic cells develop an EMF using light.
RESISTANCE
Materials, which have a low resistance to the flow of an electric current, are called conductors, and
those that have a high resistance are called insulators. Electrical resistance then is defined as the
opposition by a material to the flow of an electric current.
The practical unit of measurement of resistance is the ohm. A resistance that develops one joule of
heat when one ampere flows through it for one second has one ohm of resistance.
Resistance depends not only upon the material used for the conductor but also upon its size and
temperature:
Increase in conductor cross-sectional area will reduce resistance.
Increase in conductor length will increase resistance.
Increase in conductor temperature will increase resistance in most cases.
There are materials whose resistance decreases with increasing temperature, notably, carbon.
The symbol for resistance is R. The symbol used for the ohm is the Greek letter omega, written Ω.
Ohm's Law is used for calculations as it shows the relationship between voltage, current, and
resistance. The law states that in a given circuit, the quantity of current flow is inversely
proportional to the resistance for a given voltage, that is, an increase in resistance results in a
reduction of current flow, or
Objective Two
When you complete this objective you will be able to…
Explain electromagnetic induction and how it produces generator action and motor action.
Learning Material
ELECTROMAGNETIC INDUCTION
When an electric current flows in a conductor, a circular magnetic field is set up around the
conductor. Magnetic field direction and intensity depend upon the direction and intensity of current
flow. If conventional current flow is downward in a conductor, as illustrated in Fig. 6, concentric
magnetic lines of force travel in a clockwise direction around the conductor.
When the direction of current flow is reversed, the lines of force also reverse to an anticlockwise
direction. The dot represents the point of an arrow pointed toward the reader to indicate the
direction of current flow. An X on the tail of an arrow shows that the current is flowing away from
the reader.
Figure 6
Magnetic Field Around a Conductor
The direction of the lines of force around a conductor is determined using the Right Hand Rule for
conductors. Mentally grasp a current-carrying conductor with the right hand, with the thumb
pointing in the direction of current flow. The direction of the lines of force in the magnetic field
around the wire is in the direction the fingers are pointing. This is illustrated in Fig. 7 and Fig. 8.
Figure 7
Direction of Magnetic Field Around a Current Carrying Conductor
Figure 8
Right Hand Rule to Determine Direction
Of the Magnetic Field About a Conductor
Electromagnetic Induction
An electromotive force can be produced in a conductor by moving the conductor through a magnetic
field. The voltage developed in the conductor is called induced voltage, or induced electromotive
force (EMF).
This EMF is induced by moving a conductor in a stationary magnetic field, or by holding the
conductor steady and moving the field. Both principles are used in electric generators.
The relative directions of motion of the conductor, the magnetic field, and the induced EMF are
determined by using Fleming’s right-hand rule (Fig. 9).
Figure 9
Fleming’s Right Hand Rule
Extend the thumb, forefinger and middle finger of the right-hand mutually at right angles. Point the
forefinger in the direction of the magnetic field and the thumb in the direction of motion of the
conductor. The middle finger then points in the direction of the induced EMF.
Generator Action
If a conductor is moved relative to a magnetic field so it “cut’s” magnetic flux, then an EMF will be
induced in the conductor. If the conductor is part of a complete circuit, then “induced currents” will
flow within the conductor. The direction of the induced EMF is shown in Fig. 10 for the relative
conductor movement shown. The direction of current flow is the direction the current would flow if
connected to an external circuit.
It is “relative conductor movement” that is important, and whether that relative movement is the
consequence of a stationary conductor and a moving field, a stationary field and a moving
conductor, or both field and conductor moving, is immaterial.
Figure 10
Generator Action
The direction of the induced EMF can be determined by applying Fleming's right hand rule. If the
index finger, the middle finger and the thumb of the right hand are extended to be mutually
perpendicular to each other, and if the index finger points in the direction of the magnetic flux,
(conventional direction north to south between poles), and the thumb indicates the relative
movement of the conductor, then the middle finger indicates the conventional direction of the EMF
induced in the conductor.
Motor Action
When a current carrying conductor is placed in a magnetic field as illustrated in Fig. 11, the field
produced by the conductor distorts the magnetic field between the poles. Notice the direction of the
flux lines that circle the conductor. The main field flux lines tend to accumulate on one side of the
conductor, so that all the flux lines are gong in the same direction.
The conductor has more flux lines or a strong field on one side and fewer flux lines or a weak field
on the other side. The field flux lines try to straighten, or take the shortest path between the poles.
As there are more flux lines on the strong field side of the conductor, there is more force exerted
towards the weak side field. The force exerted by the field flux lines upon the conductor is shown by
the arrow pointing upwards.
Figure 11
Current Carrying Conductor in a Magnetic
Field
Note: The direction of the current flow in diagrams such as Fig. 10 and Fig. 11 is shown as x
(positive) or as a dot (negative). The x on a conductor indicates current flow into the page. The dot
means current flow out of the page.
A three dimensional view of motor action is shown in Fig. 12. Current flows through the conductor
from positive to negative. Using the right hand rule (Fig. 8), it can be seen that a counter-clockwise
magnetic field is produced around the conductor. The field around the conductor affects the main
magnetic field between the poles. A strong magnetic field is produced on one side of the conductor
and a weak magnetic field is produced on the other side. The strong field pushes the conductor
toward the weaker field. This is the direction of motion in Fig. 12.
Figure 12Motor Action
Fig. 13 shows what happens when a loop of wire carrying an electric current is placed in a magnetic
field. Each side or wire of the loop will have a force exerted upon it, as in Fig. 12. The direction of
the current flow is different for each side of the loop. The direction of the force exerted on each wire
is shown as an arrow marked torque. The sum of the forces or the turning forces is the torque on
the loop. In this case, it will rotate in a counter-clockwise direction. This is the principle of operation
of D.C. motors.
Figure 13
Motor Action
Fleming's left hand rule is used to indicate the direction the conductor will move due to motor
action. It is similar to Fleming’s right hand rule as digits represent the same quantities except that
the second finger becomes conventional current direction instead of the induced EMF.
Objective Three
When you complete this objective you will be able to…
Describe the design and operating principles of a DC generator or motor, clearly stating the
purposes of the armature, brushes, windings and poles.
Learning Material
DESIGN AND OPERATING PRINCIPLES OF DIRECT CURRENT MACHINES
In an actual machine, the air-gaps or distances between the poles shown in Fig. 8 would be
completely unacceptable because air has a high magnetic reluctance. Reluctance is the opposition to
the establishment of magnetic flux. Because of the large air gap, a very high force would be needed
to establish the necessary magnetic flux.
M.M.F. is magnetomotive force, and refers to the ability of a coil to produce flux. M.M.F.
corresponds to EMF in an electric circuit, and is considered to be a magnetic pressure. In addition,
the flux density in such an air gap would not be uniform. Fig. 14 shows a more practical
arrangement for the magnetic circuit of a DC machine.
Figure 14
DC Machine
Coils with many turns are laid in slots around an iron armature, which is pivoted so that it can turn
between the magnetic poles. The poles are bolted to a yoke, which is also part of the magnetic
circuit of the machine. In this manner, the air gaps between the poles and the armature can be kept
fairly small, thus greatly reducing the M.M.F. required to establish the desired flux density around
the armature conductors.
The yoke, or frame, made of cast iron or steel, has two main functions:
1. It gives a mechanical construction base for the machine, giving strength, and protection for the
vital moving and stationary parts of the machine.
2. It is a part of the magnetic circuit of the machine.
Ventilation openings at each end of the machine remove heat by allowing airflow around the
armature and field poles. A fan is mounted on the rotor shaft, providing forced air circulation. The
end shields, made of cast iron or steel, hold the bearing housings into which the armature shaft
bearings fit, enabling the armature to rotate between the poles. The end shields bolt onto the ends
of the cylindrical yoke.
The armature core is made of soft iron or mild steel laminations keyed to the armature shaft, the
assembled core has slots around its periphery into which the armature conductors are fitted. The
conductors are insulated from each other and from the core.
The commutator is an assembly of hard-drawn copper bars or segments insulated from each other
and the armature iron, assembled on the shaft at one end of the armature. The armature
conductors are wound in coils, and the ends of the coils are connected to the commutator bars. The
commutator feeds the current to or from the armature conductors. This is accomplished with
brushes, which rest on the face of the commutator, and are shaped to fit it. The brushes are made
of carbon and are held in place under spring pressure. These brushes are housed in a brush rigging
which is fastened to one of the end bells.
Figure 15
Basic DC Machine
There is virtually no difference in the construction of a DC motor and a DC generator. In fact any DC
machine can be used either as a motor or a generator. Fig 15 shows the construction of a basic DC
machine.
The location of a generator is not critical. It can be placed in a clean and dry location, with the
electrical energy it produces, transmitted to the point of utilization by suitably sized conductors. The
generator is therefore of an open type construction enabling easy access to its constituent parts for
observation and maintenance.
The motor is restricted to the vicinity of the machine, which it is driving. Often a motor is required
to operate in dusty, dirty and damp locations. In order to protect its vital parts from such
environments, the motor has to be a more closed type of construction, sometimes totally enclosed.
This requires a fan for forced cooling with a resultant loss in efficiency of the machine. This is the
only constructional difference between motors and generators. Fig. 16 shows a cutaway view of a
DC motor.
Figure 16
Cutaway View of DC Motor
Armature Windings
The single conductor loop shown in Fig. 13 produces little torque in the case of a motor, and little
EMF in the case of a generator. In a usable machine, the single loop becomes a coil of many turns,
with a complete armature winding consisting of coils evenly spaced around the armature, and
placed in the armature slots. Each slot has two coil sides, although other machines may have four,
six, or even more coil sides per slot. The common two coil sides per slot will suffice for our
explanations.
If one side of a coil occupies the top half of one slot, the other side of the coil will occupy the
bottom half of a different slot. Fig. 17 illustrates this arrangement with two coils in a partially filled
armature core, at the end opposite the commutator.
Figure 17
Armature Windings
The displacement between the centers of adjacent poles is 180 electrical degrees or one pole?pitch.
Adjacent poles are always of opposite polarity. The shortest displacement between poles of like
polarity is 360 electrical degrees. The four-pole machine shown in Fig. 18 indicates that in this case
360 electrical degrees are equivalent to 180 mechanical degrees.
In general the number of electrical degrees depend upon the number of poles, and for one complete
mechanical revolution of 360°, the electrical degrees are given by,
The distance between the two sides of one coil is always approximately one pole pitch. (180°
electrical) The reason for this can be explained as follows. When a DC armature revolves, whether
the machine is a motor or a generator, the moving conductors cut the flux of each pole in turn and
generate an EMF in each conductor. In order for the EMF’s in each side of a coil to add together and
not cancel each other out, one side of the coil must be passing a north pole when the other side is
passing a south pole.
The manner in which the two ends of each armature coil are connected to the bars of the
commutator indicates the type of winding. There are two main types of armature winding, the lap
winding and the wave winding.
Figure 18
Four Pole Machine
The Lap Winding
Fig. 19 illustrates a basic type of winding known as a lap winding. For simplicity the diagram shows
part of a developed armature cut open and stretched out flat. Each coil is represented by a single
conductor, solid lines representing conductors in the top of a slot, and dotted lines represent
conductors in the bottom of a slot. The slots are the spaces between the hatched rectangles, which
represent the outer faces of the armature core.
Figure 19
Figure 20
Lap Winding
Wave Winding
Fig. 19 shows that the two ends of one coil are attached to adjacent bars on the commutator. The
overall effect is that connections to the armature cause the coils to “overlap” each other, hence the
name lap winding.
The Wave Winding
The wave winding is illustrated in Fig. 20. It is identical in every respect to the winding in Fig. 19,
except for the connections to the armature. Now the two ends of one coil are connected to armature
bars, which are not adjacent to each other. They are placed a distance apart.
Fig. 21 shows two coils of a lap winding in relation to a field pole, (shaded rectangle). Even if the
width of a brush is less than the width of a commutator bar, the brush will frequently connect two
adjacent bars together as the commutator rotates. This means that the coil connected across the
two bars is shorting out.
If the coil is in the process of having an EMF induced within it, then a current will flow around the
circuit completed by the brush. The result is heavy sparking at the brushes. In order to prevent this
situation, the brushes are placed so that the coils being “shorted-out” or “commutated” are always
coils whose sides are between the poles and are therefore not producing an EMF. This particular
position of the brushes is called the neutral axis, and it is the position of minimum sparking at the
brushes.
Figure 21
Lap Windings
Only two brushes are necessary for a wave winding regardless of
the number of poles, because there are only two paths through the
armature. In practice, more than two are used in order to spread
the load on the brushes, and as many brushes as there are poles
can be used for a wave winding.
With a lap winding, there is no choice. There must be as many
brushes as there are poles because the number of armature paths
is the same as the number of poles. After the first brush has been
correctly located, the remaining brushes are spaced evenly around
the commutator at intervals of 90° electrical.
Objective Four
When you complete this objective you will be able to…
Explain how EMF (Electromotive force), armature reaction, and torque are created and their
influence on a DC generator. Given the speed, flux, number of poles, and number of conductors,
calculate the EMF created in a DC generator.
Learning Material
TORQUE
Once the armature starts to rotate, whether the machine is a generator or a motor, armature
conductors move with respect to the main magnetic field and therefore have a voltage or EMF
induced within them. As soon as the armature conductors of either a motor or generator carry
current, they become current carrying conductors in a magnetic field and therefore produce a
torque. Torque is a twisting or turning force exerted on the loop.
The torque produced by the armature conductors in a generator opposes the driving torque applied
to the generator shaft by the prime mover. The torque increases with load, requiring increased
input from the prime mover in order to overcome this load torque.
The voltage E or EMF induced in a conductor moving through a magnetic field is proportional to the
amount of flux “cut” per unit time. If a conductor cuts one Weber (useful flux per pole) of flux in
one second, then one volt will be induced in the conductor. The voltage induced in an armature
conductor is therefore proportional to the flux per pole and inversely proportional to the time taken
to cut that flux.
Let N = rotational speed of armature in r/min
F = flux per pole in webers
P = total number of field poles
Z = total number of armature conductors
b = number of armature paths
Then the time taken for one rotation of the armature is
Time taken to cut the flux of one pole = seconds
Therefore the average voltage induced in each conductor is
As there are Z conductors arranged in b paths in the armature, the average voltage induced in the
armature winding is given by:
This is the voltage equation for DC machines. Remember that in a wave winding b = 2, and in a lap
winding b = P.
Example 1:
A four-pole DC generator has 41 armature slots with 12 conductors in each slot. The useful flux per
pole is 50.8 mWb, and the generator is driven at 1200 r/min. Calculate the EMF generated if the
armature is (a) lap connected, (b) wave connected.
Solution:
a. The total number of armature conductors,
Z = 41 x 12 = 492
For lap, b = P and therefore b and P cancel out in the voltage equation. As the flux is given in
milliwebers, the 50.8 must be divided by 1000.
ARMATURE REACTION
When a generator is running, but is not supplying any load current, the only magnetic field present
in the machine is the main magnetic field produced by the windings on the field poles. The arrow
(main magnetic field) in Fig.22 (a) represents this magnetic field. The lighter polarity markings in
the armature conductors indicate the direction of the induced voltage for rotation indicated, but are
made lightly to suggest that no current is flowing in the armature. In this situation, the brushes are
placed as, so as to short those coils, which momentarily produce no voltage.
When a load is connected to the armature, current flows in the armature conductors and each
conductor produces a magnetic field. These individual conductor fields add together in the same
manner as the turns of a coil to produce a field in the direction shown in Fig. 22(b), where the main
field is not indicated. Armature currents are indicated by heavy polarity markings in the armature
conductors.
The field produced by the armature conductors distorts the main field flux producing a resultant
field in the general direction indicated in Fig. 22 (c).
Figure 22
Armature Reaction
This effect is referred to as armature reaction. Armature reaction causes the neutral plane within
which the brushes have been placed to shift, so that the brushes are now shorting coils, which
produce voltage. Heavy sparking occurs at the brushes as a consequence. Sparking can cause
damage, and the effects of armature reaction must be overcome.
The brushes could be moved into the new magnetic neutral plane as indicated in Fig. 22(c) and this
would stop the sparking. This is not a practical solution, however, as the amount of armature
reaction varies with the load. It would be necessary to move the brushes every time the load
changed.
The most effective method is to set up another magnetic field to oppose the field produced by the
armature currents. This is done by inserting smaller commutating poles or interpoles midway
between the main poles. These interpoles also carry armature current, and they are connected in
series with the armature with a polarity, which attempts to neutralize the armature field. Fig. 23
shows the generator of Fig. 22 fitted with interpoles to correct armature reaction. As load current
increases, so the field flux of the interpoles increases to oppose the increasing armature flux. Hence
interpoles are effective for all load conditions and enable brushes to be kept in the no-load magnetic
neutral axis.
Figure 23
Interpole Alignment
Armature reaction occurs in motors as well as generators. Interpoles are effective in both cases.
Interpole polarities change automatically when the machine is used as a motor. Interpoles are also
effective in helping to reverse the current in the coils passing under the brushes, a process known
as commutation. This is why they are called commutating poles, or simply compoles.
Self Test Problem
1. An 8-pole DC generator has 36 armature slots, with
10 conductors in each slot. The useful flux per pole is
64.5 mWb. The generator is driven at 1800 r/min.
Calculate the emf generated if the armature is lap
connected.
(Ans. 696.6 V)
Objective Five
When you complete this objective you will be able to…
Explain separate and self-excitation and describe the voltage/load characteristics of shunt, series
and compound generators. State where the various types would be used. Explain how excitation of
a DC generator is controlled.
Learning Material
TYPES OF DC GENERATORS
There are three main types of DC generators: Shunt, Series, and Compound and shown in sequence
in Fig. 24, Fig. 25, and Fig. 26. All of these machines are self-excited, meaning that their own
armatures supply their field current. They are classified as to how their field is supplied with current
from the armature.
The shunt field is always excited when a generator is in operation, whether on a heavy or light load.
The series field on the other hand is only excited when the machine is delivering a load current.
From this we can see that a
series-generator will have very low voltage when the machine is at no-load, whereas a shuntgenerator will have fairly constant voltage at all loads. This influences the generator-operating
characteristics.
Figure 24
Shunt Wound DC Generator
Figure 25
Series Wound DC Generator
Figure 26
Compound Wound DC Generator
Figure. 27
Separately Excited DC Generator
Fig. 27 shows a machine operating with field excitation supplied from a separate source. This is
referred to as a separately excited DC Generator.
Generator Characteristics
One of the most important characteristics of any generator is the variation in its terminal voltage
with changing load. Load is the current draw. The voltage change measured between no-load and
full-load is the voltage regulation, or simply regulation, and is determined by experiment, for any
machine.
The experiments are important when choosing a generator for a particular duty. The results are
expressed as a curve of voltage plotted against load (voltage regulation curve). It is derived from
readings taken during a test in which the machine is run at constant speed, with field excitation set
to give the rated terminal voltage at full?load. No adjustments are carried out during the test.
Expressed as a percentage:
The following regulation curves show the voltage characteristic for each of the generator types in
turn.
SEPARATELY EXCITED GENERATOR
The voltage decreases with increase of load current because:
(a) The armature voltage drop due to armature resistance (Ia Ra) increases
(b) The armature reaction reduces the effective flux and consequently the EMF
Note: These curves are drawn for a fixed position of the field rheostat.
Figure 28
Voltage Regulation
The separately excited generator has a decided advantage over the self-excited machine because it
will operate in a stable condition at any level of field excitation. This characteristic makes it
particularly suitable as an exciter for a central power station alternator. In this plant-arrangement
the exciter (the separately excited generator) is driven off the main turbine shaft with a second or
pony exciter, which supplies the field of the first.
SHUNT-WOUND GENERATOR
With a shunt-wound generator, the terminal voltage decreases with increase of load for the same
reasons as the separately excited machine, but the effect is more marked. This is because in this
case the shunt field is weakened by the reduction in generated EMF. The shunt-wound generator
voltage curve is shown in Fig. 29.
Figure 29
Shunt-Wound Generator Voltage Regulation Curve
A shunt generator, which is a self-excited generator, depends upon the residual magnetism in the
field circuit to build up terminal voltage as the machine is run up. Failure to build up voltage may be
due to the loss or the reversal of this residual magnetism. Passing current through the field coils can
restore the voltage. A 6-volt storage battery is usually sufficient for the purpose.
Before deciding to restore the residual magnetism, care should be taken to see that the field circuit
is in good working order since a fault could also prevent voltage build-up. The commutator must be
clean, the brushes clean and the brush-connections good. The field coils should be checked for
open-circuit and for short-circuit.
Shunt wound generators have been used for charging storage batteries. Because the voltage falls
off as the current increases, shunt generator applications need to be close to the load.
SERIES-WOUND GENERATOR
The series-wound generator is a self-excited generator, which has armature and field connected in
series. The initial EMF generated depends upon residual magnetism; the field current is also the
load current so that full flux and therefore full voltage cannot be achieved until full-load current is
flowing.
Figure 30
COMPOUND-WOUND GENERATOR
The compound-wound generator combines the principles of both shunt and series machines, and it
is the design with the most applications. The compound generator can be a short shunt or long
shunt, as shown in Fig. 31, depending on how the fields are connected. The relative strength of
shunt and series fields can be chosen so that the regulation curves show rising voltage with load
(over-compounded machine) or falling voltage with load (under-compounded machine) or a
constant voltage from no-load to full-load (flat-compounded machine).
The winding may be connected so that the shunt field is in parallel with the armature only; this is
called a “short” shunt. Alternatively the shunt field may be in parallel with armature and series field;
this is called “long” shunt. The operating characteristics of both connections are very similar.
Compound-wound generators are used for railroad power systems, synchronous motor generator
units and as power for large earth-moving equipment.
Figure 31
Voltage Regulation Curves
DC GENERATOR VOLTAGE CONTROL
The three factors affecting the electromotive force developed by a generator are:
1. The speed with which conductors cut the magnetic lines of force
2. The strength of the magnetic field
3. The number of conductors cutting the magnetic lines of force
An increase in any one of these three factors causes an increase in the electromotive force
generated. A constant speed driver drives most generators. The number of conductors on the
armature is determined prior to construction and is a fixed quantity as far as the operator of a
generator is concerned.
Varying the strength of the field controls the output voltage of a DC generator. This is accomplished
with a field regulator or rheostat, which controls the current to the field coils. A rheostat as seen in
Fig. 32 is connected in series with the shunt field winding and is used to control the current flow
through the shunt field, as shown in Fig. 33. A rheostat is a type of variable resistance. It is made
up of a long resistance wire or coil. Adjusting the movable contact to make the resistance wire
longer or shorter varies the resistance. A long resistance wire results in a small current, and a
shorter length of resistance wire results in larger current flow.
A low value of current flow through the shunt field produces a weak magnetic field while a high
value of field current produces a strong magnetic field. By changing the field current (excitation
current), the output voltage of the generator is controlled.
Figure 32
Rheostat
Figure 33
Shunt Generator with Field Regulator (Rheostat)
Generator Voltage Control
As far as generators are concerned the magnitude of the induced EMF depends mainly on the
strength of the magnetic field, and the rate at which the flux lines are cut.
An increase of load will cause a drop in terminal voltage and, to counteract this the field resistance
must be reduced. This will allow greater field current flow and increase the flux density. Generated
voltage is directly proportional to the rate of cutting lines of flux.
The required movements of the field rheostat may be carried out by hand or may be automatically
controlled. Automatic voltage regulators work on the fundamental principle that a terminal voltage
change calls for an inverse change in flux.
Objective Six
When you complete this objective you will be able to…
Explain the speed/load characteristics of shunt, series and compound DC motors; define and
calculate percent speed regulation and explain how speed is controlled in DC motors.
Learning Material
DC MOTOR SPEED AND LOAD CHARACTERISTICS
The main difference between a DC motor and a generator lies in the manner in which the machines
are operated. The generator converts mechanical energy to electrical energy, and the motor
converts electrical energy to mechanical energy.
There are three general types of DC motors, classified (like the DC generators) according to the
method of field excitation used. The three types are Shunt, Series and Compound-wound motors.
They possess certain individual characteristics, which depend upon the winding.
Figure 34
DC Motor Classifications
Speed control is easily achieved in all DC motors. Because of this, DC motor drive is preferred to
alternating current (AC) for many applications.
DC motors show characteristics regarding starting torque, overload capacity and speed variation
with load changes. In order to measure these the motor must be run from a supply with constant
voltage. It must be borne in mind that these characteristics, determined by experiment, are the
inherent characteristics and do not include any manual adjustments.
To select a correct DC motor for a particular application, it is matched with the load requirements of
a known motor’s operating characteristics.
SHUNT MOTOR SPEED
The shunt motor is classed as a constant-speed motor, and is illustrated in Fig. 35. Little change
takes place in its speed over the whole range of load. Adjustment of the field rheostat controls the
speed. The field circuit should not be opened if the motor is running unloaded. The weakening the
field causes the motor speed to increase. The increase in motor speed can be excessive and
dangerous.
Figure 35
Shunt Motor DC Field Supply
If the field is disconnected during motor operation, field flux drops to its small residual value and
motor speed goes dangerously high with the possibility of damage due to the high centrifugal forces
produced.
SERIES MOTOR SPEED
A DC motor only takes the amount of current it requires to handle the load it is driving. Hence, the
current is very low. In the case of the series motor, load current is also excitation current.
Therefore, when the load is very low, and as the speed is inversely proportional to field flux, the
speed can become dangerously high. For this reason the series motor must never be operated
without load. The load is fastened to the motor so that it cannot become disconnected. Direct shaft
coupling, chain drive or geared drives are preferred methods.
The torque of series motor increases as the speed decreases so it is commonly used with equipment
requiring a high starting torque such as driving electric trains. Series motors are also used for
cranes and hoists, where light loads are lifted quickly and heavy loads more slowly.
COMPOUND MOTOR SPEED
The compound motor combines the characteristics of the series and the shunt motor, and takes into
account both speed and torque characteristics. The compound motor is used where a fairly constant
speed is required together with the ability to handle sudden heavy loads. Fig. 36 illustrates the
speed characteristics of shunt series and compound motors of comparable full-load speed rating.
Figure 36
Speed Characteristics of DC Motors
Fig. 37 is a summary of the types, operating characteristics and uses of DC motors.
Figure 37
DC Motor Characteristics
Percentage Speed Regulation
Percentage speed regulation behaves with respect to load and is determined as follows:
The smaller the variation in speed between a no-load and a full-load, the better the speed
characteristic and the nearer the speed regulation is to zero.
Example 2:
If a compound motor has a rated full load speed of 3500 rpm and its no-load speed is 3650 rpm
what is its percentage speed regulation?
Solution:
Percentage Speed Regulation
SPEED CONTROL OF DC MOTORS
Speed control is normally restricted to shunt and compound type motors. Varying the applied
voltage or the field flux alters the speed of a DC motor. To control field flux, a regulating rheostat is
inserted in the shunt field circuit so resistance can be increased, thus reducing excitation current
and flux, and increasing speed. Such control is called above base speed control. Speeds below base
speed are obtained by reducing the voltage applied to the armature. All forms of speed control of
DC motors involve one or both of these methods.
Self Test Problem
2. A series motor has a rated no load speed of 4000 r/min. It has a full load speed of 3600 r/min.
What is its percentage speed regulation?
(Ans. = 11.1%)
Objective Seven
When you complete this objective you will be able to…
Explain DC motor torque characteristics and describe the starting mechanisms for DC motors.
Learning Material
TORQUE CHARACTERISTICS
Torque produced by a motor is proportional to both field flux and armature current. Speed does
affect the value of the armature current. The torque equation for a DC motor can be written:
T = k ΦIa where Φ = the field flux per pole in webers
k = a constant depending on the armature winding
And Ia = the armature current
T = the torque in Newton-Metres
From this equation, it appears that speed does not affect the torque of a DC motor. Therefore;
speed has an indirect affect on motor torque. This equation applies to all types of DC motors.
In a similar manner to the examination of the speed characteristics of DC motors, we can examine
the torque characteristics of the three types of DC motors.
Shunt Motor Torque
Because the flux of a shunt motor remains constant unless deliberately altered, its torque is
proportional to armature current. As load is added the current increases, increasing the torque, until
the necessary torque to handle the load is available. Fig. 38 illustrates how torque increases on a
linear basis versus armature current.
Series Motor Torque
In a series motor, flux is dependent upon armature current. The torque is proportional to the square
of the armature current until the voltage no longer increases. Beyond this maximum voltage
(voltage saturation), torque is proportional to armature current only. The series motor develops a
torque for large armature currents. It also runs at low speeds with the large armature current. This
makes it a suitable motor for starting heavy loads.
Compound Motor Torque
Again the torque characteristic of a compound motor is a mixture of the shunt and series torque
characteristics. The compound motor has a definite no-load speed and may be safely operated at no
load. Fig. 38 compares the three types of motors with the same full-load torque.
Up to the full-load value the shunt motor has a superior torque characteristic to the compound
motor and the compound motor has a better torque characteristic than a series motor. Compound
motors can be designed so that they have some of the good starting torque capabilities of the series
machine, and some of the speed characteristics of the shunt machine.
Figure 38
D.C. Motor Torque Curves
STARTING D.C. MOTORS
The counter EMF generated in the armature limits the current of a DC motor. At the moment of
starting the motor, this counter EMF is non-existent and because armature resistance is low, a very
high starting current will flow. Such a current is unsuitable for many systems, and in addition the
high starting torques produced could seriously damage gears, shafts, and other parts of the
machinery.
DC motors are restricted to a starting current of approximately 150% of full-load current.
In practice, a series resistor is inserted in the motor armature circuit to limit the current to about
150% of full-load current. The series resistor is removed as the machine accelerates to full speed.
Changing the resistance can be manual, or automatic.
Manual Starters
A typical DC manual starter is shown in Fig. 39. This particular model is known as the three-point
starter, because it has three connection points for line, field, and armature respectively labeled L, F
and A.
As soon as the DC supply switch is closed, the moveable starter arm is moved to the first stud of
the starter. This completes the field circuit via the low resistance of the holding coil, and supplies
the armature via the starting resistance. This limits starting current.
As the machine accelerates, the counter EMF increases and decreases armature current. The
moveable starter arm can be slowly moved over, decreasing the resistance in the starter circuit,
until the machine has reached full speed.
If the supply is removed, with this particular starter the field becomes open-circuited. The holding
coil becomes de-energized and the return spring returns the arm to the starting position.
Figure 39
Manual Three Point Starter
Automatic Starters
In an automatic starter the starting procedure is initiated by pressing a start button. The machine is
stopped using a stop button. Automatic starting of motors has several advantages over hand
control. The settings on the starter can be arranged to give uniform acceleration throughout the
motor run?up, and chances of improper operation, which occur under hand control, are eliminated.
There are three types of automatic starters, namely:
•
Counter EMF starters are sensitive to voltage and will act to cut out the armature resistance
in steps as the motor back EMF builds up.
•
Current limit starters measure the armature current flow and reduce the resistance in the
circuit as the starting current decreases.
•
Time limit starters operate strictly on a time basis and will cut out armature resistance
steps at definite time intervals.
Fig. 40 shows a wiring diagram for an-automatic starter of the counter EMF type with voltage
sensitive relays. Relays A, B and C are connected across the motor terminals where they measure
the armature voltage. It will increase as the back EMF builds up.
Pressing the start button starts the motor. It energizes the main contactor M, which instantly closes
the main contacts MX, to start the motor, and the auxiliary contacts M1, to seal the start button.
The motor therefore starts with resistances R1, R2, and R3 in series with the armature. As the
speed increases the rising terminal voltage energizes the relays A, B, and C in sequence.
Figure 40
Automatic Starter
Legend:
Relays: Voltage: Sensitive -A, B and C
Overload Relay - OL
Contactors: M, A1, Bl, and C1
Contacts: Normally Open - Normally Closed
Relay A will be energized at about 40% voltage, relay B at 60% and relay C at 80%. Each relay
operates to cut out armature resistance. Relay A closes the contacts AX, and energizes the main
relay A1. This in turn closes A1X and shorts out the R1 section of the resistance.
When all resistance has been cut out, the motor will run until the stop button is pressed or the
contacts OL are opened by operation of the overload relay OL. The motor will stop and will not
restart until the starting procedure is begun again.
AC Theory and Machines
Learning Outcome
When you complete this learning material, you will be able to:
Explain formation and characteristics of AC power, and describe the design, construction and
operating principles of AC generators, motors and transformers.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
Explain the creation of single phase and three-phase alternating power; define cycle,
frequency and phase relationships (voltage/current) for AC sine waves.
2. Define the following terms and explain their relationships in an ac circuit: capacitance,
inductance, reactance, impedance, power factor, alternator ratings (kVA and kW).
3. Describe the stator and rotor designs, operation, and applications for salient pole and
cylindrical rotor alternators.
4. Describe water, air and hydrogen cooling systems for large generators.
5. Explain parallel operation of alternators and state the requirements for synchronization.
Describe manual and automatic synchronization
6. Describe the design, applications and operating principles for large three-phase squirrel
cage and wound rotor induction motors
7. Describe the design and operating principle of synchronous motors
8. Explain variable speed control, variable speed starting, and step starting for large induction
motors.
9. Explain the principles and applications of power transformation. Perform transformer
calculations
10. Describe the designs and components of typical core and shell type transformers, including
cooling components.
Objective One
When you complete this objective you will be able to…
Explain the creation of single phase and three-phase alternating power; define cycle, frequency and
phase relationships (voltage/current) for AC sine waves.
Learning Material
ALTERNATING CURRENT
Almost all of the electrical power supplied at the present day is in the form of alternating current. It
has two major advantages over direct current. Firstly, it can be generated without the limits
imposed by commutators, and secondly, after generation its voltage can be very easily transformed
up or down for transmission and distribution. Alternating current power may be generated and
distributed at a higher voltage and then reduced in voltage closer to the location of the load (user).
Simple AC Generator
Fig. 1 shows a simple AC generator composed of a simple loop, a pair of slip rings, and an
electromagnet supplying the magnetic field. The slip rings and brushes provide the connections from
the loop to the external circuit. Through the use of slip rings, one side of the loop is always
connected to the same side of the external circuit rather than having the connections reversed
every half turn as with the simple commutator used with the DC generator.
Figure 1
Simple AC Generator
Fig. 2 shows the rotation of a conductor through a magnetic field. The rotation is marked in 12
positions. Each of the 12 conductor positions is shown on the graph, with the emf (electromotive
force) that is being generated at that point. The conductor starts at the 0 position, with no lines of
flux being cut in the magnetic field and no emf being generated. At position 1, lines of flux in the
magnetic field are being cut, and a positive emf is being generated, as shown on the sine wave
graph at position 1. The emf increases until the conductor reaches position 3 or 90°, where the
maximum lines of flux are being cut. The emf decreases as the conductor passes through positions
4, 5, and is back at 0 when it passes position 6 or 180°.
As the conductor moves past position 7, it is again cutting lines of flux in the magnetic field. The
conductor is moving in the opposite direction, in relation to the lines of flux of the magnetic field,
and the emf generated is now in the opposite direction (negative). At position 9, the conductor is
cutting the maximum number of flux lines creating the maximum negative emf. When the conductor
again reaches position 0, no lines of flux are being cut, and no emf is being generated. One
revolution of 360° has been completed.
The emf values corresponding to the 360° rotation takes the form of a sinusoidal (sine) wave. As
the conductor continues to rotate, the alternating voltage and current induced in the loop is
transferred directly to the external circuit.
Figure 2
Sine Wave Generation
CYCLE AND FREQUENCY
Passage of the conductor across two poles produces one cycle. On the sine wave diagram this
means from zero through positive maximum, negative maximum and back to zero. The number of
times that this occurs in one second determines the frequency in cycles per second (or Hertz) of the
generator output.
The generator shown in Fig.1 and Fig. 2 is a two-pole machine. One revolution of the armature
conductors results in one cycle of the generated emf. The cycles per second occurring in the circuit
would then be equal to the number of revolutions per second.
A two-pole alternator has two field poles on the rotor (rotating field construction). Each time the
rotor makes one revolution; one complete cycle is produced at the alternator terminals. In order to
produce 60 Hz power, the rotor must turn 60 r/s, or 3600 r/min.
A four-pole alternator has four field poles so each time the rotor makes one revolution; two
complete cycles are produced at the alternator terminals. Using the same logic as before, the rotor
would have to turn at 1800 r/min to produce 60 Hz power.
The relationship between the number of poles in the machine and its speed gives the frequency of
the supply, that is:
The power frequency used in North America is 60 Hz. In Europe and most of Asia and Africa it is 50
Hz.
PHASE RELATIONSHIP
If an AC voltage is applied to a circuit it will produce an AC current flow. If the voltage and the
current reach their maximum values at the same time they are said to be “in phase.” This would be
the case in a circuit having only resistance. A sine wave with voltage and current in phase is shown
in Fig. 3 (a).
When the current reaches its maximum later than the voltage it is said to be a lagging current. This
would occur in a circuit having an inductive load. An inductive load is usually one containing a coil or
coils, very often around a magnetic core. A sine wave with a lagging current is shown in Fig. 3 (b).
If the current reaches its maximum earlier than the voltage it is said to be a leading current. This
would occur in a circuit having a capacitance load. A capacitive load is the opposite of a capacitor or
any capacitive circuit to the flow of current. Capacitors consist of two conductors separated by an
insulating material. They are used in telephone and radio circuits.
A sine wave with a leading current is shown in Fig. 3 (c).
Figure 3
Phase Relationships
THREE-PHASE ALTERNATING POWER
A balanced three-phase circuit can be looked upon as a combination of three single-phase circuits as
far as the relationships of current, voltage, and power are concerned.
In the case of the three-phase alternator, the coil windings are connected in three different groups,
one for each phase. In this manner, three different voltages, identical in magnitude but displaced
from each other by 120° are produced. If the coil outputs were connected to separate circuits, each
circuit would carry single-phase power. When the three coil connections are connected to the same
circuit, it carries all three phases, or three-phase power.
The three-phase alternator in Fig. 4 is similar to the simple loop machine, having a stationary field
and rotating conductors. It has three rotor windings spaced 120° apart. Fig. 5 shows the three
separate voltage sine waves generated by the alternator in Fig. 4. Each of the sine waves E1, E2,
and E3 are separated or displaced by 120 electrical degrees. If the alternator output is connected to
a single circuit the result is three-phase power.
Figure 4
Three-Phase Alternator
Figure 5
Three-Phase Power Sine Waves
Fig. 5 shows three identical single-phase sine waves, each displaced by 120 electrical degrees. A
conductor passing across the faces of one N and one S pole in turn completes one cycle, and this is
termed 360 electrical degrees.
If the amount of rotation required to accomplish this were divided into thirds and three conductors
were placed on the armature so that one conductor was in each of these thirds, then these
conductors would be spaced 120 electrical degrees. When rotated, each of the conductors would
produce a voltage, which would vary as a sine wave, and the combined voltages would appear as in
Fig. 5.
In a single-phase circuit the flow of power is pulsating. Where the current and voltage are in phase
the power will be zero twice during each cycle. Although the power to each of the three phases of
the three-phase circuit is pulsating, the total three-phase power supplied to a three-phase circuit is
constant. Because of this the operating characteristics of three phase machines in general are
superior to those of similar single-phase machines. Three phase machines are smaller, lighter in
weight and more efficient than single-phase machines of the same rated capacity.
ALTERNATORS
Alternators are generators that produce alternating current. Alternators may be built the same way
as the simple loop machine, having a stationary field and rotating conductors. However, it is more
practical to build them with a rotating field and stationary conductors (Fig. 6). The rotating field is
obtained by exciting windings on the rotor with DC power supplied through a pair of slip rings. Small
portable alternators use a permanent magnet on the rotor. The stationary conductors are called the
stator.
The advantages of an alternator with a rotating field are:
1. Brushes and slip rings carry only the excitation current, which has a much smaller voltage and
amperage than the current supplied by the stator to the output terminals.
2. The size of the rotating mass is reduced.
3. Only one pair of slip rings is required for a three-phase rotating field alternator versus a
minimum of three rings for a three-phase stationary field alternator.
4. It is easier to insulate the output leads, especially important when operating at high voltages.
Figure 6
Two-Pole Alternator (Single-Phase)
Objective Two
When you complete this objective you will be able to…
Define the following terms and explain their relationships in an ac circuit: capacitance, inductance,
reactance, impedance, power factor, alternator ratings (kVA and kW).
Learning Material
CAPACITANCE
A capacitor consists of two conductors separated by an insulating material. They are used in
telephone and radio circuits. Power companies also use capacitors to correct the effects of inductive
loads. The amount of charge that a capacitor receives for each volt of applied potential is called the
capacitance of the capacitor. The unit of capacitance is the Farad (F), and the symbol is C.
Capacitive resistance is the opposition of a capacitor or any capacitive circuit to the flow of current.
In a capacitive circuit, the current flowing is directly proportional to the capacitance and to the rate
at which the applied voltage is changing (frequency). Therefore if either the frequency increases or
the capacitance increases, the current flow increases.
The vector representation of voltages and currents given in Fig. 3(a) showed that current and
voltage in a purely resistance circuit are in phase with each other, the voltage required to overcome
the resistance is calculated by
V = IR. This is often referred to as the IR Voltage drop.
INDUCTANCE
When a conductor moves relative to a magnetic field so as to pass through or “cut” the magnetic
flux, a voltage or emf is induced in the conductor. Whether the conductor is stationary and the field
moves, the field is stationary and the conductor moves, or if both move, is immaterial as long as
relative movement between field and conductor occurs. When relative movement ceases, production
of induced emf ceases. This process is called electromagnetic induction.
When a current is passed through a conductor, a magnetic field consisting of concentric lines of flux
is set up around the conductor. When the current is an alternating current, the field also alternates,
building up in one direction, then collapsing into the conductor and building up in the opposite
direction.
Lenz's Law is a law of electro-magnetic induction. It states: the direction of an induced emf is
always such that any current it produces opposes, through its magnetic effects, the charge inducing
the emf.
Hence, if a current is passed through a coil of wire, the magnetic field in building up around each
turn of the coil, cuts adjacent turns of the coil and induces an emf within them. The total voltage
induced in the coil by Lenz's law is a counter emf that opposes the voltage applied to the coil. This
counter emf produces an opposition to current flow within the coil, which is known as selfinductance.
Self-inductance is an opposition additional to that provided by the resistance of the coil. In DC
circuits, self-inductance delays the build up of current to its maximum value determined by the
value of the applied voltage and the coil resistance. Once the current reaches its steady maximum
value, no further induction takes place and self-inductance is no longer a factor. When the circuit is
opened self-inductance again becomes a factor, this time trying to delay the current collapse.
In AC circuits, because of the continually changing current, self-inductance is continually a factor in
limiting the current through a coil.
Any circuit capable of producing magnetic flux has inductance. A circuit with inductive load is usually
one containing a coil or coils, very often around a magnetic core. Examples are motor, generator
and transformer windings. A very long conductor can also have some inductance. An example is a
transformer wire.
Inductance affects the current flow only when the current is changing in value. In an AC circuit the
current is continuously changing in value. Therefore a continuous emf (electromotive force) is also
generated. The opposition to the current by the inductance is called the inductive reactance, which
is measured in measured in ohms
REACTANCE
Reactance is the combined effect of inductive reactance and capacitive reactance. In an inductive
circuit the voltage drop IXL, due to the inductive reactance XL, leads the current by 90° (the current
is said to be lagging) as shown in Fig. 3 (b).
In a capacitive circuit the voltage drop IXC, due to the capacitive reactance XC, lags the current by
90° (here the current is termed a leading current). See Fig. 3 (c)
Inductive reactance causes the current to lag the voltage. Capacitive reactance causes the current
to lead the voltage. When inductive reactance and capacitive reactance are connected in series, the
combined effect is their difference. The equation for reactance is:
X = XL - XC
Where: X = Reactance (ohms)
XL = Inductive Reactance (ohms)
XC = Capacitive Reactance (ohms)
IMPEDANCE
When the effects of inductive reactance and capacitive reactance are combined in one circuit they
cannot be added arithmetically because of the phase relationships. The impedance triangle, Fig. 7,
illustrates the method used.
Figure 7
Phase Relationships
Impedance is the total opposition in a circuit to the flow of current. It combines the effect of the
resistance and reactance of a circuit. The formula for impedance is:
Z
=
Where:
Z = Impedance (ohms)
E = Effective Applied Voltage (volts)
IR = Effective Current (amps)
Inductive reactance and capacitive reactance act in direct opposition to one another and tend to
cancel one another out. The complete expression for the impedance of an ac circuit having
resistance, inductive and capacitive loads connected in series, is:
Z
=
ohms
Where Z = Impedance (ohms)
XL = Inductive Reactance (ohms)
XC = Capacitive Reactance (ohms)
R = Resistance (ohms)
POWER FACTOR
The power in an AC circuit is equal to the effective current I times the effective voltage E at that
instant. This is only really true when the current and voltage are in phase. When reactance is
present, the voltage and current are out of phase. In this case the value of power produced is less
than E x I. The value of E x I in a circuit is also called voltamperes (VA) or kilovoltamperes (kVA).
This is called the apparent power of a system. The real power in watts is the apparent power
multiplied by the power factor.
Figure 8
Power Phase Relationship
The relationship of the real power EI cos θ, apparent power EI, and reactive power EI sin is shown
in the phase diagram Fig. 8. The angle between the apparent and reactive power is θ, and the
power factor is cos θ.
The term cos θ is known as the power factor and has some value between one and zero (100% and
zero). Because of the large number of induction motors and other inductive devices the power
factor of many such systems is low (75%), resulting in line losses and substantial voltage drops. To
improve power factor a corrective capacitor can be used. Power factor can be expressed as a
percentage or as decimal value. (75% or 0.75 for example)
If the current and voltage are in phase, the power factor is 1. If the current and the voltage were
out of phase by 90 degrees as in a purely reactive or purely inductive circuit, the power factor would
be zero. Then the actual power would be zero. Normally a circuit contains both resistive and
reactive loads. This results in a power factor between zero and one. The power factors of some
common loads are:
Small induction motors - 60 to 80 percent
Incandescent lighting - 95 to 100 percent
Large induction motors - 80 to 90 percent
Static capacitors like the pole mounted ones in Fig. 9 can be used to increase the power factor at a
facility such as an industrial plant. They are connected in parallel with the power lines. The capacitor
plates are inside the metal tanks, immersed in insulating oil for operating at high voltages.
Figure 9
Capacitors Used to Adjust Power Factor
ALTERNATOR RATINGS
Alternator capacity is rated in (kilovoltamperes) kVA or (megavoltamperes) MVA and also kilowatts
(kW) or megawatts (MW) at a specified power factor. For example, a generator may be rated at 125
MVA and 100MW at 0.8 lagging power factor. The maximum continuous rating (MCR) expressed in
MVA is based on the nominal values of the stator and rotor currents. Neither of these should be
exceeded, as the additional losses may damage their respective insulating materials.
Alternator nameplates also carry voltage, current, frequency, number of phases, and speed ratings.
Maximum temperature rise is also stated, along with the type of measurement used. Excitation data
is also included. It is stated as field voltage and field amperes.
Objective Three
When you complete this objective you will be able to…
Describe the stator and rotor designs, operation, and applications for salient pole and cylindrical
rotor alternators.
Learning Material
ALTERNATORS
AC generators are usually referred to as alternators. Both single-phase and three-phase alternators
are manufactured, but the three-phase alternator is far more common in industry. Modern
alternators consist of a stator on which the AC voltage producing windings are placed, and a
rotating armature or rotor on which a DC excitation winding is placed. The rotor’s DC winding is
supplied via slip-rings and produces a magnetic field which when rotated cuts the stator conductors
inducing an AC voltage within them. The AC winding is a distributed winding. The windings are
distributed in slots around the stator very much like the armature winding of a DC machine.
There are two different kinds of rotor, salient pole rotors and cylindrical type rotors. Cylindrical
rotors are used on alternators exceeding 1800 r/min. Steam and gas turbine-driven alternators will
have cylindrical-type rotors, as shown in Fig. 10 (a).
Figure 10
Alternator Rotor Designs
The stator consists of a magnetic steel core, built up in laminated sheets. The winding is placed in
slots in the core in the same manner as the armature winding of the DC generator. The rotor carries
the field windings, supplied through brush gear and slip-rings.
Slow-speed generators not exceeding 1800 r/min such as those driven by diesel engines or water
turbines have rotors with projecting, or salient, field poles. A salient pole rotor is shown in Fig.
10(b). Fig. 11 shows a multi-pole, 240 r/min, 2140 kW, 60 hertz Allis-Chalmers generator.
Fig. 12 shows a two-pole, 100 MW, 3000 r/min, 50-hertz machine. This figure shows the complete
turbo generator set including turbines, alternator and exciter.
Figure 11
Salient Pole Generator
Unlike DC generators alternators must be driven at very definite constant speed. This is the speed
that produces the required frequency of power. For example, if 60-hertz is required by the power
grid, a two-pole machine would have to be run at 3600 r/min.
Where a single alternator is supplying a circuit load, the frequency of that circuit or system will
depend entirely upon that alternator speed. If however, there are a number of alternators running
in parallel to supply the system, the speed of each machine will be locked into the system
frequency. The system frequency will not vary unless the speed of all the machines changes.
Again, if an additional alternator is to be switched into the system supply it must be run up to an
exact speed first to correspond with the others. This is termed the Synchronous speed. For a 60hertz frequency system a two-pole machine has a synchronous speed of 3600 r/min; a four-pole
machine, 1800 r/min; twelve-pole, 600 r/min, and so on.
Standard frequency on the North American continent is 60 hertz (Europe 50 hertz) and alternators
normally run at 3600 r/min when two-pole, and 1800 r/min when four-pole. The modern turboalternator is almost without exception of two-pole design. The lower operating speed with the fourpole machine is not generally favorable to a high-pressure turbine design and the unit as a whole is
bulkier and more expensive than a two-pole machine of similar rating. Most development has
therefore been concentrated on the two-pole generator design.
The common types of prime movers used to drive alternators are steam turbines, gas turbines,
steam and diesel engines. The types of alternator employed will be chosen to match the prime
mover, and both will be influenced by the required output, voltage, and so on.
The alternator illustrated in Fig. 12 is a multi-pole engine-type generator typical for use at speeds
below 500 r/min. The machine shown has 28 field poles on the revolving rotor and will run at 257
r/min to generate 60 hertz. Typical output will be up to 5000 kVA. Alternators for hydro-electric or
diesel engine generating stations are of the slow-speed multi-pole type; in most cases the hydrostation type will have the alternator shaft disposed vertically. Those for steam or gas turbine drive
are always of the horizontal, cylindrical rotor-type shown in Fig. 10 (a).
Figure 12
Stator and Rotor Assemblies for
Large Engine-Type Synchronous Generator
ROTOR DESIGN
The rotor of such machines is forged of solid steel, which may in the largest sizes have a diameter
of some 1070 mm, a body length of 6 m and, with the shaft ends an overall length of 10.5 m or
more. The mass of such a forging may be 50 or 60 tonnes and requires considerable care in testing
after manufacture to ensure that it contains no internal defect.
Figure 13
Rotor Construction
The body of the rotor is slotted to receive the windings. Steel retaining rings referred to as end caps
or end bells, are shrunk on to hold the end windings in position against heavy centrifugal force.
The rotor is wound as in Fig.13 (b) first. Note that it forms a concentric winding on each of the two
rotor poles. Then the slot wedges are fitted and finally the end bells are shrunk over the end turns
so that they butt against the slotted rotor body and lock the wedges in position.
These end caps may be made of non-magnetic steel alloy in order to reduce the stray losses. British
and European practice appears to favor magnetic steel because of its higher tensile strength.
The rotor windings are of copper strip insulated with micanite and held into the rotor slots against
centrifugal force by steel wedges. Fig. 13 gives a view of the rotor:
(a) Before winding
(b) After winding and before fitting slot wedges and end bells
(c) Complete with end bells, fans and couplings
STATOR DESIGN
The basic features of the stator are the core, built up from segmental steel sheets and the windings
of copper insulated with micanite and carried in slots in the inner periphery of the core. A stator
frame is necessary to support the core and windings and provide an enclosure for circulation of the
gaseous coolant.
The stator core is built up of slotted segments made of special silicon alloy steel sheets 0.35 to 4
mm thick. These are keyed into the stator frame and clamped longitudinally. Radial ducts are
provided for cooling purposes at intervals along the length of the core, these being formed by Isection spacers spot-welded to adjacent segments.
Stator windings for large turbo-alternators are of the bar type usually formed from rectangular
section copper conductors, the number of conductors per slot being chosen to suit the winding
arrangement. This will always be of the three-phase type, the conductors being circumferentially
arranged in six groups. Long end windings are necessary to connect the winding groups and special
precautions must be taken to support these. They are secured firmly to brackets and numerous
support blocks are provided to ensure that the windings will not deform in the event of fault
conditions producing surge currents.
It is, in fact, quite common for a customer to call for a machine on the test bed to be subjected to a
sudden three-phase short circuit at its terminals while running on open circuit at normal voltage and
frequency. Stator winding insulation is generally micanite although a number of different bonding
materials are in use.
Objective Four
When you complete this objective you will be able to…
Describe water, air and hydrogen cooling systems for large generators.
Learning Material
GENERATOR COOLING
The general trend in modern design is to ever-increase output from an individual machine. In all
cases a single machine will cost less than two smaller machines giving the same total output, both
in construction and in running costs. Despite the more expensive raw materials required and the
increasing complexity of design, efforts are being made to increase the size of alternators.
The main limitation on the output which can be obtained from any given turbo-alternator frame is
the amount of heat which can be dissipated from the rotor without the temperature rise of the
windings exceeding the permissible limits. Effective cooling must be carried out in the stator
windings too, but since these windings are stationary the problem is not so acute.
Liquid-Cooled Alternators
Direct cooling of the conductors in the stator windings of alternators has been carried out by
circulation of liquid through hollow conductors. The advantages to be gained through more effective
cooling of the stator windings are: increased current densities in the stator copper, and consequent
reduction in overall mass of the machine for any given output.
The liquid chosen as most suitable for this method of cooling was water. The generators being
installed employ water-cooling in the stator windings. Stainless steel manifolds carry the coolingwater supply to and from the ends of the hollow copper conductors. Plastic insulating hoses are
used for the connections.
Water of high purity is used to ensure low electrical conductivity and so minimize the losses due to
leakage current flow. Leakage current flow refers to current flowing through the water.
Direct Air Cooling
The first alternator designs used a straight through air-cooling arrangement for stator and rotor
cooling. Fans mounted on the rotor shaft drew in atmospheric air and discharged it through the core
and windings. The disadvantages were that the ventilating ducts gathered dust and grit and became
choked. The fire hazard was considerable as the hot coils of the generator could ignite the dust and
grit.
Enclosed Air System
The next design enclosed the alternator air system so that the same air re-circulates through the
windings after passing through an air cooler. Most of these designs use a separate ventilating air
fan. Fig. 14 shows a typical arrangement.
The advantages are that the windings are kept very much cleaner, the fire hazard is reduced since
the quantity of oxygen in the system is limited, and the generator area can be kept quieter and
cooler. The alternator design is made more compact because the fan and air cooler can be located
in the alternator foundation block.
The cooling medium for the air-cooler is circulating water. Care has to be taken that no leakages
occur at the tubes. Water could leak into the generator causing shorting or arcing. The water used
is not ultra pure and will conduct electricity. Means are provided for emergency access to
atmospheric air in the event of loss of cooling water supply. The atmospheric air is then used to cool
the circulating water. The load on the generator would have to be reduced, when using air as a
cooling medium.
Figure 14
Alternator Ventilating Arrangement
HYDROGEN COOLING
The use of a closed circuit system of alternator ventilation and cooling suggested the possibility of
some other gas in place of air being used as the cooling medium. Air has the disadvantages of a
poor thermal capacity, high density and the fact that it will support combustion. The gas, which was
universally chosen in place of air for alternator cooling, was hydrogen.
Hydrogen has outstanding advantages as a cooling medium. It as a high heat transfer coefficient
and will therefore absorb and reject heat rapidly. It has a high thermal conductivity and will
transmit the heat rapidly. It has a low density. This requires little power to force it through a fan
and offers very little braking effect (windage) to the rotating parts of the alternator. The low density
gives reduced windage loss and this results in a direct increase in the alternator efficiency of
approximately 1%. The specific heat of hydrogen is high enough to compensate for the low density
so that it will carry off about the same amount of heat as air for a given quantity of gas.
Compared directly with air, its specific heat is fourteen times as great, and its density is about onefourteenth. Its heat transfer coefficient is about one and one half times that of air and its thermal
conductivity six times.
The higher thermal conductivity and greater heat transfer coefficient of hydrogen both reduce the
temperature gradient in an alternator, or conversely permit a greater output to be obtained from
the same frame.
The increase in output obtained with hydrogen cooling in place of air- cooling on any particular
machine has been shown to be 20 to 30%, based on a hydrogen pressure of 3.5 kPa. A further
increase in output may be obtained by raising the pressure of hydrogen in the alternator, each 7kPa increase above atmosphere giving about 1% gain in output. Experiments have been carried out
with pressures up to 170 kPa and alternators are regularly operated up to 100 kPa.
In addition to the above, the use of hydrogen for cooling brings the following advantages: reduced
maintenance because of the gas-tight and hence dirt and moisture-proof casing; quieter operation
due to the virtual elimination of windage losses; simplified foundations since external fans and
coolers are not required.
The disadvantages are the added complications of a gas control system and shaft sealing devices,
and the necessity for a gas-tight and explosion-safe casing.
Figure 15
Arrangement of Hydrogen-Cooled Alternator
In order to avoid having an explosive mixture of air and hydrogen in the stator at times of charging
or purging, carbon dioxide is used as a buffer gas, that is, when replacing the air in the stator with
hydrogen, carbon dioxide is used to expel the air and then hydrogen in turn displaces the carbon
dioxide. In the case of purging the hydrogen from the stator prior to opening up for overhaul and
repair, CO2 is used to expel the hydrogen and then air to displace the CO2.
Hydrogen and air form an explosive mixture between the limits of 4% and 74% hydrogen in air by
volume. During normal running it is not difficult to maintain the purity of the hydrogen in the stator
at 95% or above. A hydrogen cooled alternator arrangement is shown in Fig. 15.
With regard to the risk of explosion, which is attendant upon the use of hydrogen, experience has
shown that if ordinary precautions are taken there is no danger. Nevertheless, hydrogen-cooled
alternators are enclosed in a casing, which is designed to withstand the highest pressure, which
could occur in the event of an explosion.
The complete system of piping and auxiliaries for a hydrogen-cooled alternator is illustrated in Fig.
18. The layout shows lubricating (seal) oil lines, carbon dioxide, hydrogen, distilled water (for
hydrogen coolers) and river water (for distilled water coolers) piping.
Increasing the hydrogen gas pressure in the stator can increase the effectiveness of hydrogen
cooling of alternators. Allowing the gas direct access to the copper conductors on the rotor winding
can also increase cooling. This method is known as Direct Rotor Cooling and together with increased
gas pressure has been responsible for a major advance in the design of turbo-alternators. The rotor
winding design is arranged to allow cooling gas to flow in contact with the copper by the use of
slotted, grooved or hollow conductors.
The gas flow paths vary with manufacturer’s designs. In some cases the gas enters at each end of
the rotor and leaves at the center. In others it flows from end to end. Still other designs allow the
gas to enter special rotor ventilation slots and then escape radially through slotted conductors.
Figure 16
Complete System of Pipework and Auxiliaries for Hydrogen-Cooled Alternator
Shaft Seals
The shafts must be sealed at the point where they pass through the stator casing. Various types of
shaft seals have been designed and are in use. Fig. 17 (a) and (b) illustrates a radial clearance and
an axial clearance type.
Figure 17
Shaft Seal Used in Hydrogen-Cooled Alternators
In each case the basic idea is to prevent the hydrogen from escaping outwards by forcing seal oil
inwards. The present day seals are extremely effective and the quantity of oil required to maintain
tightness is relatively small. The oil is supplied from the main machine lubricating oil system and is
returned after passing through a hydrogen detraining tank where the oil is delayed long enough to
allow any entrained hydrogen to be given off.
Objective Five
When you complete this objective you will be able to…
Explain parallel operation of alternators and state the requirements for synchronization. Describe
manual and automatic synchronization.
Learning Material
PARALLELING ALTERNATORS
The process of connecting an alternator in parallel with other operating alternators is referred to as
synchronizing. The alternator that is being synchronized must meet the following conditions before
it can be put into the operating system:
1. The incoming alternator must be the same voltage as the system. Adjust the alternator?field
rheostat until the terminal voltage matches the system voltage.
2. Alternator frequency and system frequency must be the same. Adjusting the speed of the prime
mover controls the alternator frequency. In most cases this means control of steam supply to the
turbine.
3. Its phase sequence must be the same as the system. If the system bus bars are designated Red,
White and Blue and the maximum of the voltage waves of these three phases occur in the sequence
Red, White, Blue, then the incoming machine (which is to be connected Red to Red, Blue to Blue,
etc.) must also have voltage maximums occurring in the phase sequence Red, White, Blue. Phase
sequence is also referred to as phase rotation. Lamps or a phase rotation meter can check phase
sequence.
4. It must be in phase with the system. This means that the phase voltage of the alternator must
reach its maximum at the same time as the system voltage reaches its maximum.
The phase relationship of incoming machine and system requires the use of a synchronizing device
such as an indicator; this may be in the form of a bank of lamps or a synchroscope. Modern large
machines will always use a synchroscope because indication by lamps is not accurate enough.
There are two common manual methods of synchronization, the lamp method and the synchroscope
method. The synchroscope method is the best, but lamps are cheaper and may need to be used in
an emergency, and also have definite advantages in checking phase rotation.
Lamp Method of Synchronization
There are two ways of connecting lamps for synchronizing, but the procedure prior to
synchronization is the same for both. We will therefore deal with one method and point out the
difference with the other method.
One Dark, Two Bright Synchronization (rotating lamps)
Fig. 18 shows how the lamps are connected across the synchronizing switch for this method. The
procedure is as follows:
Figure 18
One Dark, Two Bright Synchronization
i.
The prime-mover of the incoming alternator is started and brought up to speed.
ii.
The DC field excitation switch of the incoming alternator is closed and by means of the field
rheostat the voltage is adjusted to approximately the same voltage as the system.
iii.
The synchronizing lamps should go bright and dark one after the other giving a kind of
rotating effect. If they all go bright and dark in unison, then the phase sequence of the
incoming alternator is incorrect and should be corrected by changing any two of its three
output leads.
iv.
When they are rotating correctly the speed of the incoming alternator should be adjusted so
that the rotation is slow.
v.
After finally checking that the voltages are the same, and adjusting if not, the synchronizing
switch should be closed at the moment when lamp a and c are equally bright and lamp b is
dark. Be sure that it is b lamp that is dark.
vi.
Once the alternator is paralleled, it can be made to share load by increasing the driving
torque of its prime mover.
All Dark Synchronization
Fig. 19 shows how the lamps should be connected for this method of synchronization. When the
phase sequence is correct all three lamps should go dark and bright together. If they rotate in
brightness, then the phase sequence of the incoming alternator is incorrect and should be corrected.
The procedure is then the same as before, except the synchronizing switch should be closed when
all three lamps are dark. The main disadvantage of this method is that a considerable voltage can
exist across the lamps even when they are dark, and closing the switch in these circumstances can
cause disturbance in the system. All lamps should have a voltage rating at least as high as 1.15 x
line voltage of the system. Otherwise, two or more lamps connected in series, or potential
transformers should be used.
Figure 19
All Dark Synchronization
Synchroscope Synchronization
The synchroscope is a single-phase device used to synchronize three-phase and single-phase
alternators. When using a synchroscope, the phase rotation should be checked by lamps, or by
some other method, as it cannot be detected by the synchroscope. The face of the synchroscope
appears as illustrated in Fig. 20. The procedure is as before, but the alternator speed should be
adjusted so that the rotating pointer is rotating slowly in the “fast” direction. The synchronizing
switch is then closed when the pointer is vertical and pointing upwards.
Figure 20
Synchroscope
AUTOMATIC SYNCHRONIZATION
It is becoming common for each generator in a power plant to have its own equipment for
automatically synchronizing the generator to the power grid. The manual equipment as described
above is only used as a backup. The automatic synchronizing equipment includes a speed matching
relay, a voltage-matching relay, a synchronizing relay, auxiliary relays, and transformer relays or
switches. The automatic synchronizing equipment is turned on as part of the generating unit startup. As the generator unit reaches its rated speed, the speed-matching relay provides raise or lower
impulses to the prime mover. This is done to match the generator frequency to the bus or grid
frequency. The voltage-matching relay matches the generator and bus voltages by sending more or
less excitation to the generator. When the generator and bus voltages and frequencies are matched,
as determined by the synchronizing relay, the closing impulse is given to the generator breaker to
close its contacts.
Disconnecting an Alternator
To take an alternator off the line in a system involving two or more alternators, the driving torque
of the prime mover of the alternator to be removed should be reduced until it is supplying zero
current to the busbars. At this point its main disconnect switch can be opened disconnecting the
machine from the busbars. The output voltage is then reduced to a minimum by means of the field
rheostat, and the DC field excitation switch is opened. The prime mover can now be stopped.
Objective Six
When you complete this objective you will be able to…
Describe the design, applications and operating principles for large three-phase squirrel cage and
wound rotor induction motors.
Learning Material
THREE-PHASE INDUCTION MOTORS
Three-phase induction motors are superior to single-phase motors in a number of respects. They
are self-starting, smaller in dimensions for a given power rating with better power factor and higher
efficiency.
Principle of Operation
The stator of the induction motor is identical to that of the three-phase alternator. In the alternator,
a magnetic field, produced by supplying the rotor with DC current, rotates with the rotor and
produces three-phase voltages in the stator winding. As in many other electrical devices, this effect
is reversible. Supplying a three-phase stator from a three-phase supply causes a rotating field of
constant magnitude and constant speed to be produced inside the stator.
Figure 21
Rotating Field
As the magnetic field rotates, it cuts the conductors of the squirrel cage rotor inducing currents in
the rotor bars as indicated in Fig. 21. These currents in turn produce magnetic fields, which distort
the main field. The main field, in attempting to straighten out, tries to push the bars away from the
field in the same direction as the field is traveling. Thus torque is produced, the rotor rotates and
tries to attain the same speed as the magnetic field. It can never do this however, because if it did
rotate at the same speed, there would be no relative movement between the rotating field and the
rotor bars, hence induction of voltage would cease, rotor current and therefore torque would cease.
The rotor would slow down and relative movement between field and rotor would again exist
producing torque.
In practice, the rotor always rotates at a slower speed than the field, and the difference in speed
between the two is called the slip speed. The slip speed is always just enough to produce the
necessary voltage, and therefore current and torque to satisfy the load on the motor.
Figure 22
Squirrel Cage Motor Construction
The most common type of rotor used in induction motors is the squirrel cage rotor. This rotor
consists of heavy copper or aluminum bars, as seen in Fig. 22, fitted into slots in the rotor iron.
Shorting rings, of the same material as the bars, connect all the bars together at each end of the
rotor. All the iron of the magnetic circuit is laminated to minimize eddy currents. Fig. 23 shows a
squirrel cage rotor and Fig. 24 illustrates a three-phase stator.
Figure 23
Squirrel Cage Rotor (Electric Machinery Mfg. Co.)
Figure 24
Three Phase Stator
Figure 25
Squirrel Cage Induction Motor
(Courtesy Electric Motor Division Gould Inc.)
The squirrel cage induction motor, as seen in Fig. 25 has separate starter windings, and normal
running windings. The start windings are the small set. It also has a capacitor also used in the
starting circuit.
THE WOUND-ROTOR (SLIP-RING) INDUCTION MOTOR
The stator of a wound-rotor motor is identical to that of a normal induction motor. It is constructed
of poles and windings. It may be a two-pole, four-pole, etc. stator. Most induction motors have
distributed windings. If you looked at the stator windings of an induction motor, you could not count
the poles, with the compact coils of wire.
The rotor consists of coils of many turns instead of the heavy bars of the squirrel cage rotor. The
ends of the wound-rotor winding are connected to slip-rings mounted on the rotor shaft. The
principle of operation is identical to that of the ordinary induction motor with an emf (electromotive
force) being induced in the rotor by the rotating field produced by the stator winding. The basic
construction of a wound rotor induction motor is shown in Fig. 26.
In any induction motor, in order to develop high starting torque with low starting current, the rotor
resistance needs to be high. As the machine speeds up, the resistance of the rotor needs to be
reduced in order to maintain a high level of torque. The resistance of a squirrel cage rotor is fixed. A
high resistance rotor, which produces a high starting torque, also produces a high slip when fully
accelerated. The wound-rotor enables external resistance to be inserted into the rotor circuit during
starting and gradually taken out as the motor accelerates. This enables a high torque to be
maintained during the starting period.
Wound-rotor motors are also used for speed control, with a higher rotor circuit resistance causing
higher slip and therefore a lower motor speed. It is a very inefficient method of speed control due to
the heating losses within the rotor circuit resistors, although inexpensive in terms of capital cost of
equipment.
Figure 26
Wound Rotor Induction Motor
Applications
The induction motor is the most commonly used type of AC motor. This is because the design is
simple, and it is very rugged. It also has very good operating characteristics. Common uses include
driving fans, pumps, compressors, or any machine that requires a steady and reliable power source.
The wound rotor induction motor is usually used if speed control is needed. It is more expensive to
construct, but allows for varying the resistance in the rotor circuit. Induction motors are available in
power sizes from small to over 1000 horsepower.
Objective Seven
When you complete this objective you will be able to…
Describe the design and operating principle of synchronous motors.
Learning Material
SYNCHRONOUS MOTORS
The synchronous motor is identical in construction to the alternator. Any synchronous machine can
be run as an alternator or a motor. Both require a DC supply to the rotor. The difference is that the
alternator is driven by a prime mover and generates an alternating current in the stator windings.
The synchronous motor on the other hand has an AC supply connected to the stator windings, as
shown in Fig. 27.
Figure 27
Synchronous Motor
In the case of the three-phase synchronous motor a rotating field of constant speed and constant
magnitude is produced by the stator windings. Unlike the induction motor rotor, which depends on
slip for its torque, the DC rotor field “locks in” to the rotating field of the stator causing the rotor to
rotate at synchronous speed from no-load to full-load. The rotor field created by the rotor windings
locks in to the rotating field of the stator windings. The speed of rotation of the field windings is
controlled by the frequency of the AC power supply and the number of main stator poles.
Figure 28
Basic Synchronous Motor
Fig. 28 shows how the rotor is locked in position by the attractive force of the stator field. This
motor has a permanent magnet, instead of the dc-induced field. This type of synchronous motor is
used only for light loads, such as clock motors. Larger synchronous motors used for heavy loads
have the powerful magnetic poles produced by dc power.
If the synchronous motor is too heavily overloaded, it will not run at reduced speed as will the
induction motor, it simply drops out of synchronism producing heavy stator currents, which cause
the circuit protective devices to “trip” it out of the circuit.
One of the main advantages of the synchronous motor is that it can be run at a leading power
factor, unlike other motors, which run at a lagging power factor. If an industrial plant has a poor
power factor which is often the case due to the number of motor loads with lagging power factors, a
penalty is levied by the electrical supply company causing the electrical energy used by the plant to
be more expensive.
If the DC supply to the synchronous motors in the plant is increased, causing over-excitation and a
leading power factor for such motors, this will help to improve the overall power factor thus
decreasing the cost of energy. The construction of a basic synchronous motor is shown in the
exploded view Fig. 29. A picture of a synchronous motor rotor is shown in Fig. 30.
Figure 29
Synchronous Motor Parts
Figure 30
Synchronous Motor Rotor
Starting Synchronous Motors
Unlike the induction motor, the synchronous motor is not selfstarting. It cannot be started with both normal AC and DC supplies
connected to the stator and rotor windings respectively. Any
attempt to do so would produce heavy stator currents, which
would trip the machine off the line.
Synchronous machines are supplied with a special squirrel cage
winding called an amortisseur winding or damper winding (Fig. 29)
which is fitted into slots in the rotor pole faces. In the synchronous
motor, this winding allows the machine to be started as an
induction motor either directly across the line. This is done without
the DC excitation applied to the rotor, and with the rotor winding
short-circuited. As the motor accelerates as an induction motor
and nears minimum slip, the rotor short circuit is removed and the
rotor DC excitation is applied causing the rotor to “pull in” to
synchronism.
The amortisseur winding has another advantage whether the
synchronous machine is run as an alternator or a motor. When the
rotor is running at synchronous speed there is no relative
movement between rotor bars and the flux of the rotating field so
the amortisseur winding has no effect. During sudden changes of
load however when the rotor tends to slow down or speed up, the
amortisseur winding becomes effective and supplies a torque,
which counteracts the tendency to change speed.
Objective Eight
When you complete this objective you will be able to…
Explain variable speed control, variable speed starting, and step starting for large induction motors.
Learning Material
INDUCTION MOTOR SPEED CONTROL
The speed of a squirrel-cage induction motor, if the frequency of supply is fixed, can only be
changed by changing the number of poles. This can be accomplished by using separate windings for
each speed, or by re-connecting the windings so that all poles become the same polarity. By these
means a squirrel-cage motor can be made to operate at any one of several fixed speeds. Pole
arrangements of 2, 4, 6, 8 poles will give synchronous speeds of 3600, 1800, 1200, and 900 r/min
from a 60-hertz supply system. The actual operating speeds will be slightly less, about 3500, 1750,
1150, and 875 r/min. Motor design will allow this speed range to be made available with either
constant power or with constant torque.
VARIABLE SPEED STARTING
Induction motors with wound rotors are classed as adjustable speed motors. The winding
connections are as shown in Fig. 31. The variables starting resistances or rheostats are used for
speed control. Maximum resistance will give the lowest speed. The result is a constant torque,
variable speed motor with high starting torque. Prolonged operation at low speeds must be avoided
however, because of danger of overheating and since the rheostat involves a power loss, this
method of motor speed control is inefficient. It is normally used as a type of variable speed starter.
Figure 31
Wiring Diagram for Wound Rotor Induction Motor
Speed Controller
Variable Frequency Drives (VFD)
Many applications that required adjustable or variable speed control used to be limited to DC motor
drives. This is no longer true. Modern variable frequency drives are available for AC induction
motors from one horsepower to over 1000 horsepower.
VFDs (Variable Frequency Drives) are also called AC Drives and also Inverters. VFDs are static solidstate devices that have low power conversion losses. As VFDs can control standard induction
motors, they can be easily added to an existing system. Modern electronics has reduced the cost of
frequency-changing equipment to the point where it has become economical to supply a motor with
a variable frequency power supply so that the motor speed can be smoothly increased or decreased.
An important application of this equipment is the use of variable speed pumps and fans to control
flows rather than constant speed pumps and fans in combination with control valves and dampers.
The motor drive speed is controlled just fast enough to provide the required flows, rather than
wasting power by throttling across valves or dampers.
In general, the percentage drop in frequency is proportional to the percentage drop in motor speed.
For example, an induction motor that rotates at 1725 r/min when supplied with ac power at 60 Hz,
will operate at 1581 r/min (a reduction of 8.33%) when supplied with ac power at 55 Hz (a
frequency reduction of 8.33%).
VFDs are often installed in the motor control center (MCC) for AC motors. The speed control
adjustment can be in the control room, in the MCC or at the location of the motor. As Fig. 32
illustrates, VFDs take incoming 60 hertz power and convert it to direct current. The DC is then
inverted back to AC at a different or required frequency. The inverter can be continuously adjusted
to produce the desired frequency output. The AC frequency sets the speed of the AC induction
motor. In this way, the motor speed can be continuously adjusted.
Figure 32
Variable Frequency Drive
STARTING METHODS (STEP STARTING)
An induction motor will take a starting current up to about six times its normal full?load current
when it is started by connecting directly to the source of supply. Such a starting surge can have a
number of undesirable effects, causing lights to flicker as a minimum effect, with the possibility of
damage to belts, shafts and gears in more serious cases. To minimize these effects, reduced voltage
starting is used in many industrial situations. There are a number of reduced voltage starting
methods in use. Some of the more common ones are: Line Impedance Starters, Star-Delta Starters,
and Autotransformer Starters.
Line Impedance Starters
These are starters, which place resistors or inductors in series with each phase in order to reduce
the starting current. The impedances are removed in steps as the motor accelerates to full speed.
Fig. 33 (a) and (b) indicate the arrangement for line resistor and line reactor starting respectively.
The relay coils, which operate the electric relay contacts, are not shown.
Figure 33
Line Impedance Starting
This method of starting is relatively inexpensive but gives a lower starting torque than some other
methods.
Star-Delta Starting
This method can only be used on motors designed to run as delta connected machines. All six ends
of the winding must be brought out to terminals on the motor. On starting, a special switch is used
which first connects the windings in star, reducing the starting current to a third of what it would
otherwise be. As the motor accelerates the switch is moved to the run position connecting the
winding in delta. See Fig. 34 (a).
Star-delta starting is inexpensive but gives rise to an undesirable current surge during the transition
from star to delta.
Figure 34
Induction Motor Starters
Auto-Transformer Starting is an expensive method but capable of giving one of the best starting
torque to starting kVA ratios of the starting methods. The procedure is to start the motor by
connecting to a lower voltage tap, on the autotransformer, and then switching to full voltage as the
machine accelerates towards full speed. See Fig. 34 (b).
Objective Nine
When you complete this objective you will be able to…
Explain the principles and applications of power transformation. Perform transformer calculations.
Learning Material
TRANSFORMERS
One of the reasons for the popularity of alternating current systems is the ease with which AC
voltage and current levels can be transformed. Large amounts of power can be transmitted at high
voltage and comparatively low current levels, to be changed to lower voltages and higher currents
in the locality where the power is to be used. The size of the conductor is proportional to the size of
the current, thus such transmission methods affect large savings in copper costs. The device that
makes this transformation possible is called a transformer.
Principle of Operation
When magnetic flux produced by one coil cuts the conductors of a second coil, a voltage is induced
in the second coil. This process is known as mutual inductance, and is the principle upon which the
transformer operates. Fig. 35 illustrates how mutual induction makes it possible to transfer energy
from one circuit to another.
Figure 35
Mutual Inductance in Transformer
Referring to Fig. 35, an ac source emf is applied to the primary coil. The varying magnetic field
causes a magnetic field to pass through the coils of the primary and secondary coils. An induced
emf is produced in the secondary coil. The magnetic field in the secondary cuts the primary and
secondary coils. This produces a back emf in the primary coil. In this way power from one circuit
can be transferred to another circuit. The coil in which the flux originates is called the primary and
the coil in which the emf is induced is called the secondary. The amount of emf generated depends
upon the relative position of the two coils, and the number of turns of each coil. Mutual inductance
is the amount of mutual induction that exits between the coils.
TRANSFORMER APPLICATIONS
Transformers have two basic uses. One is to increase AC voltage. This is called a step-up
transformer. The other application is to decrease voltage. This is called the step-down transformer.
A transformer is designed to deliver the voltage that is required by a transmission system or that is
required by electrically powered equipment. Distribution systems commonly use single-phase
transformers for light industrial and residential applications. They convert 220V AC to 110V AC.
They are common in industrial plants for supplying 110 volts AC to MCC (motor control) panels,
which distribute power to 110V applications, such as small AC motors.
Three phase transformers are used for power transmission. They are seen in industrial plants in
substations and switchyards, supplying the required voltages for large AC machines. Common
voltages used by 3 phase motors are 600 volts, and 460 volts. Sometimes even higher voltages,
such as 4160 volts are used. Transmission line voltages are much higher such as 138,000 V (138
kV) or 240,000 V (240 kV).
Instrument transformers are used to connect meters or instruments to high voltages circuits. They
reduce the current and voltage to levels, which are safe for the instruments. An example would be
for instrumentation around power generators and transformers.
Single-Phase Transformers
Fig. 36 illustrates the arrangement of a simple transformer with two electrically isolated coils wound
on a laminated soft-iron core. When an alternating emf (VP) is applied to one coil, which is called
the primary, winding, an alternating flux is produced in the core, which induces an emf, (EP) in the
primary winding by self-induction, and also induces an emf (ES) in the other coil, the secondary
winding, by mutual induction.
With the secondary open-circuited, EP is almost equal to VP, and the primary current IP is just
enough to produce the magnetic flux and supply the iron-losses in the transformer, and very small
heating losses.
Figure 36
Simple Transformer
In a transformer, it can be assumed that all the flux produced by the primary cuts every turn of
both the primary and secondary winding, thereby inducing the same voltage in every turn. If the
number of secondary turns is greater than the number of primary turns, then the voltage induced in
the secondary will be larger than that induced in the primary. This transformer is called a step-up
transformer. If the number of secondary turns is such that secondary voltage is smaller than
primary voltage, then the transformer is a step-down transformer.
As the voltage in each winding is proportional to the number of turns in each winding, it can be
expressed mathematically as,
Where NP and NS are the number of turns in primary and secondary respectively. EP and ES are the
transformer primary and secondary voltages respectively.
Example 1:
A transformer has a primary winding with 500 turns and a secondary with 1000 turns. A voltage of
250 V is applied to the primary. Find the secondary voltage?
Solution:
When a load is connected to the secondary winding of a transformer, secondary current flows and
produces a magnetic flux, which opposes and tends to reduce the primary flux. This tends to reduce
the counter emf E in the primary allowing more primary current to flow re-establishing the main flux
to its former value. For this reason the flux of a transformer is virtually constant through all normal
load conditions.
Modern transformers are very efficient devices with large industrial transformers often better than
95% efficient. Because primary and secondary power factor are almost the same, and ignoring
losses, this becomes:
The transformer output voltamperes equal input voltamperes. In industrial transformers it is usually
far more convenient to talk in terms of kilovoltamperes or kVA.
Three-Phase Transformers
In industry three-phase systems are used extensively, and three-phase transformers are common.
A three-phase transformer is similar in construction to the single-phase shell-type transformer
except that primary and secondary windings are wound on each of the three legs as shown
schematically in Fig. 37. In practice low voltage coils are closer to the iron and high voltage coils are
over the low voltage coils, as illustrated in Fig. 38 (a). Fig. 38 (b) shows one of the alternative
methods sometimes used, “pancake” or “concentric” windings.
Figure 37
Three-Phase Transformer
High Voltage Coils
Three-phase systems often use banks of single-phase transformers to replace three-phase
transformers. The efficiency and cost of such single-phase banks do not compare favorably with the
three-phase transformer, but on the other hand, they can be much more convenient. For example,
if one coil of a three-phase transformer breaks down, the transformer must be taken out of the
system and replaced. If the same thing happens in a three-phase bank of three single-phase
transformers, the damaged transformer can often be disconnected leaving the remaining two
transformers to supply three-phase loads at 58% of normal capacity, until a replacement can be
obtained.
Figure 38
Three-Phase Transformers
Instrument Transformers
The use of voltage and current transformers reduce the hazards of dealing with direct measurement
of high voltages, and in addition enable voltmeters to be standardized at 125 V and ammeters to be
standardized at 5A. Voltage or potential transformers are simply low power versions of the normal
single-phase transformer.
Current transformers are quite unique, and special care must be taken when working on circuits
using them. Current transformers convert large primary currents into small secondary currents, and
are voltage step-up transformers. The secondary is permanently short circuited by the very low
resistance of a 5A ammeter. The primary voltage consisting of the voltage drop across one or at
least a few primary turns is very low. If the secondary is open-circuited the voltage across the
primary will suddenly increase producing a much higher voltage in the secondary, which can be
dangerous to life. For this reason, secondary windings of current transformers should never be
opened in active circuits.
The Auto-Transformer
An auto-transformer has a part of its winding common to both primary and secondary. The
transformation ratios are calculated in a similar way to the normal two winding or double-wound
transformer. When an autotransformer is used to step up the voltage, as in Fig. 39, part of the
winding acts as the primary, and the entire winding acts as the secondary. When the
autotransformer is used to step down the voltage, the entire winding acts as the primary and part of
the winding acts as the secondary. The action of the autotransformer is similar to the two winding
transformer. Power is transferred from the primary to the secondary winding by the changing
magnetic field. The amount of the step up or down depends upon the turns ratio of the primary and
secondary coils. Each coil is considered separate although some of the turns of coil are common to
both the primary and the secondary.
Figure 39
Autotransformer
Auto-transformers lead to savings in copper, but they are limited to small ratios of transformation.
This is because an open circuit occurring in that part of the winding common to both primary and
secondary can cause a large primary voltage to be impressed across a lower voltage secondary
load. A double-wound transformer (Fig. 40 a) can also be connected as an auto-transformers (Fig.
40 b).
Figure 40
Double-Wound and Auto-Transformer
Power Transmission
Although the transformer is a simple device, it makes it possible to transmit large amounts of power
over large distances with minimal losses. In power transmission lines the power delivered is the line
voltage times the current, P=E x I. Therefore for a large voltage the current is smaller. For example,
to transmit 200 kW over 100 miles, with a line voltage of 1000 V and an amperage 200,000/1000
or 200 A, would require a large diameter conductor.
If the voltage were raised to 14,400 V, the amperage would be 200,000/14,400 or 13.8 A, and a
much smaller diameter conductor could now be used. The conductor size can now be reduced while
still running with acceptable power losses. The cost of the transmission line would be much lower.
The power loss through the conductor is calculated by P=I2R. For the 13.8A conductor the power
loss is 0.0048 times the power loss for the 200A conductor. This means that the conductor size can
be reduced and still operate with acceptable power losses.
Fig. 41 shows a simple transmission system. There are applications for transformers at both ends of
the system. The voltage is increased or stepped-up to 69 kV for transmission, and then steppeddown to 480 V for distribution to the consumer.
Figure 41
Simple Transmission System
Self Test Problem
1. A transformer has a primary winding with 800 turns,
and a secondary winding with 200 turns. The secondary
voltage is 110 V. Find the voltage applied to the
primary windings?
(Ans. 440 V)
Objective Ten
When you complete this objective you will be able to…
Describe the designs and components of typical core and shell type transformers, including cooling
components.
Learning Material
CORE AND SHELL TRANSFORMERS
Single-phase transformers use two common forms of construction, and are known as the core type
and the shell type. Fig. 42 illustrates both. An air-cooled core type transformer is seen in Fig. 43.
In each case the low voltage coil is wound nearest the iron core, with the high voltage coil wound
over the low voltage coil. In the core type transformer primary and secondary windings are split into
two equal parts, with one half of the primary and one half of the secondary wound on each of the
two “legs” of the transformer. In the shell type, all of the primary and secondary is wound on the
center leg. The complete winding is then surrounded by a “shell” of iron, hence the name.
Figure 42
Core and Shell Type Transformers
Figure 43
Core Type Transformer
(Courtesy of General Electric Company)
Transformer Cooling
The kVA rating of a transformer is set primarily by the working temperature of the insulating
materials used. If the heat produced within the transformer due to copper losses and iron?core
losses can be carried away at a faster rate lowering the temperature rise, the transformer is able to
work at a higher kVA rating. The maximum temperature rating must not be exceeded. Transformers
below 50 kVA are usually air cooled by natural circulation. They have no cooling fans. Fins may be
added to increase the surface area and help dissipate the heat. Dry type transformers use air or an
inert gas as a cooling medium. Using forced cooling such as a fan may increase their kVA ratings.
Placing the core in an oil-filled tank further increases the rating because of the much larger specific
heat of the coil compared with air. Above 200 kVA this construction is normally used. Oil also is a
much better electrical insulator than air. Unfortunately oil is combustible and building and electrical
codes require special precautions thus increasing installation costs. Some of the hazards of oil
cooling can be removed by adding synthetic liquid additives such as chlorinated hydrocarbons, to
the mineral oil. PCBs (polychlorinated biphenyls) were such oil additives that were found to be toxic.
All transformers containing PCBs (over 50 ppm) had to have the PCB containing oils removed and
replaced with less toxic materials.
Selecting a method of transformer cooling involves a procedure of compromise in which cost is only
one of a number of factors. Figs. 44 shows an air-cooled transformer and Fig. 45 illustrates the
construction details of large transformer with oil cooling.
Figure 44
Air-Cooled 5000 kVA 48 kV
Transformer
Figure 45
Three-Phase Oil-Immersed Transformer
For extra transformer cooling, the shell may have radiators or fins to add to the surface area. The
transformer in Fig. 46 has both cooling fins and cooling fans. These large transformers usually have
instrumentation for monitoring the condition of the transformer.
Figure 46
Air- Cooled Transformer with Fins and Fans
(Courtesy of Kuhlman Electric Corporation)
Oil temperature gauges and pressure gauges are common and signals can be fed back to a central
control system for remote alarming and monitoring. Some transformers have three power ratings
depending on the cooling method chosen. For example a transformer could have a rating of
18/24/32 MVA. The cooling methods for the different ratings are:
•
•
•
Natural air circulation 18 MVA
Forced air cooling with fans 24 MVA
Forced oil circulation plus forced air-cooling 32 MVA
AC Systems, Switchgear, Safety
Learning Outcome
When you complete this learning material, you will be able to:
Identify the components of typical AC systems and switchgear and discuss safety around electrical
systems and equipment.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
5.
Using a one-line electrical drawing, identify the layout of a typical industrial AC power
system with multiple generators, and explain the interaction of the major components.
Explain the function of the typical gauges, meters, and switches on an AC generator panel.
Explain the purpose and function of the circuit protective and switching equipment
associated with an AC generator: fuses, safety switches, circuit breakers, circuit protection
relays, automatic bus switchover, grounding and lightning arrestors.
Explain the components and operation of a typical Uninterruptible Power Supply (UPS)
system.
Explain safety procedures and precautions that must be exercised when working around
and operating electrical system components.
Objective One
When you complete this objective you will be able to…
Using a one-line electrical drawing, identify the layout of a typical industrial AC power system with
multiple generators, and explain the interaction of the major components.
Learning Material
INDUSTRIAL AC POWER SYSTEM
Normal Utility Power Supply Systems
The main function of a power distribution system is to provide electrical power, for whatever need,
in a safe and dependable manner. This is accomplished by using a variety of electrical equipment
such as transformers, switchgear, breakers, motor control centres and emergency generators. To
provide a reliable source of power, most modern plants use a dual supply system for power
distribution. A dual supply system is one in which two independent power lines are used to supply
the same load. This dual system is used from the inlet of the main source of power to, up and
including, the end users.
Referring to Fig. 1, the power is supplied from two separate onsite electrical generators, which are
producing power at 13.8 kV, or 13800 volts. There is also an external backup power source, being
supplied at 138000 volts, which when required, is transformed down to 13800 volts.
This is then separated into two individual power lines, or buses. These are identified, in Fig. 1, as
“A” bus and “B” bus. The 15 kV main feeder breakers, identified as 11-01 and 11-02, supply the
13.8/4.16 kV – 10 MVA power transformers, PTR-101 and PTR-102. Here, the power is reduced in
voltage, from 13.8 kV to 4.16 kV, through the use of step-down transformers. This 4.16 kV power is
then fed to the 5 kV incoming switchgear breakers, 11-201 and 11-202. These two 5 kV switchgear
breakers, together with the tiebreaker, 11-203, make up the first level of automatic power transfer.
Under normal operation, both incoming breakers, 11-201 and 11-202, are closed and the tiebreaker
is open. When one of the incoming breakers loses its power supply, that breaker will open and the
tiebreaker will then close, reestablishing power through the other breaker. This 5 kV is also supplied
to high voltage motors in the plant site. The power from the 4.16 kV transformer then feeds the
4.16 kV feeder breakers. 4.16 kV power is also supplied to MCC#1 to provide power for the 4160V
boiler feed and cooling water pumps.
Feeder breakers, 11-211 and 11-212, supply the 3 MVA, 4.16- kV/480V power transformers, PTR211 and PTR-212. Feeder breakers, 11-221 and 11-222, supply the 2 MVA, 4.16- kV/480V power
transformers, PTR-221 and PTR-222, which, in turn, supplies Substation #1.
Two other feeder breakers, 11-231 and 11-232, also receive power from the main 4.16 kV supply.
These two 5 kV switchgear breakers and the tiebreaker, 11-233, make up the second level of
automatic power transfer. This system supplies power to critical 4.16 kV motor drivers.
Referring to Fig. 2, 4.16 kV power from PTR-211 and PTR-212 supplies feeder breakers, 11-301 and
11-302. These feeder breakers, together with the tiebreaker 11-303, make up the third level of
automatic power transfer. This system provides power to the many 480 kV users.
Figure 1
High Voltage Power Supply
Emergency Power Supply Systems
There are two emergency power supplies within this system. One, shown in Fig. 1, consists of a 900
kW natural gas turbine generator, two automatic transfer switches and one 4.16 kV motor control
centre. The other, shown in Fig. 2, consists of a 250 kW diesel generator, two automatic transfer
switches and a 480V motor control centre. The purpose and the method of operation of these
systems are described below:
4.16 kV Emergency MCC
In the event that the incoming 4.16 kV power should be lost, critical users are supplied with 4.16 kV
emergency power from the 900 kW natural gas turbine generator. Referring to Fig. 1, the automatic
transfer switch, ATS-1, can be fed with 4.16 kV power from either of the feeder breakers, 11-231 or
11-232. If both of these feeder breakers suffer a loss of incoming power, the emergency supply
system will sense a loss of this voltage and will then start the natural gas turbine generator. The
automatic transfer switch, ATS-2, will switch over to this generator in order to supply the
emergency MCC.
480V Emergency MCC
In the event that the incoming utility power should be lost, critical users are supplied with 480V
emergency power from the 250 kW diesel generator. The operation of the automatic transfer
switches, ATS-3 & ATS-4, function in the same manner as the automatic transfer switches describes
above for the 4.16 kV Emergency MCC system.
Figure 2
Medium And Low Voltage Power Supply
Objective Two
When you complete this objective you will be able to…
Explain the function of the typical gauges, meters, and switches on an AC generator panel.
Learning Material
AC GENERATOR PANEL
Indicators & Controls
The unit described here consists of a steam turbine coupled to an AC generator. The generator is
rated at 250 kW, 600VAC, 60 Hertz.
1. Kilowatt Hours Meter
This is a meter that measures and records the amount of power produced by the generator.
2. Exciter Field Voltage
This gives an indication of the DC voltage that is being supplied to the generators field windings.
3. Exciter Field Current
This gives an indication of the DC current that is being supplied to the generators field windings.
4. AC Kilowatts
This is an indication of the AC kilowatts that the generator is producing.
5. A, B & C Phases
These are an indication of the AC current, expressed in amps or amperes, which is being produced
by the three-phase generator.
6. Voltage Adjust
This is used to adjust the generators excitation voltage.
7. Frequency
This is an indication of the frequency of the power being produced by the generator. It is expressed
in hertz’s.
8. Power Factor
This is a meter that is used to check the power factor of the generation system.
9. AC Volts
This is an indication of the AC voltage, expressed in volts, which is being produced by the threephase generator.
10. AC Kilovars
This is a measurement of the reactive power being generated by the AC generation system.
11. Voltmeter Selector
This is used to check and verify the voltage on each phase of the generator.
Figure 3
AC Generator Control Panel
Objective Three
When you complete this objective you will be able to…
Explain the purpose and function of the circuit protective and switching equipment associated with
an AC generator: fuses, safety switches, circuit breakers, circuit protection relays, automatic bus
switchover, grounding and lightning arrestors.
Learning Material
INTRODUCTION
The protection of generators involves the consideration of more possible abnormal operating
conditions than the protection of any other system element. In unattended power stations,
automatic protection against all harmful abnormal conditions should be provided.
CIRCUIT PROTECTIVE AND SWITCHING EQUIPMENT
Fuses
A fuse is the simplest form of automatic over-current protection that has a circuit-opening fusible
link directly heated and destroyed by the passage of the overload current, through it. The link is so
sized that the heat created by the normal flow of current through it is not sufficient to fuse or melt
the metal.
Plug fuses are used on circuits rated 125 volts or less, to ground. The maximum continuous currentcarrying capacity of plug fuses is 30 A, and the commonly-used standard sizes are 10, 15, 20, 25
and 30 A. These fuses do not have published interrupting capacities since they are ordinarily used
on circuits that have relatively low values of available short-circuit current.
Cartridge fuses are used on circuits with voltage ratings up to 600 volts, the standard voltage
ratings of these fuses being 250 and 600 volts. The nonrenewable cartridge fuse is constructed with
a zinc or alloy fusible element enclosed in a cylindrical fiber tube. The ends of the fusible element
are attached to metallic contact pieces at the ends of the tube, which is filled with an insulating
porous powder. On overloads or short circuits, the fusible element is heated to a high temperature,
causing it to vaporize. The powder, in the fuse cartridge, cools and condenses the vapor and
quenches the arc, thereby, interrupting the flow of current.
Fig. 4 shows types of plug and cartridge fuses, of General Electric Company manufacture.
Figure 4
Types of Plug and Cartridge Fuses
Cartridge fuses, both in the 250 and 600V ratings, are made to fit standardized fuse-clip sizes.
These sizes are the 30, 60, 100, 200, 400, and 600 A sizes. Each fuse-clip size has several
continuous ratings of 70, 80, 90, and 100 A.
Time lag fuses are made in both the plug and cartridge types. These fuses are constructed so as to
have a much greater time lag than ordinary fuses, especially for overload currents. They do
operate, however, to clear short-circuit currents in about the same time, as do the standard fuses.
Time lag fuses have two parts, a thermal cutout part and a fuse link. The thermal cutout, with its
long time lag, operates on overload currents up to about 500 percent of normal current. Currents,
above this value, are interrupted by the fuse link. Time lag fuses find their greatest application in
motor circuits where it is desirable that the fuse provide protection for the circuit and yet, not
operate because of a momentary high current, during the starting period of the motor.
High-voltage fuses are used for the protection of circuits and equipment with voltage ratings, above
600V. Two of the commonly used fuses are shown in Fig. 5.
Figure 5
High Voltage Fuses
Fig. 5(a) shows an expulsion fuse, which consists of a fusible element mounted in a fuse tube and
depends upon the pressure built up in the fiber tube, when the metal melts to blow the gases out of
the open end. This takes with it the bottom section of the fuse link, and establishes a gap between
the two contacts. Fig. 5(b) shows a liquid-filled fuse in which the arc is quenched by the liquid. The
action is similar to that in an
oil-immersed switch. A spring is normally held in tension by a high resistance tension wire. This wire
is paralleled by the fuse wire that carries the current.
When high current melts the fuse wire, the tension wire immediately melts and releases the spring,
which then contracts and pulls the contacts apart.
Safety Switches
A switch is a device for isolating parts of an electric circuit or for changing connections in a circuit,
or system. When a switch is mounted in a metal enclosure and is operable by means of an external
handle, it is called a safety switch. The switch itself is not designed for interrupting the flow of short
circuit currents. However, switches and fuses are often incorporated into a single device called a
fusible safety switch, as shown in Fig. 6.
Safety switches are made in two-, three-, four-, or five-pole assemblies, either fused or unfused.
They are made in single-throw and double-throw units; and depending upon their use, they have a
variety of constructional features. One type, known as type A, has a quick-make, quick-break
mechanism so arranged that regardless of the speed at which the operating handle is moved, a
spring-loaded arrangement cause the contacts to open or close with a quick motion. This type of
switch also has a door interlock to prevent the opening of the enclosure door, when the switch is
closed.
Enclosed switches, either fusible or non-fusible, are used as disconnecting devices for main services
into buildings, for feeder and branch circuit protective and switching devices, and for motor
protection and switching.
Safety switches are available in two voltage ratings, 230 and 575 volts alternating current. Current
ratings are the same as for standard fuse-clip sizes.
Figure 6
Fusible Safety Switch
Circuit Breakers
A circuit breaker is an automatic device that opens under abnormally high current conditions. In
three phase systems, circuit breakers can open all three hot lines, when an overload occurs. They
are designed so that they will automatically open when a current occurs, which exceeds the rating
of the breaker. Most circuit breakers employ either a thermal or a magnetic tripping element.
They may also be activated by remote control relays. Relay systems may cause circuit breakers to
open due to changes in frequency, voltage or current. The internal construction of a circuit breaker
is shown in Fig. 7. In most cases, the circuit breakers must be reset manually.
Figure 7
Internal Construction Of A Circuit Breaker
Circuit Protection Relays
Loss Of Excitation (Loss of Field)
Modern alternators consist of a stator on which the alternating current (AC) voltage producing
windings are installed. It also contains a rotating armature, or rotor, on which a direct current (DC)
excitation winding is placed. When a synchronous generator loses excitation, the rotor accelerates
and it operates as an induction generator, running above synchronous speed.
As a result, the machine draws inductive reactive power from the system instead of supplying it to
the system. Heavy currents are induced in the rotor teeth and wedges and can cause thermal
damage to the machine if it continues to operate. Round rotor generators are not suited to such
operation because they do not have windings that can carry the induced rotor currents.
This device detects the loss of excitation on the generator. It includes two mho characteristics,
looking into the generator, each with adjustable reach, offset and time delay. Mho is the unit of
measurement of electrical conductance.
Over Excitation
When the ratio of the voltage to frequency (volts/Hz) exceeds a set value for a given generator,
severe overheating could occur due to saturation of the magnetic core of the generator and the
subsequent inducement of stray flux in components not designed to carry flux.
Such over-excitation most often occurs during start-up or shutdown while the unit is operating at
reduced frequency, or during a complete load rejection, which leaves transmission lines connected
to the generating station. Failure in the excitation system can also cause over excitation.
A volts/Hz relay, with an inverse time characteristic that matches the capabilities of the protected
equipment and with definite time setpoints, is used to protect the generator from over excitation.
Loss-Of-Synchronism Protection
When two areas of power systems, or two interconnecting systems, lose synchronism, there will be
large variations in voltages and currents throughout the systems. The voltages will be maximum
and the currents minimum, when the systems are in phase. The voltages will be minimum and the
currents maximum, when the systems are 180 degrees, out of phase.
The resulting high peak currents and off frequency operation may cause winding stresses, pulsating
torques and mechanical resonances that are potentially damaging to the turbine-generator.
Therefore, to minimize the possibility of damage, the unit should be tripped without delay.
Negative Phase Sequence or Unbalanced Currents
Unbalanced faults and other system conditions can cause unbalanced three phase currents in the
generator. The negative sequence components of these currents cause double frequency currents in
the rotor that can lead to overheating and damage.
The negative sequence overcurrent function relay, shown in Fig. 8, is provided to protect the unit
before the specified limit for the machine is reached.
Figure 8
Negative Sequence Relay
Over Voltage
Generator over voltage may occur during a load rejection or excitation control failure. In the case of
hydroelectric or gas turbine driven generators, upon load rejection, the generator may speed up and
the voltage can reach high levels without necessarily exceeding the generator’s V/Hz limit.
The voltage regulating equipment often provides this protection. If it is not, it should be provided by
an AC overvoltage relay. This relay should have a time delay unit with pickup at about 110% of the
rated voltage. It should also have an instantaneous unit with pickup at about 130% to 150% of the
rated voltage. It is not generally required with steam turbine driven generators.
Under Voltage
An under voltage condition is a decrease in the rms AC voltage, to less than 90% at the power
frequency for a duration, longer than 1 minute. The term "brownout" is often used to describe
sustained periods of under voltage initiated by the utility to reduce power demand. Under voltages
result from events which are the reverse of those causing over voltages.
A large load, switching on, or a capacitor bank, switching off, can cause under voltage until the
voltage regulation equipment can bring the voltage back to within tolerances. Overloaded circuits
can also cause under voltages.
Reversal of Power
For generators operating with another generator, it is imperative that the power direction be
supervised. If the prime mover fails, the alternator operates as a motor and drives the prime
mover. A relay detects the reversal of power direction and switches off the alternator. Power losses
and damage to the prime mover are avoided.
Dead Generator Energization Protection
If a dead generator is accidentally energized, while on turning gear, it will start and behave as an
induction motor. During the time when the generator is accelerating, very high currents are induced
in the rotor and it may be damaged very quickly.
Protection is usually provided by three, directional inverse time overcurrent relays, one in each
phase connected to operate for reverse power flow into the generator.
Over Frequency
Faults in the system can result in a system breakup into islands, which leaves an imbalance
between available generation and the load. This results in an excess of power for the connected
loads. Excess power results in an over frequency condition with a possible overvoltage from reduced
load demands.
Full or partial load rejection can lead to overspeed of the generator, therefore, over frequency
operation. In general, over frequency operation does not pose any serious overheating problem
unless the rated power and about 105% voltage are exceeded. Control action can be taken to
reduce the generator speed and frequency to normal, without tripping the generator.
Under Frequency
When insufficient power is being generated for the connected load, under frequency results with a
heavy load demand. The drop in voltage causes the voltage regulator to increase the excitation,
which results in overheating in both the stator and rotor. At the same time, more power is being
demanded with the generator less able to supply it at the reduced frequency.
Prolonged operation of a generator, at reduced frequencies, can cause particular problems for gas
or steam turbine generators, which are susceptible to damage from operations outside of their
normal frequency band. The turbine is more restrictive than the generator, at reduced frequencies,
because of possible mechanical resonance in many stages of the turbine. If the generator speed is
close to the natural frequency of any of the blades, there will be an increase in vibration, which can
lead to cracking of the blade structure.
While load shedding is the primary protection against generator overloading, under frequency relays
should be provided to provide additional protection.
Stator Ground Fault
Although a single field-ground fault will not affect the operation of a generator or produce any
immediate damaging effects, the first ground fault establishes a ground reference, thereby making
a second ground fault more likely. This will increase the stress to ground at other points in the field.
A second ground fault will cause extensive damage by:
•
•
•
•
Shorting out parts of the field winding
Causing high unit vibrations
Causing rotor heating from unbalanced currents
Arc damage at the points of the fault
A field ground relay is installed, which must reliably detect the first ground fault. This will allow
action can be taken, either through the tripping of the unit or an operator alarm. This is to avoid
continued field winding insulation deterioration that would cause a second ground fault and major
damage.
Ground Fault Protection
One of the main causes of ground fault is insulation failure. The zero sequence impedance of a
generator is usually lower than the positive or negative sequence impedance, therefore, for a solidly
grounded generator, the single phase to ground fault current is greater than the three-phase fault
current. Generators are usually grounded through an impedance, to limit the ground fault current.
The fault current available for sensing a phase to ground fault, on an impedance grounded
generator, can be very small compared to phase-to-phase faults. Depending on the location of the
fault and the method of grounding the generator, separate ground fault protection is usually
provided.
Stator Overheating Protection
This problem is caused by overloading or by failure of the cooling system. Overheating because of
short-circuited laminations is very localized and it is just a matter of chance whether it can be
detected before serious damage is done.
The practice is to embed resistance temperature-detector coils (RTDs), or thermocouples in the
slots with the stator windings of generators larger than 500 to 1000 kVA. Fig. 9 shows the bridge
circuits employed with RTDs. Enough of these detectors are located at different places in the
windings so that an indication can be obtained of the temperature conditions throughout the stator.
Several of the detectors that give the highest temperature indication are selected for use with a
temperature indicator or recorder, usually having alarm contacts. The detector giving the highest
indication may be arranged to operate a temperature relay to sound a alarm.
Figure 9
RTD Bridge Circuits
Overspeed
Overspeed protection is recommended for all prime mover driven generators. The overspeed
element should be responsive to machine speed by mechanical, or equivalent electrical connection.
If it is electrical, the overspeed element should not be adversely affected by generator voltage.
The overspeed element may be furnished as part of the prime mover, or its speed governor, or of
the generator. It should operate the speed governor, or whatever other shutdown means is
provided to shutdown the prime mover. It should also trip the generator circuit breaker. This is to
prevent over frequency operation of the generator itself from the AC system.
The overspeed element should be adjusted to operate about 3% to 5% above the full load rejection
speed.
Phase Fault Protection
Phase faults, in a generator stator winding, can cause thermal damage to insulation, windings, and
the core, and mechanical shock to shafts and couplings. Trapped flux within the machine can cause
fault current to flow for many seconds after the generator is tripped and the field is disconnected.
Primary protection, for generator phase-phase faults, is best provided by a differential relay.
Differential relays will detect phase-phase faults, three phase faults, and double phase-to-ground
faults. With low-impedance grounding of the generator, some single phase to ground faults can also
be detected.
Automatic Bus Switchover
A type of an automatic bus switchover unit, shown in Fig. 10, operates in the following manner.
Normal Utility Power Mode
Under normal circumstances, when utility power is available, the utility power runs through the
transfer switch control contactors, the power is connected to the distribution panel and then to the
electrical loads. A battery charger installed, in the transfer switch control, is powered by the utility
to keep the starting battery, in the generator set, charged.
Power Outage Occurs
When the utility power voltage fails to less than 85% of its normal value, or it fails entirely, the
standby power system will automatically go through a start sequence. The transfer switch control
circuitry constantly monitors the power quality from both the utility source and the generator set.
When the transfer switch control circuitry senses the unacceptable utility power, the control waits
for 3 seconds and then sends a signal to start the generator set engine. If the utility power returns
before the 3 seconds has passed, the generator set will not be signaled to start.
When the start signal is received and providing the manual/auto switch is set to auto, the engine
starts, reaches the proper operating speed and AC power is available, at the generator set. The
transfer switch control circuitry senses this, waits for the 3 seconds and will then transfer the
generator set power to the transfer switch contactors. The sequence of operation usually occurs in
less than 10 seconds from the time the power outage occurred to the time when generator set
power is connected.
The transfer switch includes a manually operated handle. If the transfer circuitry does not cause the
automatic transfer to generated power, the manual/auto switch can be moved to the manual
position and the handle then used to transfer from utility power to emergency power, or visa-versa.
Utility Power Returns
When the utility power comes back on, the transfer switch control circuitry senses this and will
watch for acceptable voltage levels, for a period of 5 minutes. After this
5-minute period and the voltage levels have been stable, the control will signal the transfer switch
contactors to re-transfer the load back to utility power source and then disconnect the generator set
source. At this point, the generator set is “off-line” and will be operated automatically another 5
minutes, to allow it to properly cool down. After this cool down cycle, the generator set will be
automatically shutdown and reset to standby mode.
Figure 10
Automatic Transfer Switch
Grounding System
A ground is defined as a reference point of zero voltage potential, which is usually an actual
connection to the ground of the earth. The need for grounding is very important in that an open
ground condition could present severe safety problems to anyone operating the power generation
equipment. Grounding assures that any person who touches any of the metal parts will not receive
a high voltage electrical shock. The conductor, which is used for this purpose, is either a bare wire
or a green insulated wire.
Lightning Arrestors
Lightning arrestors are used to cause the conduction to ground of excessively high voltages that are
caused by lightning strikes or other system problems. Power lines and associated equipment could
become inoperable when struck by lightning. They are designed to operate rapidly and repeatedly, if
necessary. Lightning arrestors are connected to transformers or the insides of switchgear. The
lightning arrestor, shown in Fig. 11, is used to provide a path to ground for lightning strikes, or hits.
Figure 11
Lightning Arrestor
Objective Four
When you complete this objective you will be able to…
Explain the components and operation of a typical Uninterruptible Power Supply (UPS) system.
Learning Material
UNINTERRUPTIBLE POWER SUPPLY (UPS) SYSTEM
An uninterruptible power supply is required for plant systems that cannot tolerate a momentary loss
of voltage and/or frequency. The purpose of this type of system, shown in Fig. 12, is to provide a
bumpless supply of electrical energy to critical plant control and shutdown circuitry. The term
“bumpless” means that when the normal supply of utility power is interrupted, power is always
maintained to the users by backup sources, such as batteries and generators. These would include
plant computers, control systems, plant lighting and compressor trip solenoid valves.
UPS SYSTEM COMPONENTS
Rectifier
This unit converts 600V, 3 phase AC power to 220V DC, which provides power to charge the
batteries and also supply the inverter.
Battery Bank
These are used to store electrical energy and supply the inverter in the event of a loss of AC power.
Inverter
It converts the 220V DC power from the inverter to 120V, single phase AC, for critical plant AC
power users to maintain a supply of stable voltage and frequency output power.
Static Switch
120V, single-phase AC power from the inverter, is fed through the static switch to the 120V critical
users. If the inverter should fail, for whatever reason, the control system will automatically open the
switch located upstream of the rectifier and close the switch on the alternate 600V feed. This 600V
power will then be reduced to 120V, single-phase AC, through the use of a step-down transformer.
The static switch will also switch over to this alternate supply source. This all occurs within one two
hundred and fortieth of a second (1/4 cycle).
UPS SYSTEM OPERATION
Utility power, at 600 volts AC, is supplied to the rectifier/charger section from the MCC (Motor
Control Centre). The rectifier/charger converts the 600 volts AC to 125 volts DC. This 125 volts DC
is used to supply power to critical control circuitry and also to maintain the battery banks, in a fully
charged condition. This 125 volts DC power output from the rectifier/charger also goes to the
inverter where it is converted back to alternating current. This 120-volt AC single-phase power
passes through the bypass switch to supply the various AC power users.
If there is a loss of utility power, the DC and AC users will then be supplied, with power, from the
battery banks. This will be until the automatic transfer switch starts the emergency generator and
the generator will then supply the power to the UPS system.
If the inverter should fail, the bypass power will automatically be selected to supply the AC UPS
users. The bypass switch is a “make-before-break” type of switch to provide a bumpless transfer of
power. An alarm will annunciate to alert the operator of a “UPS Trouble”. If there is a loss of utility
power while the inverter is on bypass, circuitry, in the automatic transfer switch, will not allow it to
transfer back to normal or utility power, when it becomes available.
This interlock ensures a bumpless transfer of power to the AC UPS users by employing a time
delayed restoration of normal power 60 seconds after the inverter has been placed back in service.
Whenever the inverter is on bypass and there is a temporary loss of normal or utility power to the
UPS system from the MCC, then the 120-volt AC circuits will be lost until power has been restored
to the MCC, either from the utility or the generator starts.
Figure 12
UPS System
UPS System Battery Design
The duration of time for which the batteries can perform their function will depend on their amperehour rating and the current drawn by the various DC circuits and the inverter. If the power draw is
normal and providing that the batteries are in good condition and fully charged, they should provide
adequate power for approximately 4 hours.
The batteries, for this application, use the same design as all lead-acid batteries. The sulphuric acid
electrolyte has been immobilized in a micro-porous absorbent medium leaving no free liquid acid in
the battery cases. The individual cases are sealed with rupture protection provided by a relief valve,
which opens at 41.3 kPa and resets between 15-20 kPa. Under normal operation conditions, the
batteries should not leak or vent hydrogen and acid mist, during recharging.
UPS BATTERIES MAINTENANCE
Testing
Testing the batteries should be done anywhere from one to four times each year. Recording of the
voltages, at the time of each inspection, should be performed. The completion of a load test should
be done four times per year.
Visual Inspection
A visual inspection should be completed, during each scheduled maintenance. This visual inspection
should include the possibility of any sign of cracks, leaks, swelling and corrosion of the battery
cases, taking place. Another important part of the visual inspection is to make sure that there is
sufficient space between each battery. This air gap will allow heat to escape.
Torquing The Connections
All connections must be torqued, each year, to maintain a tight connection. It is important to follow
the manufacturer’s specified torque values. If the connection is too loose, it could overheat during a
discharge and cause problems. If it is too tight, the post or terminal could be distorted.
Cleaning
The exterior of the batteries should be cleaned with a damp cloth. You may need to use a damp
cloth with a mixture of a neutralizer to remove any acid film. Corrosion should be brushed away
with either a stainless steel brush or a brass brush.
Record Keeping
The installation date of each battery should be recorded. A clear and accurate log of all the findings
from each maintenance period should be maintained
Objective Five
When you complete this objective you will be able to…
Explain safety procedures and precautions that must be exercised when working around and
operating electrical system components.
Learning Material
SAFETY PROCEDURES
Safe working habits are largely a matter of common sense. Power plant operators should be aware
of the possible danger to themselves, and others, when operating electrical equipment. Quite often,
an operator must report any electrical malfunction and take equipment out of service for
maintenance by qualified personnel. When a power plant engineer is involved in plant design, safety
of equipment and personnel is of vital importance. Attention should be placed on the following:
Electrical Installations
All motors, generators and equipment should be installed in such a way that no live parts are
exposed. Sufficient space must be allowed around equipment for inspection and repair to be carried
out safely. Guards must adequately cover all rotating parts. Identify all feeders and circuits as to
their purpose so that correct circuit breakers and switch gear can be observed easily at a breaker
panel.
Personal Clothing And Habits
Comfortable but close fitting clothing should be worn. Wearing of insulated safety shoes is
recommended when working on electrical equipment. Avoid wearing any loose articles such as
rings, and chains that may come in contact with live equipment.
Working On Live Equipment
Consider all circuits to be alive unless one is certain that they are dead and cannot, by some human
error, be made live. Place tags that show equipment is out of service for maintenance when opening
an electrical circuit. The tag should bear the name of the person who put it there and should only be
removed by this person and the switch reclosed by that person. An operator should isolate all
equipment, such as pumps, before maintenance is started. All switches must be locked open, at the
source of the power.
Test the equipment, after isolation, by attempting to start it at the start/stops station. The circuit
may be open but charged capacitors can injure a person. Always open switches completely before
removing fuses. If it is necessary to change a fuse in a live circuit, use approved fuse pullers that
can withstand the line voltage. When removing fuses of live circuits, break contact with the line side
first. Make contact with the line side first when inserting a new fuse. Switches should be opened in a
firm, positive manner to prevent arcing. All portable electrical tools should be properly grounded.
Fire Hazards
Due to the conductive nature of water, it should never be used on an electrically generated fire.
Likewise, if electrical equipment is in the area of a fire, and water is the appropriate fighting
medium, isolate the equipment, before attempting an approach.
Electrical Calculations
Learning Outcome
When you complete this learning material, you will be able to:
Define terms and perform simple calculations involving DC and AC power circuits.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
5.
6.
7.
8.
Use Ohm’s Law and Kirchhoff’s Laws to calculate current, resistance or voltage drop in
series or parallel multi-resistor circuits.
Calculate unknown resistances using a Wheatstone Bridge circuit.
Explain and perform calculations involving electrical power, work and energy.
Calculate the frequency, period and phase angle for an ac sine wave.
Define terms and calculate the peak-to-peak, root mean square, and maximum values for
ac voltage and current.
Given required parameters, calculate the inductive reactance, capacitive reactance, total
reactance, and impedance for an ac circuit, plus circuit frequency and current flow.
Calculate real power, imaginary power and power factor for an ac circuit.
Given the load, voltage and power factor of a 3-phase generator, calculate the kVA and kW
ratings of the generator.
Objective One
When you complete this objective you will be able to…
Use Ohm’s Law and Kirchhoff’s Laws to calculate current, resistance or voltage drop in series or
parallel multi-resistor circuits.
Learning Material
UNITS USED FOR CALCULATIONS
The potential difference (p.d.) is the difference in electric charge between two points. P.d. is
measured in volts. A device that has the ability to maintain a potential difference in charge between
two points is said to develop an electromotive force (emf).
A potential difference causes a current to flow and an emf maintains a potential difference. Both are
measured in volts. As both are measured in volts, a common term, voltage, is used to indicate a
measure of either.
Although potential difference, emf, and Voltage do not mean exactly the same thing, they are often
used interchangeably. In calculations, E or V are used for voltage, emf, and potential difference.
Simple Direct Current Circuits
At its simplest, an electric circuit has a source of electromotive force, a wire or conductor connecting
the source to a load or resistance, and a second wire connecting the load to the source again. (See
Fig. 1).
Fig. 1 shows an electric circuit where I is the current in amperes (A), E is the electromotive force in
volts (V), and R is the resistance in ohms (Ω).
Figure 1
Simple Direct Current Circuit
OHM’S LAW
Ohm’s Law states the relationship between current, potential difference (change in voltage), and
resistance as found by experiment. It states that current is directly proportional to electromotive
force and inversely proportional to resistance. It can be written as:
KIRCHHOFF’S LAWS
More complicated electric circuits may be solved with the aid of two simple rules, Kirchhoff’s laws.
First Law – Kirchhoff’s Current Law
The algebraic sums of the currents at any electrical junction (node) must equal zero. The law can
also be stated as the sum of currents flowing away from any point in an electric circuit must equal
the sum of currents flowing toward the point. Fig. 2 is an example of current flowing into and away
from a junction. In this case the equation would be:
I1 + I4 = I2 + I3 + I5
Figure 2
Current Flow Away From a Point
Second Law – Kirchhoff’s Voltage Law
Around any closed path in an electric circuit the algebraic sum of all potential differences (voltages)
is zero. To apply Kirchhoff’s Second Law follow these steps:
•
Specify the direction of the different emf sources, and voltage drops.
Note: We will consider the direction of potential difference (change of voltage) positive if it is in
clockwise direction. The direction of the voltage drop across a resistance is the same as the
direction of conventional current flow through the resistance, Fig. 4.
•
Mark the direction of current in every branch (connection between two current joints), or
junctions as shown in Fig. 3.
Figure 3
Change of Voltages
Figure 4
Current Flow
Example 1:
Write Kirchhoff’s laws for all the current junctions and closed paths in Fig. 5.
Figure 5
Solution:
Show the possible current paths and indicate the direction of all changes in potential.
Current Law for junction A: I1 = I2 + I3
Current Law for junction B: I1 = I2 + I3
Figure 6
Path 1:
V1 + V2 + (-E1) = 0
I1R1 + I2 R2 + (- E1) = 0 (Ans.)
Path 2:
-E2+ V3 + (-V2) = 0
(-E2) + I3R3 + (-I2 R2) = 0 (Ans.)
Path 3:
V1 + (-E2) + V3+ (-E1) = 0
I1R1 + (-E2) + I3R3 + (-E1) = 0(Ans.)
Series Circuits
With resistors connected in series, the same current flows through all the resistors. The total
resistance is equal to the sum of all the resistances in the series. The sum of the voltage drops
across the resistors in the series is equal to the total potential (voltage) drop in the circuit. The
supplied emf in volts is also equal to the total potential drop in the circuit.
Figure 7
Series Circuit
Applying this to Fig. 7 gives the total resistance in the circuit as:
Rt = R1 + R2 + R3
and the voltage drops (measured by the voltmeters) as:
Vt = V1 + V2 + V3
The subscript ‘t’ stands for total. The resistance of the wires from the generator and between the
resistors is assumed to be zero, or it could be included in R1, R2, or R3, or represented by a new
resistor, R4.
Applying Ohm’s Law to Fig. 7 gives the current in the circuit to be:
where:
E = Vt
R = Rt
therefore
The voltage drop across R1 equals V1 and:
V1 = IR1
The voltage drop across R2 equals V2 and:
V2= IR2
The voltage drop across R3 equals V3 and:
V3 = IR3
Finally the voltage drop, Vt, across all the resistors equals:
Vt = V1 + V2 + V3
Substituting IR1 for V1, IR2 for V2 and IR3 for V3, the equation is:
Vt = IR1 + IR2 + IR3
or
Vt = I(R1 + R2 + R3)
Example 2:
Fig. 8 shows a series circuit with three resistors. Using Ohm’s Law calculate:
(a) The total resistance in the circuit.
(b) The voltage drop across each resistor.
(c) The total voltage drop.
Figure 8
Series Circuit
Solution:
(a) The total resistance in the circuit equals Rt.
Rt = R1 + R2 + R3
=4Ω+6Ω+8Ω
= 18 Ω (Ans.)
(b) The voltage drop across R1 equals V1.
V1 = IR1
=2Ax4Ω
= 8 V (Ans.)
The voltage drop across R2 equals V2.
V2 = IR2
=2Ax6Ω
= 12 V (Ans.)
The voltage drop across R3 equals V3.
V3 = IR3
=2Ax8Ω
= 16 V (Ans.)
(c) The total voltage drop equals Vt.
Vt = V1 + V2 + V3
= 8 V + 12 V + 16 V
= 36 V (Ans.)
or
Vt = IRt
= 2 A x 18 Ω
= 36 V (Ans.)
Example 3:
Fig. 9 shows a series circuit with four resistors. Calculate:
(a) The total resistance, Rt, of the circuit.
(b) The current in the circuit.
(c) The voltage drop across each resistor.
Figure 9
Series Circuit
Solution:
(a) The total resistance equals Rt.
Rt = R1 + R2 + R3 + R4
= 5 Ω + 4 Ω + 10 Ω + 6 Ω
= 25 Ω (Ans.)
(b) The current in the circuit equals I.
I = E/Rt
= 50 V/25 Ω
= 2 A (Ans.)
(c) The voltage drop across R1 equals V1.
V1 = IR1
=2Ax5Ω
= 10 V (Ans.)
The voltage drop across R2 equals V2.
V2 = IR2
=2Ax4Ω
= 8 V (Ans.)
The voltage drop across R3 equals V3.
V3 = IR3
= 2 A x 10 Ω
= 20 V (Ans.)
The voltage drop across R4 equals V4.
V4 = IR4
=2Ax6Ω
= 12 V (Ans.)
Checking the total of all voltage drops, or the applied emf (E), will provide a quick check of your
answer:
E = V1 + V2 + V3 + V4
= 10 V + 8 V + 20 V + 12 V
= 50 V
Example 4:
The series circuit shown in Fig.10 consists of four known and one unknown resistance. The resistors
are supplied with a current of 5 A from a generator producing an applied emf of 110 V. Calculate:
(a) The total resistance in the circuit.
(b) The resistance of R5.
(c) The voltage drop across each resistor.
Figure 10
Series Circuit
Solution:
(a) The total resistance equals Rt.
Rt = E/I
= 110 V/5 A
= 22 Ω (Ans.)
(b) Find R5.
Rt = R1 + R2 + R3 + R4 + R5
R5 = Rt – R1 – R2 – R3 - R4
= 22 Ω - 3 Ω - 5 Ω - 2 Ω - 8 Ω
= 4 Ω (Ans.)
(c) The voltage drop across R1 equals V1.
V1 = IR1
=5Ax3Ω
= 15 V (Ans.)
and:
V2 = IR2
=5Ax5Ω
= 25 V (Ans.)
and:
V3 = IR3
=5Ax2Ω
= 10 V (Ans.)
and:
V4 = IR4
=5Ax8Ω
= 40 V (Ans.)
and:
V5 = IR5
=5Ax4Ω
= 20 V (Ans.)
Checking for Vt which equals the applied emf (E):
E = V1 + V2 + V3 + V4 +V5
= 15 V + 25 V + 10 V + 40 V + 20 V
= 110 V
Parallel Circuits
Fig. 11(a) shows a circuit with resistors in parallel. In a parallel circuit, the sum of the individual
currents through each loop or path is equal to the total current in the circuit. This is different from a
series circuit where the same current flows through all the resistors. In a parallel circuit the same
voltage is applied to all resistors. Fig. 11(b) shows another way to represent a parallel circuit that
may make the circuit easier to visualize.
Figure 11
Parallel Circuits
The total resistance of the circuit in Fig. 11 is:
Rt = E/It
The total current is:
It = I1 + I2 + I3
and the voltage is:
E = I1R1
or
E = I2R2
or
E = I3R3
When Ohm’s Law is applied to the individual resistors, the individual currents can be expressed as:
I1 = E/R1
I2 = E/R2
and:
I3 = E/R3
then:
It = (E/R1) + (E/R2) + (E/R3)
or:
It = E [(1/R1) + (1/R2) + (1/R3)]
since:
It = E/Rt
then:
E/Rt = V [(1/R1) + (1/R2) + (1/R3)]
and dividing both sides of the equation by V gives:
1/Rt = (1/R1) + (1/R2) + (1/R3)
The final equation shows that any number of resistors in parallel may be replaced with a single
resistor with a value equal to the reciprocal of the sum of the reciprocals of the individual units.
Rt is known as the total or equivalent resistance.
Example 5:
The parallel circuit shown in Fig. 12 has four resistors. If the circuit has an applied voltage of 100 V
find:
(a) The total or equivalent resistance.
(b) The total current of the circuit.
(c) The current through each resistor.
Figure 12
Parallel Circuit
Solution:
(a) The equivalent resistance equals Rt.
1/Rt = (1/R1) + (1/R2) + (1/R3) + (1/R4)
1/Rt = (1/5 Ω) + (1/8 Ω) + (1/6 Ω) + (1/16 Ω)
1/Rt = (0.200 Ω) + (0.125 Ω) + (0.167 Ω) + (0.062 Ω)
1/Rt = 0.554 Ω
Rt = 1 Ω/0.554
= 1.805 Ω (Ans.)
(b) The total current equals It.
It = E/Rt
= 100 V/1.805 Ω
= 55.40 A (Ans.)
(c) The current through R1 equals I1.
I1 = E/R1
= 100 V/5 Ω
= 20 A (Ans.)
The current through R2 equals I2.
I2 = E/R2
= 100 V/8 Ω
= 12.5 A (Ans.)
The current through R3 equals I3.
I3 = E/R3
= 100 V/6 Ω
= 16.67 A (Ans.)
The current through R4 equals I4.
I4 = E/R4
= 100 V/16 Ω
= 6.25 A (Ans.)
Check with: It = I1 + I2 + I3 + I4
It = 20 A + 12.5 A + 16.67 A + 6.25 A
= 55.42 A
(The slight difference between the calculated values is due to using fractions in one method and
decimals in the other method.)
Example 6:
The parallel circuit shown in Fig. 13 has a total current of 30 A. Find:
(a) The applied voltage.
(b) The current through each resistor.
Figure 13
Parallel Circuit
Solution:
(a) First calculate the total resistance for the circuit, Rt.
1/Rt = (1/R1) + (1/R2) + (1/R3)
= (1/10 Ω) + (1/12 Ω) + (1/15 Ω)
= (0.100/Ω) + (0.083/Ω) + (0.067/Ω)
= 0.250/Ω
Rt = 4 Ω (Ans.)
Since we now know the total or equivalent resistance, Rt, in the circuit, we can find the applied
voltage using:
E = IRt
= 30 A x 4 Ω
= 120 V (Ans.)
(b) The current through R1 is
I1 = E/R1
= 120 V/10 Ω
= 12 A (Ans.)
The current through R2 is
I2 = E/R2
= 120 V/12 Ω
= 10 A (Ans.)
The current through R3 is
I3 = E/R3
= 120 V/15 Ω
= 8 A (Ans.)
Check with:
It = I1 + I2 + I2
= 12 A + 10 A + 8 A
= 30 A
Example 7:
Calculate the resistance, R4, for the circuit shown in Fig. 14.
Figure 14
Parallel Circuit
Solution:
This and many problems can often be solved by different methods. Two different approaches are
used and shown in this example.
Method 1: From the information we can calculate the total resistance, Rt.
Rt = E/It
= 120 V/45 A
= 2.67 Ω
and:
1/Rt = (1/R1) + (1/R2) + (1/R3) + (1/R4)
1/2.67 Ω = (1/15 Ω) + (1/8 Ω) + (1/10 Ω) + (1/R4)
0.375/Ω = 0.067/Ω + 0.125/Ω + 0.100/Ω + 1/R4
Rearranging this equation to solve for R4:
1/R4 = (0.375 - 0.067 - 0.125 - 0.100)/Ω
1/R4 = 0.083/Ω
R4 = 1 Ω/0.083
= 12.05 Ω (Ans.)
Note: If this answer were calculated using fractions and common denominators it would be equal to
exactly 12. Either answer is acceptable.
Method 2: From the known resistors, R1, R2 and R3 and It, find I4.
I4 = It – I1 – I2 – I3
and:
I1 = E/R1
= 120 V/15 Ω
=8A
I2 = E/R2
= 120 V/8Ω
= 15 A
I3 = E/R3
= 120 V/10 Ω
= 12 A
I4 = It – I1 – I2 – I4
I4 = 45 A - 8 A - 15 A - 12 A
= 10 A
Using this value for I4 calculate R4
R4 = E/I4
= 120 V/10 A
= 12 Ω (Ans.)
Self Test Problems
1. A series circuit consists of three known and one
unknown resistance. The resistors are R1 = 6 Ω, R2
= 10 Ω, and R3 = 15 Ω. R4 is unknown. The
resistors are supplied with a current of 5 A from a
generator producing an emf of 220 V. Calculate:
(a) The total resistance in the circuit
(b) The unknown resistance R4
(c) The voltage drop across each resistor
(a) (Ans. 44 Ω)
(b) (Ans. 13 Ω)
(c) (Ans. Vt= 30 V, V2 = 50 V, V3 = 75 V, V4 = 65 V)
2. A parallel circuit has a total flow of 50 A. It has 3
resistors: R1 = 10 Ω, R2 =15 Ω, and R3 = 20 Ω. Calculate
(a) The applied emf
(b) The current through each resistor
(a) Ans. 230.75 V)
(b) (Ans. I1 = 23.075 A, I2 = 15.383 A, I3 = 11.5 A)
Objective Two
When you complete this objective you will be able to…
Calculate unknown resistances using a Wheatstone Bridge circuit.
Learning Material
WHEATSTONE BRIDGE CIRCUIT
The Wheatstone Bridge circuit shown in Fig. 15 and modifications of it are frequently used to
measure resistance accurately as it can be very precise. Ohm's Law will be used first to introduce
the principle of the circuit.
Figure 15
The Wheatstone Bridge Circuit
Suppose that resistors Rl and R2 of 10 and 14 Ω respectively are connected in series to form one
branch ABC of a parallel circuit whose power supply E is 120 V. Using Ohm's Law the current flow
through this branch is:
Then the voltage drop across AB = I1 R1 = 5 x 10 = 50 V
and the voltage drop across BC = I1 R2 = 5 x 14 = 70 V
Also, suppose that resistors R4 and the variable resistor R3 are fixed at 16 and 24 ohms respectively
in the other branch, ADC, of the parallel circuit where current flow I2 is passing
The voltage drop across AD = I2 R4 = 3 x 16 = 48 V
A voltage drop of 50 V exists across AB while a voltage drop of 48 V exists across AD so the
galvanometer, acting as a voltmeter, would show a voltage drop of 2 V across BD. If the variable
resistance R3 is reduced to 22.4 Ω then:
and the voltage drop across AD would be:
I2 R4 = 3.125 x 16 = 50 V
Points B and D would be at the same voltage potential and the galvanometer would indicate zero. If
the resistances of R1 and R4 are fixed and known accurately, and the maximum value of R3 is also
known, it is possible to determine the value of an unknown resistance R2 by adjusting the variable
resistance until the potential difference across the galvanometer is zero. To balance the bridge,
switches S1, and S2 are closed simultaneously. These switches are spring loaded to stay in the open
position when released.
If the galvanometer reads zero, the Wheatstone Bridge is in a balanced position and the unknown
resistance R2 can be calculated as follows:
I1R1 = I2R4 (1) (Potential difference across AB is equal to that across AD)
and
I1R2 = I2R3 (2)
dividing (1) by (2)
Note: Pay attention to the relative position of each of the resistors, as the resistors may not always
be labeled as they are in this example.
This relationship can be used to solve for one unknown resistance, when the values of the remaining
three are known. The ohmmeter utilizes a Wheatstone Bridge arrangement to find unknown
resistances in electrical applications.
Example 8:
What value would R3 have to be, to balance the bridge shown in Fig. 17?
Figure 17
Wheatstone Bridge
Solution:
To balance the bridge, this relationship must exist:
R1/R3 = R2/R4
The value of R3 can be found by transposing the equation:
R3 = (R1 x R4)/R2
R3 = (800 Ω x 300 Ω)/500 Ω
= 480 Ω (Ans.)
The unknown resistor, R3, could be a temperature sensitive resistor (thermistor). The bridge is
initially balanced, to set the output voltage to zero, by adjusting a variable resistor (R4). A voltage
change could be registered on a scale converted to show temperature, giving an accurate
temperature-measuring instrument. A simplified circuit for this application is shown in Fig. 18.
Figure 18
A Wheatstone Bridge Adapted to Measure Temperature
Self Test Problem
3. A Wheatstone Bridge is laid out as in Fig. 17,
where the applied voltage
E = 24 V, R1 = 400 Ω, R2 = 500 Ω, and R4 =
200 Ω.
Calculate the value of R3 required to balance the
bridge.
Objective Three
When you complete this objective you will be able to…
Explain and perform calculations involving electrical power, work and energy.
Learning Material
ENERGY
Energy is the ability to do work. For example, a coiled spring has energy, since it can power a clock
for weeks. Water stored behind a dam has energy. When it is released it can be changed into
mechanical and then electrical energy by the turbines and generators. Energy is stored work.
Therefore energy is expended whenever work is done. Energy also exists in many forms such as
mechanical energy, chemical energy, electrical energy, and heat energy. It can be changed from
one form to another. For example, when coal is burned, chemical energy is changed to heat energy.
An electric generator changes mechanical energy into electrical energy. Energy can neither be
created nor destroyed. This is the principle of conservation of energy. When energy is supplied to an
electric motor, it is not destroyed. It is merely changed from one form into another; from electrical
energy into mechanical and heat energy.
Electrical Work and Energy
Work is energy transferred when a force moves through a distance. When a force of one newton
moves through a distance of one metre, it does one newton metre (N·m) of work. This unit of work
is called the joule. Power is the rate of energy transfer. The unit of power is the watt and 1 watt = 1
joule per second (l W = 1 J/s).
Electric power is also the rate of doing work. Consider the power equation P = IE, and recall that I
represents current in amperes. An ampere is the rate of current flow and is defined in terms of the
quantity of electrons moving past a given point per second. E represents electromotive force in
volts. So IE represents a force moving a certain number of electrons per second past a given point.
That is, IE is the rate at which the electromotive force does work. In other words, IE is power in
watts.
Figure 19
Simple Electrical Circuit
If the switch in the simple electric circuit as in Fig. 19 is closed, a current flows through the load
(electric motor, heater, lamp) and the electrical energy transmitted to the circuit from the source
will be changed to another form of energy (mechanical, thermal and so on). The work done in an
electric circuit is a product of current flow and voltage, and on the length of time the current flows
through the load (resistance).
To calculate the work done in a simple electrical circuit as shown in Fig. 19, the formula
W = EIt is used, where:
A watt second or joule is a relatively small unit of work.
1 W·h = 3600 Ws = 3600 J
1 kWh = 103 W·h = 3.6 x 106 J = 3.6 MJ
Since E = IR we can calculate work in the following ways:
Electrical Power
Power is the rate of energy transfer or of doing work. If work W is done in time t, power is:
For example, two different motors lift a load. One motor requires 40 seconds to lift it.
A second motor lifts the load in 10 seconds. The rate of doing work for the second
motor is higher; therefore the second motor has more power.
Larger power units are:
103 watts = 1 kilowatt (kW)
106 watts = 1 megawatt (MW)
Since, E = IR we can calculate power as follows:
Electric power absorbed by a resistor with resistance R and changed to heat is
The power rating of a resistor is given by the amount of power that can be dissipated by the resistor
without affecting its characteristics. The power rating is related to a specific temperature such as
20°C.
Example 9:
What is the power used by an electric lamp that draws 1 A from a 120 V line?
Solution:
P=EI
= 120V x 1 A
= 120 watts (Ans.)
Example 10:
What is the power used by a 30 Ω electric heater when a voltage of 240 V is applied?
Solution:
Example 11:
What amount of power is dissipated in a 180 Ω resistor if a 120 V is applied?
Solution:
Example 12:
A 25 Ω resistor has a power rating of 1 W. What is the maximum loading current of the resistor?
Solution:
Example 13:
An electric heater used 10 kWh in 8 h. If the voltage at the heater is 120 V, what is the resistance
of the heater?
Solution:
Example 14:
How much energy in joules, megajoules and kilowatt hours does a 100 watt lamp use in 12 hours?
Solution:
Self Test Problems
4. What amount of power is being dissipated in a
180 Ω resistor if an emf of 240 V is applied?
(Ans. 320 W)
5. A 50 Ω resistor has power rating of 2 W. What is
the maximum loading current of the resistor?
(Ans. 0.2 A)
6. An electric heater used 20 kWh in 8 h. If the
voltage at the heater is 240 V, calculate the
resistance of the heater.
(Ans. 23.0 Ω)
7. How much energy in kilowatt-hours is used by a
200 watt lamp in 12 hours?
(Ans. 2.4 kWh)
Objective Four
When you complete this objective you will be able to…
Calculate the frequency, period and phase angle for an ac sine wave.
Learning Material
ALTERNATING CURRENT
Almost all of the electrical power supplied at present is in the form of alternating current. It has two
major advantages over direct current. Firstly, it can be generated without the limits imposed by
commutators, and secondly, after generation its voltage can be very easily transformed up or down
for transmission and distribution.
Observing the generator principle shows that a conductor rotated through a magnetic field produces
an alternating emf having a sine wave form. Passage of the conductor across two poles produced
one cycle (on the sine wave diagram this means from zero through positive maximum, to zero, to
negative maximum and back to zero). Generation of a sine wave is shown graphically in Fig. 20.
The number of times that this occurs in one second determines the frequency in cycles per second,
or hertz, of the generator output.
|Figure 20
Generation of a Sine Wave
Phase Relationship
If an ac voltage is applied to a circuit it will produce an ac current flow. If the voltage and the
current reach their maximum values at the same time they are said to be “in phase.” This would be
the case in a circuit having only resistance. When the current reaches its maximum later than the
voltage it is said to be a lagging current. If the current reaches its maximum earlier than the
voltage it is said to be a leading current.
If we connect an ac source to the electric circuit, an ac current will flow. If the ac current and ac
voltage have values of zero at the same time, and have maximum values (in same direction) at the
same time (Fig. 21), the current is in phase with the voltage. In some types of circuits where the
current and voltage zero and maximum values do not occur at the same time, the current and
voltage are out of phase.
Figure 21
Figure 22
Figure 23
Current in Phase Leading Current Lagging Current
When the current maximum value occurs earlier than the voltage maximum, the current leads the
voltage (Fig. 22).
When the current maximum value occurs later than the voltage maximum, the current lags the
voltage (Fig. 23).
Generation of an Alternating Electromotive Force (emf)
When a coil is rotated by constant speed in a uniform magnetic field, an emf is generated in that
coil. This emf reverses its direction at time intervals corresponding to the coil rotation and is
continually changing its value. Such an emf is called alternating and the value of the emf at any
given time is called the instantaneous value. The plot of the instantaneous values of emf as a
function of time is shown in Fig. 24. The alternating emf changes not only the instantaneous values
but also reverses its direction.
Figure 24
Values of emf versus Time of One Cycle (or
Period)
The plotted curve is periodic and we call it the sine wave of an alternating emf. Two characteristic
values of the sine wave are the cycle and the frequency.
Cycle and Frequency
The sine wave is periodic, which means that a certain part of the wave is repeating itself in regular
time intervals or periods. A repeating portion of the sine wave defines one cycle (Fig. 24).
The time of one cycle is the period T measured in seconds. The number of complete cycles
in one second is the frequency f. The frequency is measured in numbers of cycles per second,
or hertz (Hz),where:
One hertz = one cycle per second
The common power frequency in America is 60 Hz, but in Europe and in most of Asia and Africa it is
50 Hz. The relationship between frequency and period is:
Example 16:
What is the period of a 60 Hz wave?
Solution:
Example 17:
What is the frequency of a wave, which has a period of 2 μ sec?
Solution:
Self Test Problems
8. What is the frequency of a wave, which has
a period of 4 μ sec?
(Ans. 0.25 MHz)
9. What is the period of a 50 Hz wave?
(Ans. 0.02 sec)
Objective Five
When you complete this objective you will be able to…
Define terms and calculate the peak-to-peak, root mean square, and maximum values for ac
voltage and current.
Learning Material
VALUES OF ALTERNATING CURRENT AND VOLTAGE
One value of the alternating current is the instantaneous value. The largest value of all
instantaneous values in a positive or negative direction is the amplitude or the maximum value of
the alternating current (Imax), as seen in Fig. 25.
The peak-to-peak amplitude is the magnitude measured from the lowest negative value to the
highest positive value. The peak-to-peak value (Ipp) is equal to two times the maximum value as
shown in Fig. 25.
Figure 25
Maximum Current Values
Figure 26 illustrates peak to peak as well as instantaneous values in a sine wave.
Figure 26
Alternating Current Values
The effect of dc current flowing through a resistance is the production of heat. The rate of heating
can be measured as I2R watts. Similarly the effect of ac current flowing through a resistance is the
production of heat dependent upon the square of the instantaneous current flow. The effective
current flow in an ac circuit is therefore taken as being the instantaneous values throughout one
cycle, squared, averaged and the square root taken of the average.
Figure 27
Rms Values
The name given to this value is the “root mean square” (rms), or effective value. The rms value is
always 0.707 of the maximum value for any sine wave. Both current flow and voltage in ac circuits
will always be quoted as rms (effective) values. Figure 27 illustrates the effective value (rms values)
of a sine wave.
Example 19:
What are the peak-to-peak and rms values of voltage with a maximum value 170 V?
Solution:
Example 20:
What are the peak-to-peak and the maximum values of an alternating current if the rms value is 12
A?
Solution:
Self Test Problems
10. What are the peak-to-peak and rms
values of voltage with a maximum
value of 311 V?
(Ans. 622 V peak-to-peak, and 220 V
rms)
11. What are the peak-to-peak and the
maximum alternating current values if
the rms current value is 20 A?
(Ans. Max. = 28.29 A, and peak-topeak = 56.58 A)
Objective Six
When you complete this objective you will be able to…
Given required parameters, calculate the inductive reactance, capacitive reactance, total reactance,
and impedance for an ac circuit.
Learning Material
INDUCTANCE AND INDUCTIVE REACTANCE
Inductance is a circuit property, just as resistance is. A circuit with inductive load is usually one
containing a coil or coils, very often around a magnetic core. Examples are motor, generator and
transformer windings. Inductance is an opposition to any change in the current flow.
Inductance affects the current flow only when the current is changing in value. In an ac circuit the
current is continuously changing in value. Therefore an alternating emf is also generated. The unit
of inductance is the henry (H) and the symbol is L. L = inductance in henry.
The opposition of the inductance to the flow of an ac current is called inductive reactance. The
symbol for inductive reactance is XL. The current flow through a circuit that contains only inductive
reactance is calculated:
Inductive reactance may be calculated from the formula:
An inductance in a pure inductive circuit (inductive load only) causes the current to lag the applied
voltage by 90° (Figs. 28 and 29).
Figure 28
Inductive Circuit
Figure 29
Current Lagging Voltage by 900
Example 21:
A coil with an inductance of 0.2 H is connected to a 120 V, 60 Hz supply. Find:
(a) the inductive reactance of the coil.
(b) the current flowing through the coil.
Solution:
Example 22:
A coil has an inductance 20 mH. The inductive reactance is 100 Ω. Find the line frequency.
Solution:
Capacitance and Capacitive Reactance
Any two conductors that are separated by an insulating material form a capacitor or condenser as in
Fig. 30. A current flows in a circuit containing a capacitor only if the applied voltage of that circuit is
changing.
Figure 30
Capacitor
Capacitive reactance of the capacitor is its opposition to the flow of an ac current. The symbol for
capacitive reactance is XC, and is measured in ohms. It may be calculated by formula:
The current flowing in a circuit containing only capacitive reactance is calculated by:
I = effective current in amps
E = effective voltage, in volts
XC = capacitive reactance, in ohms
Capacitance in a purely capacitive circuit causes the current to lead the applied voltage by 90°
(Figs. 31 and 32).
Figure 31
Capacitive Circuit
Figure 32
Leading Curren
Example 23:
What is the capacitive reactance of a 0.2 μF capacitor at 60 Hz and at 600 kHz?
Solution:
Example 24:
What current will flow when a 10 μF capacitor is connected to a 240 V, 60 Hz supply?
Solution:
Reactance
Inductive reactance causes the current to lag behind the applied voltage, while capacitive reactance
causes the current to lead the voltage. When inductive and capacitive reactance are connected in
series, their effects tend to neutralize each other and the combined effect is their difference:
Impedance
Impedance is the total opposition, or combined effect of the resistance, and the reactance of a
circuit against the flow of current. The symbol for impedance is Z. The unit is the ohm.
The impedance of a series circuit is:
Ohm’s Law for an ac circuit is:
Example 25:
A resistance of 50 Ω is connected in series with an inductive reactance of 70 Ω and a capacitive
reactance of 20 Ω. What is the impedance of the circuit?
Solution:
Example 26:
A coil with inductance 0.2 H is connected in series with a resistor of 60 Ω, to a 120 V, 60 Hz source.
What current will flow through the coil?
Solution:
Self Test Problems
12. A coil has an inductance 40 mH. The
inductive reactance is 200 Ω. Find the line
frequency.
(Ans. 796 Hz)
13. What current will flow when a 10 μF
capacitor is connected to a 120 V, 60 Hz power
supply?
(Ans. 0.452 A)
14. A resistance of 60 Ω is connected in series
with an inductive reactance of 50 Ω and a
capacitive reactance of 40 Ω. What is the
impedance of the circuit?
(Ans. 60.83 Ω)
Objective Seven
When you complete this objective you will be able to…
Calculate real power, imaginary power and power factor for an ac circuit.
Learning Material
POWER
Power in a dc circuit is equal to the product of the current and voltage. In ac systems the product of
the effective value of current and voltage is apparent power, expressed in voltamperes (VA). In ac
circuits true active power or real power is used only in resistive components. Reactive components,
such as inductors and capacitors use so?called reactive or imaginary power. Energy is taken from
the source for some part of a cycle, but it is returned during another part. The net power used
therefore, is zero.
If the electric network has an impedance (combination of resistors and reactances) total current and
applied voltage are usually not in phase. Current leads or lags voltage by some phase angle θ.
We can calculate active power (real power) as:
P = EI cos θ
and reactive power (imaginary power) as:
A = EI sin θ
And apparent power as:
S = EI
Where
S = apparent power in voltamperes
P = active or real power in watts
A = reactive or imaginary power in vars
I = effective value of current in amperes
E = effective value of voltage in volts
θ = phase angle between current and voltage
Power Factor
The power in an ac circuit is equal to the current I times the voltage E at that instant. This is only
really true when the current and voltage are in phase. When reactance is present, the voltage and
current are out of phase. In this case the value of power produced is less than E x I. The value of E
x I in a circuit is the apparent power (S) measured in voltamperes (VA) or kilovoltamperes (kVA).
The real power (in watts) is the apparent power (in voltamperes) multiplied by the power factor
(pf).
Relation between different powers is:
Figure 33
Power Phase Relationship
The relationship of the real power (EI cos θ), apparent power (EI), and reactive power (EI sin θ)is
shown in the phase diagram Fig. 33. The angle between the apparent and reactive power is θ, and
the power factor is cos θ. Note that θ is also the angle between the emf and the current.
The term cos θ is known as the power factor and has a value between one and zero (100% and
zero). Because of the large number of induction motors and other inductive devices the power
factor of many such systems is low (75%), resulting in line losses and substantial voltage drops. To
improve power factor a corrective capacitor can be used. Power factor can be expressed as a
percentage or as decimal value (75% or 0.75 for example).
Example 27:
A single-phase circuit has meter readings of 20 A, and 220 V. The power factor is 78.8%. Calculate:
(a) the real power of the circuit
(b) the imaginary power of the circuit
Solution:
Example 28:
The following meter readings were taken in an inductive single-phase circuit: wattmeter 2400 W;
voltmeter 240 V; ammeter 15 A, frequency meter, 60 Hz. Note that a wattmeter indicates the
active power and voltmeters and ammeters indicate effective (rms) values.
Find: (a) the apparent power (VA)
(b) the power factor of the circuit.
Solution:
Self Test Problems
15. The following meter readings were
taken in an inductive single?phase circuit:
wattmeter 2800W; voltmeter 120 V;
ammeter 25 A, frequency meter, 60 Hz.
Find:
(a) The apparent power
(b) The power factor
(a) (Ans. 3000 VA)
(b) (Ans. 0.933 pf or 93.3%)
Objective Eight
When you complete this objective you will be able to…
Given the load, voltage and power factor of a 3-phase generator, calculate the kVA and kW ratings
of the generator.
Learning Material
THREE-PHASE CIRCUITS
A balanced three-phase circuit can be looked upon as a combination of three single-phase circuits as
far as the relationships of current voltage and power are concerned. With this in mind, problems on
three-phase become a little simpler to solve.
In a single-phase circuit the flow of power is pulsating. Where the current and voltage are in phase
(unity pf) the power will be zero twice during each cycle.
A three-phase circuit will have the phase voltages and currents spaced by 120°, as in Fig. 34 below,
which shows three voltage sine waves. This will result in a smoothing out of the power flow.
Figure 34
Three Phase Power
Three-Phase Connections
There are two possible methods of connecting up three-phase generator windings. These are known
as the Star (or wye) and the Delta connections.
If the three windings are connected in star, then one end of each is joined at the star point, and the
other three ends are brought out to form the three line connections. The star point or neutral can be
brought out to an outside terminal also.
Diagrammatically, the winding arrangement is shown in Fig. 35 in which the windings are
represented as being spaced 120° in rotation. The voltage between any two lines of a wye
connection is 1.73 times the voltage of any single phase. For example, Phase 1 has a voltage of 100
V. The voltage between Line 1 and Line 2 is 100 V x 1.73 or 173 V.
Figure 35
Star Voltage and Current Relationship
(Courtesy Prentice Hall)
Fig. 36 shows an ac generator with its three-phase windings connected in delta. In the
diagrammatic representation of the windings, three connections are brought out to form the three
lines A, B, and C; no neutral point is available in this arrangement.
Figure 36
Delta Connection Voltage and Current Relationship
(Courtesy Prentice Hall)
The voltage between any two of the leads is called the line voltage. It is the same voltage as
generated in one winding, which is called the phase voltage. Fig. 36 illustrates that all phase
voltages and all line voltages are equal and they all have the same value. Each line and each phase
has a voltage value of 100 volts.
The current in any line is 1.73 time the current in any one phase of the winding. For example, the
phase currents in Fig. 36 are all 1 A. The line currents are 1.73 times the phase currents, or 1.73 x
1, or 1.73 A.
Summarizing these two sets of conditions we have:
Power in Three Phase Circuits
The power in a single-phase ac circuit is the product of the emf (E), times the current (I) and the pf.
It is written:
Single-phase power = EI cos θ
A three-phase circuit can be taken as a combination of three single-phase circuits so that:
Three-phase power = 3 x Single-phase power
= 3 x Ep x Ip x pf
where: Ep = phase volts and Ip = phase current
Or, Three-phase power = 3 x Ep x Ip cos θ
Put in terms of line voltage (EL) and line current flow (IL) this becomes:
For a star connection:
]
and for a delta connection:
Therefore whether the circuit be connected in star or in delta the equation remains the same, using
line values for voltage and current flow:
Where
P = real power in watts
E = effective value of voltage between phases in volts
I = effective value of current in one phase in amperes
S = apparent power in voltamperes
For three phase power, the power factor rating cos θ is:
cos θ = P/1.73 E I
and is equal to the cosine of the angle between the phase current and phase voltage.
Example 28:
A three phase generator has a terminal voltage of 480 V and delivers full load current of 300 A per
terminal at a lagging power factor of 75 percent. Calculate:
(a) The apparent power in kilovoltamperes
(b) The full load real power in kilowatts
Solution:
E = 480 V
I = 300 A
Cos θ = 0.75
(a)
S = 1.73 EI
= 1.73 x 480 V x 300 A
= 249.12 x 103 VA
= 249.12 kVA (Ans.)
(b)
P = 1.73 EI cos θ
= 249.12 kVA x 0.75
= 186.84 kW (Ans.)
Self Test Problems
16. A three phase generator has a terminal
voltage of 600 V and delivers full load
current of 200 A per terminal at a lagging
power factor of 80 percent. Find:
(a) The kilovoltampere rating
(b) The full load power in kilowatts
(a) (Ans. 207.6 kVA)
(b) (Ans. 166.08 kW)
Control Loops and Strategies
Learning Outcome
When you complete this learning material, you will be able to:
Explain the operation and components of pneumatic, electronic and digital control loops, and discuss
control modes and strategies.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
5.
6.
7.
8.
Describe the operation, components and terminologies for a typical control loop.
Describe the operation and components of a purely pneumatic control loop. Explain the
function of each component.
Describe the operation and components of an analog/electronic control loop. Explain the
function of each component.
Describe the operation and components of a digital control loop. Explain the function of
each component.
Explain the purpose, operation, and give examples of on-off, proportional, proportionalplus-reset, and proportional-plus-reset-plus-derivative control. Define proportional band
and gain.
Describe and give typical examples of feed forward, feed back, cascade, ratio, split-range,
and select control.
Explain, with examples, the purpose and incorporation of alarms and shutdowns into a
control loop/system.
Explain the interactions that occur and the interfaces that exist between an operator and
the various components of a control loop/system, including the components of a controller
interface.
Objective One
When you complete this objective you will be able to…
Describe the operation, components and terminologies for a typical control loop.
Learning Material
CONTROL LOOP
Consider the heat exchanger process in Fig. 1. Cold water needs to be heated. This is the process
that needs to be managed. The temperature of the heated water leaving the exchanger is monitored
by the temperature transmitter, which converts the temperature in °C to a pneumatic signal. This
signal (20 - 100 kPa) goes to a controller, which compares the signal to a setpoint (or desired
value). If there is a difference, or error, the controller sends a corrective signal to the control valve
to manipulate the steam flow (manipulated variable).
Figure 1
Heat Exchanger Process
If the valve is told to open, more steam enters the exchanger and the water temperature rises. If
the valve closes, less steam is allowed in and the water is heated less. The valve is also called the
final actuator and the water leaving the exchanger is called the controlled variable.
The controller itself can be either on-off or proportional. On-off control is simple and inexpensive.
When the water leaving the exchanger is too cool, the controller tells the steam valve to fully open.
Once the water temperature exceeds the setpoint, the valve is told to close completely. Proportional
control works the same way except that the valve is told by the controller to open (or close) in
“proportion” to the difference between the setpoint and the exit water temperature.
The type of controller selected for a process will depend on the dynamics of the control loop. It is
important to remember two intrinsic features of this control loop when, in later modules, more
complex controllers are discussed:
1.
Feedback control means measuring the controlled variable after a change has
occurred, then signaling an additional corrective change.
2.
The type of process and its speed of response to a change are critical in
determining the type of control strategy used.
Generally, temperature and level processes are relatively “slow” while pressure and flow processes
are “fast”. Chemical processes can be either. Fig. 1(b) shows a block diagram of the water/steam
process, using instrument symbols.
The control loop is made up of four basic functional blocks:
1. Process
2. Measurement
3. Automatic controller
4. The final control element
Another loop function, which could be included as an additional block in the diagram, is the
transmission media. The transmission media refers to the technology used for transmitting signals
from one loop device to another. Because the transmission media usually has little effect on the
control loop’s behavior, the media is usually not included in the block diagram. At times, however,
the media does have an effect on the loop’s behavior and it must be considered. For example, long
pneumatic signal lines can slow down the response of a high-speed loop, and information update
rates in digital systems can add time delay.
The Process
The purpose of the process is to make a product of some desired quality and/or quantity. The
process can be a very simple function such as liquid flowing in a pipe, a more complex device such
as a distillation column, or it can include an entire plant. For purposes of control theory, a process
can be defined as an action in which material and/or energy is modified to a different form.
In the majority of control loops, it is the process functional block that dictates the behavior of the
loop. For this reason, process control theory must include the study of the characteristics of the
processes.
The Measurement
The purpose of measurement is to measure the value of the process output variable (in the case of
the feedback loop), and to convey the value to the automatic controller. Measurement is not only
the interface between the process and the controller, but is also part of the interface between the
process and the human operator. Measurement is usually comprised of a transmitter, which is used
to transmit an analog or a digital signal whose value is indicative of the magnitude of the process’s
output variable. In most cases, measurement consists of a single transmitter, such as a pressure
transmitter. At times measurement can be more complicated requiring a gas chromatograph or
another type of chemical analyzer in addition to pressure, temperature or flow.
Sometimes measurement requires more than one device to measure a single variable. For example,
flow rate is often measured with a head-type flow element, such as an orifice plate, a differential
pressure transmitter, and a square root extractor. A square root extractor must be used to linearize
(change the signal to a straight line) the measurement signal with respect to flow and may be
contained within the transmitter itself, or it may be mounted remotely in the control room area.
Also, the square root function can be executed with software in either the automatic controller or a
“smart” transmitter. No matter where the square root function is implemented, it is convenient to
consider it to be part of the measurement functional block.
There are situations in which a process variable is controlled by a controller located in the process
area, without the need to transmit the value of the process variable to the control room for
indication. The controller in this case is said to be a local controller, and very often has the process
fluid connected directly to its internals.
Transmitters may not be necessary when low-level electronic signal generating devices such as a
thermocouple are used. Sometimes they can be connected directly to the controller, particularly
when the controller is based upon digital technology.
Recording Instrumentation
Process parameters such as temperature, pressure, and flow require continuous measurements in
real time. If review of the measurements is desired, provision must be made to capture the
parameters with respect to time. The recorder, shown in Fig. 2, is a device used to accomplish this
task and may take many forms, depending on the application.
The usual method is to inscribe the measurement of the parameter on a chart with respect to time.
These charts can be circular or linear, and may be driven by a timing mechanism. The process
parameter is recorded by a pen, which leaves a trace on the chart, thus producing a historical
record. The duration of the record is a function of chart speed (time base) and length of chart
paper.
Figure 2
Circular Chart Recorder
© The University of Texas at Austin, Whalen, Bruce. This material has been copied under licence
from CANCOPY. Resale or further copying of this material is strictly prohibited.
The Final Actuator
The final actuator is the device that regulates the supply of material and/or energy to affect the
desired value of the controlled variable. Most often, the final actuator is a control valve, but it need
not be. A conveyor belt, a louver, a motor’s variable speed drive, and a compressor’s inlet guide
vanes, are all examples of other types of final actuators.
Just like the measurement functional block, the final actuator block can also be made up of multiple
components. For example, a control valve may have the following four components associated with
it: a current-to-pneumatic transducer, a positioner, a valve actuator, and the valve itself.
The Automatic Controller
The primary function of the automatic controller is to continually compare the measurement signal
to the desired value or setpoint, of the controlled variable. When a difference exists between the
setpoint and the measurement signal, the controller takes corrective action by changing its output,
which in turn adjusts the final actuator. The final actuator changes the supply of material and/or
energy to the process, in order to bring the controlled variable closer to the setpoint.
Transmission Media
The transmission medium is required to transmit a signal from one location to another. Three
common types of transmission media used are:
Pneumatic
Compressed air is the most common pneumatic media. The signal pressure is usually 20 to 103 kPa.
For remote locations, such as on gas pipelines, the gas itself is used as the media.
Electronic
Electronic signals are used between centrally located controllers and plant or field mounted
instruments. The signal most often used is 4 to 20 milliamp.
Optical
Optical signals are sent down fiber-optic cables. The cables contain glass fibers along which light
(optic signals) can be transferred. The light signal is omitted from an LED (light emitting diode). The
light is received at the other end of the fiber-optic cable and returned to an electronic signal. The
major advantages of fiber-optic cables are:
•
•
•
They can carry large quantities of data over long distances
The cables are lightweight
The cables carry no electrical current eliminating grounding and interference problems
Objective Two
When you complete this objective you will be able to…
Describe the operation and components of a purely pneumatic control loop. Explain the function of
each component.
Learning Material
PNEUMATIC CONTROL LOOP
Pneumatic systems operate on clean, dry, regulated compressed air, but other gases such as
nitrogen or methane are used for certain applications. Pneumatic field instruments, employing the
flapper-nozzle amplifier, have evolved over the years to the point where they can do an amazing
number of tasks. Descriptions of some of pneumatic devices found in a pneumatic control loop
follow.
Transmitters
These convert a process physical quantity such as level, pressure, flow, or temperature into a
representative pneumatic analog signal, usually 20 - 100 kPa, which is then transmitted to a
centrally located control room.
Boosters
When a signal has to be transmitted more than 80 m, it often starts to exhibit excessive time lag
due to the increasing resistance and capacitance. A signal booster with its own 140kPa air supply is
connected at distances of every 80 - 100 m to strengthen the signal. Boosters are normally 1:1
(signal in = signal out), but 1:1.5, and 2:1 boosters are available.
Controllers
Many control loops in a process plant are single, local (mounted on the process), pneumatic control
loops. The main advantage is low cost installation and quick response. The main disadvantage is
that the operator has to go out to the controller to change the setpoint or switch to manual control.
An example of a local, field-mounted controller is a pressure control loop on a steam letdown
station. Another example is a pressure control loop on a natural gas line, where incidentally, the
natural gas also supplies the controller and the valve with instrument supply pressure. Other single
loop, local controllers control level, temperature, and flow.
A commonly used displacer-type level controller is shown in Fig. 3. The level indicator senses the
level in the tank. In this case the level is transmitted mechanically to the level transmitter. The
transmitter sends a pneumatic air signal directly to the final control element or control valve.
Figure 3
Displacer-Type Local Level Controller
Control Valves
Control valves are responsible for providing process changes by manipulating fluid flow in a pipeline.
They are called a “Final Control Element” (FCE), as they are the final devices that the controller
uses to affect corrective action to the process. Most control valves in process plants are
pneumatically actuated, like the example shown in Fig. 4.
Figure 4
Control Valve with Pneumatic Diaphragm Actuator
Pneumatic Switches
Pneumatic level switches are available for level, pressure,
temperature, and flow. The output of a switch will be either 20 kPa
or 100 kPa, (high or low) depending on whether or not it is in an
alarm state.
Chart Recorders
These are used mainly for recording flows in a plant for accounting
purposes. Operators must change charts at appropriate intervals.
These are mechanical devices that are associated with pneumatic
systems.
Pneumatic Signal Transmission
Pneumatic signal transmission most commonly uses the 20 - 100
kPa signal range, although 20-185 kPa is found on older systems,
particularly on boiler controls. Air pressure values below 20 kPa
this are considered out of range and indicate problems in the
system.
Objective Three
When you complete this objective you will be able to…
Describe the operation and components of an analog/electronic control loop. Explain the function of
each component.
Learning Material
ANALOG INSTRUMENTATION SYSTEMS
To place modern instrument technology in context, it is necessary to recall the early years of
electronics technology, when the transistor became commercially available. The term analog goes
back to the days when system designers used multiple-transistor electronic devices called analog
computers to represent physical quantities. These physical quantities are temperature, pressure,
flow, and level, with electrical quantities like voltage and current.
For example, liquid level in a vessel was “modeled” using an electrical analog. This was typically a
voltage signal of definite range (0 - 10 volts), imposed on a capacitor of a specific size. Five volts
represented a level of 50% in the capacitor model of the vessel. This method was used in the
laboratory during the 1950s and ’60s to model complex interactive control systems, in order to
assess their performance in a real process.
In modern times, the analog computer is rarely used, and has been replaced by sophisticated
programs running on powerful “digital computers”. The term analog, however, became synonymous
with early electronic instruments, to distinguish them from the emerging “digital” technology.
Amplifiers
The heart of analog computer technology was the operational amplifier, a precise electronic device
used to amplify and manipulate analog signals. The most significant advantage of these operational
amplifiers was their ability to be connected to external resistors and capacitors, in order to
accurately perform fundamental math operations, such as adding, subtracting, multiplying, and
dividing, as well as higher math operations, like integration and differentiation.
Analog Instrumentation Loop
Fig. 5 shows an analog instrumentation loop. It consists of a field sensor/transmitter, a connecting
input signal line, a signal converter, and a signal-processing device such as a controller, an output
signal line, and a final control element. Following is a brief description of each element in the analog
loop:
Figure 5
Analog Instrumentation Loop
Sensor/Transmitter
This is a device usually designed to work in a field environment, and is used to convert physical
quantities of flow, level, temperature, pressure, and weight into electrical signals that represent
those quantities as accurately as possible. Electrical signals can be voltage, such as 0 - 10 volts, but
the 4 - 20 milliamp signal is the accepted standard for transmitter analog signals originating in the
field.
Input Signal Line
The input signal to the controller, indicator, or recorder (or computer system) is actually the
transmitter 4 - 20 milliamp output signal. Current was chosen over voltage because of its superior
immunity to electrical noise.
The 4 milliamp bias was chosen as an aid to system problem analysis, since a zero milliamp signal
cannot be distinguished from an open or shorted circuit. This means that a 50% signal value will be
represented by a 12 milliamp signal.
The actual wire used for the signal line is number 16 or 18 AWG (American Wire Gauge), shielded
twisted pair with a drain wire, and may run for thousands of feet, passing through cable trays and
junction boxes.
Signal Converter
Some analog systems convert the 4 - 20 milliamp signal to 0 - 10 volts for internal processing. The
signal converter converts current to voltage, and also provides electrical isolation from field wiring.
Square root extractors are used to convert squared signals from differential flowmeters to linear
flow signals, and can be separate units installed in a rack. In new installations they are rarely found
as a stand-alone device, since the square root is commonly extracted in either the transmitter or
the controller.
Controller
The controller is the “brain” of the loop. This device is usually an electronic controller, but may be a
simple indicator/alarm, a recorder, or a flow totalizer. The controller uses an operational amplifier to
perform a mathematical summation, in order to compare the input signal (process variable) with a
setpoint that is established by operations personnel. If the process is not at the set value, the
mathematical functions present in the controller will produce an output signal that will correct the
process. Devices such as indicators do not have outputs and the “loop” stops there.
A typical controller station allows the operator to view and change the setpoint, view the process
value, view the controller output, and switch from automatic to manual control and back.
Electronic controller hardware, indicators, and displays have traditionally been placed in centrally
located, environmentally regulated control rooms, where the operator(s) can monitor all of the
processes in a large plant. All the incoming wiring terminates in cabinets that are located behind the
main control panel, in an adjoining electrical centre, or in a rack room.
The controllers are arranged in either of two ways:
1.
Panel mounted and completely self-contained, where the control unit, displays,
setpoint adjustment, and auto/manual station are all in one unit.
2.
In a split architecture arrangement, such as the where the actual control units,
signal conditioners, and converters are set in a separate rack (or nest), located in
cabinets behind the main control panel. The operator interfaces (control stations,
displays, and recorders) are mounted on the main panel.
Output Signal Line
The output signal is typically a 4 - 20 milliamp signal, and uses the same type of wire as the input
wiring. Thus, an instrument loop uses two twisted wire pairs of pretty much equal length. The wire
terminates at a final control element, which ultimately will alter the process value such as flow,
temperature, pressure, level, or speed.
Final Control Elements
The main devices used as final control elements are control valves, variable speed motor drives
(VSDs), speed governors, and damper positioners that range in size from a quite small (13 mm, or
one-half inch) valve, to a large blower system attached to a variable speed drive.
The 4 - 20 milliamp signal is rarely used to directly alter the condition of the process, and usually
requires a transducer to change the signal into a different and more useful form. An example of this
is a current-to-pressure transducer (called an I/P), which converts a 4 - 20 milliamp signal to a
more powerful 20 - 100 kPa (3 - 15 psig) pneumatic signal that is applied to a valve actuator. The
actuator converts the pneumatic signal to a large mechanical force, which in turn drives the valve to
any position between fully open and tightly shut.
Objective Four
When you complete this objective you will be able to…
Describe the operation and components of a digital control loop. Explain the function of each
component.
Learning Material
DIGITAL INSTRUMENTATION SYSTEMS
In the modern sense, the term “digital” describes computer systems that use the binary number
system of ones and zeros, or “bits”, to form a numerical representation of physical quantities such
as level, flow, and temperature. For example, the value that represents a liquid level in a vessel is
stored in computer memory as a binary number, in the form of a microscopic array of switches that
can be set at either five volts or zero volts.
These values that represent physical quantities in the real world are exact numbers, and not
analogs represented by a voltage signal level. The numbers are handled by computer programs in
exactly the same way as the rest of the data stored in its memory.
The major difference between the computer systems used in instrumentation and general purpose
computers, is the use of devices called digital-to-analog converters (DAC), and analog-to-digital
converters (ADC), which are necessary to interface to the field current loops. These devices were
once freestanding, but now are usually built-in devices, and are seldom a concern for the user.
Computers have become so small, powerful, reliable, and accurate that they have largely replaced
the analog electronics.
Digital Accuracy
The number of bits per second that a computer or peripheral device could handle was once a
measure of its ability to represent signal values accurately. For instance, early microcomputers were
“eight bit” machines, which introduced an error of about one-half of one percent to values gathered
from field sensors, and this was a concern. Modern machines use thirty-two bit or more technology,
as well as powerful number manipulation techniques to reduce signal-processing errors to a few
hundredths of one percent.
Controller Stations
Small control rooms use panel-mounted digital controllers that look very much like the old analog
controllers, but with more powerful options. Some small operations may even use a PLC and
console, or even an ordinary PC, with appropriate interface electronics. Large control rooms almost
invariably contain a number of video operator consoles attached to a large distributed control
system data highway.
It is not unusual to find individual digital controllers located in electrical centres scattered
throughout a plant site. These controllers can be connected via a built-in communications port, to a
laptop computer for configuration.
The Digital Instrumentation Loop
For all intents and purposes, the digital loop, as shown in Fig. 6, looks very much like an analog
loop, except that there are more options from which to choose. The signal wiring is exactly the
same as for the analog loops, and is often reused in upgrading from analog to digital systems.
However, there are certain characteristics and features of the digital systems that are not found on
the older analog systems. Following is a description of each element in the digital instrument loop:
Figure 6
Digital Instrument Loop
Sensor/Transmitter
The sensor/transmitter may be one of the older analog models, and will fit well into a digital
instrument loop, since most systems today still use the 4 - 20 milliamp signals. Many models are
available today that are digital; that is to say, they contain on-board microcomputer systems that
process information digitally, but provide the option of a standard 4 - 20 milliamp output through a
DAC. These are the so-called “smart” transmitters.
The name smart transmitter has emerged in the last decade to describe a new type of transmitter
that does more than just output a 4 - 20 milliamp signal. The name intelligent transmitter is
sometimes used interchangeably with smart transmitter, but it is more accurately used to describe
a transmitter that also has considerable controller capability, along with an independent computer
communications port.
Smart transmitters transmit process information in either a digital or the 4 - 20 milliamp analog
format. They can be re-zeroed and rearranged remotely, using a hand-held calibrator. They can also
be interrogated for information about themselves, such as flange material, o-ring material, or date
of last calibration. Current practice is to select these devices based on their high accuracy, but to
use them in standard 4 - 20 milliamp mode. However, future installations will likely use digital
communications almost exclusively.
The body of the smart transmitter is not appreciably different from those of standard transmitters,
and is connected to the process in the same way. The sensor and internal electronics have
undergone radical changes, even though the case may look like that of a standard transmitter. An
example of a smart transmitter is shown in Fig. 7.
Figure 7
Smart Transmitters
The smart transmitter is really a digital device, containing an on-board microprocessor complete
with memory. It has some very powerful features, such as remote calibration capability and storage
of configuration information. The output can be selected from a number of voltage or milliamp
ranges, as well as digital communications, although the most common selection is the 4 - 20
milliamp range. Fig. 8 illustrates the components of a smart transmitter.
Figure 8
Functional Diagram of a Smart Transmitter
Input Signal Line
The wiring and cable schedules used for input signals to controllers and other signal-processing
devices look much the same as those described for the standard analog systems. The difference is
that the wires are expected to carry digital information as well as the analog signal. Most
manufacturers superimpose the digital signal on top of the analog signal, and do not interfere with
it. However, some manufacturers interrupt the analog signal to send digital communications. Future
input-signal lines will most likely consist of fiber optic cables, strung together in a network.
Signal Information Processor (Controller)
Small control systems may use one or more controllers in what is called a “stand-alone mode”.
Stand-alone simply means that the system is completely self-contained, and needs no support from
any other device. Although the processing is done digitally in the form of special programs, the
process displays are of the analog variety (bars, pointers, numbered scales, line graphs) with an
accompanying digital display for configuration and diagnostics.
To the user, it behaves as any analog controller. The input signal is usually 4 - 20 milliamps
converted to 1-5 volts using a 250 W resistor, but 25 pin DIN connectors are provided for digital
communications with other computers, such a PCs. The standard output signal is 4 - 20 milliamps,
exactly the same as an analog controller, but other signal ranges, like 10 - 50 milliamps, can easily
be selected.
For large operations, the control system is likely to be a large computer-based system called a
distributed control system, or DCS. Small operations may require only a single pneumatic or
electronic controller. If it is electronic, it will invariably be a digital controller, perhaps with an
analog appearance.
“Intelligent” transmitters that contain a sensor/controller and produce an output of 4 - 20 milliamps
have been available for some time. The evolution of powerful networks will likely put most of the
controller functions in the field with the sensor.
Final Control Element
The majority of final control elements are, and will continue to be, the traditional valves as
described in the analog loop section. The application of digital technology to these control devices is
the current trend, and will likely continue until all conventional devices are eventually replaced.
Digital advances are mainly related to communications (with wire or glass fibre), remote
programming of control characteristics, and even built-in loops (sensors and controllers). However,
it is unlikely that the physical and thermodynamic phenomena that complicate valve design and
selection will change appreciably. The devices must still be fail-safe upon loss of power or in case of
fire.
Analog and Digital Electronics Technology
The line distinguishing digital and analog electronics technology is fast becoming blurred, and will
eventually disappear altogether. Future systems will be totally digital (computerized), and
connected by fibre-optic cables or some other means of communication that does not exist at
present. Operator interfaces, however, will likely continue to be analog forms, and will be imbedded
in powerful graphic displays for the bigger systems.
Despite advances in technology, the owners of factories and process operations are not likely to
rush into the modernization of existing operations that are turning a reasonable profit. Therefore,
the existing mix of new and vintage analog instruments, pneumatics, and digital electronics at
various states of evolution, will be common for some time.
Objective Four
When you complete this objective you will be able to…
Describe the operation and components of a digital control loop. Explain the function of each
component.
Learning Material
DIGITAL INSTRUMENTATION SYSTEMS
In the modern sense, the term “digital” describes computer systems that use the binary number
system of ones and zeros, or “bits”, to form a numerical representation of physical quantities such
as level, flow, and temperature. For example, the value that represents a liquid level in a vessel is
stored in computer memory as a binary number, in the form of a microscopic array of switches that
can be set at either five volts or zero volts.
These values that represent physical quantities in the real world are exact numbers, and not
analogs represented by a voltage signal level. The numbers are handled by computer programs in
exactly the same way as the rest of the data stored in its memory.
The major difference between the computer systems used in instrumentation and general purpose
computers, is the use of devices called digital-to-analog converters (DAC), and analog-to-digital
converters (ADC), which are necessary to interface to the field current loops. These devices were
once freestanding, but now are usually built-in devices, and are seldom a concern for the user.
Computers have become so small, powerful, reliable, and accurate that they have largely replaced
the analog electronics.
Digital Accuracy
The number of bits per second that a computer or peripheral device could handle was once a
measure of its ability to represent signal values accurately. For instance, early microcomputers were
“eight bit” machines, which introduced an error of about one-half of one percent to values gathered
from field sensors, and this was a concern. Modern machines use thirty-two bit or more technology,
as well as powerful number manipulation techniques to reduce signal-processing errors to a few
hundredths of one percent.
Controller Stations
Small control rooms use panel-mounted digital controllers that look very much like the old analog
controllers, but with more powerful options. Some small operations may even use a PLC and
console, or even an ordinary PC, with appropriate interface electronics. Large control rooms almost
invariably contain a number of video operator consoles attached to a large distributed control
system data highway.
It is not unusual to find individual digital controllers located in electrical centres scattered
throughout a plant site. These controllers can be connected via a built-in communications port, to a
laptop computer for configuration.
The Digital Instrumentation Loop
For all intents and purposes, the digital loop, as shown in Fig. 6, looks very much like an analog
loop, except that there are more options from which to choose. The signal wiring is exactly the
same as for the analog loops, and is often reused in upgrading from analog to digital systems.
However, there are certain characteristics and features of the digital systems that are not found on
the older analog systems. Following is a description of each element in the digital instrument loop:
Figure 6
Digital Instrument Loop
Sensor/Transmitter
The sensor/transmitter may be one of the older analog models, and will fit well into a digital
instrument loop, since most systems today still use the 4 - 20 milliamp signals. Many models are
available today that are digital; that is to say, they contain on-board microcomputer systems that
process information digitally, but provide the option of a standard 4 - 20 milliamp output through a
DAC. These are the so-called “smart” transmitters.
The name smart transmitter has emerged in the last decade to describe a new type of transmitter
that does more than just output a 4 - 20 milliamp signal. The name intelligent transmitter is
sometimes used interchangeably with smart transmitter, but it is more accurately used to describe
a transmitter that also has considerable controller capability, along with an independent computer
communications port.
Smart transmitters transmit process information in either a digital or the 4 - 20 milliamp analog
format. They can be re-zeroed and rearranged remotely, using a hand-held calibrator. They can also
be interrogated for information about themselves, such as flange material, o-ring material, or date
of last calibration. Current practice is to select these devices based on their high accuracy, but to
use them in standard 4 - 20 milliamp mode. However, future installations will likely use digital
communications almost exclusively.
The body of the smart transmitter is not appreciably different from those of standard transmitters,
and is connected to the process in the same way. The sensor and internal electronics have
undergone radical changes, even though the case may look like that of a standard transmitter. An
example of a smart transmitter is shown in Fig. 7.
Figure 7
Smart Transmitters
The smart transmitter is really a digital device, containing an on-board microprocessor complete
with memory. It has some very powerful features, such as remote calibration capability and storage
of configuration information. The output can be selected from a number of voltage or milliamp
ranges, as well as digital communications, although the most common selection is the 4 - 20
milliamp range. Fig. 8 illustrates the components of a smart transmitter.
Figure 8
Functional Diagram of a Smart Transmitter
Input Signal Line
The wiring and cable schedules used for input signals to controllers and other signal-processing
devices look much the same as those described for the standard analog systems. The difference is
that the wires are expected to carry digital information as well as the analog signal. Most
manufacturers superimpose the digital signal on top of the analog signal, and do not interfere with
it. However, some manufacturers interrupt the analog signal to send digital communications. Future
input-signal lines will most likely consist of fiber optic cables, strung together in a network.
Signal Information Processor (Controller)
Small control systems may use one or more controllers in what is called a “stand-alone mode”.
Stand-alone simply means that the system is completely self-contained, and needs no support from
any other device. Although the processing is done digitally in the form of special programs, the
process displays are of the analog variety (bars, pointers, numbered scales, line graphs) with an
accompanying digital display for configuration and diagnostics.
To the user, it behaves as any analog controller. The input signal is usually 4 - 20 milliamps
converted to 1-5 volts using a 250 W resistor, but 25 pin DIN connectors are provided for digital
communications with other computers, such a PCs. The standard output signal is 4 - 20 milliamps,
exactly the same as an analog controller, but other signal ranges, like 10 - 50 milliamps, can easily
be selected.
For large operations, the control system is likely to be a large computer-based system called a
distributed control system, or DCS. Small operations may require only a single pneumatic or
electronic controller. If it is electronic, it will invariably be a digital controller, perhaps with an
analog appearance.
“Intelligent” transmitters that contain a sensor/controller and produce an output of 4 - 20 milliamps
have been available for some time. The evolution of powerful networks will likely put most of the
controller functions in the field with the sensor.
Final Control Element
The majority of final control elements are, and will continue to be, the traditional valves as
described in the analog loop section. The application of digital technology to these control devices is
the current trend, and will likely continue until all conventional devices are eventually replaced.
Digital advances are mainly related to communications (with wire or glass fibre), remote
programming of control characteristics, and even built-in loops (sensors and controllers). However,
it is unlikely that the physical and thermodynamic phenomena that complicate valve design and
selection will change appreciably. The devices must still be fail-safe upon loss of power or in case of
fire.
Analog and Digital Electronics Technology
The line distinguishing digital and analog electronics technology is fast becoming blurred, and will
eventually disappear altogether. Future systems will be totally digital (computerized), and
connected by fibre-optic cables or some other means of communication that does not exist at
present. Operator interfaces, however, will likely continue to be analog forms, and will be imbedded
in powerful graphic displays for the bigger systems.
Despite advances in technology, the owners of factories and process operations are not likely to
rush into the modernization of existing operations that are turning a reasonable profit. Therefore,
the existing mix of new and vintage analog instruments, pneumatics, and digital electronics at
various states of evolution, will be common for some time.
Objective Five
When you complete this objective you will be able to…
Explain the purpose, operation, and give examples of on-off, proportional, proportional-plus-reset,
and proportional-plus-reset-plus-derivative control. Define proportional band and gain.
Learning Material
ON-OFF CONTROL
The simplest type of automatic controller is the “on-off” controller, sometimes called the “two
position” controller. In this type of control, the controller signal to the final control element is either
100% positive or 100% negative, that is a control valve will be told to either open fully or close
fully. There is no throttling or proportional action within the control. With the controller output being
either a minimum or a maximum, the controller cannot maintain the process variable at a desired
condition.
On-off control systems are used where the most basic control is required. The requirements for
successful on/off control are:
1.
2.
3.
4.
5.
Economics of the process do not require sophisticated control.
Precise set-point control is not necessary.
Processes, such as heat and level, which are generally slow in response timework
best.
Manipulated variable energy or volume flowing into the process is relatively small
compared to the capacity of the process.
The fully-open/closed operation of the final control element introduces
incrementally small changes to the process and is incapable of oscillating the
process into instability.
Some common examples of on-off control would be:
1. A temperature controlled exhaust fan in a compressor building.
2. A thermostat controlled forced air furnace.
3. The compressed air supply to a storage tank.
On-off control would unlikely be used in a flow system (other than as an open/closed control) where
the flow rate itself was being controlled independent of any capacity behind the flowrate.
A good example of the difference is in a three-phase separator used in gas plant inlets to separate
gas, oil, and water. The water usually has an excess dump valve on the separator leg that either
opens or closes completely. The oil, on the other hand, may be controlled by a proportional-type
controller that uses the level or the oil flowrate as a measured variable. The oil is saleable product.
Therefore, its control is more critical. The water goes to a disposal well, therefore, is waste product
and need not be controlled as carefully.
PROPORTIONAL CONTROL
Consider a very simple form of level control, as shown in Fig.9, where a float operates a water
supply control valve to maintain the water level in the tank. Assume that the valve is closed when
the tank is full, and fully open when the tank level falls to a minimum; also assume that the valve
opening has a linear relation with the flow (25% valve opening causes 25% flow, 50% opening
causes 50% flow, and so on.)
Figure 9
Simple Proportional Control
If the output rate of liquid from the tank is 200 L/min, one can adjust the turnbuckle on the valve
linkage until the set point is at 50% of maximum level. With this condition, the input and output
flows would be equal. As the discharge rate is increased to 300 L/min, the level in the tank drops,
causing the float to drop. This in turn increases the input valve opening so that the inflow is equal to
the outflow. Now the level will stabilize below the original set point. If the discharge rate is reduced
to 100 L/min, the level will stabilize above the set point. A change in the level (process variable)
must take place before the final control element (valve) can be repositioned.
The difference between the set point and the actual value of the process variable is known as offset.
Offset is an inherent characteristic of all proportional only controllers, and may be defined as a
sustained error that cannot be eliminated by means of the proportional mode of control.
If the pivot, F, in Fig. 9 is moved to the left so that the ratio of the lever arm AF/FB is decreased, a
smaller change in level will cause the control valve to go from minimum to maximum opening the
offset will be reduced. This increases the sensitivity of the control. As sensitivity is increased the
offset is reduced.
Figure 10
Moment Balance Pneumatic Proportional Controller
Fig. 10 shows a moment balance pneumatic proportional controller. For this controller initial
discussions will assume that:
1.
The pivot point is adjusted so that L1 and L2 are equal.
2.
The set point and process variable are both adjusted to a minimum value (assume
a 20 to 100 kPa range is used).
3.
The force spring is adjusted so the controller output is at the minimum value of 20
kPa.
When the process variable (PV) increases above the set point, the increase in output will bear a
linear relation with the deviation (process variable minus the set point pressure). As the process
variable increases to the maximum value of 100 kPa, the controller output will also increase to
maximum (Fig.11). An 80 kPa deviation in the process variable causes the controller output to
increase by 80 kPa. With a proportional controller, the deviation is often referred to as the offset.
PROPORTIONAL BAND AND GAIN
The output of the controller (V), or the valve position is directly related to the process variable (PV).
When the process variable goes through its full range of values, the controller output does likewise,
and the final control element strokes through 100% of possible opening. The percent of the process
variable range that causes 100% change in controller output is often called the proportional band.
In the above example the proportional band is 100% because a 100% change of PV will cause a
100% change of V. The ratio of change of output (DV) to change of input (DPV) is referred to as the
gain (K) of a proportional controller.
Figure 11
Controller Output vs. Process Variable
When the pivot is centered so that L2 = L1, the proportional gain of the controller is:
The proportional gain (K) can also be calculated from:
Consider what happens if the pivot point in Fig. 10 is now adjusted so that L2/L1 = 2, and with a 20
kPa set point and PV pressures applied, the spring force is adjusted so the output is 20 kPa.
(Normally this calibration is not required on an actual controller but the design features are too
complicated to show in a simple sketch). After this adjustment, if the PV input pressure increases
above the set point, the PV signal has to increase only to 60 kPa or 50% before the output
increases to maximum or 100%.
Therefore:
Also:
It can be seen that the width of the proportional band or the gain determines the output from the
proportional controller and the amount of valve movement for a given error; for example, the
difference between the value of the process variable and set point. As the gain is increased, or the
proportional band is made narrower or decreased, the offset of a proportional controller decreases.
This causes the process to remain closer to the set point, (Fig. 11) with variations in process load.
The gain of the controller can be increased only to a certain value before the controller output will
start to oscillate like an on-off controller. Any controller with a proportional band of 2% or less may
be considered to operate exactly like an on-off controller. In Fig. 9, if the ratio AF/FB is made very
small, then a disturbance on the water surface can cause the valve to be positioned from the fully
closed to the fully open position.
The fact that the proportional band is equal to the percentage change in the process variable
(% PV) that causes a 100% change in the controller output (100% V), suggests that the following
equation holds true:
Normally, better control of processes is achieved if the controller output is above minimum value
when the error is zero, as any final control element such as a valve operates better about mid
opening. To overcome this effect, a constant spring force, often called manual reset, is imposed by
placing an opposing spring opposite to the negative feedback bellows.
When the process variable is at the set point, the clockwise moments will be equal to the
counterclockwise moments, so the force in the negative feedback bellows must also be equal to the
spring force. The force of the spring can be adjusted to get the desired output when the process
variable is at the set point as indicated in Fig. 10.
When a proportional controller is used in a process, offset will always exist. As the gain is increased,
the offset will decrease; but increasing the gain beyond a certain limit, depending on the process,
will cause oscillations or instability in output and in the value of the process variable which is an
undesirable result. In some processes, offset cannot be tolerated, as it will result in an inferior
product. To overcome this problem, the constant spring force, which is manually reset, is replaced
by automatic reset or integral bellows.
PROPORTIONAL PLUS RESET CONTROL
Integral control, often called reset, responds to both the amount and time duration of the deviation.
That is to say, that as long as the deviation from setpoint continues, the correction to the controller
output continues. Thus this mode of control continues to operate until it produces an exact
correction for any process load change. This is accomplished by adding a positive feedback bellows
to a proportional controller, as indicated in Fig. 12, which will continue to change the output until
the error is eliminated or possibly until the controller output is at either end of its range.
Assume that a step change is introduced in a proportional plus integral controller so the process
variable, PV, suddenly exceeds the set point (a step change is a vertical rise in PV) in Fig. 12.
The controller output will increase immediately due to proportional action by an amount that
depends on the gain and the size of error. This will create a pressure differential. As the pressure
differential decreases, the increase in force inside the integral bellows causes an increase in output
followed by an increase in negative feedback in order to maintain moment balance. While this
integration is occurring, the controller output is increased further than if proportional action was
used alone. The final control element is moved further causing the process variable to approach the
set point. As the error approaches zero or the PV approaches the set point, the pressure differential
across the integral adjustment valve approaches zero.
When the PV is at the set point, moment balance is achieved so that the set point and PV pressures
are equal. The pressure in the negative feedback bellows is equal to the pressure in the integral
bellows. If the process variable drops below the set point, the action in the controller is reversed.
Figure 12
Proportional Plus Reset Controller
The capacity tank causes a delay in the integral action by providing a capacitance and thus
providing more stability in control. In proportional plus integral controllers the offset due to
proportional action is eliminated over a period of time. The rate of change of the corrective output
by the integral mode is expressed in terms of the output change due to proportional action alone.
For any given deviation, the change in proportional controller output will depend on the gain.
Integral or reset action is always expressed in terms of the time that it takes for the integral action
to reproduce or repeat the output due to proportional action after a step change is introduced. The
time that it takes integral action to reproduce the proportional action is known as reset time,
expressed in minutes. Integral action can also be expressed in terms of repeats per minute, which is
the number of times per minute that the initial proportional action is repeated by integral action.
Reset on integral time can be varied by manipulating the integral adjustment valve. If the valve
restriction is increased (assuming PV is above the set point, SP), the pressure in the integral bellows
that provides positive feedback will increase more slowly and the controller output will increase at a
lesser rate. If the restriction valve is open wide, the pressures in both feedback bellows will increase
almost simultaneously so the positive feedback will cancel the effects of negative feedback
immediately. This will result in a very short reset time and the output of the controller oscillates
similar to an on-off controller.
PROPORTIONAL PLUS RESET PLUS DERIVATIVE CONTROL
In many processes, such as temperature control, there is considerable lag or delay from the time
that a change in load takes place, to the time that the change in the process variable is sensed by
the controller. Derivative or rate action, which could not possibly control the process by itself, takes
into account the speed at which the variable is deviating from the set point. Fig. 13 illustrates the
response of proportional action to a sudden (step) change in the process variable and the controller
response when rate action is added.
Figure 13
Rate Contribution to Controller Output
Rate contribution occurs only when there is a change in rate of error. This change occurs only at
time T0 because after that the error is changing at a constant rate. The speed of rate action is
known as rate time, TD. In Fig.13:
T D = T2 - T 1
If the process variable starts to deviate from the set point at a faster rate, rate contribution to
controller output will increase; also, T1 - T2 becomes greater.
Fig. 14 illustrates a pneumatic proportional plus reset plus rate controller. If the process variable,
PV, deviates from the set point, the controller output will increase. The rate or derivative
adjustment valve delays the effect of negative and positive feedback. Before the pressure
differential across the rate valve equalizes, the controller will momentarily act like an on-off
controller causing the output to increase to a higher value than with only proportional plus reset
action. After rate action has taken place, the controller acts similar to the proportional plus reset
controller.
In slow processes that undergo large load changes, rate action causes the process variable to
stabilize more quickly. When controlling processes such as flow that respond quickly, rate action is
not recommended because it will cause instability and the process will swing or oscillate.
Figure 14
Proportional Plus Reset Plus Rate Controller
If the error appears quickly, the rate action will counter it and allow the proportional and reset
action to begin earlier and work more efficiently.
Objective Six
When you complete this objective you will be able to…
Describe and give typical examples of feed forward, feed back, cascade, ratio, split-range, and
select control.
Learning Material
FEEDFORWARD CONTROL
A manual method of implementing feedforward control is illustrated in Fig. 15. Here, a disturbance
enters the process, the operator observes an indication of the disturbance, and adjusts the
manipulated variable in such a manner as to prevent any immediate change or variation in the
controlled variable due to the disturbance.
The difference between feedback and feedforward control is apparent. Feedback control works to
eliminate errors, whereas feedforward control operates to prevent errors from occurring in the first
place.
Figure 15
Manual Feedforward Control
Automatic Feedforward Control
In the automatic control system illustrated in Fig. 16, it is possible to maintain the manipulated
variable (m) at a point that will balance the loads (q) and hold the measurement (c) at the desired
setpoint (r).
Figure 16
Feedforward Model
Fig. 17 is a block diagram of a feedforward control scheme with feedback trim. The signal from the
feedback trim controller is fed into the feedforward math model. Feedback trim resembles feedback
control in that a transmitter and a controller are utilized. However, its function is not quite the
same. The feedback trim signal is fed into the model to trim the model parameters, and therefore it
compensates for any imperfections in the feedforward control scheme.
Figure 17
Feedforward Control With Feedback Trim
The use of feedback trim assumes that all major influences on the process have been considered in
the model, and the trim is merely making minor adjustments to the manipulated variable signal. If
this is not the case, and the trim signal is called upon to do a major share of the control because
the model is grossly in error, the object of a feedforward control strategy will be defeated.
A typical application of feedforward is applied to tank level when the level is to be controlled
precisely, as in the case of a boiler drum. Fig. 18 shows the arrangement.
Figure 18
Feedforward of a Level Process
Since it is not possible to take into account all the loads on the system, such as measurement
accuracy and varying pressure drops across pumps and fittings, it is necessary to include the level
loop as a feedback trim. Any changes in the tank outflow will be compensated for immediately by a
change in inflow. Any discrepancy between inflow and outflow will be adjusted by the feedback trim
loop (level).
CLOSED-LOOP CONTROL (FEEDBACK)
In a closed-loop control configuration, a measurement is made of the controlled variable, and this is
compared with the desired value or set point. If a difference, or error, exists between the actual and
the desired value, the controller will operate to limit the deviation of the value from the setpoint.
The controller’s function is to provide a corrective signal to the “final control element” (the physical
device which affects changes in the manipulated variable) that would bring the process variable in
line with the setpoint thus reducing the difference or error. The controller action is to position the
final control element in order to reduce the error (PV-SP) to zero. Fig. 19 illustrates the feedback
concept associated with a closed-loop control configuration.
The objective of a control system is to maintain a balance between supply and demand over a
period of time. Supply and demand is defined in terms of energy or material into and out of the
process. The closed-loop control system achieves this balance by measuring process variable and
regulating the supply, in order to maintain the desired balance over time.
The Fig. 19 process example can be used to determine how automatic control replaces the operator
action on a consistent basis. There are disturbances associated with the process, such as cold-water
temperature, cold-water flow, hot water temperature, and blended water discharge flow rate. The
controller functions automatically to maintain the desired value by means of measuring the
controlled variable to provide feedback from the process.
A comparison of Fig. 16 with Fig 19 will show the basic difference between open-loop and closedloop control. In open-loop control, no actual process measurement is made. On the other hand, in
the feedback control loop shown in Fig. 19, the temperature controller reads the blended water
temperature and compares it with the established temperature set point. Based on the temperature
measurement and the set point, an output signal would be developed to position the temperature
control valve. The Temperature Control valve is called the final control element and is manipulated
by the output signal from the controller.
Figure 19
Temperature Control Loop Courtesy
Feedback Loop Elements
Another example of closed-loop control is illustrated in Fig. 20. This simple control loop shows the
four major elements of any feedback control loop. In this example the “measurement” block is
illustrated. This function is generally performed by a transmitter, which reports the status of the
controlled variable to the controller. The controller then compares the process variable
measurement to the setpoint. An error or difference between these two values must exist before the
controllers’ output will change to manipulate the final control element (FCE). This is referred to as
feedback control, since the effect of the final control element action is fed back to the controller via
the process reaction.
Figure 20
Feedback Control Loop
© Chilton Book Company, Norman A. Anderson. This material has been copied
under license from CANCOPY. Resale or further copying of this material is
strictly prohibited.
CASCADE CONTROL
Process systems have a supply side and a demand side. The supply side is usually characterized as
the side that supplies energy and materials to the process. The demand side is the product
demanded by the customer or the next process stage. Fig. 22 illustrates the two sides of a process:
the supply side (steam supply) and demand side (hot water).
Figure 21
Typical Process Supply and Demand
In most cases, the supply side is controlled by the process control scheme and the demand side is
not. Disturbances to both the supply and demand sides of the process require different techniques
to control the process and maintain process stability. Control of supply side disturbances is best
achieved by a feedback strategy such as a single loop or a cascade control loop. The control of
demand side disturbances is the domain of feedforward control, especially when feedback cannot
provide acceptable control criteria.
There are at least two process conditions that can make the overall effectiveness of feedback
control unsatisfactory. One is the occurrence of large magnitude disturbances of such frequency
that the feedback control system can never get the process under control. Secondly, processes that
possess large amounts of lag cannot be controlled effectively with feedback control.
Different control strategies can be used to overcome the ineffectiveness of feedback control.
However, these are more complex, and require in-depth process knowledge to implement a
successful control scheme.
Cascade Control Theory
Cascade control is used in a situation like the one illustrated in Figs. 22 and 23. This method of
control is used to minimize the effect upon a primary variable due to upsets in a secondary (supply)
variable. Cascade control is achieved by the use of two controllers, but only one control valve or
final actuator.
Fig. 23 shows a heat exchanger in which the output temperature is held at the setpoint (r) by
manipulating the steam supply valve in response to load changes.
Figure 22
Simple Feedback Loop
Consider what would happen to this heat exchanger if there were a supply upset. For example, the
demand from another user on the steam header might vary and the header pressure also changes.
This will cause a change in the steam flow, which will propagate through the heat exchanger as a
deviation of T2 from setpoint. The control system will then reposition the valve to compensate for
this steam flow upset, as shown in Fig. 23.
Figure 23
Response to Supply Upsets
In a cascade system, as shown in Fig. 24, a secondary loop replaces the final actuator. Note here
that the output (m1) of the temperature (primary) controller is input as the setpoint (r2) of the flow
(secondary) controller. Typically, the loop closest to the process that controls supply input is the
secondary loop consisting of the flow transmitter, the flow controller, and the final actuator. It is
sometimes referred to as the slave, or inner loop.
Figure 24
Simple Cascade Control Loop
The loop controlling the dynamic variable is the primary loop, and consists of the temperature
transmitter, the temperature controller, and the secondary loop. It is sometimes referred to as the
master or outer loop. The primary controller operates in a normal manner, considering the input to
the secondary loop no different from the input to a final actuator.
There will now be faster compensation for changes in steam flow. A steam pressure (flow) change
will be detected as a steam change, rather than as a temperature change after it has propagated
through the lag time of the process. It should be kept in mind, however, that for cascade control to
be effective, the response of the secondary loop must be faster than the response of the primary
loop.
Advantages of Cascade Control
Consider first an upset entering the secondary loop (that is, a supply upset). Fig. 25 shows cascade
control improving loop performance following a supply upset.
Figure 25
Relative Loop Performance to Supply Upsets
The response of the dynamic variable to a supply upset is greatly improved, since now the primary
controller is telling how much energy or mass to supply, rather than how to position the final
actuator.
The advantages of cascade control are:
•
It provides isolation from supply upsets.
•
It improves loop dynamics.
•
It removes the influence of the valve characteristic with respect to the primary loop, since it
defines the amount of supply input, rather than the position of the final actuator.
•
The secondary loop permits an exact manipulation of the flow of mass or energy into the
process by the primary controller.
RATIO CONTROL
A ratio control system is a strategy whereby one process variable is controlled in a specific ratio to
another process variable. Ratio is a common type of control used frequently in process control.
Ratio control is often associated with process operations when it is necessary to continuously mix
two or more streams together in order to maintain steady composition of the resulting mixture. In
practice, this is accomplished by using a conventional flow controller on one (primary) stream, and
a ratio controller on the other (secondary) stream to maintain the secondary flow at some preset
ratio or fraction of the primary flow.
Auto-selector control allows the automatic selection between two or more measurement inputs and
provides a single control output to manipulate one final control element.
Split-range control has one controlled variable as an input, and two manipulated variables as
outputs. A split-range control system is used when precise manipulation of two variables is required
to maintain a controlled variable as close as possible to a setpoint. This type of control is also
referred to as DUPLEX control. Consider the simple sketch shown in Fig. 26
Figure 26
Basic Ratio Process
Fig. 27 depicts two ingredients, A and B, that are to be mixed to give a product R, which has a
specific ratio in relation to B and A. It is important to realize that, in order to maintain the correct
ratio, process variables A and B must be of consistent quality to ensure that the product remains in
the correct ratio. In other words, if it can be ensured that A and B flows are of consistent quality,
then the only two variables are the flow of the two streams A and B, and the ratio of the two
streams. Any other variables, such as stream quality, consistency, and chemical composition, will
result in errors in the calculation of the desired product R.
SPLIT-RANGE CONTROL
An example of a split-range control system can be found in water going to a tank that treats boiler
feedwater with chemicals before it the water enters the boiler. The temperatures of the Hot and
Cold water (the manipulated variable) are required to be maintained within close tolerances to a
specific temperature (the controlled variable) in order so that the chemicals will mix properly and
totally with the water at that specific temperature.
A feedback loop employing a single manipulated variable has a drawback. Although it may be
relatively easy to heat or cool a process by the application of energy, the system must rely on the
process load to return the process back to the setpoint in the opposite direction. However by the
application of a split-range control strategy to a process, energy or material is applied in two
directions to force the process variable back to the setpoint (Fig. 27).
Figure 27
Typical Split-Range Control Loop
The two control valves commonly used in split-range control systems use a common signal applied
to both valves and the signal is split between the two. Referring to Fig. 28 the valves are typically
ranged as follows: The cold water valve is direct acting with a range of
60-100 kPa (12-20 mA). The hot water valve is reverse acting with a range of 20-60 kPa
(4-12 mA).
Figure 28
Direct and Reverse Acting Valves
There are at least two process conditions that can make the overall effectiveness of feedback
control unsatisfactory. One is the occurrence of large magnitude disturbances of such frequency
that the feedback control system can never get the process under control. Secondly, processes that
possess large amounts of lag cannot be controlled effectively with feedback control.
SELECT CONTROL
The Auto-Select loop control allows the automatic selection between one or more measured or
controlled variables to produce a single output that is used as a controlled variable. Fig. 29
describes a typical selection of three variables around a pump. The output of each controller is
polled and the lowest output is selected as the controlled variable forming the loop that will actuate
the control valve.
Under normal pump operating conditions, the control valve should be throttled, based on the
discharge pressure of the pump. However, if any of the following conditions occur it will be
necessary to position the control valve based on an alternate controlled variable:
(a) Pump suction pressure too low.
(b) Motor electrical load too high.
(c) Pump discharge pressure too high.
A suction pressure that drops below a predetermined level can cause the pump to cavitate, thereby
causing severe mechanical damage. Also, if the motor electrical load rises above a predetermined
level, motor damage can occur from excessive current draw. Finally, if the discharge pressure rises
too high, then damage to pipes and vessels downstream can occur.
Figure 29
Auto-Select Cut Back Control
Objective Seven
When you complete this objective you will be able to…
Explain, with examples, the purpose and incorporation of alarms and shutdowns into a control
loop/system.
Learning Material
CONTROL LOOP ALARMS
Loop alarms are devices that signal the existence of an abnormal condition by means of an audible
or visible discrete change, or both, intended to attract attention. Audible or visible alarm displays
are placed where the process or machine operator is located, such as a central control room or
computer screen. In many cases where a complex process is spread out over a large area, local
audible or visual alarms adjacent to processing units or machines may be used to alert personnel in
specific areas.
Traditionally, a loop alarm is dedicated to a single purpose. It is to alert a human operator that one
or more conditions in a process or machine may lead to personnel injury and damage to equipment.
It may indicate the control loop is operating out of preset and specific operating parameters (set
point).
For example: A High Level alarm on a water tank may exist to notify an operator that the level in
the tank has exceeded the set point level for that tank. In this case, the level is above the set point
but the water going into the tank will continue to flow. The alarm is only to warn the operator that
eventually the tank may overflow or a shutdown condition can occur if corrective action is not
taken. If the level continues to rise then a High-High Level alarm can exist in the loop to shutdown
the equipment and not allow any flow to continue into the tank.
In most cases when an alarm condition occurs, the process continues to operate and the operator
takes corrective actions to remedy the high level by adjusting the water into or out of the tank or by
changing the set point on the controller.
Most alarms are equipped with an “acknowledge” button either in a central control room or near the
equipment (or both) that allows the operator to reset or silence the alarm. The tank level alarm may
only be a temporary condition and the control loop may, over time return the level to its original set
point without any need for the operator to make any changes to the control loop. Processes like a
tank level loop can experience bumps or momentary abnormal conditions that will return to
acceptable limits within time. In the example of the high level in the tank, a high-level alarm is
meant to notify the operator. Acknowledging the alarm maybe the only corrective action that needs
to be taken.
Other alarms such as gas detection alarms, warn the plant staff that a gas leak exists or the
concentration of a specific gas has surpassed a certain limit. This type of alarm indicates that an
unsafe or hazardous condition exists and plant staff may need to put on safety-breathing equipment
before they are allowed to take corrective actions.
Alarms occur when faults in the process are noticed. These faults may develop slowly over time or
instantaneously (e.g., when a pump fails). Over time operators will understand what the
consequences are of each alarm and how to specifically react to them.
Purpose of an Emergency Shutdown
Sometimes, despite plant operator’s best efforts, things get out of control with the possibility of
dramatic negative effects on plant operations. At times like these there must be some way of
quickly and safely shutting down facilities, or portions of facilities, in a way that will isolate and
contain the problem.
Emergency ShutDown (ESD) systems serve this purpose. An ESD system is made up of special
purpose devices that are designed to quickly open or close valves, energize or
de-energize equipment; either from a manual station(s), or automatically if certain operating
parameters are exceeded. The devices are operated by air, hydraulics, electricity, or combinations
of all three and may be operated selectively by different modes of ESD depending on the nature of
the emergency. Typical ESD modes are as follows:
•
Shutdown and isolate rotating equipment. This will remove a source of ignition and stop a
leak that may be located in the equipment, but still allow the process to remain
pressurized.
•
Shutdown, isolate, and depressure. The additional step here will depressure the facility in
the event of a rupture to lower the risk created by the compressed material.
Sometimes it is only necessary to shutdown and isolate a particular piece of equipment or process.
The remainder of the process may be kept pressurized. There are also times when it is not advisable
to depressure because that would present a greater hazard. An example of this would be the
release of combustible vapor to atmosphere when there is a fire already burning in the immediate
area.
Activating An ESD
An emergency shutdown could be activated automatically or manually. For example, an automatic
ESD could be activated at an unmanned station where a gas monitor detects a concentration of gas
approaching the point of combustion. All sources of ignition would be shut off, the station isolated
and possibly depressured. Ventilation fans might be turned on to clear gas from the building.
Another example of an automatic ESD might be in a pipeline system. If there is a difference in
readings between a meter placed at the discharge of a station and another meter placed at the inlet
to the plant that is receiving the pipeline product, an automatic signal is sent to shut down pumps
and close valves. This blocks both ends of the pipe and isolates a possible leak.
Manual shutdown stations are more common in manned facilities and allow an individual to shut
down a section of a facility quickly. These stations are usually located outside of buildings on the
normal route of travel, so that they can be activated while on the way out of the emergency
situation. They are clearly marked and easily accessed.
Equipment Protection
Individual pieces of equipment need to be protected against operating conditions that can cause
serious damage. These conditions are very specific to each piece of equipment and are specified by
the manufacturer of the equipment or by the designer of the process. Some of the more common
conditions monitored by a sensor and that activate shutdowns are:
•
•
•
•
•
•
•
•
High or low temperature
Loss of lubricating oil
Vibration
Low flow
High or low level
High or low pressure
Combustible gas
Toxic gas
Sensors that monitor operating conditions will immediately remove the source of energy from the
equipment the moment an operating condition exceeds specified limits. While the sensors are
specific to the piece of equipment, the valves or switches they operate are often the same ones
used for general control purposes. An example is a fuel gas valve on an engine. A controller may
adjust the valve to regulate engine speed. However, a low oil pressure switch or an ESD will stop
the engine by closing the valve completely.
Fig. 30 shows an example of a single end device being used for more than one purpose. An inlet
valve to a vessel is normally operated by a level control. The level control can be overridden by a
high-level shutdown or an ESD. The valve will close and stays closed until an operator takes action.
Protective devices prevent individual pieces of equipment from being damaged by extreme process
conditions, or faults within the equipment itself. ESDs are intended to safely shutdown whole
facilities (or portions of a facility) when operating conditions are threatened from an external
source, or become unstable and out of control.
Figure 30
Multiple Use of an End Device
Interlocks
Interlocks are another mechanism of protection. They will not allow a piece of equipment to run
unless some specific conditions are satisfied. An example is shown in Fig. 31. Before the burner can
be lit there must be sufficient flow through the tubes, otherwise the tubes would overheat and be
damaged. Interlocks are also used to prevent a restart attempt until a manual reset action has been
performed.
Figure 31
Interlocks
Operation of End Devices
End devices are the mechanisms that will actually shut down a piece of equipment or a section of a
process. While some of these devices are electrical (a switch for example), many are valves that
stop the flow of process fluid or product.
Valves can be operated directly by air, or by a motor mounted on the valve. It is powered
electrically or by air. All of these devices are fail-safe. Fail safe means that rather than remaining in
the current position, the end devices will either be fully open or fully closed once the source of
power (electricity or air) has been removed. Valves that serve to isolate equipment will usually fail
closed, while valves that depressure will normally fail open. Should the source of power fail for some
reason, the facility will shutdown in a way that isolates and depressures equipment, and removes
sources of ignition.
Air or Gas Operated Shutdown Systems
Most field facilities utilize pneumatic devices to shut down equipment with either air or fuel gas
providing the source of power. Fig. 32 illustrates a typical shutdown relay. In Fig 32(a), the device
is in the OPERATING mode. The shuttle piston is to the right. In this position air (or gas) enters the
IN port and flows to the OUT port, which in turn goes to an end device such as a valve, to keep it
open. Air also flows through the orifice in the piston. With the trip mechanisms all closed, no air
escapes through the TRIP port. The shuttle piston is maintained in this position by air acting on the
larger end of the piston, forcing the piston toward the VENT port, which is at atmospheric pressure.
The marking on the piston indicates through the window that this relay is in the OPERATING mode.
The TRIP port may be connected to one or several trip sensors. Trip sensors may sense pressure,
temperature, vibration, low lubricating oil pressure, etc. Whenever a trip sensor is activated, it
opens the TRIP port to atmospheric pressure. Pressure from the IN port causes the shuttle piston to
move to the left position as shown in Fig. 32(b). The OUT port is now connected to the VENT port
which causes the valve (or end device) to go to failed safe position. The IN port is no longer
connected to the OUT port. A check of the window indicates that this relay is in the TRIPPED
position.
When the cause of the trip has been reset, air flowing through the orifice will again pressurize the
left side of the shuttle piston causing it to slide to the operating position and allow air pressure to
flow from the OUT port. Flow from the OUT port may be directed to other relays in a series
arrangement, each having only one trip sensor. In this type of operation a quick look at the relay
windows will indicate what type of problem caused the shut down to occur.
Figure 32
Pneumatic Shutdown
Some relays may be equipped with springs to force the shuttle piston one way or the other in the
event that operating air pressure is lost. Because ESD systems must be able to operate at any time,
consideration must be given to correct installation, routine maintenance, and testing.
One critical item is the quality of the operating air or gas. The air must be adequately dried so that
it can never freeze at the end devices. ESD systems are dead-ended most of the time and are
places where water would tend to collect.
Valve actuators, of the piston type, which are operated by air, should use lubricants that will
perform well through all temperatures encountered at the site. Most piston type operators require a
lubricator on the supply airline just as it enters the operator.
A lubricator is a device that will atomize lubricating oil and inject it into the air stream as the air is
used. Valves should be exercised (stroked) occasionally to assure their reliability. During scheduled
or unscheduled shutdowns, valves should be stroked or exercised through their full operating range
to confirm their ability to make effective closure, and to indicate that they have not become lodged
in the normal running position.
Objective Eight
When you complete this objective you will be able to…
Explain the interactions that occur and the interfaces that exist between an operator and the
various components of a control loop/system, including the components of a controller interface.
Learning Material
LOCAL CONTROL LOOPS
Local or field control loops have the controller and controller interface located in the plant process or
field areas. The operator for the area adjusts the field controller. As the entire control loop is in the
area the operator may troubleshoot the loop. This can involve stroking the valve or final control
element.
Operating the control loop usually means adjusting the setpoint of the controller. The operator can
watch the output of the controller and the value of the process variable to see if the setpoint change
has the desired effect. Some local controllers can be switched to hand or manual control. In manual
the operator is manually loading or adjusting the air pressure to the control valve. For example, at 3
psi the valve is fully shut. At 15 psi the valve is fully open. An example of a local controller is shown
in Fig. 33. The field operator adjusts the setpoint and the controller changes its output to control
the process variable. The process variable and the setpoint should be close to the same value if the
controller is functioning well.
Figure 33
Local Control Loop
Operator Interaction
In general the operator will initiate changes or corrections to a control loop by adjusting the
controller. Occasionally, other components of the loop need to be interfaced with and the operator
may investigate if a transmitter is sending a faulty signal to a controller or the final control element
or valve is not responding to a signal from the controller. When a loop is not controlling properly,
the operator may have to troubleshoot each component of that control loop.
The use of a control room panel or console increases the operator’s ability to clearly and easily
monitors specific areas of the process. The panel is the operator’s interface and is the work center
for the operators. This an area where the operators follow the process, taking advantage of the fast
and accurate translation of raw data into useful trends and patterns, which can help in deciding
which action, the operator will take. One section of the panel is usually dedicated to each section of
a plant.
Analog Control Panel
An analog control panel can be a field-mounted panel or it can be located in a centralized control
room. The field-mounted type of panel is shown in Fig. 34. It has a row of analog controllers in the
center. Above the controllers is the annunciator panel with alarm windows. Below the analog
controllers are start-stop switches for electric motors. A strip chart is located on each side of the
controllers.
The analog field panel is normally located close to the equipment it is controlling. For example many
package boiler have locally mounted control panels. They have control loops for each section of the
boiler such as fuel gas flow and airflow. The operator can start and stop the boiler from this panel,
and adjust the firing rates. Annunciator or alarm panels are also located on this panel.
Figure 34
Analog Field Panel
Analog panels can be located in centralized control rooms. Here a large number of controllers are
mounted on control room panels. The control operator has control of a large number of controllers
at once. Most control loops will have alarms and/or shutdowns. An operator may have to silence or
acknowledge an alarm and proceed to look at the condition or state of all the components in that
loop. If a bump or change to a process occurs, operators can place the controller of a specific loop
into manual and make changes as they see fit. A controller in manual allows the operator to change
the set point and wait to see if the system or control loop will respond correctly. Once a new set
point has been established then the operator may enter that new value into the controller and
switch it back into automatic.
Digital Control Panels
The equipment used for computer based control rooms is physically similar to modern office
equipment. There are CRT based computer consoles, keyboards and printers. Fig. 35 illustrates a
control console arrangement for one operator. It has three screens, one for each keyboard, and one
central used as an alarm screen. Between the keyboards and the screens are strip carts.
The design of the workstations is modular, and can be built to match the number of operators and
the size of the plant. As the plant expands, new modular consuls can be added. DCS control rooms
require less space than analog control rooms. The computer systems do require extra space for
computer equipment next to the control room.
Figure 35
DCS System Consoles
Digital Displays and Controllers
Digital control layouts on CRT screens give the operator access to the digital controllers. Overviews
of the process or plant appear on the CRT displays. Controllers are identified on the displays. The
separate controllers can be enlarged in its own window. Each digital controller is made to appear as
an analog controller. They have process variables, set points, and outputs. The operator can change
set points on the CRT using a keyboard, mouse, or trackball, depending upon the system.
The CRT may also be a touch screen, in which the operator can make changes by touching the
screen. The touch feature is used to change displays and bring up control displays. Entering the
data is often done with the keyboard, or mouse. Changing set points can be done using up and
down arrows on the touch screen.
Fig. 36 shows part of a typical digital control screen. It consists of a schematic of a section of
process, including the position of the controllers for that portion of the process. On the schematic
are the controllers for that section of the process. Changes can be made by calling up various
controller faceplates. The base level controller has been called up on the screen in this example.
The display in Fig. 37 looks similar to a row of analog controllers. These controllers are digital
however. The drum level controller LIC-704 has been expanded for illustration purposes. It has the
setpoint, process variable (drum level) and controller output. This controller has a few extra
indications on the screen: the setpoint limit and output limit. There is also a deviation limit. They
set limits on the setpoint output and deviation of the controller.
Figure 36
Digital Control Screen
There are many variations in the appearance of digital control screens and controllers. The plant
engineers, operators and computer technicians at each plant configure their own displays. The
displays may also be changed for plant additions or upgrades.
Figure 37
Digital Controller Display
Instrument & Control Devices
Learning Outcome
When you complete this learning material, you will be able to:
Explain the operating principles of various instrument devices that are used to measure and control
process conditions.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
Describe the design, operation and applications for the following temperature devices:
bimetallic thermometer, filled thermal element, thermocouple, RTD, thermistor, radiation
and optical pyrometers.
Describe the design, operation and applications for the following pressure devices: bourdon
tubes, bellows, capsules, diaphragms, and absolute pressure gauge.
Describe the design, operation and applications for the following flow devices: orifice plate,
venturi tube, flow nozzle, square root extractor, pitot tube, elbow taps, target meter,
variable area, nutating disc, rotary meter and magnetic flowmeter.
Describe the design, operation and applications for the following level devices: atmospheric
and pressure bubblers, diaphragm box, differential pressure transmitter, capacitance probe,
conductance probes, radiation and ultrasonic detectors and load cells.
Objective One
When you complete this objective you will be able to…
Describe the design, operation and applications for the following temperature devices: bimetallic
thermometer, filled thermal element, thermocouple, RTD, thermistor, radiation and optical
pyrometers.
Learning Material
BIMETALLIC THERMOMETER
The operation of this thermometer depends on the principle that dissimilar metals expand at
different rates when heated. It consists of two thin metal strips of different materials welded
together face to face. When heated, they expand at different rates causing the assembly to bend, as
shown in Fig. 1.
Figure 1
Bimetal Strip
To obtain considerable rotation of a pointer on a scale and spread the scale for maximum accuracy
in reading temperatures, the bimetal strip is wound in the form of a helix, as indicated in Fig 2. This
application is used extensively in dial thermometers.
Figure 2
Helix Strip
Table 1 lists the coefficient of thermal expansion of six commonly used metals. Only metals having
a wide difference in coefficients, such as brass and invar, are used together
Material
Aluminum
Brass
Copper
Invar
Iron
Steel
Coefficient/°C
0.0000238
0.0000184
0.0000165
0.0000009
0.0000120
0.0000120
Table 1
Coefficients of Expansion
FILLED THERMAL ELEMENT
A filled thermal element system consists of the following:
•
A bulb immersed in the measuring fluid
•
A long capillary or fine bore tube
•
A measuring unit that may be a bourdon tube or bellows
•
A filling fluid that may be a liquid or gas
The whole system, shown in Fig. 3, is gas tight and filled completely with an appropriate liquid or
gas. The bulb is inserted in a vessel or pipe where a temperature measurement is required.
Thermowells are used to protect the bulb from erosion and corrosion.
As the temperature at the point of measurement increases, the liquid or gas will expand. Since the
volume is fixed, the pressure in the whole system must increase. A Bourdon tube or bellows will
respond to the change in pressure by moving a pointer or recording pen.
Figure 3
Filled Thermal Elements
THERMOCOUPLE
One of the most widely used temperature sensing devices is a thermocouple. It consists of two
wires, each made from a different metal. One end of each wire is joined together and the other end
is connected to a meter or electrical circuit, as shown in Fig. 4. If the joined end, often called the
measuring junction, is heated, a measurable voltage is generated across the meter. The free end,
referred to as the reference junction, may be connected to a millivoltmeter, which is calibrated to
read in degrees of temperature. The voltage generated by a thermocouple is proportional to the
temperature differential across the measuring and reference junctions.
The measuring junction of a thermocouple is placed at the point of temperature measurement while
the millivoltmeter, with the reference junction, may be some distance away. The measuring junction
can be placed in the path of the flue gases in a boiler while the meter may be placed on a control
panel.
Figure 4
Thermocouple Circuit
Various combinations of metals may be used depending on the temperature range to be measured.
Some types of thermocouples and their temperature ranges are shown in Table 2.
Type of Thermocouple
Temperature Range ° C
Iron - Constantan
- 18° to 760°C
Chromel - Alumel
260° to 1260°C
Platinum/Rhodium - Platinum
538° to 1480°C
Copper - Constantan
180° to 370°C
Table 2.
Thermocouple Ranges
When a thermocouple is used to measure temperature in a pipe or a heat exchanger, a thermowell
is used. This arrangement is shown in Fig. 5.
Figure 5
Thermocouple and Protecting Well
RTD
A RTD (resistance temperature detector) operates on the principle that the resistance of a metal,
such as silver, copper, nickel, or platinum, increases in direct proportion to the rise in temperature.
This is referred to as a positive temperature co-efficient. An RTD consists of a wire wound resistance
forming part of a Wheatstone bridge. A change in temperature will cause the bridge to become
unbalanced. The voltage imbalance across the bridge can be used for indicating, recording, and
controlling. Resistance thermometers are more sensitive than thermocouples over small
temperature ranges.
THERMISTOR
The term "thermistor" evolved from the phrase "thermally sensitive resistor.” Thermistors are
temperature sensitive materials that decrease in resistance with an increase in temperature. This is
known as a negative temperature co-efficient. Thermistors exhibit a large change in resistance over
a relatively small range of temperature. There are two main types of thermistors, positive
temperature coefficient (PTC) and negative temperature coefficient (NTC). NTC thermistors are
commonly used for temperature measurement.
A thermistor is made by compressing oxides of cobalt, iron, manganese, or nickel into desired
shapes, and connecting them in a bridge circuit for temperature measurement.
One disadvantage of the thermistor is its greater nonlinearity with temperature, as compared to
resistance thermometers.
RADIATION PYROMETER
This instrument operates on the principle that the intensity of heat radiation from the surface of a
body increases proportionately to the fourth power of the absolute temperature of a body. Energy
from a hot object is focused on a thermopile (a number of thermocouples connected in series) by a
pyrometer lens. The voltage generated by the thermopile can operate a voltmeter with a scale
calibrated in °C, or it may be used to record and control temperatures in the same way as
thermocouples. Fig. 6 shows a simplified sketch of the radiation principle.
Figure 6
Radiation Pyrometer
Radiation pyrometers are used in the following applications:
•
The measured temperature is above the range of thermocouples
•
The furnace atmosphere is detrimental to thermocouples
•
It is impossible to contact the material where temperature is measured
OPTICAL PYROMETER
The optical pyrometer, shown in Fig. 7, operates on the principle that the color of a hot object is a
measure of its temperature. In the pyrometer, the light from a hot body is compared to the light
emitted by a heated filament. By reducing the resistance in the electrical circuit, more current is
allowed to pass through the filament and to be brighter in color. When the brightness of the
filament is equal to brightness of light from the hot body, the amount of current passing through
the filament will be proportional to the temperature of the object. The scale on the ammeter will be
calibrated in °C.
Figure. 7
Optical Pyrometer
Objective Two
When you complete this objective you will be able to…
Describe the design, operation and applications for the following pressure devices: bourdon tubes,
bellows, capsules, diaphragms, and absolute pressure gauge.
Learning Material
BOURDON TUBE
A Bourdon tube gauge has an oval cross section, which is often shaped in the form of a C, having an
arc span of about 270°. The free end of the tube is sealed, while the other end that contains the
pressure inlet is connected to a socket. When pressure is applied to the inside of the tube, it causes
the tube to assume a more circular cross section, as shown by the dotted lines in Section “A-A” of
Fig.8. As the tube becomes more circular in cross section, it straightens out to some extent and
causes the free end to move. This linear motion of the free end is transmitted through a link to a
geared sector and pinion that causes rotation of the pointer. If the pressure in the boiler or pressure
vessel should decrease, the tube will act like a spring and will tend to return to its original shape.
Figure 8
Bourdon Tube Gauge
Fig. 9 shows the components of a Bourdon tube gauge, which operates in a similar manner to Fig.
8. The purpose of the hairspring is to take up any backlash or play between the gear teeth of the
pinion and those of the sector.
Figure 9
Pressure Gauge Components
(Courtesy of Ametek/US Gauge)
Fig.10 illustrates a double Bourdon tube steam gauge that is used on portable units or where
external vibrations will cause fluctuations in the gauge indication. When an increased pressure is
applied to the gauge, both tubes will deflect outward and cause the rack or arm to move to the right
and produce rotation of the gear and pointer.
Figure 10
Double Bourdon Tube Steam Gauge
A Bourdon tube can also be shaped into a spiral or a helix, as shown in Fig. 11 and 12. The spiral or
helix type is often used to develop sufficient power and rotation to position a pen directly on a chart
without the use of gears. With more windings, a greater degree of rotation is obtained. Like the “C”
type, they are used only through that portion of the range where rotation is linear with the applied
pressure to the tube.
Figure 11
Spiral Bourdon Spring
Figure 12
Helix Bourdon Tube
A great range of pressure gauges with Bourdon tubes is available, as shown in Fig. 13. In vacuum
measurement, air is withdrawn from the gauge, and the tube moves inwards.
Figure 13
Some Pressure Gauge Ranges
BELLOWS
The bellows or capsule element, as a pressure-deflecting element, is useful and accurate in the
range between 250 mm water and about 350 kPa. It consists of a metal tube that may expand in
the direction of its length. When made in large diameters, they develop considerable force and are
better able than the Bourdon tube. The bellows or capsule elements are made in one of several
ways:
•
•
•
•
Stamped out mechanically from cylindrical stock tubing
Consists of several annular rings welded together
Turned from solid cylindrical stock
Consists of a series of capsules, as shown in Fig. 14, with each capsule designed to expand
lengthwise
An increase in the number of corrugations in the bellows causes further travel of the tube. By using
bellows or capsules with large diameter and many corrugations, it is possible to derive considerable
work or energy from very low pressures.
In the range of 0 to 210 kPa, it is customary to use separate calibrating springs rather than depend
on the spring rate of the bellows itself. It is in this range that the great majority of bellows units are
used, particularly in transmitters, recorders, and controllers. It is standard practice to use springs to
assure constant rate of deflection, for a given pressure, in any of these units. The springs may be
mounted in the bellows or externally.
Figure 14
Bellows Made Of Capsules
Fig. 15 illustrates a simple type of bellows having the pressure applied against the outside surface.
In other designs the pressure may be applied to the inside of the bellows.
Figure 15
Pressure-Actuated Bellows Loaded
With Tension Calibrating Spring
With this type, in Fig.15, the pressure acting on the outside of the bellows will cause it to contract
thus moving the linkage. This movement may be used for an indicating pointer, a recording pen, or
a transmitting mechanism. When the maximum design pressure is reached, the overload stop stops
further movement of the bellows to prevent damage to the linkage, indicator, and the bellows.
Bellows or capsules are made of material suitable for the application and is available in all of the
materials from which Bourdon tubes are made. Brass or phosphor bronze is often prescribed for
average, non-corrosive process measurements. Both springs and bellows are so carefully made and
heat-treated that they have an extremely long cyclic life before exhibiting fatigue.
CAPSULES
Fig. 16 illustrates a pressure indicator using a multiple capsule arrangement as the pressure-sensing
element. The pressure to be measured is applied inside the capsules and the force developed is
balanced by the spring action of the multiple capsule arrangements. In this type, the outside
surface of the assembly is exposed to atmospheric pressure so the indication is gauge pressure.
Figure 16
Multiple Capsule Pressure Indicator
DIAPHRAGMS
For very low pressures up to ±250 mm of water a non-metallic diaphragm, called a limp diaphragm,
is made to distort and either stretch, compress, or deflect a spring. The material in the diaphragm
must be completely free of any spring characteristics and may include a plastic, cotton-lined rubber,
leather, or impregnated silk.
Fig. 17 shows a sectional view of a diaphragm. A thin metal disc is attached to the diaphragm at the
center to give it added strength. Fig. 18 details schematically the principals involved. The
diaphragm is connected by a pushrod to a pointer through a series of linkages.
Figure 17
Diaphragm Sectional View
Pressure or vacuum to be applied to the gauge is connected to the housing that encloses the
diaphragm. With an increase in pressure, the diaphragm and the pushrod rise to lift the pointer.
But, if a vacuum is measured the pressure in the casing would be below that of the atmosphere.
The diaphragm and the pointer would then be forced downward to indicate a negative pressure or
vacuum on the scale. The zero pressure indication may be in the middle of the scale so positive or
negative (vacuum) pressures can be indicated in mm of water. Such gauges are used to measure
draft in a boiler furnace.
Figure 18
Diaphragm Pressure Indication
ABSOLUTE PRESSURE GAUGE
Fig. 19 shows a pressure gauge that can be used to measure absolute pressure. A vacuum is
created between the two concentric bellows. When the pressure under measurement is applied
inside the casing, the evacuated bellows will be compressed until the force applied to the bellows is
equal to the force of the spring. As atmospheric pressure acts on both sides of the bellows plate, its
effects are neutralized.
Figure 19
Bellows Absolute Pressure Gauge
Objective Three
When you complete this objective you will be able to…
Describe the design, operation and applications for the following flow devices: orifice plate, venturi
tube, flow nozzle, square root extractor, pitot tube, elbow taps, target meter, variable area,
nutating disc, rotary meter and magnetic flowmeter.
Learning Material
ORIFICE PLATE
An orifice plate is the most common form of restriction that is used in flow measurement. Fig. 20
illustrates how the pressure of a fluid changes as it passes through the orifice plate. The lowest
pressure occurs at the point where the fluid has the smallest cross sectional area and this point is
called the vena contracta. It is located a short distance downstream from the orifice plate. From this
point after the orifice plate, the pressure begins to increase again. But, the entire pressure drop is
not recovered as some permanent loss of energy occurs due to friction and turbulence.
Figure 20
Pressure Variations Through Orifice Plate
The pressure differential across the orifice plate is measured by a high-pressure connection before
the plate and a low-pressure connection after it, as shown in Fig. 21.
Figure 21
Orifice Plate with Pressure Taps
Fig. 22 shows various designs of orifice plates. It consists of a disc of metal about 1.6 mm to 6 mm
thick, with an opening of a fixed area. A concentric type is the most common but the eccentric and
segmental orifice plates are also used. The outside diameter of the plate is such that it will fit inside
the bolt circle on standard pipe flanges. Special flanges with high and low-pressure connections
drilled in them are used for differential pressure measurement. This is known as a flange tap
connection.
When orifice plates are made thicker to prevent the plate from bulging due to excessive differential
pressures, one edge of the plate may be beveled. In this case, the sharp edge must always face the
upstream side of the flow.
Figure 22
Orifice Plates
The orifice plate has the advantage over other types of metering restrictions because it is easy to
install and replace. It is low in cost, and different sizes may be easily substituted to give different
flow ranges. A most undesirable feature is the high permanent pressure loss that is created due to
the turbulence in the flow across the orifice plate.
VENTURI TUBE
Another type of restriction used for measuring flow is the venturi tube, illustrated in Fig. 23. This is
a fitting, installed between flanges, which converts to a minimum cross section, called the throat
and then diverges to the original pipe size. High and low pressure taps are installed at specified
locations as indicated.
Figure 23
Venturi Tube
A venturi tube produces less permanent pressure drop than an orifice plate. It will handle about
60% more flow than an orifice plate with the same pipe size and the same pressure differential. On
the other hand, the venturi tube has the disadvantages of bulkiness and high cost.
FLOW NOZZLE
The flange type flow nozzle, shown in Fig. 24, is an adaptation of the venturi tube. It is essentially a
venturi tube without a diverging section.
Figure 24
Flow Nozzle
Pressure recovery is not as efficient as with a venturi tube, since the fluid expands in a turbulent
manner after it passes the throat section. Its principle use is for the measurement of high velocity
flow streams.
A flow nozzle will accommodate a greater rate of flow (about 60%) than an orifice plate for a given
differential pressure and throat diameter. The high-pressure connection is usually located one pipe
diameter from the nozzle inlet face. The outlet of the nozzle should cover the low-pressure tap,
which is located 0.5 times the pipe diameter from the inlet face.
Compared to the orifice plate, the flow nozzle will require fewer sections of straight pipe at the fluid
approach and discharge sides. Nozzles are more difficult to install than orifice plates. The pipe must
be sprung sideways before the nozzle can be inserted in the pipeline.
Flow nozzles tend to sweep particles through the throat, but some fouling may occur. For this
reason, nozzles are not recommended for measurement of fluids with high solids concentrations
unless the nozzle can be mounted in vertical pipes with the flow downwards. In order to achieve fine
accuracy when measuring liquids with entrained gases, nozzles should point upward.
Another disadvantage is that the nozzle is two or three times more expensive than the orifice plate,
or even more, if it is mounted at the factory in a spool piece of pipe.
SQUARE ROOT EXTRACTOR
When a float type manometer is connected to an orifice plate or venturi tube, the movement of the
float and the output spindle is proportional to the differential pressure. However, in many plant
operations it is necessary to have an output from an instrument that is proportional to flow. Since
the flow is proportional to the square root of the pressure differential, a square root extractor is
required
Therefore, the purpose of a Square Root Extractor is to linearize the flow signal. The output signal
from most differential pressure devices is the Square Root of the differential pressure.
PITOT TUBE
If a tube is placed with its open end facing into a stream of fluid, the fluid impinging on the open
end will be brought to rest, and its kinetic energy converted into pressure energy. The pressure
built up in the tube will be greater than that in the free stream by an amount equal to the impact
pressure or the pressure produced by the loss of kinetic energy.
This increase in pressure will vary as the square of the velocity of the fluid stream. The difference
between the pressure in the tube and the static pressure of the stream is a measure of the impact
pressure, and indicates the velocity of the fluid stream. The static pressure is measured by tapping
into the pitot tube. One of the traditional pitot tube designs is shown in Fig. 25.
Figure 25
Pitot Tube
The pitot tube used in a single location is particularly sensitive to upstream disturbances. For this
reason, an upstream piping run of 50 times the pipe diameter is recommended.
For more accurate measurement, static pressure should be measured at more than one point. The
impact and static pressures should be at right angles to each other, as shown in Fig. 26.
Figure 26
Pitot Tube
Pitot tubes are used where the permanent pressure loss through other devices cannot be tolerated,
and where the accuracy is not of prime concern. Pitot tubes have disadvantages that limit their use
in industrial applications:
•
•
•
Low accuracy, at low velocities
Tendency to plug in fluids containing suspended solid particles unless provision is made for
purging or flushing
Sensitivity to local disturbances in flow
The device is affected little by corrosion and erosion because the opening of the impact nozzle
measures total head pressure, and is reasonably independent of the size and the shape of the
nozzle. The pitot tube is a useful device for making temporary measurements of flow, and is used
extensively in measuring the velocity of aircraft relative to the air. It causes practically no pressure
loss in the flowing stream and is readily installed through a nipple in the side of the pipe. Another
advantage is low cost.
The averaging pitot tube, shown in Fig. 27, is a modified version of the standard pitot tube which
circumvents many of the problems associated with flow profiles across pipes and ducts.
Averaging pitot tube senses impact pressure caused by the fluid velocity by means of four ports of
equal cross-sectional area distributed along the pipe diameter to provide a single indication of the
average flow through the pipe. Static pressure is measured by a tube terminating in a port, which
faces downstream at the centerline of the fluid connector.
Figure 27
Averaging Pitot Tube
Averaging pitot tubes are suitable for measuring the rate of flow of high temperature, high
pressure, and corrosive fluids. Some models are designed to allow installation, removal, or
reinsertion without shutting down the system.
ELBOW TAPS
Elbow taps are an economical method of measuring flow rate. The device is made by drilling two
taps in an existing elbow and connecting the taps to a transmitter. Since the elbow is already in the
piping system, no further pressure loss is experienced. The taps are located midway around the
elbow and on the inside and outside of the elbow. A long length of straight pipe before the elbow,
and high velocity fluid flow, is required. Elbow taps measure the differential pressure due to the
change in centrifugal force as the fluid direction is changed through the elbow. Fig.28 shows a
typical elbow tap.
Figure 28
Elbow Tap
From Instrumentation For Process
Measurement and Control by Norman
A. Anderson, Copyright 1980 Reprinted
with the permission of the publisher,
Chilton Book Company, Radnor, PA.
TARGET FLOWMETER
Fig. 29 shows a schematic of a target flowmeter with a pneumatic flow transmitter, and an output
that is proportional to the applied force.
The target flowmeter operates by measuring the impact force provided by a flowing fluid. The fluid
impinging on the target will be brought to rest, so the pressure increases by V 2/2g in terms of
head, where V is the velocity in m/s, and g is the acceleration due to gravity. The force developed
on the target is balanced through the force bar by air pressure in the bellows so that a 20-100 kPa
signal is obtained that is proportional to the square root of the flow.
The target flowmeter requires the same length of straight pipe upstream and downstream as an
orifice. The accuracy may be in the range of ±0.5%. The meter can be used in such difficult flow
measuring applications as hot, tarry, sediment-bearing fluids, or corrosive and abrasive slurries.
Targets with diameters of 0.6, 0.7, and 0.8 times tube diameter are available. Pressures as high as
10 000 kPa, at temperatures up to 400°C, can be handled when the transmitter is welded into the
line.
Figure 29
Target Flow Meter
VARIABLE AREA METER
The variable area meter or rotameter, shown in Fig. 30, is mainly used as an indicating device. The
variable area meter consists of a tapered tube in which a float or rotor can move freely up or down.
The fluid being measured flows through the tube from the bottom to the top, and this causes the
float to take position part way up the tube. As the flow increases, the float assumes a higher
position and the flow rate can be read from a graduated scale located adjacent to the tube or etched
directly on it.
The float of the meter adjusts the area surrounding the float by rising or falling with a change in
flow so the differential pressure across the float is kept constant.
Advantages of this meter include low cost, simple construction, low-pressure drop through the
meter and good accuracy.
Figure 30
The Glass Tube Rotameter
NUTATING DISC METER
A nutating disc meter consists of a flat circular disc that has a ball-like structure at the center. The
bottom part of the ball rests in a socket while the top of the ball has a small shaft protruding from
the center, which turns a propeller-like gear connected to the integrator. The upper part of the plate
is unrestrained and the shaft assumes a position about 15° from vertical.
The flat disc has a slot in which a fixed vertical partition is rigidly placed so that the motion of the
disc is restricted to a definite pattern. One end of the disc diameter will rise as the disc rotates on
the ball and the other end will drop. The division plate also serves to partition the inlet flow to the
meter from the discharge. As the water enters the meter, it causes the disc to wobble. While water
is being admitted under the disc, the water above the disc is discharged with each revolution
trapping a given volume of liquid. The free end of the disc, containing the shaft, moves in a circular
path as the disc nutates. This circular motion rotates the gear train and drives the counter. The
pressure of the water provides energy to rotate the meter. Fig. 31 helps to illustrate the principle of
operation.
The nutating disc type is the most common meter in use, especially in domestic and industrial water
supplies.
Figure 31
Nutating Disc Meter
ROTARY METER
A rotary meter, shown in Fig. 32, is suitable for gas measurement only. It consists of lobed
impellers operating in the directions shown by the arrows. Exterior timing gears keep the teeth
mesh in the correct phase and an exterior counter registers the accumulated revolutions.
In operation, inlet gas fills the space shown shaded in position 1. The differential pressure between
inlet and outlet causes the impellers to rotate. A specific volume “A" of gas is trapped in position 2,
while “B” is filling with gas that will be similarly trapped as shown in position 3. For gas to escape
“A”, it imparts a further rotation to the left-hand impeller. Once established, rotation is continuous
while a pressure differential remains.
Figure 32
Principle of Gas Flow Through a Rotary Meter
MAGNETIC FLOWMETERS
Magnetic flowmeters are based on Faraday’s Law of electromagnetic induction that states that when
a conductor moves through a constant magnetic field, a voltage is produced which is proportional to
the relative velocity at 90° to the field. For best results the conductor should pass through the field
at right angles. Referring to Fig. 33, the magnetic flow meter consists of the following:
•
•
•
•
Two magnetic coils saddled on either of the pipe
Two electrodes opposite each other
An insulated liner
A signal conditioner
Figure 33
Magnetic Flowmeter
The two coils, shown in Fig. 34, are positioned on opposite sides of the pipe and the field between
them is perpendicular to the pipe.
Figure 34
Coils and Fields
The liquid, which must be conductive, flows through a pipe that is lined with an insulating material
such as fiberglass, neoprene, Teflon, or other suitable material. The liquid serves as the conductor
between the electrodes. This type of meter can accurately measure flows from 10-3 to 105 m3/h
and the only limitations on pressure and temperature are what the pipeline and the insulated liner
can safely handle. Viscosity and density changes have no effect on the accuracy. This is a bidirectional meter, as upstream or downstream piping does not affect the magnetic flowmeter.
Because of the clear flow-through construction there is no pressure loss across this meter.
The advantages of this meter are:
•
•
•
•
•
Obstructionless flow, which gives no pressure loss
Suitable for slurries and acids
Bi-directional
Linear
Large range ability and large volumes
The disadvantages are:
•
•
•
•
Fluid has to be conductive, will not work in hydrocarbons
Larger sizes are big, heavy, and expensive
A buildup of material on the inside of the pipe wall could become a factor if the buildup is
not of the same conductivity as the liquid
Pipe must always be full of liquid to obtain maximum performance
Objective Four
When you complete this objective you will be able to…
Describe the design, operation and applications for the following level devices: atmospheric and
pressure bubblers, diaphragm box, differential pressure transmitters, capacitance probe,
conductance probes, radiation and ultrasonic detectors, and load cells.
Learning Material
ATMOSPHERIC BUBBLER
In the bubble pipe level measurement system, the pressure of air or other gas that is required to
overcome the opposition of liquid head is proportional to the level.
Fig. 35(a) shows a simple bubbler system. A needle valve or pressure regulator provides a source of
gas or air pressure to a bubble pipe immersed at a fixed depth in the liquid. The bottom of the
bubbler standpipe is located at the zero or datum line in the tank. Sufficient air pressure is supplied
by the needle valve, or regulator, to give a slow but steady stream of bubbles when the tank level is
at maximum. A rotameter may be used to determine the flow rate.
Changes in measured level cause the pressure in the bubble pipe to vary by allowing more air to
escape when the level drops and vice versa. A pressure-sensing instrument will convert this
pressure into terms of liquid level on an indicator, level recorder, or manometer.
Figure 35
Atmospheric Bubbler System
Large variations in level will cause large fluctuations in the airflow, resulting in greater inaccuracy of
measurements. A differential pressure regulator can be installed, as shown in Fig. 35(b), to
maintain a constant pressure drop across the rotameter and give a more uniform flow out of the
bubbler tube.
The accuracy of level measurement is affected by changes in liquid density. With constant density,
the accuracy can be ±1 to 2%. It is recommended that the distance between the bottom of the tank
and the bubble pipe be not less than 75 mm to avoid blockage of the pipe due to a sediment
buildup.
A V-notch should be cut in the bottom of the pipe so the air can come out in a steady stream of
small bubbles rather than in intermittent, large bubbles.
PRESSURIZED BUBBLER
More complex bubble pipe systems are used for measuring levels in sealed or pressurized tanks.
Liquid vaporization will increase the pressure above the liquid. If this pressure is sensed by the
measuring system, the total measured pressure would be equal to the vapor pressure plus the
pressure due to the liquid head. The system shown in Fig. 36 is used to overcome this problem.
Figure 36
Bubble Pipe System for Sealed Tanks
This consists of a dual bubble pipe system. The HP (high pressure) side measures both the liquid
head and vapor pressure while the LP (low pressure) side measures the vapor pressure only. Since
the measurement of differential pressure is involved, any differential pressure instrument, including
a transmitter, may be used. The output of this device would be proportional to the liquid level in the
tank.
The different designs of bubbler pipe systems described require no moving parts in contact with the
liquid. This makes this system suitable for level measurement of high temperature and corrosive
liquids or slurries. As only the piping or tubing is exposed to corrosion, maintenance involves items
that are low in cost.
A disadvantage of this system is that the liquid must be able to mix with the gas or air used. There
must also be an access to the top or side of the tank so the piping can be installed properly.
DIAPHRAGM BOX
A diaphragm may be used as a level-sensing element for both open and closed tanks or vessels.
One method of measuring the level in an open tank with a diaphragm box is illustrated in Fig. 37.
It contains a diaphragm box consisting of two sections, with a flexible diaphragm between each
section. The liquid level that is measured comes in contact with one side of the diaphragm, while
the other side is contacted to a level instrument through a capillary tube. The diaphragm box is
installed at a fixed point, usually the minimum level, of an open or thoroughly vented tank. The
diaphragm box may be supported from the top of the tank by piping or rigid tubing while the
diaphragm box is submerged in the liquid. The internal diameter of the capillary tubing, furnished
with the box, is no larger than 2 mm.
Figure 37
Diaphragm Box Level Sensor
When the level in the tank increases, the diaphragm is distorted farther as a greater pressure is
exerted on the liquid side of the diaphragm. Greater deflection of the diaphragm causes the liquid in
the capillary tubing to be compressed until its pressure is the same as the liquid head in the tank.
This pressure is applied to a sensing element, which transmits a proportional motion to a pen,
indicating pointer, or a flapper-nozzle assembly in a transmitter.
The liquid in the diaphragm box and tubing should be at operating temperature when the pressure
connections are made to the level instrument. The diaphragm box should not be under liquid
pressure when this is done. Rubber diaphragms should not be subjected to temperatures above
65°C.
This type of level sensor has a low initial cost and is relatively maintenance free. It is also
satisfactory for liquids containing suspended solids and for slurries with finely divided particles.
DIFFERENTIAL PRESSURE TRANSMITTER
A diaphragm actuated differential pressure transmitter, shown in Fig. 38, is connected to a pressure
vessel to measure level when there is a vapour above the liquid. A simplified cross sectional view of
the diaphragm and transmitter assembly is illustrated in Fig. 39. In this example, the high-pressure
side of the diaphragm is connected directly to the tank while the low-pressure side is filled with
sealing fluid, usually water for water level measurement.
Figure 38
Level Measurement
Figure 39
Differential Pressure Transmitter
In the transmitter, one end of the force bar is connected to the diaphragm while the other end acts
as a flapper that restricts the amount of air bleeding through an air nozzle. A continuous air supply
is provided to the transmitter so that the height of liquid in the tank can be converted into a
constant proportional air or pneumatic output signal.
When the level is at minimum, the transmitter is calibrated so that the output signal is at a
minimum value, usually 21 kPa. As the level rises, the increasing head or column of liquid causes
the pressure on the right hand side of the diaphragm, in Fig. 39, to be greater than the pressure on
the left. This pressure differential causes the top of the force bar to rotate slightly clockwise about
the fulcrum. This action results in a reduction in the clearance between the nozzle and the bar or
flapper. Output from the pneumatic relay increases in direct proportion until the force in the
feedback bellows balances the force on the diaphragm caused by the differential pressure. When the
level rises to maximum, the output pressure increases to a maximum value of 100 kPa.
CAPACITANCE PROBE
A capacitor is simply two plates, separated by a distance, with an insulating substance between
them having a known dielectric constant. Most gases have a dielectric constant of 1, while solids
and liquids have a higher dielectric constant. The capacitor will store electrical energy and release it
at a later time. The phase shift, if using AC power, or the amount of electrical potential stored, can
be measured. Either of these two measurements will be an indication of the dielectric constant of
the material between the conducting plates. This principle is used in continuous level measurement
by measuring the stored potential (or the phase shift) as the level in a vessel rises between two
capacitor plates.
The measurement device may consist of a probe placed in the vessel with the probe acting as one
plate of the capacitor and the vessel wall acting as the other plate, as shown in Fig 40. In other
applications, there may be two separate probes, or one probe within a second probe.
Figure 40
Capacitance Probe
(Courtesy Petroleum Extension Service, University
of Texas)
Figure 41
Capacitance Level Measurement
From Instrumentation for Process Measurement and
Control by Norman A. Anderson, Copyright 1980.
Reprinted with the permission of the publisher, Chilton
Book Company, Radnor, PA
The probe, shown in Fig. 41, may be bare or coated with Teflonä. The bare probe is more likely to
be used when measuring the level of solids within a vessel. The Teflonä coated (insulated) probe
will be used when measuring fluid levels.
Advantages of the capacitance level instrument are:
•
•
•
No moving parts
Easy transmission of the signal from remote locations
Probes that can be designed for use in high temperature, high pressure, and corrosive
conditions
The disadvantages of the capacitive level instrument are that it will have large errors due to
changes in the:
•
•
•
Dielectric constant of the material
Composition of the material
Temperature of the material
To avoid these problems, the liquid being measured should have a uniform composition.
These instruments have an accuracy of 1% to 2% of full scale.
CONDUCTANCE PROBES
Conductance probes are point level measurement devices used to open or close a circuit, which
would alert the operator to a low or high-level condition. Two electrodes are immersed in the vessel.
When a conducting fluid covers both electrodes, the circuit is closed. When the level falls below one
of the electrodes, the circuit is opened. The fluid being measured must be capable of conducting an
electric current of several mA. The closed circuit between the two electrodes can be amplified to
start or stop a pump or send an alarm signal to a control panel. The conductive electrodes can be
coated with Teflonä or plastic, for use in high temperature or corrosive service. Fig. 42 shows a
simple conductance level measurement system.
Figure 42
Conductance Level Measurement
From Instrumentation for Process Measurement and
Control by Norman A. Anderson, Copyright 1980.
Reprinted with the permission of the publisher, Chilton
Book Company, Radnor, PA
RADIATION DETECTOR
Radiation level measurement devices use a source of gamma radiation installed either inside the
vessel or attached to the outside of the vessel. A detector is placed opposite the radiation source,
and the amount of radiation received from the source is an indication of the level in the vessel. The
radiation source may be located at the bottom of the vessel with the detector at the top, as shown
in Fig. 43. The source may be a strip of radiation material located vertically along the side of the
vessel with the detector located on the opposite side. In either case, the higher the level in the
vessel, the lower the reading will be on the detector, as more of the gamma radiation is absorbed
by the contents of the vessel. A gamma ray is a very short wavelength electromagnetic radiation
and, although highly penetrating in nature, they do not alter the contents of the vessel.
Figure 43
Radiation Level Measurement
(Courtesy Petroleum Extension Service, University of Texas)
Special precautions must be taken when dealing with these devices, since exposure of living tissue
to gamma radiation has long-term health risks. The radiation source is usually a ceramic pellet
contained in a lead-lined stainless steel container, with a narrow gap for the release of gamma
particles. The container has a cover which can be moved over the gap when the vessel requires
maintenance or when shipping the container.
Radiation level measurement devices solve some unique problems of measurement by not being in
contact with the contents of the vessel. However, these devices are high in cost and have special
handling requirements.
ULTRASONIC DETECTOR
Ultrasonic level measurement devices rely on the change in the speed of sound through different
substances. An ultrasonic pulse generator, operating in the 30 to 40 kHz range, provides the source
signal. For level measurement of solids, the generator and receiver must be located at the top of
the vessel. For liquid level measurement, the transmitter and receiver may either be located at the
top or at the bottom of a vessel. The receiver will record the time it takes for the sound to travel
from the generator to the surface of the liquid (or solid) level being measured and back to the
receiver. Once the speed of sound of the signal through the material is known, the level can be
determined. These measurement devices must compensate for temperature changes, as the speed
of sound in all substances changes with an increase or decrease in temperature.
Fig. 44 shows a simple arrangement of an ultrasonic level measurement device. With accuracies of
less than 2% of full scale, these devices are used in the measurement of level in large storage
vessels and for determining the level of liquid at the bottom of deep wells.
Figure 44
Ultrasonic Level Measurement
From Instrumentation for Process Measurement and
Control by Norman A. Anderson, Copyright 1980.
Reprinted with the permission of the publisher, Chilton
Book Company, Radnor, PA
LOAD CELLS
The use of load cells for measuring the weight of the contents of tanks is gaining popularity. When
the tank contains solids or highly corrosive liquids, other common methods of level measurement
may not be practical. It may be difficult to provide and maintain special pipe connections, pressure
taps, purges, floats, or other specialized equipment required with conventional instruments. If the
tank contains solids or slurries, the conventional methods may not respond accurately to changes in
storage tank contents.
A load cell can be conveniently installed to measure the total weight, or a fraction of the weight, of
material in the tank. Since the load cell is mounted externally from the tank, the measuring problem
is simplified considerably.
The measuring range of the load cell is selected for the nearest net weight of a full tank. This range
is suppressed by an amount equal to the weight of the empty tank. When making an installation of
this type, it is important that pipe connections to and from the tank be flexible, so that expansion
and contraction of the piping cannot exert a force on the load element.
Fig. 45 shows a hydraulic load cell measuring the total weight of a tank.
Figure 45
Hydraulic Load Cell
Although load cells are expensive, they have the advantage of having no direct contact with the
contents of the vessel. A major disadvantage is that the instrumentation may not give accurate
readings if there is a change in density of the material in the vessel.
Distributed and Logic Control
Learning Outcome
When you complete this learning material, you will be able to:
Explain the general purpose, design, components and operation of distributed and programmable
logic control systems.
Learning Objectives
You will specifically be able to complete the following tasks:
1.
2.
3.
4.
5.
Explain distributed control and describe the layout and functioning of a typical distributed
control system. Explain the function of each major component of the system.
Identify and explain the functions of the major components of the operator interface unit
(OIU), including controller interfaces, displays, alarms and shutdown.
State typical applications and explain the purpose and functioning of a programmable logic
controller, including the operator interfaces.
Identify, state purposes of, and interpret in simple terms, ladder logic diagrams for
programmable controllers.
State the purpose and explain the general functioning of a communication and data
acquisition system (eg. SCADA) as it relates to process control.
Objective One
When you complete this objective you will be able to…
Explain distributed control and describe the layout and functioning of a typical distributed control
system. Explain the function of each major component of the system.
Learning Material
DISTRIBUTED CONTROL SYSTEM LAYOUT
Distributed Control Systems (DCS) currently control many production facilities. Distributed control
allows the control of process parameters from one central location. A Distributed Control System is
instrumentation used for industrial process control. The components making up a DCS are installed
in two different work areas of processing installations and are separated by function.
The operator interface unit allows the operator to monitor process conditions and manipulate set
points of the process operation. The operator interface unit is located in a central control room.
From this location the operator can:
•
View information transmitted from the processing area on an output device such as a video
monitor
•
Change control conditions from input devices such as a keyboard, mouse or touchscreen.
The measurement and control components of the system are distributed at locations throughout the
process area and perform two functions at each location:
•
The measurement of analog and/or digital inputs
•
Generation of output signals to actuators that can change process conditions.
Early centralized control systems had separate sets of wires connected from each controller to its
field transmitters and control valves. The control panels were large, having to have space for each
controller, recording chart and switch. This type of panel is illustrated in Fig. 1. It also has a
computer, which controls some of the critical control loops.
In newer systems the panel boards and consoles of an older analog system are eliminated and the
communications are over a shared cable. The shared cable arrangement is called a data highway.
The data highway minimizes the quantity of wiring while allowing for unlimited reconfiguration
flexibility (see Fig. 2). No change is required to the wiring when process modifications result in
additions to the control system.
Figure 1
Analog Control System
Figure 2
Distributed Control System with Data Highway
DCS Components and Their Function
Components of a DCS include: transmitters and final control elements (FCEs), input/output cards
(I/O), controllers, the operator’s console (OP/CON), and a network. A DCS system with a data
highway is shown in Fig. 3.
Transmitters measure a process parameter such as temperature, pressure, level, or flow and send a
corresponding signal, by means of electrical transmission, to the I/O card.
FCEs respond to a signal generated by the I/O card and manipulate a control variable such as steam
flow. The signal is normally sent to a control valve. The I/O card sends a milliamp signal to a
current to pressure transducer. It changes the milliamp signal to a 20-100 kPa air signal, used to
position the control valve.
Figure 3
DCS System
The I/O cards both receive and transmit signals to and from the field. Input and output signals can
be both analog and digital. I/O cards may perform analog to digital conversion (ADC) and digital to
analog conversion (DAC) to interface with the electrical signals generated by the transmitters or
required by the FCEs.
Controllers read the input signal use the programmed algorithms to calculate the corrective output
signal. These programmed algorithms are called function blocks and include proportional, integral,
and derivative functionality.
The OP/CON allows the operator to monitor the process and manipulate the setpoint or the desired
output of the process manually.
The network is the communication path provided to carry signals from the field to the control room.
The communication path is either a point-to-point twisted pair wire from each remote location to the
central station as in Fig. 1, or a single cable interfacing all the remote stations as in Fig 2.
Objective Two
When you complete this objective you will be able to…
Identify and explain the functions of the major components of the operator interface unit (OIU),
including controller interfaces, displays, alarms and shutdown.
Learning Material
THE OPERATOR INTERFACE UNIT
The operator interface unit allows operating personnel and process control engineers to alter the
setpoint at which the process is controlled. For example, an operator can increase boiler pressure by
changing the setpoint on the boiler master from the control console without having to go to an
individual boiler.
An operator interface unit has input and output devices, which enable an operator or engineer to
alter plant-operating conditions. The principle components of the operator station are a video
monitor, keyboard, and mouse/trackball.
The video monitor, or CRT, is a means of providing plant information or output to the operator. The
operator of a DCS depends on the video monitor to scroll through a variety of displays pertinent to
the process. There are four types of process displays common to many suppliers’ systems. These
include the: Graphic display, Detail display, Trend Display, and Alarm display.
GRAPHIC DISPLAYS
Graphic displays allow the operator to view a process in the form of a picture or animation. The
various parameters associated with the process (temperatures, pressures, and levels) dynamically
change as real time information changes. This provides the operator with all the information
necessary to make informed decisions. For example, a tank will fill with color when the level rises.
In Fig. 4, the graphic image of the level in the drum D-505 will change as its level changes in the
process.
From this display, a power engineer may have the ability to start or stop a boiler, change the
setpoint of the boiler master or drum level, and place any loop in manual or automatic mode.
Graphic displays are generally organized so the operator has access to the next or previous process
in the controlled system. The number of graphic displays depends upon the complexity of the plant
and the processes.
Figure 4
Graphic Display
Detail Displays
The detail display is specific to a single loop (single controller) and often appears as a single loop
digital controller faceplate. It allows the operator to control such things as setpoint, auto/manual
transfer, and controller output. The faceplate displays “pop up” when a particular process loop is
addressed on the graphic display. It can be selected using a mouse, track ball or touch screen
Fig. 5 shows a detail display of the graphic illustrated in Fig. 4. From a faceplate display such as
this, an operator can easily change the setpoint, or change the controller from automatic to manual.
Figure 5
Digital Controller Display
Trend Displays
Trend displays are the DCS equivalents of chart recorders. Often an operator wishes to follow or
track several process parameters to see what is happening to the process. Dynamic trending allows
an operator to select many process parameters and plot the points on a graph. Fig. 6 shows a trend
display on a CRT screen. The graph produced on the video monitor is the equivalent of a strip chart
recorder, but allows an infinite number of custom selections through the selection (programming)
process.
For example, trend lines T1 and T2 on the display in Fig. 6 show superheater and low-pressure and
high temperature heater temperatures from 16:00 on the 21st to the 12:00 on the 22nd. The
graphs illustrate the link between the two temperatures. The lines go up and down together,
following the same pattern. The two temperatures are closely linked or on the same system.
Temperatures of the superheated steam T3 and the low-pressure steam T4 are not as closely
related. Lines on the graph for these two variables move in different patterns.
Figure 6
Trend Display
ALARM DISPLAYS
As alarm conditions arise, they are immediately brought to the attention of the operator by audible
and visual means. It is the responsibility of the operator to acknowledge the alarm, and decide on
the appropriate course of action. All alarms, whether active, acknowledged, or cleared, are stored in
memory. A report of the daily alarms is available through this display function.
SHUTDOWN
A variable that is above the high alarm can go high enough to reach the high-high alarm. The highhigh alarm can also be connected to initiate an equipment shutdown. Similarly, a low-low alarm
indicates a variable that is running below the low alarm level. It also may initiate equipment
shutdown. Shutdown status can remove control from the operator starting an automatic sequential
shutdown. The automatic shutdown is controlled by the central computer system or by a
programmable logic controller.
Input Devices
An operator or engineer enters information into the DCS through a keyboard, similar to that of a
computer. The keys may be similar to a standard computer keyboard or a membrane type, where
the keys are mounted under a flexible plastic cover. The membrane type is sealed from dust and
dirt, making it suitable for industrial environments.
A mouse or track ball is the standard input device in most plants. Movement of the mouse or track
ball causes a cursor to move on the graphic display. When the cursor is moved to the correct menu
item, it may be clicked to select the desired option. The track ball and mouse are extremely useful,
greatly increasing the speed with which an operator can use a DCS. This also relieves the operator
from manually and routinely entering data via the keyboards.
Touchscreens are another way to interface with a GUI. The sensor screen has an electrical current
or signal going through it. Touching the screen causes a voltage or signal change. This voltage
change is used to determine the location of the touch to the screen. This activates the cursor in the
same way as a mouse or trackball.
Objective Three
When you complete this objective you will be able to…
State typical applications and explain the purpose and functioning of a programmable logic
controller, including the operator interfaces.
Learning Material
PROGRAMMABLE LOGIC CONTROLLERS
The majority of industrial process control installations do more than regulating a dynamic variable,
such as the pressure in a vessel or the level in a tank. These simple control situations are referred
to as continuous control.
There are also many processes in industry in which it is not a variable that has to be controlled, but
a sequence of events. For example, a certain startup sequence must be followed before a boiler can
run continuously. This startup sequence is made up of many actions or steps necessary to complete
a sequence of events. An example would be the sequence for purging a boiler in which the actions
are done in a specific order. The interlocks are checked; the purge is started and completed before
the burners are ignited.
Programmable logic controllers (PLCs) were originally designed to control processes that required a
sequence of events to be followed. Today, PLCs have advanced to the stage of being incorporated in
SCADA (Supervisory Control and Data Acquisition) systems, and continuous control systems. For an
introductory look into the operations of a PLC, this module will concentrate on discrete control,
using PLCs to control a sequence of events. The components of a PLC include the input/output
cards, the processor card, and the operator interface.
Input/Output Cards
PLCs retrieve information from a process, and based upon the information at a particular point in
time, generate a control signal. Fig. 7 shows a block diagram of the inputs/outputs (I/O) of a typical
PLC.
Figure 7
Inputs/Outputs of a Typical PLC
The following terms are commonly used in the industry:
•
•
•
•
DI–Discrete inputs are signals that have only two positions; for example, open/closed or
on/off.
AI– Analog inputs are ever-changing signals, such as temperature. The temperature can be
any value between its upper and lower range.
DO – Discrete outputs are the control signals for devices that have only two positions; for
example, to turn a pump on or off.
AO – Analog outputs are ever-changing signals that control the process. An example is the
control of a valve to perhaps 30% flow, or some other value between its upper and lower
range.
It should be noted that the remainder of this module concentrates on the use of DIs and DOs. Other
I/Os such as thermocouples and RTDs are also available on some PLCs, but the I/Os summarized in
Fig. 7 make up the majority of PLC input points.
Processor Card
Most of today’s PLCs are built around microprocessors. A microprocessor is an integrated circuit that
fits on a single chip. It contains an arithmetic unit, control circuitry, and memory registers. The
processor contains the computing power of the PLC.
Operator Interface
Fig. 8 shows the connection of a PLC programmer to a PLC. A PLC programmer connects to the PLC
so that an operator or instrument technician can enter the ladder logic directly into the PLC. The
ladder logic controls the sequence of events. The operator interface allows the operator to make
changes to the PLC logic and to observe the condition of any portion of the process it controls.
Figure 8
Connection of a PLC Programmer to a PLC
A physical device must be used to configure or program the PLC to carry out the proper sequence of
events. The sequence can be altered any time a PLC programmer is connected. After the ladder
logic has been entered, the PLC programmer is disconnected and the PLC becomes a dedicated
controller. Under normal conditions, the PLC operates the process from the I/O points. PLCs are not
limited to controlling a single process and can control several processes at a time.
Objective Four
When you complete this objective you will be able to…
Identify, state purposes of, and interpret in simple terms, ladder logic diagrams for programmable
controllers.
Learning Material
PROGRAMMABLE LOGIC CONTROLLERS
Programmable logic controllers (PLCs) are computers developed to replace control relays.
The control relay is an electromagnetic or electromechanical device. A small voltage from the
control system is applied to a coil and the resulting magnetic field causes mechanical contacts to
open or close. The contacts become the switches wired into the higher voltage electrical circuit used
to perform the control action.
Symbols for indicating the program that resides in a PLC’s memory were developed from standard
electrical symbols (Fig. 9).
Figure 9
Electrical Schematic Symbols
Ladder Logic Diagrams
The PLC control diagram is called a ladder logic diagram (Fig. 10). Ladder logic is used extensively
when programming PLC’s. Some of the simpler tasks performed by ladder logic will be described
along with a suitable ladder logic diagram that could be used to start a boiler. Instrument
technicians or electricians usually programme the PLC’s.
Figure 10
Ladder Logic Diagram
Inputs are shown on the left side of the ladder and outputs on the
right. On the first or top rung, when the start button (SB) is
pressed contact 1 (C1) is energized. The rung is now considered to
be “true”. With C1’s contacts closed, power passes from left to
right on rung 2, holding C1 in it’s energized state even if SB is
released. C1 remains energized until the halt button (HB) is
pressed or C11 is energized. C1 also energizes C2 on rung 3,
which opens the boiler’s dampers.
C2 allows a damper switch (DS) to energize C3 and start the
combustion fan when the dampers reach a safe position. C3 also
starts a 30 second timer that stalls the ladder program, allowing
the combustion fan to purge the firebox. Then C4 is energized and
the dampers position themselves to minimum and a two second
timer is started. Next, C5 is energized, which starts the igniter and
energizes C6. C6 opens the pilot valve and starts a six second
timer, to allow a flame switch to heat up, before C7 is energized. If
the flame is present, C7 will energize C8, which completes a
successful start-up. However, if the flame is not present, C7 will
energize C9, which will sound an alarm and energize C10.
C10 will open the dampers and start a 60 second timer allowing the
combustion fan to purge the firebox again. Finally, C11 becomes
energized, breaking the circuit in rung 2 and stopping the start-up
cycle.
Objective Five
When you complete this objective you will be able to…
State the purpose and explain the general functioning of a communication and data acquisition
system (eg. SCADA) as it relates to process control.
Learning Material
SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA)
Since the early years of the oil industry, it has been extremely important to monitor well and
pipeline flow. The information gathered from monitoring points can indicate if pumps and/or
compressors are working properly, whether there is a leak in the pipeline, and the current
production rate. To complete this task, people were once employed to check each pumping station,
wellhead, and points along the pipeline. This task was time consuming, expensive, and resulted in
environmental damage because of time delays in locating leaks. The need to solve these problems
led to the development of a system that could be monitored continuously from a remote location.
The SCADA System
SCADA, or Supervisory Control And Data Acquisition system allows continuous process monitoring
and simple loop control. It is accomplished from a distant location by local phone system or radio
transmission. The system consists of a Remote Terminal Unit (RTU), a Master Terminal Unit (MTU),
and modems or other data communication equipment (DCE) compatible with the method of
communication chosen.
Remote Terminal Unit
A Remote Terminal Unit (RTU) is used to monitor and execute simple control of a process. The RTU
consists of a microprocessor, memory, input/output terminals, and a power supply.
Measurement instruments send either an analog or digital signal to the input/output terminals. If an
analog signal is sent, analog to digital converters (ADC) convert the signal to a binary signal that
the microprocessor can understand. This information is manipulated by the microprocessor using
user-configured programming. The resulting information is then sent to a historical log and, if
needed, a control signal is sent back to the process through a digital to analog converter (DAC).
An operator from a distant location using communication equipment accesses the RTU. The person
accessing the RTU can download configurations to the RTU, upload a historical log, change RTU
parameters, or manipulate the process.
Communication
In order to retrieve historical logs or manipulate the process, operators must be able to access
RTUs, through a communication system.
In the main office the operator can call the remote location through a modem and talk to the RTU
using a computer and related software. The software is designed to configure the RTU and access
the historical logs.
Information, configurations, and control signals must be sent across a communication medium.
Communication can be carried out in several ways:
•
On dedicated wires which run directly from the RTU to the central computer
•
Through the telephone system, using modems at the RTU and the central computer
•
Using radio, microwave signals, or satellite links
A simplified sketch of a basic SCADA system, including telephone links, is shown in Fig. 11.
Figure 11
Simplified SCADA System
Running dedicated lines from the central computer to the RTU is extremely costly. The number of
wire pairs installed, plus the cost of installation and operation, generally makes this type of
communication impractical. The advantage of this type of system, however, is uninterrupted contact
with the RTU.
Communicating with the remote site via the local phone system is a practical and cost effective
method of communication with the RTU. A dial-up modem must be installed at each end of the
system, which converts the serial signal used by the phone system to a signal that can be
recognized by the computer. A dedicated phone line is run from each site to the local phone system,
and each site can then be dialed up from the central computer system and accessed accordingly.
The disadvantage of this type of communication is that it relies upon the local phone system as the
main link between the central computer and the remote site. The phone system may not be as
reliable as dedicated lines.
Radio and microwave transmission are popular media used to communicate with RTU’s. A
transmitter/receiver is placed at the remote site along with antennae or microwave dishes. Signals
are then sent to the main computer and received by similar transmitter/receiver equipment.
Very high frequency (VHF) and ultra high frequency (UHF) radio signals have a greater range than
microwave signals, and are not affected as severely by land-bound obstacles. Antennas can be
placed on towers to transmit over top of obstacles.
Microwave signals are sent from one site to another in a series of “hops”. Microwave transmission
equipment can carry large volumes of high-speed data, but it may require greater maintenance
than UHF or VHF radio equipment. Microwave dishes are adversely affected by frost and ice, and
may have to be occasionally realigned by service companies. Microwave signals can be affected by
different reflective properties, such as snow on the ground. Therefore, microwave is a more costly
communication medium than VHF or UHF radio unless very high-speed data, or many voice
channels, are required.
Fire Protection Systems
Learning Outcome
When you complete this learning material, you will be able to:
Discuss the classes and extinguishing media of fires, and explain systems that are used to
detect and extinguish industrial fires.
Learning Objectives
You will specifically be able to complete the following tasks:
1.Explain the classifications of fires and describe the extinguishing media that are
appropriate for each classification.
2.Describe the components and operation of a typical fire detection and alarm system in
an industrial setting.
3.Describe the design and operation of a typical standpipe system.
4.Describe the wet pipe, dry pipe, pre-action and deluge designs for sprinkler systems.
5.Describe the layout, components and operation of a typical firewater system with fire
pump and hydrants. Explain seasonal considerations for a firewater
system.
6.Describe the construction and operation of a typical fire hydrant.
7.Explain the purpose and describe a typical deluge water system for hydrocarbon
storage vessels.
8.Explain the purpose and describe a typical foam system for process buildings and
tanks.
9.Describe a typical fire response procedure for an industrial setting.
Objective One
When you complete this objective you will be able to…
Explain the classifications of fires and describe the extinguishing media that are
appropriate for each classification.
Learning Material
CLASSIFICATION OF FIRES
The following are the four classifications of fires:
Class A
Class A fires occur in ordinary combustible materials such as wood, cloth and paper.
Class B
Class B fires occur in the vapor-air mixture over the surface of flammable liquids such as
greases, gasoline and lubricating oils.
Class C
Class C fires occur in energized electrical equipment.
Class D
Class D fires occur in combustible metals such as magnesium, titanium, zirconium and
sodium.
FIRE EXTINGUISHING AGENTS
The following are the most common types of fire extinguishing agents in use, today, and
the types of fires they are used to extinguish:
Dry chemicals
Gaseous
Dry powders
Water
Foams
Dry Chemicals
Dry chemical fire extinguishing agents stop the chemical chain reaction sequence
associated with fire. On a weight basis, they are probably more effective than even the
halons
in extinguishing fires. As such, they have found their greatest utilization in portable and
wheeled extinguishers and also in some stationary equipment.
Sodium Bicarbonate
The first dry chemical fire-extinguishing agent to be formulated was based on sodium
bicarbonate. It was compounded with certain materials to make the formulation water
repellant so that it could be capable of flowing from a pressurized container. Sodium
bicarbonate based formulations are effective on Class B and C type fires, but not on Class
A or D. Their effectiveness is approximately 50% greater than that of water, applied to
the same fire.
Potassium Bicarbonate
Research conducted at the U.S. Naval Research Laboratory led to the development of a
second-generation dry chemical fire-extinguishing agent based on potassium
bicarbonate, rather than sodium bicarbonate. This material is commonly referred to as
"Purple-K". Formulations based upon potassium bicarbonate are found to be about twice
as effective as those based on sodium bicarbonate. Potassium bicarbonate formulations
are effective on Class B and C type fires, only.
Multi-Purpose
A third type of dry chemical evolved, which was quite unique in its effectiveness on
Class A fires in addition to the normal Class B & C capability. Referred to as multipurpose
dry chemical, it is based upon mixtures of ammonium phosphates or ammonium
phosphates and sulphates.
Applications
Dry chemical fire extinguishing agents are most generally used where significant fire
extinguishment capability is required from a relatively small quantity of material. This is
the reason that dry chemical fire extinguishing agents are mostly used in portable and
wheeled extinguishers, having capacities up to 160 kilograms. There are also special
applications involving stationary equipment up to 1360 kilograms capacity.
Gaseous
Gaseous extinguishing agents alter the vapor phase concentration of the fuel oxidizing
agent so that it is either below the lower flammability limit or above the upper
flammability limit. There are two categories of gaseous extinguishing agents, which are
used on class C fires to prevent the possibility of electric shock:
Inert type agents, such as nitrogen or carbon dioxide
Halons or halogenated hydrocarbon type fire extinguishing agents
Dry Powder
Dry powders are those formulations developed specifically for use on Class D
combustibles. Class D combustibles represent reactive and combustible materials such as
sodium,
potassium, magnesium and aluminum.
Water
Water is used on Class A fires. The primary mechanism of extinguishment by water is its
ability to cool the fuel/oxidizing agent mixture below the ignition temperature of the
fuel. The volume of water present, as a liquid, is expanded by a factor of 1700 times in
converting it to steam.
Foams
Foam is the result of adding certain materials to water to improve its ability to wet certain
fuel surfaces.
Foam extinguishing agents can be divided into two categories:
Chemical foams
Mechanical foams
Chemical Foams
Chemical foams are produced by chemical reaction between substances such as, sodium
bicarbonate and aluminum sulphate. In this chemical reaction, carbon dioxide is
released and is the blowing agent, which results in the formation of a mass of foam
bubbles. Chemically foams are mostly obsolete in North America.
Mechanical Foams
Mechanical foams are produced by mechanically mixing air with a proportioned foam
solution. The solution is a mixture of water and foam concentrate at an appropriate
dilution, the two most common dilutions being 6% and 3%, (that is, 6 parts foam
concentrate to 94 % water or 3 parts foam concentrate to 97 parts water). Foam agents are
most often employed in fighting fires involving Class B flammable and combustible
liquids.
Mechanical foam agents place a barrier, or effective separation, between the fuel and the
oxidizing agent (usually air). A secondary mechanism of extinguishment is associated
with the boiling of water to produce a cooling effect. All of the foam extinguishing agents
can be used on Class A combustibles. The most commonly used foams for Class A
combustibles are based on synthetic type concentrates using hydrocarbon surfactants
(detergents).
Types of mechanical foam concentrates are:
Protein
Fluoroprotein
Aqueous Film-Forming (AFFF)
Alcohol Resistant Concentrates
Synthetic
Protein Foam
Protein Foam is derived from a naturally occurring chemical found in the hoofs and horns
of animals. Chemicals are added to the protein to protect it from freezing, from being
decomposed by natural microorganisms, and to make it less corrosive. Protein foams
result in a thick mass of foam bubbles that have excellent burn back resistance, but are
not particularly mobile on a fuel surface. Protein foams also have a tendency to pick up
the fuel to which it is being applied.
Fluoroprotein Foam
Fluoroprotein Foam was successfully developed to overcome two of the drawbacks of
protein foams. The first being the ease with which the foam blanket spreads across a fuel
surface; and the second being a reduction in the amount of fuel picked up by the foam
blanket. Fluoroprotein foam differs from protein foam in that a fluorocarbon surfactant
is added at relatively low concentrations to provide better extinguishment speed and burn
back resistance. Fluoroprotein foams are commonly used in both topside and
subsurface application for the protection of flammable and combustible liquid storage
tanks.
Aqueous Film Forming Foam (AFFF)
Aqueous Film Forming Foam (AFFF) was developed at the U.S. Naval Research
Laboratory primarily to provide very rapid fire extinguishment, or knockdown
capabilities. It
consists of fluorocarbon and hydrocarbon surfactants that can be used in both aspirating
and non-aspirating mechanical foam hardware. Aspirating nozzles are specifically
designed to entrain air in certain proportions into the diluted foam water solution. Nonaspirating type foam hardware is designed primarily for the application of water in either
spray or straight-stream patterns.
Alcohol-Resistant Concentrates (ARC)
Objective Two
When you complete this objective you will be able to…
Describe the components and operation of a typical fire detection and alarm system in an
industrial setting.
Learning Material
FIRE DETECTION AND ALARM SYSTEMS
Fire detection provisions are needed so that automatic or manual fire suppression can be
initiated. Other fire protection systems should be activated (for example, automatic
fire doors for compartmentalization and protection of escape routes), so that occupants
will have time to move to safe locations, typically outside the building.
One reason for concern over any rapid initial fire growth is that it can reduce the time
available after detection for these life-and-property-saving responses. Therefore,
detection provisions must be designed to reflect the building's features, its occupants, and
its fire safety features.
Smoke is often the first indicator of fire, so a system of automatic detectors should be
used. However, in certain properties or areas, detectors based on heat or rate of increase
in heat may be more appropriate because of the types of fires likely to occur in those
areas. Whatever type of detection is chosen, it is important for each area of the building,
that an assessment is made of the implications for response time, after the fire is detected
and before a lethal or other high-hazard condition develops.
Alarms do not need be linked to the detection sensor locations, but should be designed
systematically to inform occupants. This would include the possible use of central
annunciator panels and monitors, or voice messages to provide instructions and direct
remote alarms to supervised stations or fire departments. All of these options will have
an impact on the time available for some type of response and possibly, on the efficiency
of that response.
HEAT DETECTORS
Heat detectors are the oldest type of automatic fire detection device. They begin with the
development of automatic sprinklers in the 1860s and have continued to the present
with a large number of devices. Heat detectors are generally located on or near the ceiling
and respond to the thermal energy released from a fire. They respond either when
the detecting element reaches a predetermined fixed temperature or to a specified rate of
temperature change. In general, heat detectors are designed to operate when heat
causes a change in a physical or electrical property of a material or gas.
Heat detectors that only initiate an alarm and have no extinguishing function are still in
use. Although they have the lowest false alarm rate of all automatic fire detector
devices, they also are the slowest in detecting fires. A heat detector is best suited for fire
detection in a small confined space where rapidly building high-heat-output fires are
expected, in areas where ambient conditions would not allow the use of other fire
detection devices, or where speed of detection is not a prime consideration.
A sprinkler can be considered a combined heat-activated fire detector and extinguishing
device when the sprinkler system is provided with water flow indicators connected to the
fire alarm control system. Water flow indicators detect either the flow of water through
the pipes or the subsequent pressure change upon actuation of the system.
Operating Principles of Fixed Temperature Heat Detectors
Fixed-temperature heat detectors are designed to alarm when the temperature of the
operating element reaches a specified point. The air temperature at the time of alarm is
usually considerably higher than the rated temperature because it takes time for the air to
raise the temperature of the operating element to its set point. This condition is
called thermal lag. Fixed temperature heat detectors are available to cover a wide range
of operating temperatures, from about 57°C and higher. Higher temperature detectors
are also necessary so that detection can be provided in areas normally subjected to high
ambient (non-fire) temperatures, or in areas zoned so that only detectors in the
immediate fore area operate.
Fusible Element Type
Eutectic metals, alloys of bismuth, lead, tin, and cadmium that melt rapidly at a
predetermined temperature, can be used as operating elements for heat detection. The
most
common use is the fusible element in an automatic sprinkler, as shown in Fig. 1. Fusing
(melting) of the element allows the cover on the orifice to fall away, water to flow in the
system, and the alarm to be initiated.
Figure 1
Automatic
Sprinkler Head
Eutectic metals, used as solder to secure a spring under tension, may also be used to
actuate an electrical heat detector. When the element fuses, the spring action closes
contacts and initiates an alarm. Detectors using eutectic metals cannot be restored; either
the device or its operating element must be replaced following operation.
Bimetallic Type
When two metals with different coefficients of thermal expansion are bonded together
and then heated, differential expansion causes bending or flexing toward the metal
having the lower-expansion rate. This action closes a normally open circuit. The low
expansion metal commonly used is Invar™, an alloy of 36% nickel and 64% iron.
Several
alloys of manganese-copper-nickel, nickel-chromium-iron, or stainless steel may also be
used for the high-expansion component of a bimetal assembly. Bimetals are used for
the operating elements of a variety of fixed-temperature detectors. These detectors are
generally of two types: (1) the bimetal strip and (2) the bimetal snap disc.
As it is heated, a bimetal strip deforms in the direction of the contact point. With a given
bimetal, the width of the gap between the contacts determines the operating
temperature; the wider the gap the higher the operating point.
The operating element of a snap disc device is a bimetal disc formed into a concave shape
in its unstressed condition, as shown in Fig. 2. Generally, a heat collector is attached
to the detector frame to speed the transfer of heat from the room air to the bimetal. As the
disc is heated, the stresses developed cause it to suddenly reverse curvature and
become convex. This provides a rapid positive action that closes the alarm contacts. The
disc itself usually is not part of the electrical circuit.
All heat detectors using bimetal elements are automatically self-restoring after operation,
when the ambient temperature drops sufficiently below the operating point.
Figure 2
Bimetallic Snap
Disc Fixed
Temperature
Detector
Rate Compensation Detectors
A rate compensation detector, shown in Fig. 3, is a device that responds when the
temperature of the surrounding air reaches a predetermined level, regardless of the rate of
temperature rise.
A typical example is a spot-type detector with a tubular casing of metal that tends to
expand lengthwise as it is heated, and an associated contact mechanism that will close at
a certain point in the elongation. A second metallic element inside the tube exerts an
opposing force on the contacts, tending to hold them open. The forces are balanced so
that, with a slow rate of temperature rise, there is more time for heat to penetrate to the
inner element. This inhibits contact closure until the total device has been heated to
its rated temperature level. However, with a fast rate of temperature rise, there is less time
for heat to penetrate to the inner element. The element therefore exerts less of an
inhibiting effect, so contact closure is obtained when the total device has been heated to a
lower level.
Thermal detectors using expanding metal elements are automatically self-restoring after
operation, when the ambient temperature drops, to some point below the operating
point.
Figure 3
Spot-Type Rate
Compensation
Detector
Rate Of Rise Detectors
One effect that a flaming fire has on the surrounding area is to rapidly increase air
temperature in the space above the fire. Fixed-temperature heat detectors will not initiate
an
alarm until the air temperature near the ceiling exceeds the design-operating point. The
rate of rise detector, however, will function when the rate of temperature increase
exceeds a predetermined value, typically around 7 to 8°C per minute. Rate of rise
detectors are designed to compensate for the normal changes in ambient temperature, less
than 6.7°C per minute, which are expected under non-fire conditions.
In a pneumatic fire detector, air heated in a tube or chamber expands, increasing the
pressure in the tube or chamber. This exerts a mechanical force on a diaphragm that
closes the alarm contacts. If the tube or chamber were hermetically sealed, slow increases
in ambient temperature, a drop in the barometric pressure, or both, would cause the
detector to initiate an alarm regardless of the rate of temperature change. To overcome
this, pneumatic detectors have a small orifice to vent the higher pressure that builds up
during slow increases in temperature or during a drop in barometric pressure. The vents
are sized so that when the temperature changes rapidly, as in a fire, the rate of
expansion exceeds the venting rate and the pressure rises. When the temperature rise
exceeds 7 to 8°C per minute, the pressure is converted to mechanical action by a
flexible diaphragm. Pneumatic heat detectors are available for both line and spot-type
detectors.
Line Type
The line type detector consists of metal tubing, in a loop configuration, attached to the
ceiling or sidewall near the ceiling of the area to be protected. Lines of tubing are
normally spaced not more than 9.1 m apart, not more than 4.5 m from a wall, and with no
more than 305 m of tubing on each circuit. Also, a minimum of at least 5 % of each
tube circuit or 7.6 m of tube, whichever is greater, must be in each protected area.
Without this minimum amount of tubing exposed to a fire condition, insufficient pressure
would build up to achieve proper response.
In small areas where the line type tube detectors might have insufficient tubing exposed
to generate sufficient pressures to close the alarm contacts, air chambers or rosettes
of tubing are often used. These units act like a spot-type detector by providing the volume
of air required to meet the 5% or 25 ft (7.6 m) requirement. Since a line type rate
of rise detector is an integrating detector, it will actuate either when a rapid heat rise
occurs in one area of exposed tubing, or when a slightly less rapid heat rise takes place in
several areas where tubing on the same loop is exposed.
Referring to Fig. 4, air in a tube is heated by the fire, which causes increase in pressure.
The pressure increase acts on two diaphragms, which causes them to move and
complete the alarm electrical circuit. If the tube was sealed completely, then slow
increases in ambient temperature, or a fall in barometric pressure would cause the alarm
to
initiate regardless of the rate of temperature change. This is overcome by using a small
orifice to vent the pressure build up during slow increases in temperature or a fall in
barometric pressure.
Figure 4
Line-Type
Rate-of-Rise
Detector
Spot Type
The pneumatic principle is also used to close contacts within spot detectors. The
difference between the line and spot type detectors is that the spot type contains all of the
air
in a single container rather than in a tube that extends from the detector assembly to the
protected area(s).
Combination Detectors
Combination detectors contain more than one element that responds to a fire. These
detectors may be designed to respond from either element, or from the combined
response of both elements. An example of the former is a heat detector that operates on
both the rate of rise and fixed temperature principles. Its advantage is that the rate
of rise element will respond quickly to a rapidly developing fire, while the fixed
temperature element will respond to slowly developing fire, when the detecting element
reaches
its set point temperature. The most common combination detector uses a vented air
chamber and a flexible diaphragm for the rate-of-rise function, while the fixed
temperature element is usually a spring restrained by a eutectic metal. When the fixedtemperature element reaches its design operating temperature, the eutectic metal
fuses and releases the spring, which closes the contacts.
Fig. 5 illustrates a combined rate of rise and fixed temperature device. Air supplied to
chamber A slowly escapes through vent B. A high rate of temperature increase causes
pressure in A to increase until diaphragm C closes contacts D and E. Fixed temperature
operation occurs when fusible alloy F melts, releasing spring G which pushes on C
closing
D and E.
Figure 5
Spot Type
Combination Rate
of Rise, Fixed
Temperature
Detector
Electronic Spot Type Thermal Detectors
A thermoelectric effect detector is a device that utilizes a sensing element consisting of
one or more thermistors, which produce a change in electrical resistance in response to
an increase in temperature. This resistance change is monitored by associated electronic
circuitry, and the detector responds when the resistance changes at an abnormal rate
(rate of rise type) or when the resistance reaches a specific value (fixed temperature
type).
Rate of rise detectors use two thermistors. One is exposed to changes in atmospheric
temperature. When the temperature rapidly changes as in a fire situation, the
temperature of the exposed thermistor increases faster than the temperature of the
unexposed reference thermistor, generating a net change in resistance causing the
detector to go into alarm condition. Most rate of rise detectors are designed with a fixed
temperature backup feature so that, should the temperature rise be slower than 8°C,
per minute, the detector will operate when the exposed thermistor has reached a
predetermined fixed temperature.
SMOKE DETECTORS
A smoke detector will detect most fires much more rapidly than a heat detector.
Smoke detectors are identified by their operating principle. Two of the operating
principles are (1) ionization and (2) photoelectric. Smoke detectors using the ionization
principle provide somewhat faster response to high energy (open flame) fires, since these
fires produce large numbers of the smaller smoke particles. Smoke detectors
operating on the photoelectric principle respond faster to the smoke generated by low
energy (smoldering) fires, as these fires generally produce more of the larger smoke
particles.
The sensors are available as photoelectric, ionization, or combination photoelectric, and
ionization units. As fire alarm systems technology advances, analog sensors will be the
choice for any system application, regardless of system size.
Ionization Smoke Detectors
Smoke detectors utilizing the ionization principle are usually of the spot type, as shown
in Fig. 6. An ionization smoke detector has a small amount of radioactive material that
ionizes the air in the sensing chamber, rendering the air conductive and permitting a
current flow through the air between two charged electrodes. This gives the sensing
chamber an effective electrical conductance. When smoke particles enter the ionization
area, they decrease the conductance of the air by attaching themselves to the ions,
causing a reduction in ion mobility. When the conductance is below a predetermined
level, the detector responds.
Figure 6
Ionization Smoke
Detector
Photoelectric Smoke Detectors
The presence of suspended smoke particles generated during the combustion process
affects the passing of a light beam through the air. This effect can be used to detect the
presence of a fire in two ways:
Obscuration of light intensity over the beam path
Scattering of the light beam
Light Obscuration Principle
Smoke detectors that operate on the principle of light obscuration consist of a light
source, a light beam gathering system, and a photosensitive device. When smoke
obscures
part of the light beam, the light reaching the photosensitive device is reduced, and this
initiates the alarm.
Most light obscuration smoke detectors, Fig. 7, are the beam type and are used to protect
large open areas. They are installed with the light source at one end of the area to
be protected and the photosensitive device at the other. Projected beam detectors are
generally installed in accordance with manufacturer’s instructions.
Figure 7
Obscuration
Smoke Detector
Light Scattering Principle
When smoke particles enter a light path, scattering results. Smoke detectors utilizing the
photoelectric light-scattering principle, Fig. 8, are usually of the spot type. They
contain a light source and a photosensitive device arranged so the light rays normally do
not fall onto the device. When smoke particles enter the light path, light strikes the
particles and is scattered onto the photosensitive device, causing the detector to responds.
The photosensitive device used in scattering detectors usually is a photodiode or a
phototransistor.
Figure 8
Scattering Smoke
Detector
Objective Three
When you complete this objective you will be able to…
Describe the design and operation of a typical standpipe system.
Learning Material
STANDPIPE SYSTEMS
Standpipe systems are used in buildings over 3 stories (14 metres) in height, since that is
the practical limit for firefighters to couple hose together from the pumper truck at
street level up the stairways to the fire floor. It is also close to the limit from which a fire
can be fought externally from ladders and snorkel equipment.
A standpipe system is used to overcome the above difficulties. The standpipe rises up the
stairwell or wells. At each floor level, provision is made for the connection of fire
hoses. The firefighters need only couple hoses to one of the valved outlets provided to get
a water supply.
The connections used are frequently on the floor below the fire. This allows the use of the
connections on the fire floor as well, and the fire is approached from below rather
than above. If the fire were approached from above with the stair doors open and the heat
of the fire rising, it would be similar to approaching the fire through a chimney.
There are three classes of standpipe systems:
Class I systems use NPS 63 mm hose and hose connections, and are provided for use
by fire departments, and those trained in firefighting techniques.
Class II systems use NPS 38 mm hose and hose connections, and are provided for use
by the building occupants, until the fire department arrives. Subject to
approval of the local authority, a minimum NPS 25 mm hose and hose connections
can be used in Class II service in light hazard occupancies.
Class III systems use both NPS 63 mm and NPS 38 mm hose connections. The NPS
63 mm are for the use by those trained in handling heavy hose streams and
the NPS 38 mm for the building occupants.
The number and location of standpipes and equipment is dependent upon the use,
occupancy and construction of the facility.
Provincial and local authorities govern the Fire Acts, Codes, and Regulations. In general
terms, the number of standpipes and hose stations is the same for each Class.
In each building, and in each section of a building divided by fire walls, there shall be
standpipes and hose stations such that all portions of each story of the building are within
9 m of a nozzle, attached to not more than 30 m of hose.
Where in Class II service a NPS 25 mm hose has been approved, then all portions of each
story of the building shall be within 6 m of a nozzle, when attached to not more than
30 m of hose.
The standpipe risers are located in noncombustible, fire-rated stairwells. If it is not
possible to locate all standpipes in fire-rated stairwells, then additional standpipes may be
located in pipe shafts at the building interior column locations.
For Class I and III service systems, at least one NPS 63 mm roof outlet connection shall
be provided from each standpipe. Fig. 9 illustrates a typical roof manifold system.
Figure 9
Typical Roof
Manifold
The hose connections to the standpipe for Class I service should be located in the
stairwell.
For Class II service, the hose connection should be located in the corridor or space
adjacent to the stairwell.
For Class III service, the NPS 63 mm hose connection should be located in the stairwell
and the NPS 38 mm hose connection in the corridor or space adjacent to the stairwell.
Where the building has a large area, the connections NPS 63 mm and NPS 38 mm for
Class III may also be located at building interior columns.
Standpipes for risers of less than 30 m are usually NPS 102 mm pipe, over 30 m, the pipe
is usually NPS 152 mm. Where a building has a high level fire zone; that is, floors
more than 85 m above street level, then the riser to these higher floors is usually NPS 203
mm. The water pressure at the topmost outlet of each standpipe should not be less
than 450 kPa, with a flow rate in the system of 32 L/s. If the flowing pressure at any hose
valve outlet will exceed 690 kPa, then a pressure reducing system shall be installed
to reduce the pressure, at the required flow, to not more than 690 kPa.
Fig. 10 is a schematic of a typical single zone system, while Fig. 11 & 12 show systems
for buildings having two fire zones.
There are two basic standpipe systems. A wet standpipe is one that is always filled with
water. A dry standpipe is one that is normally dry and terminates at its base outside the
building with a fire department connection. In the event of a fire that requires fire
department participation, a pumper engine will connect to a nearby street hydrant and
discharge water into the standpipe system through the fire department connection. The
fire department connection is a “Y” piece so that two hoses can feed the standpipe
system. This special “Y” piece is called a “Siamese connection”. A Siamese connection
is also provided on a wet standpipe system.
Class II and Class III systems must be connected to a wet standpipe system as it is
essential that the NPS 1 ½” (38 mm) hose system has water immediately available.
Figure 10
Typical Single
Zone Standpipe
System
Figure 11
Typical Two Zone
Standpipe System
Figure 12
Alternate Typical
Two Zone
Standpipe System
Objective Four
When you complete this objective you will be able to…
Describe the wet pipe, dry pipe, pre-action and deluge designs for sprinkler systems.
Learning Material
TYPES OF SPRINKLER SYSTEMS
There are five basic types of sprinkler system defined in NFPA 13, Standard for the
Installation of Sprinkler Systems.
Wet Pipe
Dry Pipe
Preaction
Combination of Dry Pipe and Preaction
Deluge
NFPA 13 is the fundamental document that governs the design and installation criteria
for these specialized fire protection systems. NFPA 13 is a standard, thus it provides the
necessary requirements and guidance with respect to the specifics of “how” to design,
layout, and install a system. It does not tell when a system is needed, that is the function
of NFPA 101 or a building code.
Wet Pipe Systems
This system, shown in Fig. 13, is the most common, easiest to design, and simplest to
maintain. These systems contain water under pressure at all times and utilize a series
of closed sprinklers. Once a fire occurs and produces enough heat to activate one of more
sprinklers, the water will discharge immediately from any of the open sprinklers. Wet
pipe should only be used when the temperature of the protected area is maintained at or
above 4°C.
This system is typically found in office buildings, stores, manufacturing facilities, hotels,
and health care facilities.
1. Main Water Supply
2. Main Drain Connection
3. Fire Department Connection
4. Water Flow Alarm
5. Water Pressurized Distribution
Piping
6. Check Valve
7. Alarm Valve
8. Water Supply Gate Valve
9. Automatic Sprinklers
10. Inspectors test Connections
Figure 13
Wet Pipe Sprinkler System
Dry Pipe Systems
These systems, shown in Fig. 14, are found in environments where the temperature is
maintained below 4°C. The system piping contains air under pressure, 275 kPa
maximum, under normal circumstances. A dry-pipe valve is used to hold back the water
supply and to serve as the water/air interface. The valve acts on a pressure differential
principle, the surface area of the valve face on the airside being greater than the surface
area on the waterside.
When a fire occurs and enough heat is generated, one or more sprinklers will operate, the
system air pressure will then escape through the open sprinklers, drop to a
predetermined level, and allow the dry pipe valve to open. Once the valve opens, the
water supply will be admitted into the system piping, fill the pipe network, and water will
discharge from any sprinklers that have operated.
These systems are more complex, require a reliable air supply source and involve specific
design limitations such as the volume of pipe that can be governed by one dry pipe
valve, and special adjustments that are necessary for the anticipated area of operation.
Dry pipe systems can be found in buildings that are not maintained at the 4°C limit, such
as outside canopies and structures, and cold-storage warehouses.
1. Main Water Supply
2. Main Drain Connection
3. Fire Department Connection
4. Water Flow Alarm
5. Water Pressurized Distribution Piping
6. Dry Pipe Valve
7. Check Valve
8. Water Supply Gate Valve
9. Automatic Sprinklers
10. Inspectors test Connections
Figure 14
Dry Pipe Sprinkler System
Preaction Systems
The piping for these systems, shown in Fig. 15, is typically provided with some minimal
quantity of air pressure, thus the pipe network has no water in it under normal
circumstances. The water is held back by means of a preaction valve. The system is
equipped with a supplemental detection system. Operation of the detection system allows
the preaction valve to automatically open and admit water into the pipe network. Water
will not discharge from the system until a fire has generated a sufficient quantity of heat
to cause operation of one or more sprinklers. In essence, the system appears as a wet pipe
system once the preaction valve operates.
The small amount of air, which is maintained in the pipe, is used to monitor the integrity
of the pipe. If the pipe develops a leak, air-pressure will drop and an alarm will sound,
indicating a low air-pressure condition exists within the pipe. The preaction valve stays in
its normal position until the detection system is activated.
Preaction systems are typically found in environments that house computer equipment or
communication equipment, museums, and other facilities where inadvertent water
discharge is of major concern to the end user. The double-interlock system is most
common in deep-freeze facilities where accidental valve operation may result in freezing
of
the pipe in a matter of minutes.
1.
Main Water Supply
8. Low Pressure Supervisory Panel
1a.
Control Water Supply
9. Solenoid Valve
2.
Water Supply Gate Valve
10. Supervisory Low Pressure Alarm
3.
Control Valve
11. Heat Detectors
4.
Pressure Alarm Switch
12. Deluge Release Panel
5.
Check Valve
13. Fire Alarm Bell
6.
Water Motor Alarm
14. Trouble Horn
7.
Manual Control Station
15. Automatic Sprinklers
Figure 15
Preaction Sprinkler System
Combination of Dry Pipe and Preaction
Another type of preaction system is commonly referred to as a double-interlock preaction
system. This system has characteristics as previously described for preaction systems
and characteristics of a dry-pipe system. In order to admit water into this type of system,
the detection system must operate and the fire must generate a sufficient quantity of
heat to cause operation of one or more sprinklers, thereby allowing a loss of pressure.
Deluge Systems
Rapidly growing and spreading fires are most effectively protected with this type of
system. Deluge systems, shown in Fig. 16, are intended to deliver large quantities of
water
over a large area in a relatively short period of time. The sprinklers that are used in a
deluge system have their operating elements removed. These open sprinklers are
attached to branch-line piping in the same manner as other types of sprinklers.
A deluge valve is used to control the system water supply. The sprinkler system pipe is at
atmospheric pressure, since the open sprinklers are attached to it. The system water
supply is maintained to the system side of the deluge valve. In a similar manner to the
preaction system, a supplemental detection system is provided throughout the same
area as the sprinklers. Upon activation of this detection system the deluge valve is
electrically opened, thereby admitting water into the pipe network. As the water reaches
each
sprinkler in the system, it immediately discharges from the open sprinkler.
The nature of this system makes it appropriate for facilities that contain combustible or
flammable liquids. In addition, this system is used for situations in which thermal
damage is likely to occur in a relatively short period of time.
1.
Main Water Supply
7.
Solenoid Valve
1a.
Control Water Supply
8.
Heat Detector
2.
Water Supply Gate Valve
9.
Deluge Release Panel
3.
Control Valve
10.
Fire Alarm Bell
4.
Pressure Alarm Switch
11.
Trouble Horn
5.
Water Motor Alarm
12.
Open Sprinklers
6.
Manual Control Station
Figure 16
Deluge Sprinkler System
There are several variations to each one of these basic systems. Antifreeze systems are
basically wet-pipe systems with a certain percentage of antifreeze concentrate added in
to depress the freezing point. This type of system can be used to protect small areas, such
as may be found at outside loading docks or exterior canopies. NFPA 13 specifies
select types of antifreeze concentrate and percentages.
Objective Five
When you complete this objective you will be able to…
Describe the layout, components and operation of a typical firewater system with fire
pump and hydrants. Explain seasonal considerations for a firewater system.
Learning Material
Fig. 17 shows the water piping for fire protection of an industrial site. Typical details
shown are connections to public mains and supplies for a private fire pump, main water
piping loops, sectional control valves, and hydrants.
Fire pumps are discussed extensively, in the 4th Class module entitled “Plant Fire
Protection”. There will not be any further reference made to them. Fire hydrants are
covered
in the following module.
Figure 17
Industrial Site Fire
Water Protection
System
Reprinted with permission from NFPA Fire Protection Handbook Copyright 1997,
National Fire Protection Association, Quincy, MA 02269. This reprinted material is not
the
complete and official position of the National Fire Protection Association, on the
referenced subject, which is represented only by the standard in its entirety.
Opinions vary on how many valves should be used in a system of underground mains.
Making sure all sectional control valves are open is probably more critical than avoiding
the problem of too few sectional valves. Nevertheless, the modern tendency is to make
fairly liberal use of valves. A few well-established principles are shown in the above
figure, they include:
A city supply check valve (and meter, if required) located between indicating valves so it
can be repaired without affecting the city and plant systems.
A pump check valve located between pump and indicating valves so that the latter can be
used to shut off the connection to the system when making check valve and pump
repairs.
Three sectional valves (“G” and “H”, to take care of present loop and “J”, for a short
branch supplying a small detached building) in addition to the main water supply valve.
The branch will ultimately be part of a second loop. There should be a loop valve on each
side of every valuable water supply to permit cutting off a part of the loop without
cutting the water supply off altogether. Best practice requires that post indicators, which
shows the valve position, either open or closed, be attached to valves in pits.
Sectional control valves (indicator posts C, “E”, and “F”) can cut the loop into four
sections (in conjunction with Valves “G” and “H”). In large or complicated underground
systems, it is recommended that indicator posts controlling risers to sprinklers or
standpipes be painted a different color from sectional control valves. Generally, no more
than
six hydrants or indicator posts should be located between sectional valves.
Gate valves must be provided on hydrant laterals to isolate the hydrant in the event it
malfunctions is damaged, or when repairs are necessary.
Location
Hydrant spacing is usually determined by the fire flow demand established on the basis of
the type, size, occupancy, and exposure of structures.
When hydrants are located on a private water system and hose lines are intended to be
used directly from the hydrants, they should be so located as to keep hose lines short,
preferably not over 75 m. At a minimum, there should be enough hydrants to make two
streams available at every part of the interior of each building not covered by a
standpipe system protection. They should also provide hose stream protection for exterior
parts of each building using only the lengths of hose normally attached to the
hydrants. It is desirable to have a sufficient number of hydrants to concentrate the
required fire flow about any important building with no hose line length exceeding 150
m.
For average conditions, hydrants normally are placed about 12.2 m from buildings to be
accessible, during a fire event. When that is impossible, they are set where the chance
of injury by falling walls or debris is small and where fire fighters are not likely to be
driven away by smoke and heat. In crowded industrial yards, hydrants usually can be
placed
beside low buildings, near substantial stair towers, or at corners, formed by masonry
walls that are not likely to fall.
Hydrants that must be located in areas subject to heavy traffic need protection against
damage from collision. The parking lots of shopping centers and mill yards are good
examples.
Seasonal Considerations
The depth of cover to provide protection against freezing will vary from about 0.76 m, in
the southern United States to about 3.05 m, in northern Canada. Because there is
normally no circulation of water in fire protection mains, they require greater depth of
covering than do public mains. The minimum cover should always be maintained to
prevent mechanical damage. Depth of covering should be measured from top of pipe to
ground level, and consideration should always be given to future or final grade and
nature of soil. A greater depth is required in a loose, gravelly soil (or in rock) than in
compact or clay soil. A safe rule to follow is to bury the top of the pipe not less than 0.3m
below the lowest frost line for the locality.
Alcohol-Resistant Concentrates have been specially formulated for extinguishment of
fires involving water-soluble fuels.
All of the foam agents discussed up to this point are effective on non-water-soluble fuels
such as gasoline, diesel fuel, crude oil, kerosene, toluene, etc. If any of these foam
agents is used on a water-soluble fuel, such as methyl alcohol or acetone, the foam will
simply dissolve because of the high solubility of the fuel in water.
Most of the currently used alcohol-resistant concentrates (ARC) are based on formulating
AFFF in such a way as to allow it to be used on a water-soluble fuel. This is
accomplished by adding a chemical, which forms an insoluble membrane (similar to an
egg white) between the fuel and the foam blanket. In this way, alcohol-resistant
concentrates, based on AFFF, have been successfully formulated and are now widely
used.
Synthetic Foam
Synthetic foams are divided into the following three categories, based on their expansion
ratio:
Low expansion, having an expansion ratio of 20:1, or less
Medium expansion, having an expansion ratio greater than 20:1, but less than 200:1
High expansion foam, having an expansion ratio greater than 200:1
Objective Six
When you complete this objective you will be able to…
Describe the construction and operation of a typical fire hydrant.
Learning Material
TYPES OF FIRE HYDRANTS
There are two types of fire hydrants in general use today. The most common is the base
valve (dry barrel), shown in Fig. 18, in which the valve controlling the water is located
below the frost line between the foot piece and the barrel of the hydrant.
Figure 18
Dry Barrel or Frost
Proof Hydrant
The barrel of this type hydrant is normally dry with water being admitted only when there
is a need. A drain valve at the base of the barrel is open when the main valve is
closed, allowing residual water in the barrel to drain out. This type of hydrant is used
whenever there is a chance the temperature will go below freezing, because the valve and
water supply are installed below the frost line.
The other type of hydrant is the wet barrel (California) type, shown in Fig. 19, is used
where the temperature remains above freezing. These hydrants usually have a
compression valve at each outlet, but they may have another valve in the bonnet that
controls the water flow to all outlets.
Figure 19
Wet Barrel
(California Type)
Hydrant
(Courtesy Mueller
Co.)
Hydrants
Well-designed and properly installed hydrants present a minimum of maintenance
difficulties. The dry barrel hydrant, for example, has a small drain near the base of the
barrel arranged to permit water to drain out when the main valve is shut. When the main
valve is opened several turns, this drain is closed. If the drain is working properly and
the main valve is tight, the difficulty of water freezing in the barrel is avoided.
Occasionally, situations are found where ground drainage is unsatisfactory or where
ground water
may stand at dangerous levels. In those cases, drains may be closed entirely and hydrant
barrels pumped out periodically.
The use of salt or salt solutions to prevent freezing is not recommended because of their
corrosive effect and limited usefulness. If antifreeze is used in hydrant barrels, its use
must be confined to hydrants that are not part of a system supplying water for domestic
consumption.
Ethylene glycol is extremely toxic, with as little as 0.1 mg/L ingested for a period of a
week being fatal. This substance should not be used. Propylene glycol is not as toxic and
may be used to prevent freezing but with proper precautions and in accordance with local
health regulations.
Suggestions for detecting freezing in hydrants include:
Sound by striking the hand over an open outlet. Water or ice shortens the length of the
“organ tube” and raises the pitch.
Turning the hydrant stem. If solidly frozen, the stem will not turn. If only slightly
bound by ice, placing a hydrant wrench on the nut and tapping smartly may
release the stem. Blows should be moderate to prevent breaking the valve rod.
Lowering a weight on a stout string into the hydrant. It may strike ice or come up wet,
showing water in the barrel.
Probably the most satisfactory method of thawing a hydrant is by means of a steam
hose. A thawing device in which steam may be rapidly produced should
be standard equipment for fire departments in cold-weather climates. The steam hose
is introduced into the hydrant through an outlet and pushed down,
thawing as it goes.
Objective Seven
When you complete this objective you will be able to…
Explain the purpose and describe a typical deluge water system for hydrocarbon storage
vessels.
Learning Material
HYDROCARBON STORAGE TANK DELUGE WATER SYSTEMS
Prevention of Fire
It is sometimes possible to use water spray to dissolve, dilute, disperse, and cool
flammable or combustible materials before they are ignited.
Fixed water sprays are designed specifically to provide optimum control, extinguishment,
or exposure protection for special fire protection problems. Limitations to the use of
water spray that should be recognized involve the nature of the equipment to be protected
and the physical and chemical properties of the material(s) involved.
Fixed Water Spray Systems
A water spray system is a special pipe system connected to a reliable supply of fire
protection water, and equipped with water spray nozzles for specific water discharge and
distribution over the surface or area to be protected. The piping system is connected to a
water supply through a deluge valve that can be actuated both automatically and
manually to initiate the flow of water.
Automatic system actuation valves for spray systems can be actuated electrically by the
operation of automatic detection equipment, such as heat detectors, relay circuits, gas
detectors, or mechanically by hydraulic or pneumatic systems, depending upon the
operating mode of the individual valves. Generally, each manufacturer of system
actuation
valves, most of which can do dual service in deluge systems, provides its own particular
combination of system actuation valve, releasing mechanism, detection system, and
supervisory service.
Systems Application
Fixed water spray systems are most commonly used to protect equipment from exposure
fires in flammable liquid and gas tankage, piping, and equipment; in electrical
equipment such as transformers, oil switches, rotating machinery, and cable trays; in
structural supports; and in conveyor systems and the openings in firewalls and floors
through which they pass. The type of water spray required for any particular hazard will
depend on the nature of the hazard and the purpose for which the protection is provided.
A water spray system is designed to give complete surface wetting with a specified water
density, taking into consideration the following:
a) Nozzle types, sizes, and spacing
b) Influence of wind and drafts
c) Probability of water rundown
d) Prevention of the formation of difficult-to-wet deposits of soot or carbon surfaces
e) Overlap of water discharge patterns onto the surfaces
f) Ability of the water supply to furnish adequate pressure to all of the nozzles
In most cases, it is neither desired nor expected that a water spray be used to extinguish
burning gases, such as LPG (Liquefied Petroleum Gas). However, the cooling effect of
the water on the tank may reduce and control the rate of burning until the gas supply to
the fire is exhausted or it can be isolated.
Objective Eight
When you complete this objective you will be able to…
Explain the purpose and describe a typical foam system for process buildings and tanks.
Learning Material
FOAM SYSTEMS
Where flammable liquid fire protection is required for permanently installed hazards,
such as fuel storage tanks or dip tanks containing flammable or combustible liquids,
air-foam-generating and distributing devices are installed internally in the tank. These
fixed devices, which are piped to a source of foam solution, may be arranged for manual
control or automatic activation by fire detectors in the event of fire.
Foam Chambers for Large Fuel Storage Tanks
Fire protection of large outdoor fuel tanks requires that several foam chambers with
foam-makers be installed at equally spaced positions slightly below the top rim of the
tanks, as shown in Fig. 20. These chambers are connected to lines on the ground that
supply foam solution to each foam-maker simultaneously in case of ignition of the
flammable contents of the tank. Frangible seals at the discharge outlet of the foam
chamber prevent vapor from entering the foam piping. These seals are designed to burst
when foam pressure is applied. A screen for the air inlet to the aspirating foam-maker
prevents clogging from foreign matter, such as bird nesting material. A universal or
swing
pipe joint is installed at ground level in the foam solution inlet pipe to prevent fracturing
of the supply piping if an explosion precedes a tank fire.
Figure 20
Air Foam At Top
Of Storage Tanks
Internal Tank Foam Distributing Devices
A prime requirement for efficient fuel tank extinguishment by topside foam devices has
always been that the foam must be applied to the burning surface without undue
plunging into the fuel, or allowing the foam to become coated with burning fuel. This
gentle application of foam must be accomplished at any level of the contents of the tank.
Many devices have been developed to gently apply foam from one point regardless of
burning fuel level. These devices are listed as “Type I” foam-discharge outlets for tanks
and are required for some alcohol-type foams. When foam discharge into a tank is
deflected to run down the inside tank shell to the burning fuel surface, it is called a “Type
II” outlet for foam application.
Central Foam Distributing Systems
These systems consist of an enclosure housing a foam concentrate supply tank and a
proportioning device, as shown in Fig. 21. Foam solution is supplied under pressure from
this foam house to the piping system, and controlled by appropriate valves so that the
foam chambers with foam-makers on the burning tank, receive foam solution.
Figure 21
Schematic
Arrangement Of
Air Foam
Protection For
Storage Tanks
Reprinted with permission from NFPA Fire Protection Handbook Copyright 1997,
National Fire Protection Association, Quincy, MA 02269. This reprinted material is not
the complete and official
position of the National Fire Protection Association, on the referenced subject, which is
represented only by the standard in its entirety.
Semi-fixed systems of similar design are more frequently used with mobile foam
concentrate supply from foam trucks. The truck proportions and pumps foam solution to
the
pipe laterals feeding the foam-makers from a safe location outside the dike.
Fixed systems consisting of automatically operated combinations of foam spray systems
and foam monitors are often installed to protect chemical processing plants.
Alcohol-resistant foams are usually required. In these designs, where there may be a high
risk, process vessels, pumps, and piping often are all included within the foam
distribution pattern for overall protection. The sensing of heat by fire detectors can
automatically activate the system.
Foam-Water Sprinkler Systems
In areas where flammable and combustible liquids are processed, stored, or handled, a
water discharge may be ineffective for controlling or extinguishing fires. The
foam-making sprinklers (aspirating-type) and deluge or spray nozzles using AFFF foams
have successfully replaced water sprinkler nozzles for such systems so that fires in
these occupancies may be controlled and property safeguarded.
When supplied with foam solution, sprinkler system piping grids provided with foamwater nozzles generate air-foam in essentially the same water sprinkler pattern as when
water is discharged from the same nozzle. This dual capability affords the system Class A
and B extinguishment ability.
Fixed sprinkler systems using these nozzles require that foam concentrate tanks,
proportioners, and suitable pumps be provided to supply the system with foam solution or
water. Detection devices may also be used to activate the system, or the system may be
activated manually. Closed-head sprinklers may also be used, and are now recognized
in NFPA 30.
Objective Nine
When you complete this objective you will be able to…
Describe a typical fire response procedure for an industrial setting.
Learning Material
FIRE RESPONSE PROCEDURE FOR AN INDUSTRIAL SETTING
There is always a risk of an emergency, no matter how complete the safety program.
Emergency preparedness means having plans in place in the event of an emergency.
Industrial plants are required to have an Environment, Health and Safety Program in
place. This program covers, among other areas, training in safe work procedures as well
as
Emergency Response Procedures. Emergency response procedures are written
procedures, established to ensure the immediate and competent handling of emergencies
involving any unplanned occurrences, such as: accidents or property threatening events
such as fires.
In large industrial settings, workers on shift will be trained in specific assignments to
follow in the event of an emergency, including fire. All employees must be familiar with
the
specific emergency procedures plan appropriate to their work location. An overview of
the plan is usually provided as part of the safety orientation and reinforced at regularly
scheduled safety meetings. Employees are trained in the use of emergency equipment,
including the use of fire extinguishers, and practice preparedness through regularly
documented emergency drills and evacuations.
Emergency routes and response procedures are located at each worksite, outlining
personnel responsibilities, evacuation, medical attention, and location of emergency
equipment and shutdown procedures. Emergency contact numbers are located by all
telephones. Emergency equipment, such as fire fighting, respiratory, first aid and rescue,
is
located on each site and regularly inspected and documented.
Emergency response procedures are developed to instruct first responders in the event of
a fire. A typical procedure would consist of the following:
1. Sound the fire alarm. This may be an in plant only and/or local fire department.
2. Complete a risk assessment of the situation.
a) Are there any other hazards?
b) Can you control the fire?
c) Do you need and or have help available?
d) Do you have an escape route?
3. Attempt to extinguish, or control the fire. If the fire escalates, back away. Never
turn your back on a fire.
Fire Protection Systems
Learning Outcome
When you complete this learning material, you will be able to:
Discuss the classes and extinguishing media of fires, and explain systems that are used to
detect and extinguish industrial fires.
Learning Objectives
You will specifically be able to complete the following tasks:
1.Explain the classifications of fires and describe the extinguishing media that are
appropriate for each classification.
2.Describe the components and operation of a typical fire detection and alarm system in
an industrial setting.
3.Describe the design and operation of a typical standpipe system.
4.Describe the wet pipe, dry pipe, pre-action and deluge designs for sprinkler systems.
5.Describe the layout, components and operation of a typical firewater system with fire
pump and hydrants. Explain seasonal considerations for a firewater
system.
6.Describe the construction and operation of a typical fire hydrant.
7.Explain the purpose and describe a typical deluge water system for hydrocarbon
storage vessels.
8.Explain the purpose and describe a typical foam system for process buildings and
tanks.
9.Describe a typical fire response procedure for an industrial setting.
Objective One
When you complete this objective you will be able to…
Explain the classifications of fires and describe the extinguishing media that are
appropriate for each classification.
Learning Material
CLASSIFICATION OF FIRES
The following are the four classifications of fires:
Class A
Class A fires occur in ordinary combustible materials such as wood, cloth and paper.
Class B
Class B fires occur in the vapor-air mixture over the surface of flammable liquids such as
greases, gasoline and lubricating oils.
Class C
Class C fires occur in energized electrical equipment.
Class D
Class D fires occur in combustible metals such as magnesium, titanium, zirconium and
sodium.
FIRE EXTINGUISHING AGENTS
The following are the most common types of fire extinguishing agents in use, today, and
the types of fires they are used to extinguish:
Dry chemicals
Gaseous
Dry powders
Water
Foams
Dry Chemicals
Dry chemical fire extinguishing agents stop the chemical chain reaction sequence
associated with fire. On a weight basis, they are probably more effective than even the
halons
in extinguishing fires. As such, they have found their greatest utilization in portable and
wheeled extinguishers and also in some stationary equipment.
Sodium Bicarbonate
The first dry chemical fire-extinguishing agent to be formulated was based on sodium
bicarbonate. It was compounded with certain materials to make the formulation water
repellant so that it could be capable of flowing from a pressurized container. Sodium
bicarbonate based formulations are effective on Class B and C type fires, but not on Class
A or D. Their effectiveness is approximately 50% greater than that of water, applied to
the same fire.
Potassium Bicarbonate
Research conducted at the U.S. Naval Research Laboratory led to the development of a
second-generation dry chemical fire-extinguishing agent based on potassium
bicarbonate, rather than sodium bicarbonate. This material is commonly referred to as
"Purple-K". Formulations based upon potassium bicarbonate are found to be about twice
as effective as those based on sodium bicarbonate. Potassium bicarbonate formulations
are effective on Class B and C type fires, only.
Multi-Purpose
A third type of dry chemical evolved, which was quite unique in its effectiveness on
Class A fires in addition to the normal Class B & C capability. Referred to as multipurpose
dry chemical, it is based upon mixtures of ammonium phosphates or ammonium
phosphates and sulphates.
Applications
Dry chemical fire extinguishing agents are most generally used where significant fire
extinguishment capability is required from a relatively small quantity of material. This is
the reason that dry chemical fire extinguishing agents are mostly used in portable and
wheeled extinguishers, having capacities up to 160 kilograms. There are also special
applications involving stationary equipment up to 1360 kilograms capacity.
Gaseous
Gaseous extinguishing agents alter the vapor phase concentration of the fuel oxidizing
agent so that it is either below the lower flammability limit or above the upper
flammability limit. There are two categories of gaseous extinguishing agents, which are
used on class C fires to prevent the possibility of electric shock:
Inert type agents, such as nitrogen or carbon dioxide
Halons or halogenated hydrocarbon type fire extinguishing agents
Dry Powder
Dry powders are those formulations developed specifically for use on Class D
combustibles. Class D combustibles represent reactive and combustible materials such as
sodium,
potassium, magnesium and aluminum.
Water
Water is used on Class A fires. The primary mechanism of extinguishment by water is its
ability to cool the fuel/oxidizing agent mixture below the ignition temperature of the
fuel. The volume of water present, as a liquid, is expanded by a factor of 1700 times in
converting it to steam.
Foams
Foam is the result of adding certain materials to water to improve its ability to wet certain
fuel surfaces.
Foam extinguishing agents can be divided into two categories:
Chemical foams
Mechanical foams
Chemical Foams
Chemical foams are produced by chemical reaction between substances such as, sodium
bicarbonate and aluminum sulphate. In this chemical reaction, carbon dioxide is
released and is the blowing agent, which results in the formation of a mass of foam
bubbles. Chemically foams are mostly obsolete in North America.
Mechanical Foams
Mechanical foams are produced by mechanically mixing air with a proportioned foam
solution. The solution is a mixture of water and foam concentrate at an appropriate
dilution, the two most common dilutions being 6% and 3%, (that is, 6 parts foam
concentrate to 94 % water or 3 parts foam concentrate to 97 parts water). Foam agents are
most often employed in fighting fires involving Class B flammable and combustible
liquids.
Mechanical foam agents place a barrier, or effective separation, between the fuel and the
oxidizing agent (usually air). A secondary mechanism of extinguishment is associated
with the boiling of water to produce a cooling effect. All of the foam extinguishing agents
can be used on Class A combustibles. The most commonly used foams for Class A
combustibles are based on synthetic type concentrates using hydrocarbon surfactants
(detergents).
Types of mechanical foam concentrates are:
Protein
Fluoroprotein
Aqueous Film-Forming (AFFF)
Alcohol Resistant Concentrates
Synthetic
Protein Foam
Protein Foam is derived from a naturally occurring chemical found in the hoofs and horns
of animals. Chemicals are added to the protein to protect it from freezing, from being
decomposed by natural microorganisms, and to make it less corrosive. Protein foams
result in a thick mass of foam bubbles that have excellent burn back resistance, but are
not particularly mobile on a fuel surface. Protein foams also have a tendency to pick up
the fuel to which it is being applied.
Fluoroprotein Foam
Fluoroprotein Foam was successfully developed to overcome two of the drawbacks of
protein foams. The first being the ease with which the foam blanket spreads across a fuel
surface; and the second being a reduction in the amount of fuel picked up by the foam
blanket. Fluoroprotein foam differs from protein foam in that a fluorocarbon surfactant
is added at relatively low concentrations to provide better extinguishment speed and burn
back resistance. Fluoroprotein foams are commonly used in both topside and
subsurface application for the protection of flammable and combustible liquid storage
tanks.
Aqueous Film Forming Foam (AFFF)
Aqueous Film Forming Foam (AFFF) was developed at the U.S. Naval Research
Laboratory primarily to provide very rapid fire extinguishment, or knockdown
capabilities. It
consists of fluorocarbon and hydrocarbon surfactants that can be used in both aspirating
and non-aspirating mechanical foam hardware. Aspirating nozzles are specifically
designed to entrain air in certain proportions into the diluted foam water solution. Nonaspirating type foam hardware is designed primarily for the application of water in either
spray or straight-stream patterns.
Alcohol-Resistant Concentrates (ARC)
Alcohol-Resistant Concentrates have been specially formulated for extinguishment of
fires involving water-soluble fuels.
All of the foam agents discussed up to this point are effective on non-water-soluble fuels
such as gasoline, diesel fuel, crude oil, kerosene, toluene, etc. If any of these foam
agents is used on a water-soluble fuel, such as methyl alcohol or acetone, the foam will
simply dissolve because of the high solubility of the fuel in water.
Most of the currently used alcohol-resistant concentrates (ARC) are based on formulating
AFFF in such a way as to allow it to be used on a water-soluble fuel. This is
accomplished by adding a chemical, which forms an insoluble membrane (similar to an
egg white) between the fuel and the foam blanket. In this way, alcohol-resistant
concentrates, based on AFFF, have been successfully formulated and are now widely
used.
Synthetic Foam
Synthetic foams are divided into the following three categories, based on their expansion
ratio:
Low expansion, having an expansion ratio of 20:1, or less
Medium expansion, having an expansion ratio greater than 20:1, but less than 200:1
High expansion foam, having an expansion ratio greater than 200:1
Objective Two
When you complete this objective you will be able to…
Describe the components and operation of a typical fire detection and alarm system in an
industrial setting.
Learning Material
FIRE DETECTION AND ALARM SYSTEMS
Fire detection provisions are needed so that automatic or manual fire suppression can be
initiated. Other fire protection systems should be activated (for example, automatic
fire doors for compartmentalization and protection of escape routes), so that occupants
will have time to move to safe locations, typically outside the building.
One reason for concern over any rapid initial fire growth is that it can reduce the time
available after detection for these life-and-property-saving responses. Therefore,
detection provisions must be designed to reflect the building's features, its occupants, and
its fire safety features.
Smoke is often the first indicator of fire, so a system of automatic detectors should be
used. However, in certain properties or areas, detectors based on heat or rate of increase
in heat may be more appropriate because of the types of fires likely to occur in those
areas. Whatever type of detection is chosen, it is important for each area of the building,
that an assessment is made of the implications for response time, after the fire is detected
and before a lethal or other high-hazard condition develops.
Alarms do not need be linked to the detection sensor locations, but should be designed
systematically to inform occupants. This would include the possible use of central
annunciator panels and monitors, or voice messages to provide instructions and direct
remote alarms to supervised stations or fire departments. All of these options will have
an impact on the time available for some type of response and possibly, on the efficiency
of that response.
HEAT DETECTORS
Heat detectors are the oldest type of automatic fire detection device. They begin with the
development of automatic sprinklers in the 1860s and have continued to the present
with a large number of devices. Heat detectors are generally located on or near the ceiling
and respond to the thermal energy released from a fire. They respond either when
the detecting element reaches a predetermined fixed temperature or to a specified rate of
temperature change. In general, heat detectors are designed to operate when heat
causes a change in a physical or electrical property of a material or gas.
Heat detectors that only initiate an alarm and have no extinguishing function are still in
use. Although they have the lowest false alarm rate of all automatic fire detector
devices, they also are the slowest in detecting fires. A heat detector is best suited for fire
detection in a small confined space where rapidly building high-heat-output fires are
expected, in areas where ambient conditions would not allow the use of other fire
detection devices, or where speed of detection is not a prime consideration.
A sprinkler can be considered a combined heat-activated fire detector and extinguishing
device when the sprinkler system is provided with water flow indicators connected to the
fire alarm control system. Water flow indicators detect either the flow of water through
the pipes or the subsequent pressure change upon actuation of the system.
Operating Principles of Fixed Temperature Heat Detectors
Fixed-temperature heat detectors are designed to alarm when the temperature of the
operating element reaches a specified point. The air temperature at the time of alarm is
usually considerably higher than the rated temperature because it takes time for the air to
raise the temperature of the operating element to its set point. This condition is
called thermal lag. Fixed temperature heat detectors are available to cover a wide range
of operating temperatures, from about 57°C and higher. Higher temperature detectors
are also necessary so that detection can be provided in areas normally subjected to high
ambient (non-fire) temperatures, or in areas zoned so that only detectors in the
immediate fore area operate.
Fusible Element Type
Eutectic metals, alloys of bismuth, lead, tin, and cadmium that melt rapidly at a
predetermined temperature, can be used as operating elements for heat detection. The
most
common use is the fusible element in an automatic sprinkler, as shown in Fig. 1. Fusing
(melting) of the element allows the cover on the orifice to fall away, water to flow in the
system, and the alarm to be initiated.
Figure 1
Automatic Sprinkler Head
Eutectic metals, used as solder to secure a spring under tension, may also be used to
actuate an electrical heat detector. When the element fuses, the spring action closes
contacts and initiates an alarm. Detectors using eutectic metals cannot be restored; either
the device or its operating element must be replaced following operation.
Bimetallic Type
When two metals with different coefficients of thermal expansion are bonded together
and then heated, differential expansion causes bending or flexing toward the metal
having the lower-expansion rate. This action closes a normally open circuit. The low
expansion metal commonly used is Invar™, an alloy of 36% nickel and 64% iron.
Several
alloys of manganese-copper-nickel, nickel-chromium-iron, or stainless steel may also be
used for the high-expansion component of a bimetal assembly. Bimetals are used for
the operating elements of a variety of fixed-temperature detectors. These detectors are
generally of two types: (1) the bimetal strip and (2) the bimetal snap disc.
As it is heated, a bimetal strip deforms in the direction of the contact point. With a given
bimetal, the width of the gap between the contacts determines the operating
temperature; the wider the gap the higher the operating point.
The operating element of a snap disc device is a bimetal disc formed into a concave shape
in its unstressed condition, as shown in Fig. 2. Generally, a heat collector is attached
to the detector frame to speed the transfer of heat from the room air to the bimetal. As the
disc is heated, the stresses developed cause it to suddenly reverse curvature and
become convex. This provides a rapid positive action that closes the alarm contacts. The
disc itself usually is not part of the electrical circuit.
All heat detectors using bimetal elements are automatically self-restoring after operation,
when the ambient temperature drops sufficiently below the operating point.
Figure 2
Bimetallic Snap Disc Fixed Temperature Detector
Rate Compensation Detectors
A rate compensation detector, shown in Fig. 3, is a device that responds when the
temperature of the surrounding air reaches a predetermined level, regardless of the rate of
temperature rise.
A typical example is a spot-type detector with a tubular casing of metal that tends to
expand lengthwise as it is heated, and an associated contact mechanism that will close at
a certain point in the elongation. A second metallic element inside the tube exerts an
opposing force on the contacts, tending to hold them open. The forces are balanced so
that, with a slow rate of temperature rise, there is more time for heat to penetrate to the
inner element. This inhibits contact closure until the total device has been heated to
its rated temperature level. However, with a fast rate of temperature rise, there is less time
for heat to penetrate to the inner element. The element therefore exerts less of an
inhibiting effect, so contact closure is obtained when the total device has been heated to a
lower level.
Thermal detectors using expanding metal elements are automatically self-restoring after
operation, when the ambient temperature drops, to some point below the operating
point.
Figure 3
Spot-Type Rate Compensation Detector
Rate Of Rise Detectors
One effect that a flaming fire has on the surrounding area is to rapidly increase air
temperature in the space above the fire. Fixed-temperature heat detectors will not initiate
an
alarm until the air temperature near the ceiling exceeds the design-operating point. The
rate of rise detector, however, will function when the rate of temperature increase
exceeds a predetermined value, typically around 7 to 8°C per minute. Rate of rise
detectors are designed to compensate for the normal changes in ambient temperature, less
than 6.7°C per minute, which are expected under non-fire conditions.
In a pneumatic fire detector, air heated in a tube or chamber expands, increasing the
pressure in the tube or chamber. This exerts a mechanical force on a diaphragm that
closes the alarm contacts. If the tube or chamber were hermetically sealed, slow increases
in ambient temperature, a drop in the barometric pressure, or both, would cause the
detector to initiate an alarm regardless of the rate of temperature change. To overcome
this, pneumatic detectors have a small orifice to vent the higher pressure that builds up
during slow increases in temperature or during a drop in barometric pressure. The vents
are sized so that when the temperature changes rapidly, as in a fire, the rate of
expansion exceeds the venting rate and the pressure rises. When the temperature rise
exceeds 7 to 8°C per minute, the pressure is converted to mechanical action by a
flexible diaphragm. Pneumatic heat detectors are available for both line and spot-type
detectors.
Line Type
The line type detector consists of metal tubing, in a loop configuration, attached to the
ceiling or sidewall near the ceiling of the area to be protected. Lines of tubing are
normally spaced not more than 9.1 m apart, not more than 4.5 m from a wall, and with no
more than 305 m of tubing on each circuit. Also, a minimum of at least 5 % of each
tube circuit or 7.6 m of tube, whichever is greater, must be in each protected area.
Without this minimum amount of tubing exposed to a fire condition, insufficient pressure
would build up to achieve proper response.
In small areas where the line type tube detectors might have insufficient tubing exposed
to generate sufficient pressures to close the alarm contacts, air chambers or rosettes
of tubing are often used. These units act like a spot-type detector by providing the volume
of air required to meet the 5% or 25 ft (7.6 m) requirement. Since a line type rate
of rise detector is an integrating detector, it will actuate either when a rapid heat rise
occurs in one area of exposed tubing, or when a slightly less rapid heat rise takes place in
several areas where tubing on the same loop is exposed.
Referring to Fig. 4, air in a tube is heated by the fire, which causes increase in pressure.
The pressure increase acts on two diaphragms, which causes them to move and
complete the alarm electrical circuit. If the tube was sealed completely, then slow
increases in ambient temperature, or a fall in barometric pressure would cause the alarm
to
initiate regardless of the rate of temperature change. This is overcome by using a small
orifice to vent the pressure build up during slow increases in temperature or a fall in
barometric pressure.
Figure 4
Line-Type Rate-of-Rise Detector
Spot Type
The pneumatic principle is also used to close contacts within spot detectors. The
difference between the line and spot type detectors is that the spot type contains all of the
air
in a single container rather than in a tube that extends from the detector assembly to the
protected area(s).
Combination Detectors
Combination detectors contain more than one element that responds to a fire. These
detectors may be designed to respond from either element, or from the combined
response of both elements. An example of the former is a heat detector that operates on
both the rate of rise and fixed temperature principles. Its advantage is that the rate
of rise element will respond quickly to a rapidly developing fire, while the fixed
temperature element will respond to slowly developing fire, when the detecting element
reaches
its set point temperature. The most common combination detector uses a vented air
chamber and a flexible diaphragm for the rate-of-rise function, while the fixed
temperature element is usually a spring restrained by a eutectic metal. When the fixedtemperature element reaches its design operating temperature, the eutectic metal
fuses and releases the spring, which closes the contacts.
Fig. 5 illustrates a combined rate of rise and fixed temperature device. Air supplied to
chamber A slowly escapes through vent B. A high rate of temperature increase causes
pressure in A to increase until diaphragm C closes contacts D and E. Fixed temperature
operation occurs when fusible alloy F melts, releasing spring G which pushes on C
closing
D and E.
Figure 5
Spot Type Combination Rate of Rise, Fixed Temperature
Detector
Electronic Spot Type Thermal Detectors
A thermoelectric effect detector is a device that utilizes a sensing element consisting of
one or more thermistors, which produce a change in electrical resistance in response to
an increase in temperature. This resistance change is monitored by associated electronic
circuitry, and the detector responds when the resistance changes at an abnormal rate
(rate of rise type) or when the resistance reaches a specific value (fixed temperature
type).
Rate of rise detectors use two thermistors. One is exposed to changes in atmospheric
temperature. When the temperature rapidly changes as in a fire situation, the
temperature of the exposed thermistor increases faster than the temperature of the
unexposed reference thermistor, generating a net change in resistance causing the
detector to go into alarm condition. Most rate of rise detectors are designed with a fixed
temperature backup feature so that, should the temperature rise be slower than 8°C,
per minute, the detector will operate when the exposed thermistor has reached a
predetermined fixed temperature.
SMOKE DETECTORS
A smoke detector will detect most fires much more rapidly than a heat detector.
Smoke detectors are identified by their operating principle. Two of the operating
principles are (1) ionization and (2) photoelectric. Smoke detectors using the ionization
principle provide somewhat faster response to high energy (open flame) fires, since these
fires produce large numbers of the smaller smoke particles. Smoke detectors
operating on the photoelectric principle respond faster to the smoke generated by low
energy (smoldering) fires, as these fires generally produce more of the larger smoke
particles.
The sensors are available as photoelectric, ionization, or combination photoelectric, and
ionization units. As fire alarm systems technology advances, analog sensors will be the
choice for any system application, regardless of system size.
Ionization Smoke Detectors
Smoke detectors utilizing the ionization principle are usually of the spot type, as shown
in Fig. 6. An ionization smoke detector has a small amount of radioactive material that
ionizes the air in the sensing chamber, rendering the air conductive and permitting a
current flow through the air between two charged electrodes. This gives the sensing
chamber an effective electrical conductance. When smoke particles enter the ionization
area, they decrease the conductance of the air by attaching themselves to the ions,
causing a reduction in ion mobility. When the conductance is below a predetermined
level, the detector responds.
Figure 6
Ionization Smoke Detector
Photoelectric Smoke Detectors
The presence of suspended smoke particles generated during the combustion process
affects the passing of a light beam through the air. This effect can be used to detect the
presence of a fire in two ways:
Obscuration of light intensity over the beam path
Scattering of the light beam
Light Obscuration Principle
Smoke detectors that operate on the principle of light obscuration consist of a light
source, a light beam gathering system, and a photosensitive device. When smoke
obscures
part of the light beam, the light reaching the photosensitive device is reduced, and this
initiates the alarm.
Most light obscuration smoke detectors, Fig. 7, are the beam type and are used to protect
large open areas. They are installed with the light source at one end of the area to
be protected and the photosensitive device at the other. Projected beam detectors are
generally installed in accordance with manufacturer’s instructions.
Figure 7
Obscuration Smoke Detector
Light Scattering Principle
When smoke particles enter a light path, scattering results. Smoke detectors utilizing the
photoelectric light-scattering principle, Fig. 8, are usually of the spot type. They
contain a light source and a photosensitive device arranged so the light rays normally do
not fall onto the device. When smoke particles enter the light path, light strikes the
particles and is scattered onto the photosensitive device, causing the detector to responds.
The photosensitive device used in scattering detectors usually is a photodiode or a
phototransistor.
Figure 8
Scattering Smoke Detector
Objective Three
When you complete this objective you will be able to…
Describe the design and operation of a typical standpipe system.
Learning Material
STANDPIPE SYSTEMS
Standpipe systems are used in buildings over 3 stories (14 metres) in height, since that is
the practical limit for firefighters to couple hose together from the pumper truck at
street level up the stairways to the fire floor. It is also close to the limit from which a fire
can be fought externally from ladders and snorkel equipment.
A standpipe system is used to overcome the above difficulties. The standpipe rises up the
stairwell or wells. At each floor level, provision is made for the connection of fire
hoses. The firefighters need only couple hoses to one of the valved outlets provided to get
a water supply.
The connections used are frequently on the floor below the fire. This allows the use of the
connections on the fire floor as well, and the fire is approached from below rather
than above. If the fire were approached from above with the stair doors open and the heat
of the fire rising, it would be similar to approaching the fire through a chimney.
There are three classes of standpipe systems:
Class I systems use NPS 63 mm hose and hose connections, and are provided for use
by fire departments, and those trained in firefighting techniques.
Class II systems use NPS 38 mm hose and hose connections, and are provided for use
by the building occupants, until the fire department arrives. Subject to
approval of the local authority, a minimum NPS 25 mm hose and hose connections
can be used in Class II service in light hazard occupancies.
Class III systems use both NPS 63 mm and NPS 38 mm hose connections. The NPS
63 mm are for the use by those trained in handling heavy hose streams and
the NPS 38 mm for the building occupants.
The number and location of standpipes and equipment is dependent upon the use,
occupancy and construction of the facility.
Provincial and local authorities govern the Fire Acts, Codes, and Regulations. In general
terms, the number of standpipes and hose stations is the same for each Class.
In each building, and in each section of a building divided by fire walls, there shall be
standpipes and hose stations such that all portions of each story of the building are within
9 m of a nozzle, attached to not more than 30 m of hose.
Where in Class II service a NPS 25 mm hose has been approved, then all portions of each
story of the building shall be within 6 m of a nozzle, when attached to not more than
30 m of hose.
The standpipe risers are located in noncombustible, fire-rated stairwells. If it is not
possible to locate all standpipes in fire-rated stairwells, then additional standpipes may be
located in pipe shafts at the building interior column locations.
For Class I and III service systems, at least one NPS 63 mm roof outlet connection shall
be provided from each standpipe. Fig. 9 illustrates a typical roof manifold system.
Figure 9
Typical Roof Manifold
The hose connections to the standpipe for Class I service should be located in the
stairwell.
For Class II service, the hose connection should be located in the corridor or space
adjacent to the stairwell.
For Class III service, the NPS 63 mm hose connection should be located in the stairwell
and the NPS 38 mm hose connection in the corridor or space adjacent to the stairwell.
Where the building has a large area, the connections NPS 63 mm and NPS 38 mm for
Class III may also be located at building interior columns.
Standpipes for risers of less than 30 m are usually NPS 102 mm pipe, over 30 m, the pipe
is usually NPS 152 mm. Where a building has a high level fire zone; that is, floors
more than 85 m above street level, then the riser to these higher floors is usually NPS 203
mm. The water pressure at the topmost outlet of each standpipe should not be less
than 450 kPa, with a flow rate in the system of 32 L/s. If the flowing pressure at any hose
valve outlet will exceed 690 kPa, then a pressure reducing system shall be installed
to reduce the pressure, at the required flow, to not more than 690 kPa.
Fig. 10 is a schematic of a typical single zone system, while Fig. 11 & 12 show systems
for buildings having two fire zones.
There are two basic standpipe systems. A wet standpipe is one that is always filled with
water. A dry standpipe is one that is normally dry and terminates at its base outside the
building with a fire department connection. In the event of a fire that requires fire
department participation, a pumper engine will connect to a nearby street hydrant and
discharge water into the standpipe system through the fire department connection. The
fire department connection is a “Y” piece so that two hoses can feed the standpipe
system. This special “Y” piece is called a “Siamese connection”. A Siamese connection
is also provided on a wet standpipe system.
Class II and Class III systems must be connected to a wet standpipe system as it is
essential that the NPS 1 ½” (38 mm) hose system has water immediately available.
Figure 10
Typical Single Zone Standpipe System
Figure 11
Typical Two Zone Standpipe System
Figure 12
Alternate Typical Two Zone Standpipe System
Objective Four
When you complete this objective you will be able to…
Describe the wet pipe, dry pipe, pre-action and deluge designs for sprinkler systems.
Learning Material
TYPES OF SPRINKLER SYSTEMS
There are five basic types of sprinkler system defined in NFPA 13, Standard for the
Installation of Sprinkler Systems.
Wet Pipe
Dry Pipe
Preaction
Combination of Dry Pipe and Preaction
Deluge
NFPA 13 is the fundamental document that governs the design and installation criteria
for these specialized fire protection systems. NFPA 13 is a standard, thus it provides the
necessary requirements and guidance with respect to the specifics of “how” to design,
layout, and install a system. It does not tell when a system is needed, that is the function
of NFPA 101 or a building code.
Wet Pipe Systems
This system, shown in Fig. 13, is the most common, easiest to design, and simplest to
maintain. These systems contain water under pressure at all times and utilize a series
of closed sprinklers. Once a fire occurs and produces enough heat to activate one of more
sprinklers, the water will discharge immediately from any of the open sprinklers. Wet
pipe should only be used when the temperature of the protected area is maintained at or
above 4°C.
This system is typically found in office buildings, stores, manufacturing facilities, hotels,
and health care facilities.
1. Main Water Supply
2. Main Drain Connection
3. Fire Department Connection
4. Water Flow Alarm
5. Water Pressurized Distribution Piping
6. Check Valve
7. Alarm Valve
8. Water Supply Gate Valve
9. Automatic Sprinklers
10. Inspectors test Connections
Figure 13
Wet Pipe Sprinkler System
Dry Pipe Systems
These systems, shown in Fig. 14, are found in environments where the temperature is
maintained below 4°C. The system piping contains air under pressure, 275 kPa
maximum, under normal circumstances. A dry-pipe valve is used to hold back the water
supply and to serve as the water/air interface. The valve acts on a pressure differential
principle, the surface area of the valve face on the airside being greater than the surface
area on the waterside.
When a fire occurs and enough heat is generated, one or more sprinklers will operate, the
system air pressure will then escape through the open sprinklers, drop to a
predetermined level, and allow the dry pipe valve to open. Once the valve opens, the
water supply will be admitted into the system piping, fill the pipe network, and water will
discharge from any sprinklers that have operated.
These systems are more complex, require a reliable air supply source and involve specific
design limitations such as the volume of pipe that can be governed by one dry pipe
valve, and special adjustments that are necessary for the anticipated area of operation.
Dry pipe systems can be found in buildings that are not maintained at the 4°C limit, such
as outside canopies and structures, and cold-storage warehouses.
1. Main Water Supply
2. Main Drain Connection
3. Fire Department Connection
4. Water Flow Alarm
5. Water Pressurized Distribution Piping
6. Dry Pipe Valve
7. Check Valve
8. Water Supply Gate Valve
9. Automatic Sprinklers
10. Inspectors test Connections
Figure 14
Dry Pipe Sprinkler System
Preaction Systems
The piping for these systems, shown in Fig. 15, is typically provided with some minimal
quantity of air pressure, thus the pipe network has no water in it under normal
circumstances. The water is held back by means of a preaction valve. The system is
equipped with a supplemental detection system. Operation of the detection system allows
the preaction valve to automatically open and admit water into the pipe network. Water
will not discharge from the system until a fire has generated a sufficient quantity of heat
to cause operation of one or more sprinklers. In essence, the system appears as a wet pipe
system once the preaction valve operates.
The small amount of air, which is maintained in the pipe, is used to monitor the integrity
of the pipe. If the pipe develops a leak, air-pressure will drop and an alarm will sound,
indicating a low air-pressure condition exists within the pipe. The preaction valve stays in
its normal position until the detection system is activated.
Preaction systems are typically found in environments that house computer equipment or
communication equipment, museums, and other facilities where inadvertent water
discharge is of major concern to the end user. The double-interlock system is most
common in deep-freeze facilities where accidental valve operation may result in freezing
of
the pipe in a matter of minutes.
1.
Main Water Supply
8. Low Pressure Supervisory Panel
1a.
Control Water Supply
9. Solenoid Valve
2.
Water Supply Gate Valve
10. Supervisory Low Pressure Alarm
3.
Control Valve
11. Heat Detectors
4.
Pressure Alarm Switch
12. Deluge Release Panel
5.
Check Valve
13. Fire Alarm Bell
6.
Water Motor Alarm
14. Trouble Horn
7.
Manual Control Station
15. Automatic Sprinklers
Figure 15
Preaction Sprinkler System
Combination of Dry Pipe and Preaction
Another type of preaction system is commonly referred to as a double-interlock preaction
system. This system has characteristics as previously described for preaction systems
and characteristics of a dry-pipe system. In order to admit water into this type of system,
the detection system must operate and the fire must generate a sufficient quantity of
heat to cause operation of one or more sprinklers, thereby allowing a loss of pressure.
Deluge Systems
Rapidly growing and spreading fires are most effectively protected with this type of
system. Deluge systems, shown in Fig. 16, are intended to deliver large quantities of
water
over a large area in a relatively short period of time. The sprinklers that are used in a
deluge system have their operating elements removed. These open sprinklers are
attached to branch-line piping in the same manner as other types of sprinklers.
A deluge valve is used to control the system water supply. The sprinkler system pipe is at
atmospheric pressure, since the open sprinklers are attached to it. The system water
supply is maintained to the system side of the deluge valve. In a similar manner to the
preaction system, a supplemental detection system is provided throughout the same
area as the sprinklers. Upon activation of this detection system the deluge valve is
electrically opened, thereby admitting water into the pipe network. As the water reaches
each
sprinkler in the system, it immediately discharges from the open sprinkler.
The nature of this system makes it appropriate for facilities that contain combustible or
flammable liquids. In addition, this system is used for situations in which thermal
damage is likely to occur in a relatively short period of time.
1.
Main Water Supply
7.
Solenoid Valve
1a.
Control Water Supply
8.
Heat Detector
2.
Water Supply Gate Valve
9.
Deluge Release Panel
3.
Control Valve
10.
Fire Alarm Bell
4.
Pressure Alarm Switch
11.
Trouble Horn
5.
Water Motor Alarm
12.
Open Sprinklers
6.
Manual Control Station
Figure 16
Deluge Sprinkler System
There are several variations to each one of these basic systems. Antifreeze systems are
basically wet-pipe systems with a certain percentage of antifreeze concentrate added in
to depress the freezing point. This type of system can be used to protect small areas, such
as may be found at outside loading docks or exterior canopies. NFPA 13 specifies
select types of antifreeze concentrate and percentages.
Objective Five
When you complete this objective you will be able to…
Describe the layout, components and operation of a typical firewater system with fire
pump and hydrants. Explain seasonal considerations for a firewater system.
Learning Material
Fig. 17 shows the water piping for fire protection of an industrial site. Typical details
shown are connections to public mains and supplies for a private fire pump, main water
piping loops, sectional control valves, and hydrants.
Fire pumps are discussed extensively, in the 4th Class module entitled “Plant Fire
Protection”. There will not be any further reference made to them. Fire hydrants are
covered
in the following module.
Figure 17
Industrial Site Fire Water Protection System
Reprinted with permission from NFPA Fire Protection Handbook Copyright 1997,
National Fire Protection Association, Quincy, MA 02269. This reprinted material is not
the
complete and official position of the National Fire Protection Association, on the
referenced subject, which is represented only by the standard in its entirety.
Opinions vary on how many valves should be used in a system of underground mains.
Making sure all sectional control valves are open is probably more critical than avoiding
the problem of too few sectional valves. Nevertheless, the modern tendency is to make
fairly liberal use of valves. A few well-established principles are shown in the above
figure, they include:
A city supply check valve (and meter, if required) located between indicating valves so it
can be repaired without affecting the city and plant systems.
A pump check valve located between pump and indicating valves so that the latter can be
used to shut off the connection to the system when making check valve and pump
repairs.
Three sectional valves (“G” and “H”, to take care of present loop and “J”, for a short
branch supplying a small detached building) in addition to the main water supply valve.
The branch will ultimately be part of a second loop. There should be a loop valve on each
side of every valuable water supply to permit cutting off a part of the loop without
cutting the water supply off altogether. Best practice requires that post indicators, which
shows the valve position, either open or closed, be attached to valves in pits.
Sectional control valves (indicator posts C, “E”, and “F”) can cut the loop into four
sections (in conjunction with Valves “G” and “H”). In large or complicated underground
systems, it is recommended that indicator posts controlling risers to sprinklers or
standpipes be painted a different color from sectional control valves. Generally, no more
than
six hydrants or indicator posts should be located between sectional valves.
Gate valves must be provided on hydrant laterals to isolate the hydrant in the event it
malfunctions is damaged, or when repairs are necessary.
Location
Hydrant spacing is usually determined by the fire flow demand established on the basis of
the type, size, occupancy, and exposure of structures.
When hydrants are located on a private water system and hose lines are intended to be
used directly from the hydrants, they should be so located as to keep hose lines short,
preferably not over 75 m. At a minimum, there should be enough hydrants to make two
streams available at every part of the interior of each building not covered by a
standpipe system protection. They should also provide hose stream protection for exterior
parts of each building using only the lengths of hose normally attached to the
hydrants. It is desirable to have a sufficient number of hydrants to concentrate the
required fire flow about any important building with no hose line length exceeding 150
m.
For average conditions, hydrants normally are placed about 12.2 m from buildings to be
accessible, during a fire event. When that is impossible, they are set where the chance
of injury by falling walls or debris is small and where fire fighters are not likely to be
driven away by smoke and heat. In crowded industrial yards, hydrants usually can be
placed
beside low buildings, near substantial stair towers, or at corners, formed by masonry
walls that are not likely to fall.
Hydrants that must be located in areas subject to heavy traffic need protection against
damage from collision. The parking lots of shopping centers and mill yards are good
examples.
Seasonal Considerations
The depth of cover to provide protection against freezing will vary from about 0.76 m, in
the southern United States to about 3.05 m, in northern Canada. Because there is
normally no circulation of water in fire protection mains, they require greater depth of
covering than do public mains. The minimum cover should always be maintained to
prevent mechanical damage. Depth of covering should be measured from top of pipe to
ground level, and consideration should always be given to future or final grade and
nature of soil. A greater depth is required in a loose, gravelly soil (or in rock) than in
compact or clay soil. A safe rule to follow is to bury the top of the pipe not less than 0.3m
below the lowest frost line for the locality.
Objective Six
When you complete this objective you will be able to…
Describe the construction and operation of a typical fire hydrant.
Learning Material
TYPES OF FIRE HYDRANTS
There are two types of fire hydrants in general use today. The most common is the base
valve (dry barrel), shown in Fig. 18, in which the valve controlling the water is located
below the frost line between the foot piece and the barrel of the hydrant.
Figure 18
Dry Barrel or Frost Proof Hydrant
The barrel of this type hydrant is normally dry with water being admitted only when there
is a need. A drain valve at the base of the barrel is open when the main valve is
closed, allowing residual water in the barrel to drain out. This type of hydrant is used
whenever there is a chance the temperature will go below freezing, because the valve
and water supply are installed below the frost line.
The other type of hydrant is the wet barrel (California) type, shown in Fig. 19, is used
where the temperature remains above freezing. These hydrants usually have a
compression valve at each outlet, but they may have another valve in the bonnet that
controls the water flow to all outlets.
Figure 19
Wet Barrel (California Type) Hydrant
(Courtesy Mueller Co.)
Hydrants
Well-designed and properly installed hydrants present a minimum of maintenance
difficulties. The dry barrel hydrant, for example, has a small drain near the base of the
barrel arranged to permit water to drain out when the main valve is shut. When the main
valve is opened several turns, this drain is closed. If the drain is working properly and
the main valve is tight, the difficulty of water freezing in the barrel is avoided.
Occasionally, situations are found where ground drainage is unsatisfactory or where
ground water
may stand at dangerous levels. In those cases, drains may be closed entirely and hydrant
barrels pumped out periodically.
The use of salt or salt solutions to prevent freezing is not recommended because of their
corrosive effect and limited usefulness. If antifreeze is used in hydrant barrels, its use
must be confined to hydrants that are not part of a system supplying water for domestic
consumption.
Ethylene glycol is extremely toxic, with as little as 0.1 mg/L ingested for a period of a
week being fatal. This substance should not be used. Propylene glycol is not as toxic and
may be used to prevent freezing but with proper precautions and in accordance with local
health regulations.
Suggestions for detecting freezing in hydrants include:
Sound by striking the hand over an open outlet. Water or ice shortens the length of the
“organ tube” and raises the pitch.
Turning the hydrant stem. If solidly frozen, the stem will not turn. If only slightly
bound by ice, placing a hydrant wrench on the nut and tapping smartly may
release the stem. Blows should be moderate to prevent breaking the valve rod.
Lowering a weight on a stout string into the hydrant. It may strike ice or come up wet,
showing water in the barrel.
Probably the most satisfactory method of thawing a hydrant is by means of a steam
hose. A thawing device in which steam may be rapidly produced should
be standard equipment for fire departments in cold-weather climates. The steam hose
is introduced into the hydrant through an outlet and pushed down,
thawing as it goes.
Objective Seven
When you complete this objective you will be able to…
Explain the purpose and describe a typical deluge water system for hydrocarbon storage
vessels.
Learning Material
HYDROCARBON STORAGE TANK DELUGE WATER SYSTEMS
Prevention of Fire
It is sometimes possible to use water spray to dissolve, dilute, disperse, and cool
flammable or combustible materials before they are ignited.
Fixed water sprays are designed specifically to provide optimum control, extinguishment,
or exposure protection for special fire protection problems. Limitations to the use
of water spray that should be recognized involve the nature of the equipment to be
protected and the physical and chemical properties of the material(s) involved.
Fixed Water Spray Systems
A water spray system is a special pipe system connected to a reliable supply of fire
protection water, and equipped with water spray nozzles for specific water discharge and
distribution over the surface or area to be protected. The piping system is connected to a
water supply through a deluge valve that can be actuated both automatically and
manually to initiate the flow of water.
Automatic system actuation valves for spray systems can be actuated electrically by the
operation of automatic detection equipment, such as heat detectors, relay circuits,
gas detectors, or mechanically by hydraulic or pneumatic systems, depending upon the
operating mode of the individual valves. Generally, each manufacturer of system
actuation valves, most of which can do dual service in deluge systems, provides its own
particular combination of system actuation valve, releasing mechanism, detection
system, and supervisory service.
Systems Application
Fixed water spray systems are most commonly used to protect equipment from exposure
fires in flammable liquid and gas tankage, piping, and equipment; in electrical
equipment such as transformers, oil switches, rotating machinery, and cable trays; in
structural supports; and in conveyor systems and the openings in firewalls and floors
through which they pass. The type of water spray required for any particular hazard will
depend on the nature of the hazard and the purpose for which the protection is
provided.
A water spray system is designed to give complete surface wetting with a specified water
density, taking into consideration the following:
a) Nozzle types, sizes, and spacing
b) Influence of wind and drafts
c) Probability of water rundown
d) Prevention of the formation of difficult-to-wet deposits of soot or carbon surfaces
e) Overlap of water discharge patterns onto the surfaces
f) Ability of the water supply to furnish adequate pressure to all of the nozzles
In most cases, it is neither desired nor expected that a water spray be used to extinguish
burning gases, such as LPG (Liquefied Petroleum Gas). However, the cooling effect
of the water on the tank may reduce and control the rate of burning until the gas supply to
the fire is exhausted or it can be isolated.
Objective Eight
When you complete this objective you will be able to…
Explain the purpose and describe a typical foam system for process buildings and tanks.
Learning Material
FOAM SYSTEMS
Where flammable liquid fire protection is required for permanently installed hazards,
such as fuel storage tanks or dip tanks containing flammable or combustible liquids,
air-foam-generating and distributing devices are installed internally in the tank. These
fixed devices, which are piped to a source of foam solution, may be arranged for
manual control or automatic activation by fire detectors in the event of fire.
Foam Chambers for Large Fuel Storage Tanks
Fire protection of large outdoor fuel tanks requires that several foam chambers with
foam-makers be installed at equally spaced positions slightly below the top rim of the
tanks, as shown in Fig. 20. These chambers are connected to lines on the ground that
supply foam solution to each foam-maker simultaneously in case of ignition of the
flammable contents of the tank. Frangible seals at the discharge outlet of the foam
chamber prevent vapor from entering the foam piping. These seals are designed to burst
when foam pressure is applied. A screen for the air inlet to the aspirating foam-maker
prevents clogging from foreign matter, such as bird nesting material. A universal or
swing pipe joint is installed at ground level in the foam solution inlet pipe to prevent
fracturing of the supply piping if an explosion precedes a tank fire.
Figure 20
Air Foam At Top Of Storage Tanks
Internal Tank Foam Distributing Devices
A prime requirement for efficient fuel tank extinguishment by topside foam devices has
always been that the foam must be applied to the burning surface without undue
plunging into the fuel, or allowing the foam to become coated with burning fuel. This
gentle application of foam must be accomplished at any level of the contents of the tank.
Many devices have been developed to gently apply foam from one point regardless of
burning fuel level. These devices are listed as “Type I” foam-discharge outlets for tanks
and are required for some alcohol-type foams. When foam discharge into a tank is
deflected to run down the inside tank shell to the burning fuel surface, it is called a “Type
II” outlet for foam application.
Central Foam Distributing Systems
These systems consist of an enclosure housing a foam concentrate supply tank and a
proportioning device, as shown in Fig. 21. Foam solution is supplied under pressure from
this foam house to the piping system, and controlled by appropriate valves so that the
foam chambers with foam-makers on the burning tank, receive foam solution.
Figure 21
Schematic Arrangement Of Air Foam Protection For Storage
Tanks
Reprinted with permission from NFPA Fire Protection Handbook Copyright 1997,
National Fire Protection Association, Quincy, MA 02269. This reprinted material is not
the
complete and official position of the National Fire Protection Association, on the
referenced subject, which is represented only by the standard in its entirety.
Semi-fixed systems of similar design are more frequently used with mobile foam
concentrate supply from foam trucks. The truck proportions and pumps foam solution to
the
pipe laterals feeding the foam-makers from a safe location outside the dike.
Fixed systems consisting of automatically operated combinations of foam spray systems
and foam monitors are often installed to protect chemical processing plants.
Alcohol-resistant foams are usually required. In these designs, where there may be a high
risk, process vessels, pumps, and piping often are all included within the foam
distribution pattern for overall protection. The sensing of heat by fire detectors can
automatically activate the system.
Foam-Water Sprinkler Systems
In areas where flammable and combustible liquids are processed, stored, or handled, a
water discharge may be ineffective for controlling or extinguishing fires. The
foam-making sprinklers (aspirating-type) and deluge or spray nozzles using AFFF foams
have successfully replaced water sprinkler nozzles for such systems so that fires in
these occupancies may be controlled and property safeguarded.
When supplied with foam solution, sprinkler system piping grids provided with foamwater nozzles generate air-foam in essentially the same water sprinkler pattern as when
water is discharged from the same nozzle. This dual capability affords the system Class A
and B extinguishment ability.
Fixed sprinkler systems using these nozzles require that foam concentrate tanks,
proportioners, and suitable pumps be provided to supply the system with foam solution or
water. Detection devices may also be used to activate the system, or the system may be
activated manually. Closed-head sprinklers may also be used, and are now
recognized in NFPA 30.
Objective Nine
When you complete this objective you will be able to…
Describe a typical fire response procedure for an industrial setting.
Learning Material
FIRE RESPONSE PROCEDURE FOR AN INDUSTRIAL SETTING
There is always a risk of an emergency, no matter how complete the safety program.
Emergency preparedness means having plans in place in the event of an emergency.
Industrial plants are required to have an Environment, Health and Safety Program in
place. This program covers, among other areas, training in safe work procedures as well
as Emergency Response Procedures. Emergency response procedures are written
procedures, established to ensure the immediate and competent handling of emergencies
involving any unplanned occurrences, such as: accidents or property threatening events
such as fires.
In large industrial settings, workers on shift will be trained in specific assignments to
follow in the event of an emergency, including fire. All employees must be familiar with
the specific emergency procedures plan appropriate to their work location. An overview
of the plan is usually provided as part of the safety orientation and reinforced at
regularly scheduled safety meetings. Employees are trained in the use of emergency
equipment, including the use of fire extinguishers, and practice preparedness through
regularly documented emergency drills and evacuations.
Emergency routes and response procedures are located at each worksite, outlining
personnel responsibilities, evacuation, medical attention, and location of emergency
equipment and shutdown procedures. Emergency contact numbers are located by all
telephones. Emergency equipment, such as fire fighting, respiratory, first aid and
rescue, is located on each site and regularly inspected and documented.
Emergency response procedures are developed to instruct first responders in the event of
a fire. A typical procedure would consist of the following:
1. Sound the fire alarm. This may be an in plant only and/or local fire department.
2. Complete a risk assessment of the situation.
a) Are there any other hazards?
b) Can you control the fire?
c) Do you need and or have help available?
d) Do you have an escape route?
3. Attempt to extinguish, or control the fire. If the fire escalates, back away. Never
turn your back on a fire.