Many of you must be aware that Intergraph announced an extension of Caesar II 2017 in May 2017. B31J Essentials provides a set of calculations for revised SIFs and flexibility factors, as defined in the code ASME B31J-2017, Stress Intensification Factors (i-Factors), Flexibility Factors (k-Factors), and their Determination for Metallic Piping Components.
Benefits of Using the B31J Module of Caesar II
By using these revised SIFs and flexibilities, your stress analyses produce more accurate results. B31J Essentials provides the “more applicable data” referenced in recent editions of the piping codes. If someone is currently on CAESAR II maintenance and has installed CAESAR II 2017 (v.9.00), He can download the B31J Essentials installer from Intergraph Smart Support (https://smartsupport.intergraph.com) for free and install in their system. This article will try to inform what ASME B31J covers in brief.
What is ASME B31J?
For a long time, there was a need for a standard method to develop stress intensification factors (SIFs or i-factors) for ASME piping components and joints. At the time, the B31 Code books provided SIFs for various standard fittings and joints but did not provide guidance on how to conduct further research on existing SIFs or how to establish SIFs for nonstandard and other standard fittings or joints.
ASME B 31J is the outcome of recent research by MDC on current manufacturing practices in the SIF and k-factor test procedures, to provide a consistent and up-to-date table of SIFs and k-factors for metallic piping components.
ASME B 31J provides a standard approach for the development of SIFs, k-factors, and sustained stress multipliers for piping components and joints of all types, including standard, nonstandard, and proprietary fittings. However, this code still does not cover fittings that have a D/T ratio greater than 100 for which you have to be dependent on FEA analysis.
Fig. 1: B31J Menu bars explaining the functions.
Sustained stress multipliers are used to multiply the nominal bending stress due to sustained loading and reflect the collapse capacity of the metallic piping component or joint. Where more accurate sustained stresses are needed but an equation for the sustained stress is not given in the B31 Code book, nominal stresses due to sustained moments computed using the section modulus of the matching pipe should be multiplied by the appropriately sustained stress multiplier. Where the sustained stress is needed and an equation for the sustained stress is given in the Code book as a function of the SIF and provided in lieu of more applicable data, the sustained stress multipliers developed using the method in this Standard may be substituted as more applicable data and used with the nominal stress computed using the section modulus of the matching pipe.
Broadly The code provides the following:
Fig. 2: Typical Output SIF results as calculated by the B31J module of Caesar II
Included the most applicable currently available stress intensification and flexibility factors compiled from test and analysis data for standard commercially available metallic components in a tabular format.
Nonmandatory Appendix B provides the standard method to develop branch connection flexibility factors.
Nonmandatory Appendix C demonstrates how the new branch connection k-factors should be used in the elastic analysis of piping systems, and
Nonmandatory Appendix D provides a standard method to develop sustained stress factors.
B31J Essentials is a FEATools (Version 3.0) but limited to only the B31J calculations (for SIFs and Flexibilities). One can access the B31J calculations by selecting the FEA Translation option from the CAESAR II Main Menu. The software starts FEATools, which provides the B31J computations for the translated CAESAR II model.
Surface coating for corrosion prevention is a critical aspect of preserving the integrity and longevity of steel structures and components. Corrosion, which is the gradual deterioration of metal due to chemical reactions in its environment, can lead to significant economic losses and safety hazards. Therefore, protecting steel surfaces from corrosion is essential in various industries, including piping, pipeline, construction, infrastructure, automotive, aerospace, and marine.
Surface coatings are designed to act as a barrier between the steel substrate and the corrosive environment, preventing the interaction that leads to corrosion. These coatings can be applied to various forms of steel, including sheet metal, structural steel, pipelines, and more.
What is Surface Coating?
Surface coating decorates and protects the surface on which it is applied. It can be defined as a homogeneous mixture of pigments, binders, solvents, and additives. The surface coating covers the surface completely and serves as an anti-corrosive agent. The success or failure of any coating is influenced by the following factors:
Substrate Condition
Surface condition and method of application
Environmental condition at which it is applied and expected to withstand during service
And last but not least the quality of paint used
Why Coat a Surface?
Decorates the surface on which it is applied.
Protects the surface from rust
Protects from micro-organisms like fungi and algae maintaining their original body.
RUST NEVER SLEEPS!!!
Corrosion of Steel
Before delving into surface coatings, it’s crucial to understand the mechanisms behind corrosion. Corrosion occurs due to electrochemical reactions between metal, moisture, and other corrosive agents. The most common types of corrosion include:
Uniform Corrosion: This is the most straightforward form of corrosion, where the entire surface of the steel corrodes uniformly. It typically occurs in environments with a consistent level of corrosivity.
Localized Corrosion: Localized corrosion includes pitting corrosion, crevice corrosion, and stress corrosion cracking (SCC). Pitting corrosion forms small, deep pits on the steel surface, while crevice corrosion occurs in gaps or crevices where moisture and oxygen are trapped. SCC is the result of tensile stresses and specific environmental conditions.
Galvanic Corrosion: Galvanic corrosion happens when two dissimilar metals are in electrical contact and immersed in an electrolyte. One metal corrodes rapidly (the anode), while the other remains protected (the cathode).
Using Inhibitive Primers Zinc phosphates/Chromate forms a passive layer with adhered rust.
Using Sacrificial Primer. Indirect catholic Protection by Zinc in Zinc-rich primers
Barrier Coatings. High DFT Coating System Isolates Surface from Corrosive Environment
Types of Surface Coatings
Surface coatings can be categorized into three main types: organic coatings, inorganic coatings, and metallic coatings.
Organic Coatings
Organic coatings are based on carbon-containing compounds and are widely used for corrosion prevention. They include:
Paints: Traditional paints consist of pigments, binders (resins), solvents, and additives. Epoxy, polyurethane, and acrylic paints are commonly used for steel surfaces. They provide good barrier protection and are available in various colors.
Powder Coatings:Powder coatings are applied as dry powder and then cured with heat. They are known for their durability, resistance to chemicals, and smooth finishes. Epoxy, polyester, and epoxy-polyester hybrid powders are commonly used.
Coil Coatings: Coil coatings are applied to steel coils before they are formed into specific shapes. They are commonly used in the automotive and construction industries.
Marine Coatings: Marine coatings are designed for steel structures exposed to harsh marine environments. They offer excellent corrosion resistance and are often used on ships, offshore platforms, and bridges.
Inorganic Coatings
Inorganic coatings are based on non-carbon compounds and include:
Zinc-rich Coatings: These coatings contain a high concentration of zinc particles, which act sacrificially to protect the steel substrate. Zinc-rich coatings are often used in harsh environments and as a primer for other coatings.
Phosphate Coatings: Phosphate coatings are commonly applied as a pre-treatment to improve the adhesion of organic coatings. They also provide some corrosion resistance.
Chromate Conversion Coatings: These coatings, often used on aluminum and zinc-coated steel, provide corrosion protection and enhance paint adhesion.
Metallic Coatings
Metallic coatings involve the deposition of a layer of another metal onto the steel surface. Common metallic coatings include:
Galvanizing: Galvanizing involves coating steel with a layer of zinc through hot-dip galvanizing or electro-galvanizing. Zinc provides sacrificial protection, and galvanized steel is widely used in construction and outdoor applications.
Aluminizing: Aluminizing involves applying a layer of aluminum to the steel surface, offering excellent corrosion resistance at high temperatures.
Tin Coatings: Tin coatings are used in the food and beverage industry for corrosion protection and as a barrier against contamination.
Composition of Paint or Surface Coat
The basic constituents of paints are
Pigments 5 to 25%
Binders 60 to 65%
Solvents 15 to 25%
Additives 1 to 5 %
The relative proposition of these ingredients can be varied to produce films with any desired physical and application characteristics
Pigments for Surface Coating
A finely divided powder that can disperse in media of various types to produce paints. It is insoluble in the medium. Important properties are
Color
Tinting Strength
Opacity
Fastness to light
Resistance to heat
The oil absorption of pigment
Particle size: Hiding Power, Gloss or smoothness, Rate of settling of pigment
Binders for Surface Coating
Binders are the heart of the paint system. Binders bind or cement the pigment particle into a coherent film that adheres to the substrate. The mechanical and resistive properties of the film are controlled very largely by the binder.
The durability of the paint depends on the quality and quantity of binder used!!!!
Convert the liquid coating on application to a solid dry film.
Provide gloss to film
Making the coating adhere to the substrate
Given the elasticity of the film
Resistance to water, chemicals, and abrasion
Disperse the pigments and extenders
Hold the pigment in suspension.
The Choice of Binder for Paint depends on the end use of the paint
Type of Binders
Drying oils: Vegetable oils on exposure to air, convert from liquid to solid through a process of oxidation. Can be a sole film former but most often mixed with resin
Resins: Most surface coatings contain a synthetic resin-based film former. Most decorative paints are based on oil-modified resins.
Few Important Binders/Resins
ALKYD Resins
Largest groups of synthetic resins.
They are oil-modified polyester
Good exterior durability
Low alkali and water resistance.
AMINO Resins: Melamine and urea-formaldehyde
Epoxy Resins:
Has excellent adhesion, hardness, chemical, and corrosion resistance
Can be used to do high-build paint
Poor exterior durability
Poly-amide Resins: Used as curing agents for epoxy resins.
Polyurethane Resins:
Good resistance to high temp, chemical and acid resistance, good resistance to various gases, alkali resistance.
Low resistance to solvents like ketones, esters
Chlorinated Rubber:
It is one pack of thermoplastic.
Have good Chemical resistance and good acid and alkali resistance.
Can be applied as high-build paint.
Disadvantage: Poor resistance to high temp and solvents like ketones, aromatic HC
Vinyl Resins:
Cellulose Resins: Widely used in auto-finishing
Acrylic Resins: Possess good light fastness, good adhesion, and excellent durability.
Solvents for Surface Coating
The primary function of the solvent is to dissolve film formers, thereby consistency suitable for the application. Choice solvent influences viscosity, drying and flow, and leveling.
Solvents are lost in the atmosphere, so it is an economic loss.
Solvents, in isolation or combination, are used in making thinner for the paints.
Examples of solvents:
Hydrocarbon Solvent: Aliphatic, aromatic, solvent Naptha, alcohols, ketones, esters, etc.
Additives for Surface Coating
Used in a small amount to give a coating one or more desirable properties. The only difference between additives and other raw materials is that the amount of additives is very small. Properties that can be controlled through additives are:
Viscosity
Setting
Drying
Gloss
Opacity
Bacterial action
Thickness
Deodorants, etc.
Classification of Paints and Surface Coatings
Paints can be classified based on:
The Physical state: Liquid Paint and Stiff Paint
The Thinner Used: Water thinnable and solvent thinnable
The End used: Decorative and protective.
Modes of film formation: Thermosetting and Thermoplastics
The order of application: Undercoat and topcoat
The extent of gloss: Glossy, semi-glossy, egg-shell. matt
Modes of Film Formation: Film formation is either by thermosetting or thermoplastics.
Thermoplastic (Non -convertibles):
In these coatings when the paint is applied on a surface, the solvent evaporates living resin to its original form spread over the surface. So change is only physical and can be reversed to its original form by using thinner. E.g Chlorinated Rubber
Thermosetting (Convertible):
Chemical changes occur in the coating and dry film is different from its liquid state. Ex. Epoxy, alkyds, etc.
Surface Preparation
Surface preparation is a crucial step before applying any coating. It involves the removal of contaminants, oxides, and rust from the steel surface to ensure proper adhesion and performance of the coating. Surface preparation is the most important part of a coating system. The surface preparation of the coating system is what a foundation is for a building.
Surface Preparation of Steel
Some of the common surface preparation methods are
Mechanical Cleaning: This includes techniques such as abrasive blasting (sandblasting), grinding, and wire brushing. Abrasive blasting is particularly effective in removing rust and scale.
Chemical Cleaning: Chemical methods involve the use of acids, alkaline solutions, or solvents to remove contaminants and rust. Pickling and phosphating are common chemical cleaning methods.
Electrocleaning: This process uses an electric current to remove contaminants from the steel surface. Electrocleaning is effective for removing organic residues.
Conversion Coatings: Conversion coatings, such as chromate and phosphate coatings, chemically modify the steel surface to enhance adhesion and corrosion resistance.
Some of the various surface preparation methods of steel are
Degreasing
Hand tool cleaning
Power tool cleaning
Flame Cleaning
Pickling
Abrasive Blast Cleaning
Wet Abrasive Blast Cleaning
International Standard of Blast Cleaning
Fig. 2: Few International Standards for Blast Cleaning
Paint or Surface Coat Application Methods
The choice of coating application method depends on factors such as the type of coating, the substrate, and the intended use. Common methods include:
a. Brushing and Rolling: Suitable for small-scale projects and touch-ups, this method involves manually applying coatings using brushes or rollers.
b. Spraying: Spraying is a versatile method suitable for both small and large projects. It includes airless spraying, air-assisted spraying, and electrostatic spraying, among others.
c. Dipping: Dipping involves immersing the steel substrate into a tank of coating material. It is often used for small, complex parts.
d. Powder Coating: Powder coatings are applied using an electrostatic gun that charges the powder particles, making them adhere to the grounded steel substrate. The coated part is then cured in an oven.
e. Hot-Dip Galvanizing: This method involves immersing the steel in molten zinc. It is commonly used for large structures and provides excellent corrosion protection.
Theoretical Coverage (Sq.M/Ltr) =(%Volume Solids X100)/DFT in microns
Surface Coating Performance Evaluation
To assess the effectiveness of a surface coating for corrosion prevention, various tests and standards are employed:
a. Salt Spray Test (ASTM B117): This test assesses a coating’s resistance to corrosion in a salt-laden atmosphere. It involves exposing coated samples to a salt spray and monitoring their corrosion over time.
b. Adhesion Test (ASTM D3359): Adhesion tests measure the ability of a coating to adhere to the substrate. Various methods, including cross-cut and pull-off tests, are used.
c. Cyclic Corrosion Tests: These tests simulate real-world corrosion conditions, including wet and dry cycles, temperature variations, and UV exposure.
d. Electrochemical Impedance Spectroscopy (EIS): EIS measures the electrical impedance of a coated surface and can provide insights into the coating’s corrosion resistance.
e. Coating Thickness Measurement (ASTM D7091): This test ensures that the coating thickness meets the specified requirements, as inadequate thickness can compromise corrosion protection.
Factors Affecting Surface Coating Performance
The performance of a surface coating can be influenced by several factors:
a. Substrate Quality: The condition and cleanliness of the steel surface before coating application are crucial for adhesion and overall performance.
b. Environmental Conditions: The exposure environment, including temperature, humidity, and corrosive agents, can impact the rate of corrosion.
c. Coating Thickness: The thickness of the coating layer affects its ability to provide a barrier against corrosion. Thicker coatings generally offer better protection.
d. Coating Quality: The quality of the coating application, including uniformity, coverage, and absence of defects, is critical for long-term performance.
e. Maintenance: Regular inspection and maintenance of coated surfaces are essential to identify and address any damage or degradation of the coating.
Maintenance and Repair of Coated Steel Surface
Maintenance and repair of coated steel surfaces are essential to ensure long-term corrosion protection. Common maintenance practices include:
a. Regular Inspection: Periodic visual inspections to detect any signs of coating damage, corrosion, or defects.
b. Cleaning: Removing dirt, debris, and contaminants from the coated surface to maintain the coating’s effectiveness.
c. Touch-up Painting: Repairing small areas of coating damage with compatible coatings to prevent further corrosion.
d. Recoating: When the existing coating reaches the end of its service life, recoating may be necessary to maintain protection.
e. Cathodic Protection: In some cases, cathodic protection systems can be used alongside coatings to provide additional corrosion protection.
Emerging Trends in Corrosion Prevention
The field of corrosion prevention is continually evolving. Some emerging trends include:
a. Nanotechnology: Nanocoatings, which incorporate nanoparticles, offer enhanced corrosion resistance and durability.
b. Smart Coatings: Smart coatings can sense and respond to changes in the environment, providing real-time corrosion protection.
c. Biodegradable Coatings: Environmentally friendly coatings that degrade over time without harming the environment are gaining popularity.
d. Self-healing Coatings: Self-healing coatings contain materials that can repair small defects and cracks, extending the life of the coating.
e. Corrosion Inhibitors: Advanced corrosion inhibitors, both organic and inorganic, are being developed for improved corrosion protection.
Fatigue Analysis: Definition, Methods, Types, Reasons, Failure Criteria, Caesar II Case Study
Fatigue Analysis is the structural analysis of the failure tendency of systems when subjected to cyclical loads. Various software is available in the market to study fatigue behavior under cyclic loads. Fatigue is the progressive and localized structural damage that occurs when a material is subjected to cyclic loading. Continued cycling of high-stress concentrations may eventually cause a crack that propagates and results in leakages. This failure mechanism is called fatigue. Damage once done during the fatigue process is cumulative and normally unrecoverable.
Fatigue analysis is performed to find out the satisfactory performance level of a structural member under cyclic loading. It estimates the performance of the member under all three stages of fatigue failure. This means fatigue analysis will give data related to crack initiation, crack propagation, and finally failure probability for a specific material.
What is Fatigue in Piping and Structural Applications?
Fatigue for piping or structural applications can be defined as a failure methodology under a repeated or varying load situation. That load never reaches to such a level that it can cause failure of the member in a single application. However, the cumulative effect of each cycle can cause the failure by crack initiation and propagation. It’s a slow process and takes time for complete failure.
Objective of Fatigue Analysis
The aim of fatigue analysis of piping or structural systems is to assess and predict the potential for fatigue failure in these systems over time by calculating fatigue life and total damage. Fatigue analysis is essential for ensuring the structural integrity and reliability of various engineering components, including pipes, bridges, aircraft structures, and more.
Fatigue Analysis Methods
Fatigue analysis is performed using any of the two methods listed below:
The Stress-Life (S-N) or S-N method of fatigue analysis or
The local Strain or Strain-Life (e-N) method of fatigue analysis
The S-N method of fatigue analysis is highly popular in the piping industry. The Caesar II software uses the S-N curve as input and compares the piping stresses with it to provide a safe time limit before failure as fatigue analysis output. The S-N curves for each material are established by standards like ASME Sec VIII-Div 2.
On the other hand, the (e-N) method of fatigue analysis which is also known as the Crack Initiation method concerns itself only with the initiation of the first crack.
Types of Fatigue
Fatigue can be grouped into two classes;
High cycle fatigue and
Low cycle fatigue.
High Cycle Fatigue:
High-cycle fatigue involves little or no plastic action. Therefore, it is stress-governed. Normally, a fatigue curve (also called the S–N curve) is generated for every material by experimental tests that correlate applied stress with the number of cycles to cause failure. For high-cycle fatigue, the analysis is performed to determine the endurance limit, which is actually a stress level that can be applied an infinite number of times without showing any failure. As a general rule, the number of cycles 105 is considered a demarcation point for high and low cycle fatigue.
Low Cycle Fatigue:
The loading cycles applied in the piping design are normally very few in the order of a few thousand. This type of fatigue is identified as low-cycle fatigue. For low-cycle fatigue, the applied stress normally exceeds the yield strength of the material, which causes plastic instability in the specimen under test. But when strain is used as the controlled variable, the results in the low-cycle region are reliable as well as reproducible.
Reason for Fatigue Analysis of Piping System
A piping system may be subjected to cyclic loading from various sources. Hence, it is always better to perform fatigue analysis during the design stage. For the Piping system, Cyclic loading is primarily due to:
The fatigue process is divided into three stages: crack initiation from the continued cycling of high-stress concentrations, crack propagation to a critical size, and unstable rupture of the section.
Factors Affecting Fatigue Behavior
The factors which affect the fatigue behavior are listed below:
Characterized by high loads and a small number of cycles before failure.
Here failure occurs only with stress levels in the plastic range, i.e. significant plastic strain occurs during each cycle.
The stresses which cause fatigue failure in the piping are the peak stresses.
In piping design, most of the loading cycles encountered would be of the low-cycle type
Characteristics of High Cycle Fatigue
Characterized by a high number of cycles (Preferable N>10^4) with relatively low-stress levels, and the deformation is in the elastic range.
This type of fatigue failure is used in the design of rotating machinery.
This type of fatigue results from strain cycles in the elastic range.
A stress level, endurance limit, may be applied for an infinite time without failure, is calculated.
Fatigue Analysis Theory and Failure Criteria
While preparing fatigue curves, the strains obtained in the tests are multiplied by one-half of the elastic modulus to obtain pseudo-stress amplitude. This pseudo-stress is directly compared with the stresses calculated on the assumption of the elastic behavior of piping. During piping stress analysis, stress called alternating stress (Salt) is used which is defined as one-half of the calculated peak stress. Fatigue failure can be prevented by ensuring that the number of load cycles (N) associated with specific alternating stress is less than the number allowed in the S–N curve or endurance curve. However, in practical service conditions, a piping system is subjected to alternating stresses of different magnitudes. These changes in magnitudes make the direct use of the fatigue curves inapplicable since the curves are based on constant stress amplitude. Fatigue tests of metallic materials and structures have provided the following main clues to the basic nature of fatigue:
Fatigue failure, or cracking under repeated stress much lower than the ultimate tensile strength, is shown in most metals and alloys that exhibit some ductility in static tests. The magnitude of the applied alternating stress range is the controlling fatigue life parameter.
Failure depends upon the number of repetitions of a given range of stress rather than the total time under load. The speed of loading is a factor of secondary importance, except at elevated temperatures.
Some metals, including ferrous alloys, have a safe range of stress. Below this stress, called the “endurance limit or fatigue limit”, failure does not occur irrespective of the number of stress cycles.
Notches, grooves, or other discontinuities of section greatly decrease the stress amplitude that can be sustained for a given number of cycles.
The range of stress necessary to produce failure in a fixed number of cycles usually decreases as the mean tension stress of the loading cycle is increased.
Examination of fatigue fracture shows evidence of microscopic deformation, even in the apparently brittle region of origin and propagates of the crack. The plastic deformation that accompanies a spreading fatigue crack is usually limited in the extent to regions very near the crack.
Therefore, to make fatigue curves applicable for piping, some alternate approach is necessary. One hypothesis asserts that the damage fraction of any stress level S is linearly proportional to the Ratio of the number of cycles of operation at the stress level to the total number of cycles that would produce failure at that stress level. This means that failure is predicted to occur if U≥1.0 where U= Usage factor = ∑(ni/Ni) for all stress levels Where ni= number of cycles operating at stress level i Ni= the number of cycles to failure at stress level i as per material fatigue curve.
Fatigue Analysis Methods
Fatigue Analysis considers the cumulative effect of all individual load cycles that may arise from temperature change, pressure fluctuation, wave motions, etc. If there are two or more types of stress cycles that produce significant stresses, their cumulative effect shall be evaluated as stipulated in Steps 1 through 6 below:
Designate the specified number of times each type of stress cycle of types 1,2,3,…,n, will be repeated during the life of the component as n1, n2, n3,……., nn, respectively. In determining n1, n2, n3,……., nn, consideration shall be given to the superposition of cycles of various origins which produce the greatest total alternating stress range. For example, if one type of stress cycle produces 1000 cycles of a stress variation from zero to +60,000 psi and another type of stress cycle produces 10,000 cycles of a stress variation from zero to -50,000 psi, the two cycles to be considered are shown below:
cycle type 1: n1=1000 and Salt1= (60000+50000)/2
cycle type 2: n2=9000 and Salt2= (0+50000)/2
For each type of stress cycle, determine the alternating stress intensity Salt, which for our application is one-half of the range between the expansion stress cycles (as shown above). These alternating stress intensities are designated as Salt1, Salt2, Saltn.
On the applicable design fatigue curve find the permissible number of cycles for each Salt computed. These are designated as N1, N2, …….Nn.
For each stress cycle calculate the usage factor U1, U2, …….Un where U1= n1/N1, U2= n2/N2,……..Un=nn/Nn.
Calculate the cumulative usage factor U as U=U1+U2+…….+Un.
The cumulative usage factor shall not exceed 1.0
Fatigue Analysis Softwares
Various software is available in the market with the potential for fatigue analysis. The most widely used fatigue analysis software are
The plot of the Cyclic Stress capacity of a material is called the fatigue curve, also known as the S-N curve. ASME Section VIII Div 2 Provides a fatigue curve for various materials.
Fig. 1: Typical S-N Plot
Fatigue design curves are generated from test data by applying large safety margins to the average property curve. While considering material fatigue in design, an additional safety margin is often applied against the cycles-to-failure at a given stress amplitude. As an example, if a component is cycled continuously over the same stress range (Any constant stress range), a design limit on allowable (permitted) cycles may correspond to the cycle life multiplied by a factor (safety margin) such as 0.8. This is the common safety margin employed in a vessel and piping design. For every material, a fatigue curve is normally generated by an experimental analysis that correlates the peak stress range with the number of cycles to failure.
Fig. 2: Design Fatigue Curve for Carbon and Low Alloy Steel
The alternating stress Sa is defined as one-half of the calculated peak stress.
The fatigue failure may be prevented by ensuring that the number of load cycles N that the system experiences is lower than the number permitted for the alternating stress developed. The cumulative effect shall be evaluated in case there are two or more types of stress cycles that produce significant stresses. The material fatigue resistance at a given applied stress or strain range is a function of a number of factors, including material strength and ductility.
When to Perform Fatigue Analysis
Normally the fatigue analysis is performed for existing plants to evaluate the actual cause of any failure. For new plants, the analysis can be performed only if the project specification permits it to do so. Refer to project guidelines on the application requirement for fatigue analysis.
Input for Fatigue Analysis
Before starting the analysis be ready with the following data which will be required during the analysis:
Fatigue Curve of the piping material
Enough process data for finding the total number of cycles throughout the design life of the piping system.
Steps for Fatigue Analysis using Caesar II
Assigning the fatigue curve data to the Piping Material in use:
This is done on the Allowable auxiliary screen. Fatigue data may be entered directly or can be read from a text file by clicking the Fatigue Curves Button. Seven commonly used curves are available in \Caesar\System\*.Fat. (For Caesar versions 2012, 2013 &2014 you may not find it on a few computers, But these are available in earlier versions) Fatigue curves provide a series of S-N data that define the allowable stress with a given anticipated cycle and vice versa.
Defining the fatigue load cases:
For this purpose, a new stress type, FAT, has been already defined in the Caesar II database. For every fatigue case, the number of cycles anticipated must also be entered in the appropriate space.
Calculation of the fatigue stresses:
Caesar II automatically does this calculation for us. The fatigue stresses, unless explicitly defined by the applicable code are the same as Caesar II calculated stress intensity (Max Stress Intensity), in order to conform to the requirement of ASME Section VIII, Division 2 Appendix 5.
Determination of the Fatigue stress allowable:
The allowable stresses for fatigue analysis are required to be interpolated logarithmically from the fatigue curve based on the number of cycles (throughout its life) designated in the fatigue load cases. The calculated stress is assumed to be a peak-to-peak cycle value (i.e., thermal expansion, settlement, pressure, etc.) for static load cases, so the allowable stress can be extracted directly from the fatigue curve. On the other hand for harmonic and dynamic load cases, the calculated stress is assumed to be a zero–to-peak cycle value (i.e., vibration, earthquake, etc.), so the extracted allowable needs to be divided by 2 prior to use in the comparison.
Determination of the allowable number of cycles:
The flip side of calculating the allowable fatigue stress for the designated number of cycles is the calculation of the allowable number of cycles for the calculated stress level. This is done by logarithmically interpolating the “Cycles” axis of the fatigue curve based on the calculated stress value. Since static stresses are assumed to be peak-to-peak cycle values, the allowable number of cycles is interpolated directly from the fatigue curve. Since harmonic and dynamic stresses are assumed to be zero-to-peak cyclic values, the allowable number of cycles is interpolated using twice the calculated stress value.
Reporting the analysis results:
Caesar II provides two reports for viewing the results of load cases of stress type FAT; standard stress report and cumulative usage report. The first of these is the standard stress report for displaying the calculated fatigue stress and the fatigue allowable at each node. Stress reports could be generated individually for each load case and show whether any of the individual load cases in isolation would fail the system or not.
However, in situations where there is more than one cyclic load case potentially contributing to fatigue failure, the cumulative usage report is more appropriate. In order to generate this report, the user should select all of the FAT load cases that contribute to the overall system degradation (possible failure). The cumulative usage report lists for each node point the usage ratio (actual cycles divided by allowable cycles) and then sums (combines) these up for total cumulative Usage. A total value greater than 1.0 indicates a potential fatigue failure.
Fatigue Analysis Case Study
To perform fatigue analysis we need to calculate the thermal and pressure fluctuations the piping system will undergo in its design life. We have to calculate the worst possible cycles from preliminary data provided by the process/operation department. Let’s assume we received the following data from the process for a typical piping system.
Operating cycle from ambient (40°C) to 425°C (400,000 cycles anticipated)
Shutdown external temperature variation from ambient (40°C) to -20°C (300,000 cycles anticipated)
Pressurization to 5.5 Bars (400,000 cycles anticipated)
Pressure fluctuations of plus/minus 1.5 Bars from the 5.5 Bars (1,000,000 cycles anticipated)
Now, in order to do a proper fatigue analysis, these should be grouped in sets of load pairs which represent the worst-case combination of stress ranges between extreme states which we can do in the following way (Refer to the attached Figure, Fig. 3 for proper understanding):
Fig.3: Estimation of Number of Cycles for Fatigue Analysis
The above figure (Fig. 3) explains the calculation of the worst-case cycle combination for fatigue analysis
From -20°C, 0 Bars to 425°C, 7 Bars. 300,000 Cycles
From 40°C, 0 Bars to 425°C, 7 Bars.: 100,000 Cycles
From 425°C, 4 Bars to 425°C, 7 Bars: 600,000 Cycles
From 425°C, 4 Bars to 425°C, 5.5 Bars: 400,000 Cycles
So in Caesar II, we can define the above data as follows (Refer Fig. 4): T1= 425°C; T2= -20°CP1= 5.5 Bar; P2= 4 Bar and P3= 7 Bar
Fig. 4: Fatigue Input in Caesar II for Analysis
Fig. 4 above shows the Caesar II spreadsheet explaining the input requirement Now go to the load case editor and define load cases as shown in Fig. 5 for fatigue analysis. Click on the load cycles button to input the number of cycles calculated above.
Fig. 5: Creating Load Cases for Fatigue Analysis
Fig. 5 above shows the fatigue analysis Load cases that have to be created for Fatigue Analysis Don’t forget that all load cases with stress type FAT (for fatigue) must have their expected number of Load Cycles specified. After the load cases are prepared, run the analysis to find out the results from the output processor. Part of the output results are provided in the attached figures for your reference (Fig. 4 and Fig. 5) The fatigue stress range (Maximum Stress Intensity as calculated in the Expansion stress case) may be checked against the fatigue curve allowable for each fatigue load case as shown in Fig 6.
Fig 6: Output Screen showing stress range
However, this is not a true evaluation of the situation, because it is not a case of “either-or.” The piping system is subjected to all of these load cases throughout its expected design life, not just one of them. Therefore, we must review the Cumulative Usage report, which shows the total effect of all fatigue load cases (or any combination selected by the user) on the design life of the system. Refer to Fig 7 for an example.
This report lists for each load case the expected number of cycles, the allowable number of cycles (based on the calculated stress), and the Usage Ratio (actual cycles divided by allowable cycles). The Usage Ratios are then summed for all selected load cases; if this sum exceeds 1.0, the system has exceeded its fatigue capabilities.
Glass Reinforced Epoxy Piping or GRE pipes are becoming a popular choice in the piping and pipeline industry due to their many advantages. The present article aims to give some basic principles and cares to be considered at the moment of the draft design of an aboveground GRE pipeline.
GRE pipe and GRP pipe differ in the used resin during bonding the glass fiber. GRE pipe used Epoxy Resin while GRP pipe used Isophthalic Resin. The designer should evaluate if a deeper stress and strain analysis is required for the pipeline, for the supports, and for other bearing structures connected to the pipeline.
Apart from special cases, GRE pipes should be always connected to the bearing structures by means of saddles, made of steel or concrete or of other materials (GRE itself for instance), in order to distribute the loads on a length and on an angle that is able to minimize the stress concentration on the pipe/support contact points.
In nearly all aboveground applications tensile resistant couplings should be used.
Only in the case of well-supported pipelines for non-pressure applications, a non-tensile-resistant system can be used. The forces close to elbows or other singular points such as valves, reducers, or tees, can become relevant.
GRE/GRP Pressure Class Selection
The selection of the GRE pressure class has to be made according to the following loads:
The stress in the hoop direction due to the internal pressure is calculated as shown in Fig. 1:
Fig. 1: Calculation of Hoop Stress and Axial Stress for a GRP Piping System
In GRE pipes it is important to always check the axial stress due to internal pressure since the material is anisotropic and the difference of strength in the hoop and axial direction is relevant.
The sum of stresses due to the above loads, calculated in the hoop and axial direction, has to be lower than the allowable stresses, defined for each pipe class or by a specific job.
Approximate values for allowable stresses for a common filament wound pipe for above-ground use are 50 Mpa in the hoop direction and 30 MPa in the axial direction.
The high working temperature could reduce the allowable stress in the GRP pipe and consequently reduce the pressure class.
The Code (AWWA M45) generally considers a 40% tolerance in the allowable stresses in case of transient surge pressure based on the increased strength of fiberglass pipes for rapid strain rates.
Both the following equations (Fig. 2) have to be calculated:
Fig. 2: Equations to calculate stresses
Vacuum Design for GRE pipes
The AWWA M45 standards admit a safety factor for vacuum conditions between 1.3 and 3.
For different pressure classes and the same standard pipe (55° filament winding), the approximate relation between pressure class, stiffness, and vacuum resistance is resumed in the following table (Fig. 3).
Fig. 3: Table showing Vacuum resistance with respect to pressure class and pipe stiffness
For low-pressure pipes with a vacuum, a convenient solution can be either to provide stiffening ribs or a sandwich pipe wall structure with a mortared core.
Thermal Expansion Coefficient of GRE Pipes
The approximate axial coefficient of thermal expansion (α) for a GRP pipe made by filament winding with a winding angle of 55°is:
α = 1.8×10−5 m/m °C
For different GRP pipe classes (with mortar core) or for different winding angles, please consult the GRP Vendor.
The total expansion (or contraction) of a pipe length ( L ) is calculated as:
ΔL =α ⋅ L ⋅ ΔT
ΔT is the temperature gradient (positive or negative) with reference to the installation temperature T0.
The thermal expansion coefficient of GRP has the same magnitude as the steel coefficient (α=1.2× 10-5 °C-1), whilst thermal end loads for restrained expansion are significantly lower since the axial E-modulus of GRP (Ea) is around 1/20th of steels.
The loads applied to expansion joints and to bearing structures are hence considerably lower in GRP pipelines.
Thermal End Loads for GRE pipes
The thermal end load (F) due to constrained expansion is calculated as shown in Fig. 4:
Fig. 4: Calculation of end loads for GRP piping for constrained expansion
and ID is the internal (nominal) diameter.
The thermal end load due to constrained expansion could be too big for both the stress arising in the pipe and for the load that the bearing structures have to support.
Considering the pipe itself, its elastic stability has to be checked. The pipe’s elastic stability depends on the pipe section, on the E-modulus, and on the span between axial guide supports which is the length of free deflection.
The allowable compressive end load due to instability (Pcr) is calculated as shown in Fig. 5:
Fig. 5: Calculation of End load due to Instability
When the end loads are too big, they should be reduced by providing the system with anchor points and expansion joints, or better, by operating on the pipeline’s geometry and on the support placement in order to let the line expand where it is not dangerous. Expansion loops can be added to the system where it is possible.
The second solution is preferable since the involved loads and thrusts are much lower than in a similar steel pipeline.
Selection of Anchor Points in GRE Pipeline
Pipe Anchors have to be placed in such a way that pipeline expansions are forced in predetermined directions, in order to balance loads and displacements on the different expansion devices, and to minimize displacements close to dangerous locations, for example in weak branch connections or in connections that are not allowed to move.
Use of Directional Changes or Offsets in GRE Piping
Changes of direction in a pipeline can be used to partially absorb the line’s elongation, when close to an elbow; a branch that is free to expand is available, as shown in the following figure (Fig. 6):
Fig. 6: Effect of Direction Changes
The “available bending strength” is considered the remaining strength, after that, all of the other stresses on the pipe have been removed, such as the stresses due to internal pressure.
Clearly, any term of the equation can be obtained once all of the other terms are known, for instance, the length ΔL that can be absorbed can be found when the length of the leg that is available is H.
Expansion Loops for Long GRE Pipelines
“U” expansion loops are provided for long straight pipeline runs, as shown in the figure (Fig. 7) below:
Fig. 7: Expansion loop in GRP piping system
The recommended spacing between axial guide supports close to the expansion loop is also shown in the drawing. Other supports shall be spaced following other calculations (beam load).
Use of Expansion Joints in GRE Piping Systems
Various kinds of standard expansion joints can be used. Low-stiffness expansion joints are preferable since they develop a low reaction in correspondence with relatively big displacements. GRE pipes expand more than steel pipes but have much lower thrusts.
Using stiff expansion joints would reduce the stresses in the pipe only by a little
We suggest rubber joints with one or more waves, possibly with limiting travel devices, with an activation load lower than the Pcr load, and with a working travel equal to the total expansion.
Support Span for GRE Pipes
Horizontal pipes should be supported according to the spacing suggested by the support spacing data or according to a specific project.
A pipe support span is defined as the distance between two consecutive pipe supports or anchoring devices.
The maximum support span/spacing length for every pipe size and class is suggested by the Technical Department of GRP Vendor for standard pipes or according to a specific project.
The span length is limited by the following considerations:
the maximum axial strain must not exceed the allowable value;
the mid-span deflection has to be smaller than 1/300th of the span length and anyway not exceed 15 mm which is the minimum value.
If factor (b) is the determinant factor, then the distance between supports must not be changed by reducing the working pressure.
Often the spacing between the supports is set by other reasons, for instance, joint spacing or existing bearing structures. Normally the 6-meter half-length span is the maximum that is used, even for large-diameter pipe, for which a theoretical longer span could be used. The maximum support span in meters is shown in the following table (Fig. 8), for different pipe sizes and pressure classes:
Fig. 8: Table showing the typical support span for a specific project
The maximum span has to be evaluated for a continuous span length when the joint can transmit axial loads.
GRE Piping Support Design Rules
The following are suggested basic rules for design and for the positioning of supports, anchors, and guides.
Loads with linear and punctiform contacts have to be avoided, therefore curved supports that bear at least 120 degrees of the bottom part of the pipe and that have maximum bearing stress of 600 kPa have to be used. Unprotected pipes are not allowed to press against roller supports or flat supports. Do not bear any pipe directly against ridges or other points of the support’s surface. Protective sleeves have to be used in these cases.
To protect pipes against external abrasion between the pipe and the steel collar, a PVC saddle (Fig. 9) or a protective rubber layer has to be positioned in between. The PVC saddle is necessary when free axial sliding of the pipe must be permitted (axial guides).
Valves and other heavy equipment must be supported independently in both horizontal and vertical directions.
The pipe clamps must fit firmly but must not transfer excessive force to the pipe wall. This could result in deformations and excessive wall stresses
Vertical runs have to be supported as shown in Fig. 9. Excessive loading in vertical runs has to be avoided. It is preferable to design a “pipe in compression” than a“ pipe in tension”. If the “pipe in tension” method cannot be avoided, take care to limit the tensile loading below the maximum tensile rate recommended for the pipe. The guiding collars will have to be installed by using the same space intervals used for horizontal supports.
Fig. 9: Figure showing a typical arrangement of PVC saddle and Vertical Supports
Anchoring Points in GRE Piping Installations
An anchoring point must efficiently restrain the movement of the pipe against all of the applied forces. Anchors can be installed in both horizontal and vertical directions. Pipe anchors divide a pipe system into two sections and must be attached to some structure that is capable of withstanding the applied forces. In some cases pumps, tanks, and other similar equipment function as anchors.
However, most installations require additional anchors where pipe sizes change or where fiberglass pipes join another material or a product from another manufacturer. Additional anchors are usually located on valves, pipeline changes of direction, and major branch connections.
It is a good practice to anchor long, straight runs of aboveground piping at intervals of approximately 90 m.
In any case, the correct positioning of anchor points has to be decided only after a detailed stress analysis.
The pipe must be able to expand radially within the pipe clamps.
To secure the pipe to the clamp it is suggested to apply a GRP lamination (as shown in Fig. 10 below) on each side of the clamp. If the movement of the pipe has to be restrained only in one direction, it is sufficient to apply only one overlay ring of GRP in the opposite position.
Fig. 10: Figure showing GRP lamination in pipe anchors
FAQs for GRE Piping Systems
What is GRE piping?
GRE stands for Glass Reinforced Epoxy. It is a composite material used for manufacturing pipes and fittings. GRE piping systems are known for their corrosion resistance and durability.
What are the advantages of using GRE piping systems?
GRE piping systems offer several advantages, including excellent corrosion resistance, high strength-to-weight ratio, low maintenance requirements, high hydraulic efficiency, and a long service life. They are also lightweight and easy to install.
Where are GRE piping systems commonly used?
GRE piping systems are used in a wide range of industries, including chemical processing, offshore oil and gas, plant piping, oil and gas flowlines, water treatment, power generation, downhole tubing and casing, irrigation, and desalination plants.
How does GRE piping compare to other materials like steel or PVC?
GRE piping is corrosion-resistant, making it an excellent choice for environments with corrosive substances. It is lighter than steel, making installation easier, and it doesn’t require painting or coating. PVC is also corrosion-resistant but may not be suitable for high-temperature applications or certain chemical environments.
What is the temperature and pressure rating of GRE piping systems?
The temperature and pressure ratings of GRE piping systems can vary depending on the specific material and design. Generally, they can handle temperatures up to 250°F (121°C) and pressures up to 1500 psi (10,342 kPa).
Can GRE piping systems be used for underground applications?
Yes, GRE piping systems can be used for underground applications. They are resistant to soil corrosion and can be designed to meet the specific requirements of buried installations.
Are GRE piping systems environmentally friendly?
GRE piping systems are considered environmentally friendly because they are corrosion-resistant, reducing the risk of leaks and spills that can harm the environment. Additionally, they have a long service life, reducing the need for frequent replacements.
How are GRE pipes joined together?
GRE pipes are typically joined using adhesive bonding or flange connections. Adhesive bonding involves using epoxy resin to bond pipe sections together, creating a strong and leak-proof joint. Flange connections are used for larger pipe sizes and provide a more mechanical connection.
What maintenance is required for GRE piping systems?
GRE piping systems require minimal maintenance. Regular inspections for signs of damage or wear are recommended. In most cases, maintenance involves cleaning and visual inspections.
Can GRE piping systems be customized for specific applications?
Yes, GRE piping systems can be customized to meet the specific requirements of different applications. They can be designed to handle various chemical fluids, temperatures, pressures, and sizes.
Are GRE piping systems cost-effective?
While GRE piping systems have a higher initial cost compared to some materials, their long service life, low maintenance requirements, and corrosion resistance can make them cost-effective over the long term.
Are there any limitations to using GRE piping systems?
GRE piping systems are not suitable for extremely high-temperature applications or applications where fire resistance is critical. It’s important to consult the manufacturer to ensure the system meets the specific needs of the project.
What are the Design Codes for GRE Piping Systems?
Design codes and standards for GRE (Glass Reinforced Epoxy) piping systems may vary depending on the specific application and location of the project. The most widely used GRE piping codes are:
Vertical Columns or Fractionating Towers are frequently used in the process units for fractionation and stripping. They are cylindrical in shape and their axis is vertical to the grade. This article will provide guidelines for piping design considerations from such columns or towers.
What is Fractionation?
Fractionation is the process of separating a mixture of different miscible liquids by vaporizing the mix and condensing the constituents at their individual boiling points. The process of distillation has evolved during the century from the Batch shell still process to the Continuous shell still process to the present Fractional distillation process.
Principle of operation of Fractionating tower
Fractionation is the process of separating a mixture by vaporizing the mix and condensing the constituents at their individual boiling points. Higher boiling point liquids will condense first, followed by lower boiling point products. This is achieved in the fractionating tower by creating zones of different temperatures along the length of the tower, the lowest at the top and the highest at the bottom. As the vapors rise along the column, they lose heat and condense at their respective boiling points. Column internal trays / packed beds, accumulators, and draw-offs help in this function.
What are Trays in a Vertical Column?
Trays are stamped plates of steel with unidirectional valves attached to them. They allow the passage of vapor in the upward direction only. They are placed all along the length of the tower. The valve lifts when the vapor force on the bottom of the valve exceeds the liquid force on top of it. As the vapors push the valves and pass through the liquid, vapors with higher condensation points lose heat and condense. The excess liquid on the tray flows down to the lower tray via a downcomer. Lighter boiling fractions in this liquid are vaporized on the lower tray by the heat of the upward-traveling vapors. Vaporization and condensation take place all along the length of the tower. Draw-offs at appropriate locations allow the removal of desired products from the column.
What are Packed Beds in a Vertical Column
These are beds of metal rings, packed along the length of the column. They function similarly to trays. Rising vapor passing through the metal rings comes in contact with liquid flowing down the column. The down-flowing liquid is heated by the upward-flowing vapor similar to trayed columns.
Design Considerations for Vertical Columns Piping Layout
Column Piping Layout: Locating the column
The piping designer should economize piping interconnections between the column and its adjacent pieces of equipment (pumps, condensers, heaters, reboilers, etc.) when locating the column. The following documents are needed to locate the column on the plot plan.
The column is located on the plot plan as per the process sequence dictated by the P&ID. Small columns can be placed on stand-alone structures. Large columns need a civil foundation of their own. In plants where the related equipment is housed, they are placed adjacent to the building or structure. Columns are best located on either side of the pipe rack, serviced by auxiliary roads for maintenance access. Vessel transportation, erection, and other constructibility issues should also be looked into while finalizing the location of the vessel. Adequate space must be provided around the column for operator movement and maintenance access. Locating close to an access road to reduce maintenance efforts. Interdistances between adjacent pieces of equipment are fixed as per Table 5 of Piping & Plant Layout Specification. The Bottom Tan Line elevation is fixed by the P&ID. The same may be increased to facilitate piping and equipment layout in consultation with the Process group.
After the column has been located on the plot plan, the following jobs are carried out.
Column Piping: Column elevation review and support selection
The Bottom Tan Line elevation fixed by the P&ID is the minimum elevation required for NPSH of the bottom pumps. This may be increased in consultation with Process Group for the following.
Operator Access – Proper headroom clearance should be available for safe operator access to the column.
Maintenance Access– Proper maintenance access clearance should be available for the safe movement of maintenance equipment around the column.
Minimum clearance as per piping layout
Bottom nozzle size – The bottom nozzles are connected to the bottom head with a straight pipe piece and a 90(elbow. This lowers the clearance available below the bottom of the elbow
Bottom head details (elliptical, hemispherical, etc.) The hemispherical head has a depth twice as compared to the elliptical (2:1) This will change the centerline elevation of the bottom nozzle and consequently the clearance under the elbow.
Vertical thermosyphon reboiler connections -The Reboiler bonnet removal area dictates the minimum tan line elevation of the column when the reboiler is attached to the column.
Column Piping: Supporting Arrangement of Vertical Column
Columns are generally supported by the following methods
Skirt Supported with a foundation on grade – most preferred. Skirts are straight for short columns and flared for tall ones.
Ring girder supported – On tabletop (when the bottom nozzle needs to be accessed)
Skirt supported – On the tabletop
The choice of support may fix the column elevation for some layouts.
Fig. 1: Image of a Typical Vertical Column
Tray orientation on Column Piping
The following documents are required for orienting the trays.
Vessel Process sketch & Tray data (No. Of pass, downcomer area, tray spacing, etc)
P&ID
Plot plan
Plant Layout Specification
Vertical Column Piping: Tray nomenclature
Odd and Even trays – Trays are numbered from the top of the column to the bottom. Trays with odd numbers 1,3,5 are the odd trays and those with even numbers 2,4,6, are the even trays.
Number of Passes – Trays can be One-pass, Two-pass, Three-pass, or Four-pass depending on column diameter.
Active Area (Bubbling area) – Area of the tray, which allows vapor to pass thru it
Downcomer area – The area allows excess liquid on one tray to flow down to the tray below it.
Tray spacing – Interdistance between adjacent trays.
Chimney tray – It is a solid plate with a central chimney section and is provided at the draw-off sections of the column.
Feed nozzles are large in diameter and their orientation is fixed by the piping layout. The feed nozzle may have one or multiple external connections with different internal configurations for the following:
One nozzle with two orientations
Two nozzles with two orientations
One nozzle with multiple orientations
It is of utmost importance that the feed nozzle is parallel to the tray downcomer. The reboiler location is fixed on the plot plan. Now, as the reboiler draw-off nozzle is mostly located on the same side as the reboiler to minimize piping run, the draw-off orientation is established. The reboiler returns the nozzle to be parallel to the tray downcomer. For the bottom draw-off nozzle arrangement, tray orientation remains unaffected. Access Manholes on the cylindrical section are best located towards areas of direct maintenance access and opposite pipe racks. Thus their location may dictate the orientation of the trays.
Vertical Column Nozzle orientation
The following documents are required for orienting the nozzles.
General considerations for locating nozzles in Column Piping
Generally, the following nozzles are present on all columns.
Feed Inlet
Bottoms Outlet
Drain
Vapor Outlet
Vent
Reboiler Draw off
Reboiler Return
Product Draw off
Reflux
Instrument Nozzles
Steams Out Nozzle
Access Manholes
Orienting the nozzles
While orienting these nozzles the following points are to be considered.
The feed inlet is to be placed parallel to the downcomer tray as discussed in tray orientation. The orientation of the feed inlet is in the sector towards the pipe rack from which the feed piping is coming. Proper support and flexibility should be available to route the piping.
Bottoms Outlet will be on the bottom head, best located on the center of the head. This is of gooseneck type for vessels with skirt-type support and the nozzle flange has to be brought outside the skirt. A separate drain nozzle at the bottom head but a tapped nozzle on the bottom outlet is most preferred. Orientation is generally chosen to minimize piping to the bottom pump keeping the line flexible enough from a stress point of view.
The vapor outlet, PSV connections, and Vent will be on the top head of the column. The vapor outlet is best located in the center of the head, though it may have to be shifted based on some layout considerations as explained. A large diameter makes the location of the vapor nozzle critical. The nozzle may have to be offset from the center of the column so that, after two elbows, the piping travels down the column at a practically supportable distance from the column.
The reboiler draw-off nozzle is mostly located on the same side as the reboiler to minimize piping run, thus the draw-off orientation is established. For the bottom draw-off nozzle arrangement, the best-suited orientation as per the piping layout may be chosen.
The re-boiler return nozzle is to be parallel to the tray downcomer as discussed in tray orientation.
Reflux nozzles are to be oriented for proper and even flow of refluxed liquid on the bubbling area. This can be achieved by internal distributor piping.
Level Instrument nozzles should be oriented as close to any inlet nozzle as possible to avoid the effects of turbulence. When baffles are provided this consideration is relaxed.
Pressure tapping for vapor pressure should be oriented in the bubbling area of the tray above it.
Temperature tapping for liquid temperature measurement should be oriented in the downcomer area. They are best oriented perpendicular to the tray downcomer. When multiple temperature elements are required, they are best placed at the same orientation but at different elevations. Care must be taken to ensure that the internal projection of the temperature element does not hit the downcomer. The nozzle should be made hillside if the probe length cannot be accommodated in the radial direction.
Inaccessible Instrument nozzles to be oriented near ladders (location of ladder and Instrument nozzles to be decided concurrently)
Steam-out connection should preferably be hillside type on the cylindrical shell so that swirling action is generated inside the vessel. This will ensure faster steam out of the column. These should be placed as close to the bottom tangent line as possible.
Access manholes can be located at the following places, depending on the type of access required in the column.
On the top of the column. (In this case, the vent can be located on the blind flange of the access manhole.)
On the cylindrical portion of the column (radially or hillside), this is the most preferred location. The orientation of the manhole should be such that the manhole faces the maintenance access area. This is to be in conjunction with tray orientation. Manhole entry should be directly in a bubbling area and never in the downcomer area. Internal piping should not block the access area of a manhole.
It should be verified that the davit swing area of the manhole cover does not obstruct the movement of maintenance personnel and does not hit any instruments or instrument nozzle connections. The centerline of the manhole should be between 600mm to 1000mm (ideally 760mm) from the top of the service elevation of the vessel.
A Gooseneck nozzle for a Vapor outlet should be considered when the piping layout is fixed and requires an elbow immediately at the nozzle. This can be a flanged type, thus acting as a manhole also for big nozzle diameters. Flange-type nozzles have the added advantage that their orientation can be changed even after the delivery of the vessel at the site.
Skirt access manholes are to be oriented for easy access.
Skirt vents are to be oriented in such a manner so that they do not come at the same location as the access ladder.
Nozzle standouts
Nozzles on the top of the column should have their flange a minimum of 180mm and a maximum of 1000mm from the TOG of the access platform. Nozzle standouts on the shell are calculated on the clearance requirement for maintenance access to nuts on the back of the flange. Due consideration is to be given to vessel insulation when calculating the standout. This standout will be confirmed by mechanical so that the nozzle passes the mechanical requirements.
Preparing the Nozzle Orientation Document
This document should show the plan, and if required, the elevation of the vessel with the location of nozzles on the same. Nozzle orientation is to be from plant north and taken clockwise. Dimensioning should show the radial distance of the vessel flange from the vessel center. A nozzle summary table indicating the Nozzle number, service, size, rating, flange face, elevation from the bottom tan line, and stand out from the vessel center is to be included in the drawing. For nozzles on the vessel heads, the F/F stand out from the bottom or top tan line should be given. In lieu of elevation from the bottom tan line.
Miscellaneous Data to be included in Nozzle Orientation Document
Lifting Lugs
Generally, columns can be lifted with two lugs welded below the top tan line. A tailing lug is to be provided near the bottom of the skirt for tailing operation. The preferred locations should be marked on the nozzle orientation drawing.
Earthing Lugs
Two earthing lugs, ideally 180° apart should be provided on the lower portion of the skirt. The same should be marked on the nozzle orientation drawing.
Name Plate
The nameplate should be located at a prominent location and marked on the nozzle orientation drawing. Care should be taken that the nameplate projects outside the vessel insulation.
Vessel Insulation Clips
Indicate that insulation clips/rods are required for holding the vessel insulating bands.
Platforms and Access Ladders
Platforms are required for the following purposes
Operational access to valves and instruments etc.
Maintenance access to manholes.
Mid landings (when the elevation difference between two platforms exceeds 9m)
Calculating the TOG elevation
The platform on the top head of the column
TOG elevation from the top of column head = Insulation thickness + 50mm clearance + Platform member depth (assume 200mm minimum) + 30mm grating. Round off to the next higher multiple of 10.
Platforms on the cylindrical portion of the column
Nozzles – Platform to be 500mm (minimum) below the bottom of the flange of the nozzle.
Instruments (LT/LG) and their standpipes – Platform to be 200mm below the lowest process drain on any of these items.
Access manholes – The platform is to be ideally 750 mm below the centerline of the manhole. The acceptable range is 600mm to 1500mm below the centerline of the manhole.
Mid-landing platforms are to be provided when the elevation difference between two platform levels exceeds 9m. The mid-landing is to be ideally evenly placed between the two platforms.
Two platforms being serviced by a single ladder should ideally have an elevation difference of 600mm between them.
The platform elevations (TOG) should be rounded off to the nearest multiple of 10.
Platform sizing
The platform on the top head of the column
This platform should be rectangular. It should cover all the nozzles, instruments davits, etc. that need access for operations and maintenance. Ideally, a space of 750mm should be provided around 3 sides of a nozzle. This may be lowered at the discretion of the piping lead. Side entry access to the platform should be the first preference when deciding the exact shape of the platform. Orienting the platform axis along the ladder orientation and providing an extended landing point may achieve this.
Platforms on the cylindrical portion of the column
Determining the Orientation angles
This platform should be circular. Its orientation extent should cover all the nozzles, instruments davits, etc. that need access for operations and maintenance. The platform should extend beyond the centerline of the manhole by a minimum of 1 manhole diameter.
A free landing space of 750mm is to be provided for access ladders.
Ideally, a space of 750mm should be provided around the sides of a nozzle. This may, however, be lowered to 600mm at the discretion of the piping lead.
Determining the width
The inner radius of the platform should clear the column insulation by 50mm.
Platform width is dictated by operator access requirements. The following considerations are to be taken care of when deciding the width.
The minimum platform width is to be 750mm(free of all obstructions).
The width of the manhole platform is to be a minimum of 900mm.
Platforms may be locally extended width-wise at regions where vertical pipes pierce the platform, maintaining 750mm clear space from the insulation of piping to the handrail of the platform.
When controls are located on the platform, the width of the platform is to be 900mm plus the width of the controls.
Platform bracket orientation
Platform support brackets are to be oriented so that they clear the vertical piping traveling down the column, through the platform. Support bracings for platforms at all elevations should be maintained the same as far as possible.
Fig. 2: Sample Column Piping Example
Access ladder
Access ladders are to be vertical. They should have a clear climbing space of 680mm. Toe clearance from the centerline of the ladder rung to any obstruction to be 230mm. Special care is to be taken for vessel stiffeners.
A cage is to be provided for all ladders at an elevation of 2300mm and above. Side entry ladders are the first preference.
The ladder is to be oriented so that it can also be utilized for access to instrument connections that are inaccessible from the working level.
Inclined ladders are permissible on inclined portions of the skirt and column. The angle is limited to 150 from vertical.
Preparing the Platform Input Document
Platform and Access ladder input is transmitted to Civil via a platform input drawing.
Platforms on the top head of the column
This should clearly indicate the TOG elevation from bottom T/L, dimensions of the platform, and its location w.r.t. The vessel centerlines. Grating cutout requirements (indicating size, shape, and location), required swing direction of the self-closing gate, and davit location need to be marked on the same drawing. Any pipe supports intended to be taken from the platform should be marked.
Platforms on the cylindrical portion of the column
This should clearly indicate the TOG elevation from bottom T/L; the dimensions of the platform (orientation angles and width), and its outer radius from the vessel axis. Grating cutout requirements (indicating size, shape, and orientation), required the swing direction of the self-closing gate. Any pipe supports intended to be taken from the platform should be marked. Orientations of access ladders should be marked on the respective platform elevation plans.
Orienting piping on the face of the column
It is imperative that the orientations, arrangement, and standouts of various piping traveling down the face of the column are calculated keeping in mind the following points.
Large diameter columns
Piping has to be arranged in the order of the elevation and orientation of the nozzles.
The piping of these columns can travel down the column radially, with independent supports.
The clear minimum space between the pipe and shell is to be 300 mm excluding any insulation.
The pipe with insulation should clear the stiffening ring and its insulation.
The minimum orientation angle between two adjacent pipes should be calculated to clear the support bracket of one pipe hitting the insulation cladding of the adjacent pipe.
Support points of adjacent piping should be offset to save space between them. as the support brackets will have to be oriented so that there is no clash between the cleats of the supports or between the support members and bracings.
Small diameter columns
Piping has to be arranged in the order of the elevation and orientation of the nozzles.
Small-diameter columns have an inherent problem of supporting and guiding each line independently due to the small circumference available for the piping. After the first rest support near the nozzle, the pipes should be oriented as though they are traveling down a vertical pipe rack.
The clear minimum space between the back of the pipe or shoe and shell is to be 600mm. On the vertical run, minimum spacing requirements have to be followed.
Supporting Piping from Vertical Columns
Piping should be supported from the vessel or its platform when it is difficult to construct civil support from grade or adjacent structures at the required location. Vessel support may also be taken to take advantage of lower differential thermal growth between vessel and piping, as compared to piping and civil support. A judicious selection of support locations can eliminate the requirement for springs.
Thumb rules for supporting piping from columns
Small loads can be transferred directly to the platform members. These include rest, one-way stop, two-way stop, or hold-down supports and the piping layout should be done accordingly.
Large loads should be transferred to the vessel shell and the piping layout should be done such that the platform members do not interfere with these independent supports.
The first piping support is Rest support and it should be as close to the equipment nozzle as possible. The second and subsequent supports are guides and they are to be located as per the allowable piping spans available in the tables. For tall columns, another rest support may be needed. This is done by providing spring support which will take care of the differential expansion of the vessel and piping.
Piping support should not cause any hindrance to the movement of personnel.
Vessel growth should be considered to check the clash of piping support with any adjacent piping or structure.
Types of supports for Column Piping
Supports welded to piping
Horizontal trunnions welded to the pipe take the vertical load of the pipe. They are generally used in pairs, set apart at 180°. Their axis is perpendicular to a line drawn from the center of the column to the center of the pipe at the location of support. Trunnion lengths should be adequate enough so that their ends project 50 mm from the outer edge of the support bracket member Shoes are provided for guidance purposes and to prevent insulation cladding from hitting the support bracket member. Adequate shoe length is to be taken for differential movement of pipe and vessel.
Supports welded to the vessel
Support brackets( non-braced and braced ) and Guide brackets( non-braced and braced ) are the most common support arrangements for vertical piping.
Calculating the minimum dimensions of support members
Load bearing supports
Trunnions or springs transfer load to these supports. Minimum clear inside dimensions are calculated so that the insulation cladding is 50 mm away from the inside of the structural member or support plate of the spring.
Guide supports
The bare pipe is guided directly by the guide bracket. Shoes are provided in pairs,180° apart, for lines with insulation. These can be single pairs or double pairs depending upon the type of guiding required at that particular location. The guide gap required by stress is to be added to the end-to-end-to-end dimensions of bare pipe or pipe with shoes.
Preparing the Civil Pipe Support (CPS) Input Document
CPS input is transmitted to Civil and Mechanical via a CPS input drawing. A sketch clearly indicating the TOS, dimensions, and CPS location with respect to the vessel centerline needs to be drawn. Any requirement for additional support plates for springs or trunnions is to be indicated. A summary table indicating the CPS number, TOS, stress file number, and corresponding node number from the Nozzle cleat load information chart needs to be created. The Nozzle cleat load information chart indicates the various loads acting at the support location under various conditions. It is to be attached along with the CPS input document.
Pipe support spans play a crucial role in maintaining the longevity, efficiency, and safety of aboveground piping and pipeline systems. Pipe support span is also known as pipe support spacing. A proper pipe support span not only reduces the pipe supporting problems but also adequately supports pipes at regular intervals to reduce failures associated with improper supporting. In this comprehensive guide, we will discuss the intricacies of pipe support spans, covering design considerations, factors on which it depends, best practices, and pipe support spacing charts based on different codes and standards.
A. What is a Pipe Support Span?
Pipe Support Span is defined as the optimum distance between two consecutive pipe supports to avoid excessive stress, sagging, bending, vibration, or failure of the piping or pipeline system in extreme cases. It ensures that the piping system remains securely in place throughout operation. Adequate pipe support spacing is synonymous with
Structural Integrity
Reduced Maintenance
Safety
Operational Efficiency
We all know that while routing aboveground piping or pipeline from one part or equipment to another we have to support the pipe at some definite spans. A properly designed pipe support span helps the piping design personnel to support pipes at regular spacings, thus reducing his work for unnecessary calculations. Pipe Support Span is also known as Pipe Support Spacing. Refer to Fig. 1 which defines the pipe support span for a pipeline system.
B. Factors on Which Pipe Support Span Depends
Various factors influence the pipe support span. In the following section, we will discuss 11 such important criteria that dictate the Pipe support spacing.
1. Pipe Material:
Pipe Support spacing varies with pipe material, For non-metallic pipes, the support span is lower than metallic pipes of the same size. Even Stainless Steel pipes have lower pipe support spacing as compared to Carbon steel pipes.
2. Nominal Diameter of Pipe & Schedule:
With the increase in pipe diameter and schedule, the pipe support span increases. That is the reason you will find that a 10-inch pipe has more support span as compared to a 4-inch pipe support spacing.
3. Type of Fluid Service:
Piping support span varies with fluid service; Pipes carrying liquid service have less support span as compared to pipes carrying gaseous fluids. This means with an increase in the density of the flow medium pipe support spacing decreases.
4. Type and Thickness of Insulation Material:
With an increase in thickness and density of the pipe insulation material, pipe support spacing reduces. An increase in insulation density and thickness imposes more load on the parent pipe which needs to be supported by increasing the number of supports which means the pipe support span reduces.
5. Piping Configuration (Straight pipe and Pipe with elbows):
Pipe support spacing is dependent on the piping routing or geometry. A straight pipe has more support span as compared to pipes with directional changes. Because of this reason, to find out the span for piping including elbows, the straight pipe span is multiplied by a factor as shown in Fig. 2.
6. Locations of Valves and Rigid Bodies:
The presence of rigid bodies in a piping or pipeline system reduces the pipe support span. It is a general engineering practice to provide at least one support near rigid bodies like valves (Preferably to provide support on both sides of the valve).
7. Structural Availability for Supporting:
Available structures are normally used for supporting the pipe. So, the pipe span chart may be reduced in those places. Also, an increase in the number of supports distributes the piping loads on supports and increases the piping stiffness. So, if a structure is available, pipe supports are usually taken from those structures.
8. Vibrating or Pulsating lines:
For vibrating or pulsating lines pipe support span is reduced to avoid vibration tendency and to increase the natural frequency of the piping system. A reduction in pipe support spacing increases the system rigidity which reduces the tendency of pipe vibration.
9. Fluid Temperature:
With an increase in fluid temperature as the pipe material’s allowable stress value reduces, the pipe is supported in a nearby position, thus reducing the pipe support spacing.
10. Equipment Connection
Sometimes, the Pipe support span is determined considering various equipment connections that have the potential for vibration transfer from the equipment like reciprocating compressors and reciprocating pumps. For these pipes, the supporting span is reduced from the standard pipe support spacing.
11. Flow Induced Vibration Criteria
For lines with the flow-induced vibration susceptibility as high, the pipe support span is reduced to increase the natural frequency of the piping system so that the tendency of FIV failure is reduced.
Fig. 1: Figure showing pipe support span
C. Deciding Pipe Support Span
Pipe Support Span Length Depends On-
Bending Stress
Deflection
Indentation
Allowable Loads
Vibration Possibility and Natural Frequency of the piping system
Deflection (Δ) is defined as a relative displacement of the point from its original position.
The basic piping practice is to limit pipe deflection between supports to 1” or 1/2 the nominal pipe diameter, whichever is smaller.
The most important reason for limiting deflection is to make the pipe stiff enough, that is, of high enough natural frequency, to avoid a large amplitude response under any slight perturbing force. As a rough rule, for average piping, a natural frequency of 4 cycles per second will be found satisfactory. The natural frequency can be calculated by
3. Indentation
Where,
t=corroded Thickness of pipe Wall(mm)
S=0.67Sh(N/mm^2)
R=Radius of pipe (mm)
d=Bearing Length(mm)
b=Bearing width(mm)
4. Allowable Load at Support
Where,
Pa=Allowable Load at the Support point
t=effective local thickness (pipe wall +Reinforced Pad If Any)
R=outer radius of Pipe
b=Bearing length of pipe (along the axis) on the support structure
IF THE ACTUAL LOAD AT SUPPORT IS GREATER THAN THE ALLOWABLE LOAD GIVEN BY THE ABOVE FORMULA, A REINFORCEMENT PAD WILL BE REQUIRED.
5. Vibration Possibility
The support span for vibration-prone lines is reduced to make the system stiffer such that the pipe does not easily vibrate. The natural frequency of the system is usually maintained above 4 Hz as mentioned in clause C.2 above.
D. Pipe Support Span Chart
A pipe support span chart is a table or diagram that provides information on the maximum allowable span for different types of piping and support configurations. The span is the distance between two points where a pipe is supported, such as at two adjacent pipe hangers.
The purpose of a pipe support span chart is to help engineers and designers ensure that piping systems are properly supported to prevent sagging, bending, or other types of stress that could cause damage or failure. By referring to the span chart, designers can select the appropriate type and spacing of supports for a given piping configuration, based on the materials used, the size and weight of the pipes, the fluid being transported, and other factors.
Pipe support span charts may also include information on the recommended type of support for different piping materials, such as steel, copper, or plastic, as well as information on recommended hanger spacing, temperature limits, and other design considerations. Proper use of a pipe support span chart can help ensure that piping systems are safe, reliable, and long-lasting.
Normally project-specific Support Span is provided in tabular format for straight pipes that are known as a “Pipe Support Span Chart”. But for elbows or turns, the span is to be reduced by a factor as shown in the attached figure (Fig. 2). Readymade support spans for specific pipe diameters and thicknesses are available in the MSS code. For the Shell group of companies, the support span is provided in DEP in tabular format.
Fig. 2: Factor to reduce support span depending on layout.
1. Pipe Support Spacing Chart for Steel Piping as per MSS-SP-69
A pipe support span chart is a tabular chart giving a rough idea of supporting distance. These charts are normally mentioned in piping stress analysis project specifications. In the following image (Fig. 3) pipe support span chart from MSS SP-69 is reproduced as a sample.
Fig. 3: Sample Piping Support Span Chart (Reference: MSS SP-69)
2. Pipe Support Spacing Chart for Steel Piping Based on ASME B31.1
The pipe support span as per ASME B31.1 for Steel piping is provided below:
Pipe Support Span Based on ASME B31.1, Power Piping Code
NPS (Inches)
DN (mm)
Water/ Liquid Service (m)
Water/ Liquid Service (ft)
Steam, Gas, Air Service (m)
Steam, Gas, Air Service (ft)
1
25
2.1
7
2.7
9
2
50
3.0
10
4.0
13
3
80
3.7
12
4.6
15
4
100
4.3
14
5.2
17
6
150
5.2
17
6.4
21
8
200
5.8
19
7.3
24
12
300
7.0
23
9.1
30
16
400
8.2
27
10.7
35
20
500
9.1
30
11.9
39
24
600
9.8
32
12.8
42
Table 1: Pipe Support Spacing in ft and m as per ASME B31.1-Power Piping Code
General Notes for Table 1:
This support span is valid for horizontal straight runs of standard and heavier steel pipe at a maximum operating temperature of 750°F (400°C).
This support spacing chart does not apply in the presence of concentrated loads between supports, such as flanges, valves, and specialties.
The pipe support spacing is based on a fixed beam support with a bending stress limiting to 2,300 psi (15.86 MPa) and insulated pipe filled with water or the equivalent weight of steel pipe for steam, gas, or air service, and the pitch of the line is such that a sag of 0.1 in. (2.5 mm) between supports is permissible.
3. Pipe Support Span Chart as per ASME B31.3
Process piping code ASME B31.3 does not provide any span chart for steel piping systems. Users usually develop their pipe support spacing table considering parameters like allowed stress, deflection, etc. A typical pipe support span for process piping for carbon steel and stainless steel pipe material is provided below (Reference: Shell DEP) in Table 2 and Table 3.
3.1 Pipe Support Span for Carbon Steel
Typical Support Span for carbon steel and heavy wall stainless steel
Vapour service
Liquid service
Pipe size
Bare
Insulated
Bare
Insulated
DN 15 (NPS ½)
900 mm (3 ft)
800 mm (2 ½ ft)
900 mm (3 ft)
800 mm (2 ½ ft)
DN 20 (NPS ¾)
1400 mm (4 ½ ft)
1200 mm (3.9 ft)
1400 mm (4 ½ ft)
1200 mm (3.9 ft)
DN 25 (NPS 1)
3600 mm (11.8 ft)
2300 mm (7.5 ft)
3450 mm (11.3 ft)
2250 mm (7.3 ft)
DN 40 (NPS 1 ½)
3600 mm (11.8 ft)
3000 mm (9.8 ft)
3450 mm (11.3 ft)
2800 mm (9.1 ft)
DN 50 (NPS 2)
3600 mm (11.8 ft)
3450 mm (11.3 ft)
3450 mm (11.3 ft)
3300 mm (10.8 ft)
DN 80 (NPS 3)
6550 mm (21.4 ft)
4600 mm (15 ft)
5450 mm (17.8 ft)
4200 mm (13.7 ft)
DN 100 (NPS 4)
7500 mm (24.6 ft)
5550 mm (18.2 ft)
6100 mm (20 ft)
4900 mm (16 ft)
DN 150 (NPS 6)
9150 mm (30 ft)
6800 mm (22.3 ft)
7100 mm (23.2 ft)
5800 mm (19 ft)
DN 200 (NPS 8)
10500 mm (34.4 ft)
8050 mm (26.4 ft)
7950 mm (26 ft)
6700 mm (21.9 ft)
DN 250 (NPS 10)
11800 mm (38.7 ft)
9050 mm (29.6 ft)
8700 mm (28.5 ft)
7400 mm (24.2 ft)
DN 300 (NPS 12)
12900 mm (42.3 ft)
9800 mm (32.1 ft)
9150 mm (30 ft)
7800 mm (25.5 ft)
DN 350 (NPS 14)
15150 mm (49.7 ft)
11850 mm (38.8 ft)
10850 mm (35.5 ft)
9300 mm (30.5 ft)
DN 400 (NPS 16)
16250 mm (53.3 ft)
12850 mm (42.1 ft)
11200 mm (36.7 ft)
9750 mm (31.9 ft)
DN 450 (NPS 18)
17250 mm (56.5 ft)
13750 mm (45.1 ft)
11500 mm (37.7 ft)
10150 mm (33.3 ft)
DN 500 (NPS 20)
18200 mm (59.7 ft)
14450 mm (47.4 ft)
11750 mm (38.5 ft)
10400 mm (34.1 ft)
DN 600 (NPS 24)
18950 mm (62.1 ft)
16050 mm (52.6 ft)
12150 mm (39.8 ft)
10950 mm (35.9 ft)
DN 750 (NPS 30)
21000 mm (68.9 ft)
17500 mm (57.4 ft)
13100 mm (43 ft)
11500 mm (37.7 ft)
DN 900 (NPS 36)
22700 mm (74.5 ft)
18500 mm (60.7 ft)
13700 mm (45 ft)
12500 mm (41 ft)
DN 1050 (NPS 42)
23400 mm (76.8 ft)
19500 mm (64 ft)
14300 mm (47 ft)
13000 mm (42.6 ft)
DN 1200 (NPS 48)
25000 mm (82 ft)
20500 mm (67.2 ft)
14600 mm (48 ft)
13400 mm (44 ft)
Table 2: Pipe Support Span for Carbon Steel and Heavy Wall Stainless Steel
3.2 Pipe Support Span for Stainless Steel
Maximum spans for stainless steel, schedule 10S
Vapour service
Liquid service
Pipe size
Bare
Insulated
Bare
Insulated
DN 25 (NPS 1)
2200 mm (7.2 ft)
1800 mm (5.9 ft)
2100 mm (6.8 ft)
1800 mm (5.9 ft)
DN 40 (NPS 1 ½)
2800 mm (9.1 ft)
2500 mm (8.2 ft)
2400 mm (7.8 ft)
2500 mm (8.2 ft)
DN 50 (NPS 2)
2800 mm (9.1 ft)
2600 mm (8.5 ft)
2700 mm (8.8 ft)
2600 mm (8.5 ft)
DN 80 (NPS 3)
6400 mm (21 ft)
4050 mm (13.2 ft)
4950 mm (16.2 ft)
3500 mm (11.4 ft)
DN 100 (NPS 4)
6400 mm (21 ft)
4800 mm (15.7 ft)
5300 mm (17.3 ft)
4000 mm (13.1 ft)
DN 150 (NPS 6)
9400 mm (30.8 ft)
5750 mm (18.8 ft)
5950 mm (19.5 ft)
4600 mm (15 ft)
DN 200 (NPS 8)
10750 mm (35.2 ft)
6800 mm (22.3 ft)
6450 mm (21.1 ft)
5200 mm (17 ft)
DN 250 (NPS 10)
10750 mm (35.2 ft)
7600 mm (24.9 ft)
6950 mm (22.8 ft)
5650 mm (18.5 ft)
DN 300 (NPS 12)
10750 mm (35.2 ft)
8250 mm (27 ft)
7350 mm (24.1 ft)
6050 mm (19.8 ft)
DN 350 (NPS 14)
10750 mm (35.2 ft)
8700 mm (28.5 ft)
7600 mm (24.9 ft)
6300 mm (20.6 ft)
DN 400 (NPS 16)
11000 mm (36 ft)
9450 mm (31 ft)
7750 mm (25.4 ft)
6550 mm (21.4 ft)
DN 450 (NPS 18)
11000 mm (36 ft)
9700 mm (31.8 ft)
7850 mm (25.7 ft)
6750 mm (22.1 ft)
DN 500 (NPS 20)
11500 mm (37.7 ft)
10500 mm (34.5 ft)
8400 mm (27.5 ft)
7300 mm (23.9 ft)
DN 600 (NPS 24)
12000 mm (39.3 ft)
11000 mm (36 ft)
9050 mm (29.6 ft)
8050 mm (26.4 ft)
DN 750 (NPS 30)
14000 mm (45.9 ft)
13000 mm (42.6 ft)
10500 mm (34.5 ft)
9500 mm (31.2 ft)
DN 900 (NPS 36)
16000 mm (52.5 ft)
15000 mm (49.2 ft)
11500 mm (37.7 ft)
10500 mm (34.5 ft)
DN 1050 (NPS 42)
18000 mm (59 ft)
16500 mm (54 ft)
12500 mm (41 ft)
11500 mm (37.7 ft)
DN 1200 (NPS 48)
20000 mm (65.6 ft)
17300 mm (56.8 ft)
13500 mm (44.3 ft)
12500 mm (41 ft)
Table 3: Maximum Pipe Support Spans for Stainless Steel, Schedule 10S Pipe
E. HDPE Pipe Support Span
The maximum allowable span for HDPE pipes will depend on various factors, such as the pipe size, wall thickness, and temperature of the fluid being transported. In general, HDPE pipes require more support than steel pipes due to their flexibility and low modulus of elasticity.
The Plastics Pipe Institute (PPI) provides guidelines for designing supports for HDPE pipes, which includes recommendations for maximum allowable span. According to PPI, the maximum allowable span for HDPE pipes should not exceed the following:
4 feet for 1-inch diameter pipes
5 feet for 1.25-inch diameter pipes
6 feet for 1.5-inch diameter pipes
7 feet for 2-inch diameter pipes
9 feet for 3-inch diameter pipes
11 feet for 4-inch diameter pipes
13 feet for 6-inch diameter pipes
15 feet for 8-inch diameter pipes
18 feet for 10-inch diameter pipes
22 feet for 12-inch diameter pipes
However, it is important to note that these are general guidelines and the actual span may vary depending on the specific application and the design criteria used. It is always recommended to consult with a qualified engineer or piping designer to determine the appropriate support span for a specific HDPE piping system.
F. GRE Pipe Support Span
The maximum allowable span for Glass Reinforced Epoxy (GRE) pipes will depend on various factors, such as the pipe diameter, wall thickness, and the type of fluid being transported.
The Fiberglass Reinforced Plastic Institute (FRPI) provides guidelines for designing supports for GRE pipes, which includes recommendations for maximum allowable span. According to FRPI, the maximum allowable span for GRE pipes should not exceed the following:
2 feet for 1-inch diameter pipes
2.5 feet for 1.25-inch diameter pipes
3 feet for 1.5-inch diameter pipes
4 feet for 2-inch diameter pipes
6 feet for 3-inch diameter pipes
7 feet for 4-inch diameter pipes
8 feet for 6-inch diameter pipes
10 feet for 8-inch diameter pipes
12 feet for 10-inch diameter pipes
14 feet for 12-inch diameter pipes
It is important to note that these are general guidelines and the actual span may vary depending on the specific application and the design criteria used. It is always recommended to consult with a qualified engineer or piping designer to determine the appropriate support span for a specific GRE piping system.
ISO 14692-2002 also provides a typical GRE pipe support span table to be used for FRP/GRE pipes in Table 1 (The same is reproduced below in Fig. 4).
Fig. 4: GRE Pipe Support Span as per ISO 14692-2002
G. ABS and PVC Pipe Support Spacing
PVC and ABS pipe support spacing is mainly based on the manufacturer. The following image (Fig. 5) provides some typical values for ABS and PVC Pipe Support Spans.
Fig. 5: Horizontal Support Spacing for PVC and ABS Pipes
H. Online Video Courses on Piping Support
To learn more about piping support design and engineering you can opt for the following video course.
