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Liquified Natural Gas (LNG): Properties, Uses, Origin, Composition, Process, Companies

Written by Anup Kumar Dey in Piping Design Basics,Piping Interface,Process

Liquefied Natural Gas (LNG) is a natural gas that has been cooled to a temperature of -162°C (-260°F) at atmospheric pressure, which results in the gas transforming into a liquid state. This process, called liquefaction, reduces the volume of natural gas by about 600 times, making it easier and more economical to transport and store.

LNG is primarily composed of methane, which is the main component of natural gas. It is produced by cooling natural gas to its boiling point, which causes it to condense into a liquid. The resulting LNG is clear, odorless, non-corrosive, and non-toxic.

LNG is typically stored in insulated tanks and transported in special carriers, such as LNG ships or tanker trucks. It can be used as a fuel for power generation, heating, and transportation, or as a feedstock for producing chemicals and other products.

Due to its high energy density and low environmental impact, LNG is becoming an increasingly popular alternative to other fossil fuels, such as coal and oil. It is also considered a bridge fuel toward a low-carbon future, as it can help reduce greenhouse gas emissions compared to other fossil fuels.

Liquefied Natural Gas or LNG is natural gas with the primary element as methane. The Liquefied Natural Gas is converted to liquid form for ease of transport and storage. While in liquid form, Liquified Natural Gas takes up around 1/600th of the volume of its gaseous form. So, LNG can easily be transported in liquid form in locations where natural gas transportation through pipelines is not feasible. Special tankers carry this liquefied natural gas to the terminals where the LNG is returned to the gaseous phase and distributed through pipelines.

Characteristics of Liquefied Natural Gas

Liquefied natural gas or LNG is colorless, odorless, non-toxic, and non-corrosive. The main characteristics of liquefied natural gas are

  • It is a cryogenic liquid so must be handled using special materials and technologies.
  • LNG is stored in special containers.
  • It is a fossil fuel created by organic deposited materials.
  • The boiling point of LNG is typically -162 Deg. C
  • The density of liquefied natural gas varies between 430 Kg/m3 to 470 Kg/m3.
  • At ambient conditions, LNG will convert to vapor form.
  • LNG is non-flammable.
  • Liquefied Natural Gas has a very hot flame temperature means it rapidly burns and creates huge heat because its heat of combustion is 50.2 MJ/kg.
  • It is hazardous if not contained properly.
  • LNG is a very good source of energy.

Uses of Liquefied Natural Gas

LNG or liquefied natural gas is used widely for the following applications.

  • To generate electricity or power.
  • Used as fuel for industrial and commercial boilers.
  • for heating water and buildings, to cook in residential applications.
  • For Road transport as LNG vehicles
  • For sea transport in ships, ferries, etc
  • Used as fuels for furnaces, fluid bed dryers
  • As marine fuel

Origin of Natural Gas

Natural gas exists in nature under pressure in rock reservoirs in the Earth’s crust, either in conjunction with and dissolved in heavier hydrocarbons and water or by itself. It is produced from the reservoir similarly to or in conjunction with crude oil.

Natural gas has been formed by the degradation of organic matter accumulated in the past millions of years. Two main mechanisms (biogenic and thermogenic) are responsible for this degradation. Natural gas produced from geological formations comes in a wide array of compositions. The varieties of gas compositions can be broadly categorized into three distinct groups:

  • Non-associated gas – it occurs in conventional gas fields
  • Associated gas – it occurs in conventional oil fields, and
  • Unconventional natural gas.

Unconventional gas

It occurs outside of the former two. The most common types of unconventional gas are:

  • Tight gas – natural gas produced from reservoir rocks with such low permeability that massive hydraulic fracturing is necessary to produce the well at economic rates;
  • Coalbed methane – methane adsorbed into the solid matrix of the coal;
  • Natural gas from geo-pressurized aquifers;
  • Gas hydrates – methane clathrate is a solid clathrate compound in which a large amount of methane is trapped within a crystal structure of water, forming a solid similar to ice;
  • Deep gas

Composition of Natural Gas

Natural gas is a complex mixture of hydrocarbon and non-hydrocarbon constituents and exists as a gas under atmospheric conditions.

Raw natural gas typically consists primarily of methane (CH4), the shortest and lightest hydrocarbon molecule. It also contains varying amounts of:

  • Heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), iso-butane (i-C4H10), pentanes, and even higher molecular weight hydrocarbons.
  • Acid gases: carbon dioxide (CO2), hydrogen sulfide (H2S), and mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH).
  • Other gases: nitrogen (N2) and helium(He).
  • Water: water vapor and liquid.
  • Liquid hydrocarbons: crude oil and/or gas condensates.
  • Mercury: only trace amounts.

Refer to the table in Figure 1 for a typical composition of Natural gas.

Table showing typical composition of natural gas
Fig. 1: Table showing the typical composition of natural gas

LNG Process

Naturally, liquefaction is advantageous as it can be transported or stored in a greater quantity. The LNG Process is the process of liquefaction. The process of cooling the gaseous LNG to -259°F or -162°C for transforming it into liquid is known as the LNG Process. The process is actually a chain of methods, hence popularly known as LNG Process Chain.

Natural Gas – Exploration to End-User

Fig. 2 below shows the flow chart for Liquefied natural gas exploration.

Flow chart showing exploration of natural gas
Fig. 2: Flow chart showing the exploration of natural gas

LNG Plant

An LNG plant refines the crude natural gas received from deep within the earth and condenses it into a pure, concentrated, efficient, liquid form of energy. Three basic processing steps are performed in the LNG plant. These are:

  • Purification of the extracted natural gas by removing dust, acid gases (CO2), helium, water, and heavy hydrocarbons.
  • Liquefaction by condensing and cooling it to approximately −162 °C.
  • Transportation of the liquefied natural gas to the consumer by sea or road transport.

Typical processes of a 2-train LNG plant are shown in Fig. 3.

A typical 2 train LNG plant
Fig. 3: A typical 2-train LNG plant

Liquefaction Temperatures of LNG

Image showing liquefaction temperature
Fig. 4: Image showing liquefaction temperature

LNG Process Flow

Fig. 5 shows a Schematic of a Simple Refrigeration Cycle (LNG Process Flow)

Natural Gas Liquefaction Techniques

Different LNG Process liquefaction techniques include:

  • Single Refrigeration cycle
  • Multiple Refrigeration cycles
  • Self Refrigerated cycles
  • Cascade Processes
  • The cooling of natural gas involves the use of refrigerants which could either be pure component refrigerants or mixed component refrigerants.
Schematic of a Simple Refrigeration Cycle
Fig. 5: Schematic of a Simple Refrigeration Cycle

LNG Process Liquefaction Technologies

LNG process liquefaction is performed using various technologies mentioned below:

  1. CASCADE PROCESS by ConocoPhillips
  2. C3MR or AP-X by Air Products
  3. DMR by Shell
  4. Mixed Fluid Cascade – MFC by Linde
  5. Liquefin by Axens / Air Liquide

Liquefied Natural Gas by CASCADE Process

  • Most Straight Forward of All Processes
  • Kenai Plant Continuous Operation 1969
  • CoP License, Plant Build by Bechtel.
  • The raw gas is first treated to remove typical contaminants.
  • Next, the treated gas is chilled, cooled, and condensed to -162 ˚C in succession using propane, ethylene, and methane.
  • The last stage is pumping LNG to storage tanks and awaiting shipment.
Schematic of Cascade process
Fig. 6: Schematic of Cascade process
  • Pure component Refrigerants
  • Specific operating ranges for each component
  • Mixed Refrigerants
  • Modified to meet specific cooling demands.
  • Helps improve the process efficiency
  • Mixed refrigerants are mainly composed of hydrocarbons ranging from methane to pentane, Nitrogen, and CO2. Typically, Methane – 25-30%, Ethane – 45-55%, Propane – 15-20%, Nitrogen – 1-5%, and Butane – 1-2%.

Liquefied Natural Gas by Single MR Process

  • Significant improvement from Cascade Process
  • The use of Coil wound Heat Exchangers & MR refrigerant simplified the process.
  • Mixed Refrigerant offered a way to provide the required refrigeration over the temperature range required.

C3MR process of Liquefaction of LNG Process

  • Introduction of Propane as Pre-cooling to liquefication
  • Improved Efficiency, increased single train capacity
  • Reduction in MR refrigerant volumetric flow due to pre-cooling by Propane
  • Train size continued to grow with larger drivers & larger compressors
  • Liquefication capacity up to 5 MMTPA.
Schematic of C3MR process
Fig. 7: Schematic of the C3MR process

Liquefied Natural Gas by AP-X Hybrid LNG Process

  • Improved C3-MR process – pre-cooling by Propane, liquefaction using MR, and sub-cooling using Nitrogen Cycle.
  • Nitrogen Cycle has a simple & efficient expander loop.
  • Increased capacity by a reduction in volume flow of MR (40%of C3MR) & Propane (20% of C3MR).
  • Liquefication capacity up to 8.0 MMTPA.
  • Nitrogen Cycle is a simplified version of the cycle employed by Air Products in Air Separation plants.

Why Nitrogen:

  • Higher vapor pressure at the required liquefication temperature of Natural Gas
  • The relatively smaller volumetric flow rate in low-pressure Nitrogen circuits.
  • Improved efficiency by reducing pressure losses

DMR LNG Liquefaction Process

  • DMR – Dual Mixed Refrigerant is very similar to C3MR
  • The difference is in the utilization of a second pre-cooling refrigerant component.
  • The use of two mixed refrigerant cycles allows full utilization of power in a design with two mechanically driven compressors.
  • It allows keeping the compressors at their best efficiency point over a very wide range of ambient temperature variations and changes in feed gas composition.
  • The natural gas stream is cooled via two stages. The first stage cools natural gas to -50°C while the second column cools natural gas to LNG at -160°C.

Liquefied Natural Gas using Liquefin by Axens (Air Liquide)

  • Developed by IFPEN and AXENS, now owned by Air Liquide.
  • a highly efficient process and provides the most cost-competitive LNG product per ton.
  • is optimized best with the Brazed Aluminium Heat Exchanger, leading to further cost reductions and scalable output.
  • Compact and modular design
  • Balanced refrigeration power allows for identical refrigerant compressor drivers
  • Very cost-effective solution

Codes and Standards for Liquefied Natural Gas

Stringent code and standard guidelines are followed at every step of the LNG process to ensure safety. The primary LNG codes and standards are

  • NFPA 59A
  • EN1473
  • EN 1160
  • EN 14620
  • EN 1474
  • EN 1532
  • EN 13645
  • 33 CFR Part 127
  • API 620
  • JGA-107-RPIS
  • JGA-108-RPAS
  • JGA-102
  • JGA-103
  • OISD 194
  • NFPA 30.

Types of Liquefied Natural Gases

There are two main types of liquefied natural gas (LNG), which are based on the processes used to produce them:

  1. Associated Gas LNG: This type of LNG is produced as a by-product of oil extraction from oil fields that contain natural gas. When the oil is extracted, the natural gas is separated and liquefied. Associated Gas LNG typically has a higher content of hydrocarbons other than methane, such as ethane and propane, which makes it suitable for use as a feedstock for producing petrochemicals.
  2. Non-Associated Gas LNG: This type of LNG is produced from natural gas fields that do not have any associated oil. The natural gas is extracted from the fields and processed to remove impurities before being liquefied. Non-Associated Gas LNG typically has a higher methane content than Associated Gas LNG, which makes it suitable for use as a fuel for power generation, heating, and transportation.

Both types of LNG have similar properties and can be used interchangeably, although their specific applications may differ depending on their composition and quality.

LNG pricing

The pricing of Liquefied Natural Gas is not straightforward. In the current LNG contracts, three major pricing systems are prevalent as mentioned below:

  • Oil-indexed contract. Primary user countries are Japan, Korea, Taiwan, and China.
  • Oil, oil products, and other energy carriers indexed contracts. Specifically used in Continental Europe; and
  • Market-indexed contracts. Used mostly in the US and the UK.;
  • The equation used for the calculation of an indexed price is as follows:

CP = BP + β X

Here,

  • BP: constant part or base price
  • β: gradient
  • X: indexation

The above-mentioned formula finds its wide use in Asian LNG SPAs. The base price is represented by various non-oil factors but is usually a constant determined by negotiation at a level that can prevent LNG prices from falling below a certain level. It thus varies regardless of oil price fluctuation.

Quality of Liquefied Natural Gas

In the LNG Business, the quality of LNG is one of the most important issues. During trading, any natural gas that does not meet the agreed specifications is termed as “off-specification” or “off-quality” LNG. That’s why the LNG Quality must be regulated. Such regulations serve the following purposes:

  • Ensures the distributed gas is non-corrosive and non-toxic.
  • Guards against liquid or hydrate formation in the networks.
  • Allow interchangeability of the distributed gases by limiting the parameter variation ranges. Such parameters are the content of inert gases, calorific value, Incomplete Combustion Factor, Wobbe index, Soot Index, Yellow Tip Index, etc.

The quality of liquefied natural gas is measured at the delivery point by instruments like gas chromatograph.

Amount of the sulfur and mercury content and the calorific value are the most important gas quality concerns. To ensure the lowest concentration of sulfur and mercury in LNG, the liquefaction process must be accurately refined and tested.
The other concern for LNG is the heating value. In terms of heating value, the natural gas markets can be grouped into three markets as follows:

  • Asia (Japan, Korea, Taiwan) with a gross calorific value (GCV) higher than 43 MJ/m3(n), i.e. 1,090 Btu/SCF, known as rich gas distribution.
  • the UK and the US, with a GCV usually lower than 42 MJ/m3(n), i.e. 1,065 Btu/SCF, known as lean gas distribution
  • Continental Europe with the acceptable GCV range is quite wide: approx. 39 to 46 MJ/m3(n), i.e. 990 to 1,160 Btu/scf.

Sometimes to increase the heating value of liquefied natural gas, propane and butane are injected. In general, the price of lean LNG in terms of energy value is lower as compared to the rich LNG.

LNG Safety

Natural gas is the most environmentally friendly fossil fuel with the lowest CO2 emissions per unit of energy. But, Natural gas, being fuel and a combustible substance, must be handled with care. For the design, construction, and operation of liquefied natural gas facilities, proper measures must be taken to ensure safe and reliable operation.

However, LNG in its liquid form can not ignite and is not explosive. For LNG to burn, it must vaporize first and mix with air in the proper proportions. During leakage, LNG rapidly vaporizes and turns into a gas that easily mixes with the air. In such a case, there is a risk of ignition causing fire and thermal radiation hazards.

What is Floating Liquefied Natural Gas or FLNG?

Floating Liquefied Natural Gas (FLNG) is a technology used to produce, liquefy, store, and transfer LNG at sea. It involves using a specialized vessel that is equipped with liquefaction facilities and can be moored at a natural gas field to produce and process gas in situ.

FLNG technology enables the production of LNG from offshore natural gas fields that are too small or too remote to justify the cost of building onshore liquefaction facilities. It also allows for greater flexibility in LNG production, as the vessel can be moved from one location to another depending on the demand for LNG.

The FLNG vessel typically includes a processing plant, storage tanks, and a liquefaction plant that cools the natural gas to its liquid state. The LNG is then stored in onboard tanks until it can be transferred to LNG carriers for transportation to markets around the world.

The main advantage of FLNG technology is its ability to produce LNG at the source of natural gas, which reduces the need for long-distance pipelines and onshore liquefaction plants. This can result in significant cost savings and reduced environmental impact compared to traditional LNG production methods. However, FLNG technology also has some challenges, including the need for specialized vessels and the potential for safety and environmental risks associated with offshore operations.

Liquefied Natural Gas vs Propane

Liquefied Natural Gas (LNG) and propane are both forms of liquefied gases that can be used as fuels. However, there are some differences between the two:

  • Composition: LNG is primarily composed of methane, while propane is a hydrocarbon gas composed of propane molecules.
  • Production: LNG is produced by cooling natural gas to its boiling point, while propane is produced as a by-product of natural gas processing and crude oil refining.
  • Energy content: LNG has a lower energy content per unit volume than propane, which means that a larger volume of LNG is required to provide the same amount of energy as propane.
  • Storage and transportation: LNG is typically stored and transported in insulated tanks at cryogenic temperatures of around -162°C (-260°F), while propane is stored and transported as a liquid under pressure at room temperature.
  • Applications: LNG is primarily used as a fuel for power generation, heating, and transportation, while propane is commonly used for heating, cooking, and as a fuel for vehicles and industrial processes.

Both LNG and propane are considered cleaner-burning fuels compared to other fossil fuels like coal and oil, as they produce fewer emissions of pollutants and greenhouse gases. However, the choice of which fuel to use depends on the specific application and availability of the fuel.

Differences Between LPG and LNG

LPG (liquefied petroleum gas) and LNG (liquefied natural gas) are two types of liquefied gases that are commonly used as fuels. Here are some of the key differences between LPG and LNG:

  • Composition: LPG is a mixture of propane and butane gases, while LNG is primarily composed of methane.
  • Production: LPG is produced as a by-product of natural gas processing and crude oil refining, while LNG is produced by cooling natural gas to its boiling point.
  • Energy content: LNG has a lower energy content per unit volume than LPG, which means that a larger volume of LNG is required to provide the same amount of energy as LPG.
  • Storage and transportation: LPG is typically stored and transported as a liquid under pressure at room temperature, while LNG is stored and transported in insulated tanks at cryogenic temperatures of around -162°C (-260°F).
  • Applications: LPG is commonly used for heating, cooking, and as a fuel for vehicles and industrial processes, while LNG is primarily used as a fuel for power generation, heating, and transportation.
  • Availability: LPG is generally more widely available than LNG, as it is produced as a by-product of oil and natural gas extraction and processing. LNG production requires specialized facilities and transportation infrastructure.

Both LPG and LNG are considered cleaner-burning fuels compared to other fossil fuels like coal and oil, as they produce fewer emissions of pollutants and greenhouse gases. The choice of which fuel to use depends on the specific application, availability, and cost of the fuel.

Liquefied Natural Gas Companies

There are many companies involved in the production, transportation, and marketing of liquefied natural gas (LNG). Here are some of the largest and most well-known companies in the LNG industry:

  • Royal Dutch Shell: Shell is one of the world’s largest energy companies and is involved in all aspects of the LNG business, from production to transportation and marketing.
  • ExxonMobil: ExxonMobil is a global energy company that is involved in LNG production and marketing, as well as the development of LNG infrastructure.
  • Chevron: Chevron is a major player in the LNG industry, with interests in LNG production, transportation, and marketing.
  • Total: Total is a French multinational energy company that is involved in all aspects of the LNG business, from production to transportation and marketing.
  • BP: BP is a global energy company with interests in LNG production and marketing, as well as the development of LNG infrastructure.
  • Qatargas: Qatargas is a joint venture between Qatar Petroleum and several major international oil and gas companies, and is one of the largest producers of LNG in the world.
  • Cheniere Energy: Cheniere is a US-based energy company that specializes in LNG production and export, and is one of the largest LNG exporters in the world.
  • Woodside Energy: Woodside is an Australian energy company that is involved in LNG production and marketing, with a particular focus on the Asia-Pacific region.
  • Novatek: Novatek is a Russian energy company that is one of the largest producers of LNG in Russia and is expanding its LNG export capabilities.

ASME B31J & B31J Essentials: Why these are useful in Piping Stress Analysis?

Written by Anup Kumar Dey in Caesar II,Piping Stress Analysis,Piping Stress Basics

Introduction to B31J Essentials in Caesar II

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.

B31J Menu bars explaining the functions.
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:

Typical Output SIF results as calculated by B31J module of Caesar II
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 A provides the standard method to develop stress intensification factors.
  • 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.

Steel Surface Coating for Corrosion Prevention

Written by Anup Kumar Dey in Engineering Materials,Piping Design Basics

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).

Figure showing rate of corrosion.
Fig. 1: Figure showing the rate of corrosion.

Corrosion Control

  • 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

Few International Standards for 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

Written by Anup Kumar Dey in Caesar II,Piping Stress Analysis,Piping Stress Basics

What is Fatigue Analysis?

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:

  • Thermal Expansion & Contraction
  • Vibration due to Occasional loading
  • Pressure variation within the Piping system
  • Motion wave.
  • Due to Flow-induced Vibration

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:

  • Type and Nature of Loading.
  • Size of Component and stress or strain Distribution.
  • Surface finish and Directional Properties.
  • Stress or Strain Concentration.
  • Mean stress or Strain.
  • Environmental Effects.
  • Metallurgical Factors and Material Properties.
  • Strain Rate and Frequency Effects.

Characteristics of Low Cycle Fatigue

  • 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:

  1. 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

Fatigue Analysis Steps

The majority of the established software mentioned above follows the same steps for performing fatigue analysis. The steps are

  • Determining the fatigue loading details like the calculation of the number of cycles in the design life of the member
  • Add this information to the software as input for fatigue analysis.
  • Define the material fatigue data (like the S-N curve) from Codes/Standards
  • Create the fatigue analysis load cases
  • Run the Analysis and
  • Process the output as relevant

Fatigue Curve

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.  

Typical S-N Plot
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.

Design Fatigue Curve for Carbon and Low Alloy Steel
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):  

Estimation of Number of Cycles for Fatigue Analysis
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

Fatigue Input in Caesar II for Analysis
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.  

Creating Load Cases for Fatigue Analysis
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.    

Output Screen showing stress range
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.  

Output Screen showing Cumulative usage factor
Fig. 7: Output Screen showing Cumulative usage factor

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.  

Basic Principles of Aboveground GRE Piping System

Written by Anup Kumar Dey in Engineering Materials,Pipeline,Piping Design Basics,Piping Interface,Piping Stress Basics

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:

Hoop Stress and Axial Stress for a GRP Piping System
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:

Equations to calculate stresses
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).

Vacuum resistance with respect to pressure class and pipe stiffness
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:

Calculation of end loads for GRP piping for constrained expansion
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:

Calculation of End load due to Instability
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):

Effect of Direction Changes
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:

Expansion loop in GRP piping system
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:

  1. the maximum axial strain must not exceed the allowable value;
  2. 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:

typical support span for a specific project
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.

PVC saddle and Vertical 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.

GRP lamination in pipe anchors
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:

  • ISO-14692
  • NORSOK M-710
  • DNV GL RP-F112
  • AWWA M45

Few more related Resources for you..

HYDROSTATIC FIELD TEST of GRP / GRE lines
Stress Analysis of GRP / GRE / FRP piping system using Caesar II
A short article on GRP Pipe for beginners
Stress Analysis of GRP / GRE / FRP Piping using START-PROF

Piping Design Considerations for Vertical Columns or Tall Towers (Column Piping)

Written by Anup Kumar Dey in Piping Design Basics

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.

  • P&ID
  • Process Vessel Sketch
  • Plot plan
  • Piping & Plant Layout Specification

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 elevation review and support selection
  • Tray orientation
  • Nozzle orientation
  • Platform and access requirement
  • Support cleat location detailing
  • Lifting lugs and earthling lugs location planning
  • Finalizing Vessel Name Plate location

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.
Image of a Typical Vertical Column
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.

Column Piping Layout: Tray orientation considerations

The main items influencing tray orientation are

  • Feed nozzle orientation
  • Reboiler location
  • Access Manholes

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.

  • Process vessel sketch
  • Level co-ordination diagram
  • P&ID
  • Plant layout specification
  • Nozzle summary
  • Insulation requirements
  • Plot plan

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.

Column Piping
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.

Few more Resources for you..

Stress Analysis of Column piping system using Caesar II
Piping Design and Layout Considerations
Piping Materials Basics
Piping Stress Analysis