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Complete Pipe Stress Analysis using Caesar II Online Course

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

Piping systems are the veins of industrial plants, carrying fluids and gases critical for various processes. Ensuring the reliability and safety of these piping systems is paramount, and this is where Advanced Pipe Stress Analysis comes into play. Advanced Pipe Stress Analysis goes beyond basic analysis, offering a comprehensive understanding of how pipes behave under various conditions.

Pipe Stress Analysis is a critical aspect of piping design that evaluates the effects of loads, pressures, and thermal gradients on a piping system. Basic Pipe Stress Analysis typically considers factors like pressure, temperature, and weight to ensure the system’s integrity. However, as systems become more complex and industries demand higher efficiency, Advanced Pipe Stress Analysis becomes essential.

Various sophisticated software tools are essential for Advanced Pipe Stress Analysis. One such powerhouse in the field is Caesar II. Developed by Hexagon PPM, Caesar II is a widely used software application that plays a pivotal role in ensuring the integrity and reliability of piping systems. Caesar II allows engineers and designers to model, analyze, and optimize piping systems. Known for its robust capabilities, the software enables a comprehensive evaluation of various factors influencing pipe behavior, providing a detailed understanding of stress, deformation, and stability under different operating conditions. Throughout the course, the explanations and case studies are provided using Caesar II software.

The complete online pipe stress analysis course is divided into several modules. Each module will explain some aspects of Pipe Stress Analysis that are required for every pipe stress engineer. New modules will be added as and when prepared. You can enroll in the module that you require.

Module 1: Basics of Pipe Stress Analysis (Duration: 5 hours)

  • Click here to join the course. You will learn the following:
    • How to Use Caesar II Software
    • Creating a 3D model of the piping system adding piping, components, fittings, supports, etc
    • Modeling equipment connection in Caesar II
    • Basics Theory of Pipe Stress Analysis
    • Load Case Preparation
    • Analyzing the system and reviewing the Results

Module 2: Pipe Support Engineering (Duration: 2 hours)

  • Join the module by clicking here. The support engineering module will cover the following details:
    • Role of Pipe Supports in Piping Design
    • Types of Pipe Supports
    • Pipe Support Spacing or Span
    • How to Support a Pipe
    • Pipe Support Optimization Rules
    • Pipe Support Standard and Special Pipe Support
    • Pipe Support Engineering Considerations

Module 3: ASME B31.3 Basics for Pipe Stress Engineer (Duration: 1.5 hrs)

  • To enroll in this module click here. You will learn the following:
    • Learn the basics from ASME B31.3 required for a pipe stress engineer
    • Learn Code equations that stress analysis software use
    • Learn the allowable values for different types of code stresses
    • Learn Material allowable stresses
    • Learn to calculate pipe thickness as per ASME B31.3

Module 4: Stress Analysis of PSV/PRV Piping System in Caesar II (Duration: 1 hr)

  • Enroll in this module by clicking here. This module covers
    • Brief about Pressure Safety Valve Systems
    • PSV Reaction Force Calculation
    • Application of PRV Reaction Force in Stress System
    • Case Study of Stress Analysis of PSV System using Caesar II Software
    • Best Practices for PSV Piping Stress Analysis

Module 5: Flange Leakage Analysis in Caesar II (Duration: 1 hr)

  • Click here to enroll in this module. It covers
    • Reasons for Flange Leakage
    • Basics of Flange Leakage Analysis
    • Types of Flange Leakage Analysis
    • Case Study of Flange Leakage Analysis using Caesar II (Case Studies of Pressure Equivalent Method, NC 3658.3 method, ASME Sec VIII method)

Module 6: Spring Hanger Design and Selection (Duration: 1.5 hours)

  • Here is your module for registering. Spring hanger module covers:
    • What is a Spring Hanger?
    • Types of Spring Hangers
    • Differences between Variable and Constant Spring Hangers
    • Design and Selection of Spring Hangers
    • Case Study of Spring Hanger Design and Selection Using Caesar II

Module 7: WRC 537/WRC 297 Calculation in Caesar II (Duration: 1 hr)

  • To join the module click here. It will cover the following:
    • What is WRC 537 and WRC 297
    • When to Perform WRC Calculation
    • Steps for WRC Calculation
    • Practical Case Study of WRC Calculation

Module 8: Buried Pipe Stress Analysis (Duration: 1.5 hr)

  • Click here to enroll for this course. It covers
    • Learn how to model buried piping and pipeline systems in Caesar II software
    • Additional Inputs required for buried pipe stress analysis
    • Create load cases based on ASME B31.3/B31.4/B31.8 codes
    • Perform the underground/buried pipe stress analysis
    • Review the results calculated by the software and understand their meanings

Module 9: Pump Piping Stress Analysis Using Caesar II (Duration: 2.5 hrs)

  • To enroll in this course proceed by clicking here. The course briefly covers
    • Learn the basics of pump piping stress analysis.
    • Learn to create load cases for pump piping analysis in Caesar II software.
    • Learn to read data from pump GA to model and analyze using Caesar II.
    • Practical Case Study of a Pump Piping Stress Analysis

Module 10: Static and Dynamic Analysis of Slug Flow in Caesar II (Duration: 1.5 hrs)

  • To learn from this course click here. It covers
    • Basics of Slug Flow Analysis
    • Calculation of Slug Forces
    • Application of Slug Forces
    • Static Analysis of Slug Flow
    • Dynamic Analysis of Slug Flow

Module 11: FRP-GRP-GRE Piping/Pipeline Stress Analysis Using Caesar II (Duration: 1.5 hrs)

  • Proceed here to enroll in this module of the course. It briefly explains
    • Basics of FRP/GRE/GRP Piping
    • Inputs to ask from the vendor for FRP/GRP/GRE Pipe Stress Analysis
    • Modeling and Analyzing GRP/FRP/GRE Piping system in Caesar II
    • Flange Leakage Checking for FRP Piping Systems
    • FRP Pipe Supporting Guidelines

Module 12: Pipeline Stress Analysis using Caesar II (Duration: 1.5 hrs)

  • Click here for enrolling in this module. This module covers
    • Liquid and Gas Pipeline Stress Analysis using ASME B31.4 and ASME B31.8
    • Difference between Piping and Pipeline
    • Differences between ASME B314 and ASME B31.8
    • Use Caesar II software for pipeline stress analysis with a practical case study

Module 13: Dynamic Analysis of Piping Systems in Caesar II Software (Duration: 1.5 hrs)

  • Join this module by clicking here. This module covers
    • Dynamic Analysis Basics
    • Static Analysis vs Dynamic Analysis
    • Types of Dynamic Analysis
    • Modal Analysis Case Study
    • Response Spectrum Analysis Case Study

Module 14: Guide to Reviewing a Pipe Stress Analysis Report (Duration: 1 hr)

  • Click here for joining this module. It covers
    • Learn How to Review a Pipe Stress Analysis Report
    • Requirements of Pipe Stress Analysis Report
    • What to Review in a Pipe Stress Analysis Report
    • Practical Sample Review Process
    • Steps for Reviewing Pipe Stress Analysis Report

Module 15: Flow-Induced Vibration Analysis of Piping System (Duration: 1 hr)

  • Enroll in the FIV analysis module by clicking here. It covers:
    • Common causes of piping vibration and their effects.
    • Definition of Flow-Induced Vibration.
    • Reasons for FIV in a piping system.
    • FIV Study/Analysis Steps Based on Energy Institute Guidelines
    • Mitigation Options of FIV Study Results.

Module 16: Acoustic Induced Vibration Basics for Piping Systems (Duration: 45 Mins)

  • Click here to enroll in this module. This module covers:
    • What is Acoustic-Induced Vibration or AIV?
    • Causes and Effects Of Piping Vibration
    • Acoustic-Induced Vibration Analysis Steps
    • Mitigation of AIV

Module 17: Storage Tank Piping Stress Analysis (Duration: 1 hr)

  • Click here to enroll in this module. Storage tank piping stress analysis module covers the following
    • Differences between a storage tank and a pressure vessel?
    • Types of storage tanks used in oil and gas industries
    • Why is storage tank piping critical?
    • What is Tank settlement?
    • What is Tank bulging?
    • Storage Tank Nozzle Load Qualification
    • Practical case study of storage tank piping analysis

Module 18: Stress Analysis of Tower/Vertical Column Piping System (Duration: 1.5 hrs)

  • To join Module 18, Click here. This module Covers:
    • Application of Vertical Columns/Towers
    • Inputs Required for Column Piping Stress Analysis
    • Creating temperature profiles for Column/Tower Piping systems
    • Modeling of the Equipment
    • Clip/Cleat Support Modeling from Towers
    • Skirt Temperature Calculation
    • Nozzle Load Qualification
    • Practical Case Study

Module 19: Stress Analysis of Heat Exchanger Piping System (Duration: 1.5 hrs)

Module 20: A Roadmap to Pursue a Career in Pipeline Engineering (Duration: 1 hr)

  • Join the course by clicking here. It covers:
    • What is a Pipeline?
    • What is Pipeline Engineering?
    • Types of Pipeline Engineers, Their Roles and Responsibilities
    • Opportunities for Pipeline Engineers
    • Piping vs Pipeline; What are the Differences?
    • Piping or Pipeline- Which Career Option is Better?
    • How to become a Pipeline Engineer

Module 21: Steps for Pipeline Wall Thickness Calculation & Case Study (Duration: 1 hour)

  • Click here to enroll in this module. This module covers:
    • Need for Pipeline Thickness Calculation
    • Pipeline Thickness Calculation Steps for Restrained and Unrestrained Pipelines
    • Example of Pipeline Thickness Calculation for Aboveground Pipelines
    • Buried Pipeline Thickness Calculation Case Study
    • Additional Checks to satisfy pipeline thickness calculations

As mentioned earlier, new modules will be added frequently. So, keep visiting this post. Also, you can request any specific module by mentioning it in the comment section.

Detailed Online Course on Pipe Stress Analysis (25 hours of Content) with Certificate + Free Trial Version of Pipe Stress Analysis Software

Written by Alex Matveev in Engineering Courses,Pipeline,Piping Design Basics,Piping Stress Analysis,Piping Stress Basics,Start-Prof

This course is created by an experienced pipe stress analysis software developer (15+ years experience), Ph.D. and covers all features of onshore above ground and underground piping and pipeline analysis. This course is based on the PASS/START-PROF software application, though it will be interesting for users of any other pipe stress analysis software tools as it contains a lot of theoretical information.

The course consists of video lectures, quizzes, examples, and handout materials.

Type: an on-demand online course.

Duration: 25 hours.

Course price: 200 USD 30 USD.

Instructor: Alex Matveev, head of PASS/START-PROF Pipe Stress Analysis Software development team. Always available for your questions at Udemy, LinkedIn, Facebook

Alex Matveev

Who should attend

All process, piping, and mechanical engineers specialized in design and piping stress analysis for the specified industries:

  • Oil & Gas (Offshore/Onshore)
  • Chemical & Petrochemical
  • Power (Nuclear/ Non-Nuclear)
  • District Heating/Cooling
  • Water treatment
  • Metal industry

Training software

All trainees are provided with a free 30-day pipe stress analysis software license (PASS/START-PROF). How to get a free license

Certificate

After finishing the course, you will receive Certificates from both the Udemy and from PASS Team.

Detailed Training Agenda: Download the detailed training agenda in PDF.

Brief Summary of the Course

Introduction
Section 1. Working with PASS/START-PROF User Interface339 min
Section 2. Piping Supports138 min
Section 3. Stress Analysis Theory and Results Evaluation237 min
Section 4. Underground Pipe Modeling249 min
Section 5. Static and Rotating Equipment Modeling and Evaluation244 min
Section 6. Expansion Joints, Flexible Hoses, Couplings106 min
Section 7. Non-Metallic Piping Stress Analysis99 min
Section 8. External Interfaces65 min
Brief Course Summary

How to Enroll for the Course

Visit the Pipe Stress Analysis course page on Udemy

Then click Add to Cart or Buy Now and follow the instructions

What you will learn in this Course

  • Pipe stress analysis theory. Load types. Stress types. Bourdon effect. Creep effect in high-temperature piping, creep rupture usage factor (Appendix V B31.3)
  • ASME B31.1, ASME B31.3, ASME B31.4, ASME B31.5, ASME B31.8, ASME B31.9, ASME B31.12 code requirements for pipe stress analysis
  • How to use PASS/START-PROF software for pipe stress analysis
  • How to work with different load cases
  • How to model different types of piping supports, the spring selection
  • What are stress intensification and flexibility factors and how to calculate them using FEA and code requirements
  • How to model trunnion and lateral tees
  • How to model pressure vessels and columns connection: modeling local and global flexibility, WRC 297, WRC 537, FEA
  • How to model storage tank connection (API 650)
  • How to model connection to air-cooled heat exchanger API 661, fired heater API 560, API 530
  • How to model connection to Pump, Compressor, Turbine (API 610, API 617, NEMA SM23)
  • How to model buried pipelines: Submerged Pipelines, Long Radius Bends Modeling of Laying, Lifting, Subsidence, Frost Heaving, Fault Crossing, Landslide
  • Underground pipelines Seismic Wave Propagation, Pipe Buckling, Upheaval Buckling, Modeling of Pipe in Chamber, in Casing with Spacers. Electrical Insulation kit
  • Minimum design metal temperature calculation MDMT calculation, impact test
  • Modeling of Expansion Joints, Flexible Hoses, Couplings
  • Import and export to various software: CAESAR II, AVEVA, REVIT, PCF format, etc.
  • How to do Normal Modes Analysis and how to interpret results
  • ASME B31G Remaining Strength of Corroded Pipeline Calculation

Mechanism of Oxide Film Formation in Stainless Steel

Written by Mustafa Hashim in Engineering Materials,Process

The remarkable corrosion resistance of Fe-Cr-Ni-Mo stainless steel in dilute acidic environments containing trace chlorides has been well-known over the years. The corrosion resistance arises because of the formation of a thin, yet robust, passive oxide film in the stainless steel surface. This article will present the A to Z of this phenomenon, exploring the formation, composition, and interactions within this protective layer.

Elements of Oxide Film in Stainless Steel

The elements that help the formation of the oxide film in the stainless steel to resist corrosion are

  • Fe (Iron): The base metal of the steel, susceptible to corrosion in acidic environments.
  • Cr (Chromium): The key element, responsible for passivating the steel.
  • Ni (Nickel): Enhances stability and formability of the passive film.
  • Mo (Molybdenum): Improves resistance to pitting corrosion, particularly from chlorides.
  • H₂O (Water): The source of hydroxyl (OH⁻) ions, crucial for film formation and stability.
  • Cl⁻ (Chloride ions): The villain in this story, is capable of disrupting the protective film.

Passivation Process: Building the Oxide Film

Stainless steel undergoes a pre-treatment process called passivation before facing acidic environments. This process involves creating the protective oxide film you mentioned. Let’s learn the atomic-level details of this film formation:

Step 1: Surface Activation

  • Dissolution (Limited): A minuscule amount of iron atoms at the steel’s surface lose electrons and become Fe²⁺ ions. This creates a slight positive charge on the surface.
  • Oxygen Adsorption: Oxygen molecules (O₂) from the environment are attracted to the positively charged surface. At the atomic level, individual oxygen atoms (O) adsorb onto the metal surface.

Step 2: Initial Oxide Formation

Electron Transfer and Oxide Creation: The adsorbed oxygen atoms (O) readily accept electrons from iron atoms (Fe) on the surface, further oxidizing the iron. This forms a thin layer of iron (II) oxide (FeO) at the atomic level.

Fe + O → FeO

Step 3: Hydrolysis and the Rise of Chromium

Water Dissociation:

Water molecules (H₂O) from the environment come into play. At the atomic level, these water molecules dissociate near the positively charged surface due to electrostatic attraction. This dissociation breaks the H₂O molecule into a positively charged hydrogen ion (H⁺) and a negatively charged hydroxyl ion (OH⁻).

Chromium Takes Centre Stage:

Here’s where chromium shines. Due to its higher electronegativity compared to iron, chromium atoms (Cr) are more attracted to oxygen and hydroxyl ions.

Chromium Oxide and Hydroxide Formation:

Chromium atoms (Cr) readily react with oxygen atoms (O) and hydroxyl ions (OH⁻) to form chromium (III) oxide (Cr₂O₃) and chromium (III) hydroxide (Cr(OH)₃) at the atomic level. This chromium-rich layer starts forming on top of the initial iron oxide layer.

Cr + 3/2 O₂ → Cr₂O₃ (Chromium oxide formation)
Cr + 3OH⁻ → Cr(OH)₃ (Chromium hydroxide formation)

Chromium: The Key Player:

Chromium’s superior affinity for oxygen and hydroxyl ions, the stability of its oxides, and its amphoteric nature make it the star player in forming the protective passive film. Nickel and molybdenum play crucial supporting roles by enhancing film stability and offering localized corrosion resistance. This synergy between elements is what truly empowers Fe-Cr-Ni-Mo stainless steel to excel in acidic environments.

Here’s a deeper dive into the chemical properties that make Cr the key player, compared to nickel (Ni) and molybdenum (Mo):

High Affinity for Oxygen (O) and Hydroxyl (OH⁻):

Chromium boasts a higher electronegativity compared to iron (Fe), nickel (Ni), and molybdenum (Mo). This translates to a stronger attraction for oxygen and hydroxyl ions. As a result, chromium readily reacts with these species to form stable chromium oxide (Cr₂O₃) and chromium hydroxide (Cr(OH)₃) during the passivation process.

Greater Stability of Chromium Oxides:

Chromium oxide (Cr₂O₃) is thermodynamically more stable than iron oxide (FeO) or the corresponding oxides of nickel (NiO) and molybdenum (MoO₂, MoO₃). This stability ensures that the chromium-rich layer persists and doesn’t readily break down in the acidic environment. This stable layer acts as the foundation for the entire passive film.

Amphoteric Nature:

Chromium exhibits amphoteric behavior, meaning it can react with both acids and bases. This property allows chromium to react with hydroxyl ions (OH⁻) in the developing film, further promoting its incorporation and film growth.

In a slightly acidic environment (presence of H⁺ ions), chromium can dissolve to a limited extent as chromate or dichromate ions (CrO₄²⁻ or Cr₂O₇²⁻). This slight dissolution allows chromium to be more readily available for subsequent reactions with hydroxyl ions (OH⁻) as the environment becomes more basic.

As water dissociates near the positively charged metal surface, it provides the crucial hydroxyl ions (OH⁻). Chromium, due to its amphoteric nature, readily reacts with these OH⁻ ions to form chromium hydroxide (Cr(OH)₃), even if trace amounts of acidity persist. This reaction helps kickstart the incorporation of chromium into the growing oxide film.

Why Ni and Mo Play Supporting Roles

While not the main characters, nickel (Ni) and molybdenum (Mo) contribute significantly:

Role of Nickel (Ni):

Nickel enhances the film’s stability by going into a solid solution with chromium oxide (Cr₂O₃). Nickel (Ni) incorporates itself within the chromium oxide (Cr₂O₃) lattice structure through a process called solid solution formation. This occurs because the atomic radii of nickel and chromium are relatively close. Nickel atoms can substitute for chromium atoms in the Cr₂O₃ lattice without causing significant distortion. This “substitution” strengthens the overall structure of the film.

The incorporation of nickel atoms introduces a slight lattice strain within the chromium oxide. This strain acts like microscopic reinforcements, hindering the film’s ability to deform or crack under stress. Chromium oxide can have occasional vacancies within its crystal lattice. Nickel atoms filling these vacancies improve the film’s overall density and integrity, further reducing the risk of crack formation and enhancing its stability.

A very important note

Chromium itself wouldn’t achieve the same effect. While chromium can form its oxides, incorporating chromium into its lattice (Cr₂O₃) wouldn’t introduce the beneficial strain-hardening effect observed with nickel. The slight size difference between nickel and chromium is crucial for this strengthening mechanism.

Role of Molybdenum (Mo):

Molybdenum primarily concentrates at grain boundaries within the steel. Here, it forms molybdenum oxides (MoO₂ and MoO₃), which offer additional resistance to localized corrosion, particularly pitting caused by chloride ions.

How & why?

Molybdenum has a different atomic size and electronic configuration compared to iron (Fe) and chromium (Cr), the main constituents of the steel matrix. This difference in properties leads to molybdenum atoms exhibiting a stronger tendency to segregate towards grain boundaries during the solidification of the molten steel.

Molybdenum has a lower solid-state solubility in the steel matrix compared to iron and chromium. As the steel cools from its molten state, molybdenum tends to solidify and precipitate out of the matrix. Grain boundaries represent regions of higher energy within the steel’s crystal structure. Molybdenum atoms, due to their lower solubility in the matrix, are attracted to these higher energy zones to minimize the overall system’s energy. This preferential attraction leads to molybdenum enrichment at the grain boundaries.

The interplay of molybdenum’s chemical properties (different sizes and lower solubility) and the metallurgical nature of grain boundaries (higher energy regions) leads to the localized enrichment of molybdenum at these critical sites. This enrichment translates to the formation of molybdenum oxides, which offer additional protection against localized corrosion, especially pitting caused by chloride ions, by promoting passivation and chloride scavenging.

Step 4: Film Organisation – A Dynamic Process

The oxide film is not a static structure. At the atomic level, there’s constant rearrangement and reorganization as new chromium oxide and hydroxide molecules integrate, while some may detach and re-dissolve. This dynamic process helps the film achieve a more stable and optimal configuration.

The End Result: A Robust Oxide Film

Through this passivation process, a layered oxide film forms on the stainless-steel surface. The inner layer is primarily composed of chromium oxide (Cr₂O₃), offering a strong and compact barrier. The outer layer is enriched with chromium hydroxide (Cr(OH)₃) and may also incorporate nickel oxide (NiO) and molybdenum oxides (MoO₂ and MoO₃). This outer layer is more flexible and allows for self-healing if minor damage occurs.

The Role of Hydroxyl (OH⁻) Ions:

Hydroxyl ions (OH⁻) play a critical role in two ways:

  • Promoting Film Formation: They react with chromium to form chromium hydroxide, a key component of the outer layer. This layer readily incorporates other beneficial metal oxides like NiO and MoO₃.
  • Stabilizing the Film: The negative charge of OH⁻ ions electrostatically attracts positively charged metal cations (Cr³⁺, Ni²⁺, Mo⁴⁺) towards the outer layer, promoting film stability and integrity.

The Antagonist: Chloride Ions (Cl⁻)

While trace amounts of chloride ions might seem insignificant, they can disrupt the protective film. Chloride ions can:

  • Compete with Hydroxyl Ions: They compete with OH⁻ ions for bonding with chromium, leading to the formation of soluble chromium chlorides (CrCl₃). This depletes chromium from the film, weakening its corrosion resistance.
  • Increase Film Porosity: Chloride ions can penetrate the outer layer, increasing its porosity and making it more susceptible to further attack by the acidic environment.

Beyond the Usual Suspects: Other Potential Players:

While OH⁻ is the primary contributor to film formation, other species like sulfate (SO₄²⁻) or phosphate (PO₄³⁻) ions, present in some dilute acids, can also participate. They can co-precipitate with chromium, forming mixed metal oxides and enhancing film stability to some extent. However, their effectiveness depends on the specific acid composition and concentration.

The Takeaway:

The exceptional corrosion resistance of Fe-Cr-Ni-Mo stainless steel in dilute acidic environments with trace chlorides arises from the formation of a complex, self-healing passive oxide film. Chromium plays the starring role, forming a robust chromium oxide inner layer and contributing to the chromium hydroxide-rich outer layer. Nickel and molybdenum bolster the film’s stability and resistance to pitting corrosion. Hydroxyl ions are instrumental in film formation and stability. While chloride ions pose a threat, the intricate interplay between these elements ensures a remarkable degree of protection.

Design of Sub-Sea Pipelines

Written by Anup Kumar Dey in Pipeline

Subsea pipelines play a critical role in transporting oil and gas (hydrocarbon) from remote exploration and production sites to processing facilities and ultimately, consumers. They are essential components of the offshore oil and gas production process. With an increase in the energy demand, the need for reliable and efficient subsea pipeline solutions has also increased a lot. This is where companies dealing with Sebsea Pipelines come into play. In this article, we will briefly learn about the basics of Subsea Pipelines and their design stages.

What is a Sebsea Pipeline?

A subsea pipeline (also known as submarine pipeline), is the length of pipe that is laid on the seabed or below it inside a trench. They specifically transport oil, gas, or other fluids from subsea wells to onshore processing facilities or between various offshore facilities. However, they can also transfer potable water to different islands. The design of sub-sea pipelines is very challenging as they are subjected to harsh subsea environments, very high pressures, and corrosive fluids. These pipelines are typically made of steel and are designed to withstand the harsh conditions of the marine environment. Subsea pipelines are crucial for the transportation of hydrocarbons from offshore oil and gas fields to onshore processing facilities, contributing significantly to the global energy supply chain.

In general, the lines below 16 inches are laid inside a trench whereas the larger pipelines(above 16 inches) are laid on a seabed. However, various other parameters need to be considered.

Advantages and Disadvantages of Sub-Sea Pipelines

Subsea pipelines represent the lifelines of offshore oil and gas exploration and production, serving as critical arteries for the transportation of hydrocarbons from deep beneath the ocean floor to onshore facilities. The main advantages of sub-sea pipelines are:

  • Greater Reach: It can connect any length of pipe generally without any limitation.
  • Reduced Installation Time: The installation of subsea pipelines is very fast as compared to conventional pipeline installation.

However, sub-sea pipelines are costly. The installation, construction, and maintenance costs are very high. Also, building and maintaining subsea pipelines pose numerous challenges, including:

  • Corrosion and Erosion: The harsh marine environment can cause corrosion and erosion of pipeline surfaces over time, necessitating the use of protective coatings and cathodic protection systems to extend the lifespan of the pipelines.
  • Geological Hazards: Subsea pipelines must navigate through complex geological formations, including fault lines, submarine canyons, and seafloor irregularities, which can pose risks such as landslides and earthquakes.
  • Operational Risks: Operational challenges such as pipeline leaks, equipment failures, and marine vessel collisions can pose significant risks to the integrity of subsea pipelines, requiring robust monitoring and maintenance protocols.

Subsea pipelines can be installed at almost any depth of water. The water depths are classified as follows:

  • Ports or Harbors: Water depth less than 25 m.
  • Shallow Water: Water depth from 25 m up to 180 m.
  • Deep Water: Water Depth above 180 m up to 1000 m.
  • Ultra Deep Water: Water depth above 1000 m.

Subsea pipelines are subjected to various vertical and horizontal forces.

Design of Subsea Pipelines

Subsea pipelines are designed following certain steps as mentioned below in Fig. 1.

Fig. 1: Steps for Subsea Pipeline Design

Identifying Requirements to Transport Product

This is the first step in sub-sea pipeline design. All the process requirements (like flow rate, temperature, pressure, etc) are identified in this stage. All the field surveys (such as bathymetric surveys, geotechnical surveys, tidal wave measurements, etc) must be carried out during this stage. These surveys are required to understand the nature of the sea bed and sea conditions that will be used during the detailed design process.

Identification of Codes and Standards for Sub-sea Pipeline Systems

There are various codes and standards that can be applicable to each subsea pipeline system design. So, in this stage, all such codes and standards are finalized. Some of the most common codes and standards for subsea pipeline systems are:

  • DNV-OS-F101: Submarine pipeline systems
  • DNV-ST-F101: Code compliance stresses
  • DNV-RP-F109: On-bottom stability of submarine pipelines
  • API-RP-1111: Design, Construction, and Operation of Offshore Pipelines.
  • ASME B31.3: Process Piping

Pipeline Internal Diameter Calculation

Hydraulic analysis is performed to find out the required pipeline internal diameters satisfying the governing code and standard requirements. The selected pipeline diameter should be adequate to deliver the required flow rate and pressure.

Deciding Pipeline Material

In this stage, a techno-commercial study is performed to find out the optimum material from the proposed materials. The selected material must be suitable for the given design pressure and economics.

Pipeline Wall Thickness Calculation

The minimum required pipeline wall thickness is calculated considering various parameters such as:

  • External and internal design pressure
  • Pipeline material
  • Pipeline Diameters
  • Buckling Consideration

Pipeline Route Selection

Before laying the pipeline, engineers conduct extensive surveys of the seabed to determine the most suitable route, taking into account factors such as water depth, seabed topography, and environmental concerns. Based on the bathymetric survey and other site investigation work, the pipeline route is selected to minimize unsupported pipeline length. The seabed in most cases will not be smooth. So, the route must be selected in such a way as to avoid long unsupported pipeline lengths.

On-Bottom Stability

In this stage, all the vertical and horizontal forces that act on a pipeline are calculated. It is ensured that the pipeline will be stable under the combined effect of all loads. All forces including sea waves, uplift buoyancy force, loads due to weight, etc are considered and checked. In situations when the pipeline is found to be unstable, additional stabilizing systems such as concrete ballast, rock dumping, concrete mattress, etc are introduced to make the subsea pipeline stable.

Pipeline Stress Analysis

In this stage, the complete pipeline configuration is modeled in available pipeline stress analysis software such as Caesar II or AutoPipe to find if the system is safe from all stress considerations. The results generated by these software programs are sufficient to judge the system and decide whether any modification is required or whether the system can be accepted as it is.

Pipeline Installation Analysis

This is the last stage of subsea pipeline design. In this stage, the stresses generated on the pipeline system during installation are investigated considering the installation methodology to be employed. Specialist professionals are contacted for this analysis purpose.

Construction and Installation of Subsea Pipelines

Subsea pipelines are engineering marvels, meticulously designed and constructed to withstand the extreme conditions of the marine environment. The construction process typically involves several key steps:

Pipeline Fabrication:

The pipeline segments are manufactured onshore using high-strength steel, with coatings applied to protect against corrosion and abrasion. These segments are then transported to the offshore installation site.

Installation:

Installation methods vary depending on factors such as water depth and seabed conditions. Common techniques include S-lay, J-lay, and reel-lay methods, each offering unique advantages depending on the project requirements.

Subsea Infrastructure:

In addition to the pipelines themselves, subsea infrastructure such as risers, manifolds, and subsea tie-backs are installed to facilitate the transportation and processing of hydrocarbons.

Subsea pipelines play a vital role in the global energy supply chain. It enables the development of offshore oil and gas fields that would otherwise be uneconomical to exploit, unlocking new sources of energy to meet growing global demand.

What are Pipeline Block Valves? Design of Pipeline Block Valve Stations

Written by Anup Kumar Dey in Pipeline

Pipeline block valves are one of the critical components in a pipeline network that ensures the proper management of liquids and gases that it transports. These valves play a crucial role in regulating the flow, controlling pressure, and facilitating maintenance activities along the pipeline route. In this comprehensive guide, we’ll delve into the world of pipeline block valves, exploring their function, types, importance, maintenance, and safety considerations.

What is a Pipeline Block Valve?

A pipeline block valve is a type of valve installed at strategic points along a pipeline to control the flow of fluid or gas. Unlike other valves that regulate flow continuously, block valves are primarily designed to completely stop the flow when necessary. They serve as barriers, isolating sections of the pipeline to facilitate maintenance, repair, or in emergencies such as leaks or ruptures.

How Do Pipeline Block Valves Work?

Pipeline block valves operate on the principle of obstruction. When activated, these valves shut off the flow of fluid or gas by closing a barrier within the pipeline. This barrier, often a gate, ball, or butterfly valve, blocks the passage of the substance through the pipeline. Block valves are typically actuated either manually, through mechanical means, or automatically, using hydraulic or pneumatic systems. The choice of actuation method depends on factors such as the size of the pipeline, the nature of the transported substance, and operational requirements.

Types of Pipeline Block Valves

Several valves can be used as a pipeline block valve. Some of the notable ones are:

  • Gate Valves: Gate valves employ a wedge-shaped gate to control the flow. They are suitable for applications requiring full flow or complete shut-off.
  • Ball Valves: Ball valves utilize a spherical closure element to regulate flow. They offer quick operation and tight sealing, making them ideal for high-pressure applications.
  • Butterfly Valves: Butterfly valves feature a disc-shaped closure element that rotates to control flow. They are compact, lightweight, and well-suited for large-diameter pipelines.
  • Check Valves: While not traditionally considered block valves, check valves prevent reverse flow in pipelines, adding a layer of protection against unintended flow.

What is a Pipeline Block Valve Station?

A pipeline block valve station, also known simply as a block valve station, is a critical component of a pipeline system designed to control the flow of fluids or gases along the pipeline route. It typically consists of a series of block valves strategically placed at intervals along the pipeline to isolate sections of the pipeline when necessary.

The primary function of a pipeline block valve station is to provide a means for shutting off the flow of fluid or gas in case of emergencies, maintenance activities, or operational adjustments. By closing specific block valves within the station, operators can isolate a segment of the pipeline to contain leaks, perform repairs, or redirect flow as needed.

Key features of a pipeline block valve station may include:

  • Multiple Block Valves: The station comprises several block valves spaced at regular intervals along the pipeline route. These valves are typically equipped with actuators for manual or automatic operation.
  • Access and Control Infrastructure: Infrastructure such as access roads, platforms, and control panels are provided to facilitate operation and maintenance activities at the station.
  • Monitoring and Control Systems: Block valve stations may incorporate monitoring and control systems to enable remote operation, real-time monitoring of pipeline conditions, and automated responses to anomalies.
  • Safety Features: Safety measures such as pressure relief devices, emergency shutdown systems, and environmental containment measures may be incorporated into the design to mitigate risks associated with pipeline operations.
  • Regulatory Compliance: Block valve stations must adhere to relevant industry regulations, standards, and guidelines governing the design, installation, operation, and maintenance of pipeline infrastructure, including block valves.

Importance of Pipeline Block Valves

The significance of pipeline block valves cannot be overstated, particularly in industries such as oil and gas, petrochemicals, and water distribution. Here’s why these valves are indispensable:

  • Safety: Pipeline block valves serve as critical safety measures, allowing operators to isolate sections of the pipeline in case of emergencies such as leaks, ruptures, or equipment failures.
  • Operational Efficiency: By enabling targeted shutdowns for maintenance or repairs, block valves minimize downtime and disruption to operations, thereby enhancing overall efficiency.
  • Environmental Protection: Rapid response to pipeline incidents facilitated by block valves helps mitigate the environmental impact of spills or leaks, safeguarding ecosystems and communities.
  • Asset Protection: By controlling pressure surges and regulating flow, block valves help protect pipeline infrastructure from damage, extending its service life and reducing maintenance costs.
  • Regulatory Compliance: Compliance with industry regulations and standards often mandates the installation and proper maintenance of pipeline block valves to ensure the safety and integrity of the system.

Installation and Maintenance

Proper installation and regular maintenance are essential for ensuring the optimal performance of pipeline block valves. Key considerations include:

  • Location: Block valves should be strategically placed along the pipeline route, considering factors such as accessibility, terrain, and proximity to sensitive areas.
  • Inspection: Routine inspections should be conducted to check for signs of wear, corrosion, or leaks. Any anomalies should be promptly addressed to prevent potential failures.
  • Testing: Periodic testing of block valves, including functional tests and leak tests, is crucial to verify their proper operation and integrity.
  • Lubrication: Moving parts of block valves should be adequately lubricated to minimize friction and ensure smooth operation.
  • Training: Operators and maintenance personnel should receive proper training on the operation, maintenance, and emergency procedures related to pipeline block valves.

Safety Considerations

While pipeline block valves enhance safety, certain precautions must be observed to mitigate risks effectively:

  • Emergency Response: Clear protocols and procedures should be established for responding to pipeline incidents, including the activation of block valves and coordination with emergency responders.
  • Monitoring Systems: Implementing remote monitoring and control systems can provide real-time visibility into pipeline conditions, allowing for proactive intervention in case of abnormalities.
  • Pressure Management: Proper pressure management strategies, including pressure relief devices and surge control measures, are essential for preventing overpressure situations that could compromise block valve integrity.
  • Environmental Protection: Containment and mitigation measures should be in place to minimize the environmental impact of potential spills or leaks occurring during block valve operations.

Common Problems Associated with Pipeline Block Valves

The most common problems associated with pipeline block valves are

  • Leakage: Over time, seals and gaskets can degrade, leading to leakage around the valve.
  • Corrosion: Exposure to corrosive substances or environmental factors can cause the deterioration of valve components, compromising their integrity.
  • Obstruction: Debris or buildup within the valve can impede proper operation, leading to flow restriction or blockage.
  • Mechanical Failure: Wear and tear on moving parts, such as stems or discs, can result in malfunction or failure of the valve to open or close properly.
  • Sticking or Binding: Improper lubrication or accumulation of debris can cause valves to stick or bind, affecting their responsiveness.

Design Guidelines for Pipeline Block Valve Stations

  • The requirement of a block valve station is decided either by Quantitative risk analysis or by assessing in line with ASME B31.8 section 846.1.1.
  • The number of BVS must be limited to a minimum.
  • A BVS, including above-ground pipework, shall be designed according to the same code as the pipeline (B31.4 or B31.8). The piping beyond the bypass valves may be however designed to B31.3.
  • The location of each BVS is determined by carrying out a study for each pipeline.
  • For pipelines designed with a hoop stress design factor higher than 0.6, the block valve stations shall be designed with a design factor of 0.6, to increase safety margins.
  • For pipelines designed with a factor of less than 0.6, the block valve stations shall be designed with a factor equal to that of the pipeline.
  • The design pressure of the BVS shall be equal to that of the pipeline.
  • The maximum and minimum design temperature of the buried pipeline within the BVS shall be the same as for the buried pipeline outside the BVS. For above-ground pipework within the BVS, the design temperatures shall be the same as for the pipeline pig traps.
  • For piping in intermittent service acceptable maximum velocities are 8 m/s in the case of oil and 40 m/s in the case of gas.

Components of a Pipeline Block Valve Station

The main components of a pipeline block valve station are:

  • Pipework that includes the main pipeline, bypass line, drain line, and flare/vent lines.
  • Valves like Mainline isolation valve, bypass valve, throttle valve, relief valve, etc.
  • Branch connections.
  • Pressure Indicator.
  • Pig Signallers.
  • Pipe Supports, etc.

Refer to Fig. 1 and 2 below which explain a typical pipeline block valve system layout for liquid and gas pipelines respectively.

Pipeline Block Valve Station Layout for Liquid Pipelines
Fig. 1: Pipeline Block Valve Station Layout for Liquid Pipelines
Pipeline Block Valve Station for Gas Pipelines
Fig. 2: Pipeline Block Valve Station for Gas Pipelines

Pipeline block valves are indispensable components of pipeline infrastructure, playing a crucial role in ensuring the safety, efficiency, and integrity of fluid and gas transportation systems. Understanding their function, types, importance, maintenance, and safety considerations is essential for operators, engineers, and stakeholders involved in pipeline operations. By adhering to best practices in installation, maintenance, and safety protocols, we can harness the full potential of pipeline block valves to support sustainable and reliable energy transportation worldwide.

Pressure Safety Valve Sizing | Relief Sizing Calculation

Written by Rakesh Sutrave in Process

The purpose of pressure safety valves is to shield machinery from extreme overpressure. In addition to offering the necessary protection, appropriately sized relief valves can help prevent problems caused by high flow rates, such as undersized discharge pipes and effluent handling systems, potential valve damage, decreased performance, and increased expenses. Increased vessel pressure can arise from a variety of conditions, and each scenario may call for a different valve size. Finding the most modest sizing usually requires doing several case studies. Typical examples include the following:

  • a run-away reaction,
  • a loss of cooling,
  • thermal expansion of a liquid, or
  • an external fire.

Under each of these conditions, the pressure will rise until it reaches a pre-set relief pressure, after which the relief pressure valve is actuated and the pressure will drop following the turnaround time.

Design and Sizing Terms

MAWP: The maximum allowable working pressure (MAWP) is the main parameter used to describe a pressure vessel. The maximum acceptable pressure at a vessel’s top at a certain temperature is known as the MAWP.

MAWT: The maximum acceptable working temperature (MAWT) is the name given to this specified temperature. The MAWT is significant because, due to the metal’s decreased strength, the MAWP drops as temperature rises. In addition, embrittlement could be a problem at extremely low operating temperatures (about –20°F).

Set Pressure: A relief device’s set pressure is the value of pressure at which it functions. Small quantities of leakage begin to occur with spring-operated relief valves at 92–92.5 percent of the set pressure.

Over Pressure: The pressure rise over the set pressure of a relief device is known as overpressure, and it is often stated as a proportion of the set pressure. Pop-acting relief valves do not open fully (to 100% lift) right away. It takes enough overpressure to get the maximum lift. The entire rated capacity of ASME-certified relief valves must be reached at 10% or less over-pressure. The National Board of Boiler and Pressure Vessel Inspectors has code-certified relief valves. Conducting flow testing under ASME code-specified conditions is part of the code certification process.

The degree of pressure increment above the MAWP typically represented as a percentage of the MAWP, is known as pressure vessel accumulation. Both the buildup and the overpressure are equivalent when the pressure relief device is at the MAWP.

Back Pressure: The pressure below the relief device is known as back pressure. It consists of the built-up backpressure from the fluid discharge through the relief device down the subsequent piping and/or treatment system, as well as the continuous superimposed backpressure.

Relief Device Sizing:

The most popular guide for sizing relief devices in the chemical manufacturing sectors is API 520 Part 1 (3), the American Petroleum Institute’s Guideline Procedure for Sizing, Selection, and Installation of Pressure-Relieving Systems in Refineries.

Determining the necessary relief area for the relief device is the goal of the relief sizing calculation. The specific design challenges and special factors that are specific to each installation of a relief device will affect the relief sizing estimates. To find these problems, the steps listed in the flowchart shown in Figure 2 need to be followed. This article outlines a general sizing process that only addresses sizing calculations for standard spring-operated devices in liquid and gas (vapor) service.

Pressure Vessel vs Relief Valve as per ASME
Fig. 1: Pressure Vessel vs Relief Valve as per ASME

Sizing for Liquid service:

The most popular guide for sizing relief devices in the chemical process industries is API 520 Part 1 (3), the American Petroleum Institute’s Suggested Procedure for Sizing, Selection, and Installation of Pressure-Relieving Systems in Refineries.

Finding the necessary relief area for the relief device is the aim of the relief sizing calculation. The specific design challenges and special factors specific to each installation of a relief device will affect the relief sizing estimates. This article outlines a general sizing process that only addresses sizing calculations for standard spring-operated devices in liquid and gas (vapor) service. For liquid service, the sizing calculation is based on the fundamental equation for liquid discharge through an orifice.

PSV Sizing Equations for Liquid Services
Fig. 2: PSV Sizing Equations for Liquid Services

Where

  • u is the average discharge velocity of the fluid through the relief orifice (distance/time);
  • Kd is the effective discharge coefficient (unitless);
  • gc is the gravitational constant (distance-mass/force-time2);
  • Q is the volumetric flow of liquid;
  • A is the Orifice area;
  • ∆P is the pressure drop across the orifice (force/area); and
  • Þ is the density of the fluid (mass/volume).

The unitless discharge coefficient, Kd, is normally provided by the valve manufacturer. It can also be obtained from the ASME National Board of Boiler and Pressure Vessel Inspectors for code-certified devices. For preliminary sizing, a value of Kd = 0.65 is assumed.

Equations 1–3 model liquid discharge through an orifice with fully turbulent flow. Equation 3 must be adjusted for the viscosity of the fluid; a fluid with a higher viscosity requires a larger orifice. Equation 3 must also be adjusted for back- pressure if a balanced-bellows relief valve is selected. Incorporating these adjustments into Eq. 3 results in the equation 4 in Fig. 2:

In Equation 4,

  • Kw is the adjustment factor for backpressure (unitless); Kw can be determined from Figure 3.
  • Kv is Kv is the unitless viscosity correction factor and can be determined from Figure 3.
  • G is the specific gravity of the liquid referenced to water at 70°F, which is equal to Þ / Þref;
  • P1 is the upstream relieving pressure (gage pressure), which is the set pressure plus allowable overpressure.
  • P2 is the total back pressure (gauge pressure).

Viscosity adjustment is not required for Reynolds numbers higher than 16,000 (i.e., Kv = 1.0). However, the relief area needs to be specified to compute the Reynolds number. It can be necessary to solve Eq. 4 by making mistakes. Determine the relief area first, assuming Kv=1.0, and then the Reynolds number.

Chart for determining Kw and Kv
Fig. 3: Chart for determining Kw and Kv

The Reynolds number, on the other hand, will typically be far higher than 16,000. On the other hand, if the value of the Reynolds number is less than 16,000, compute a new relief using Figure 3 to ascertain a new viscosity correction factor.

Repeat this procedure until the solution converges on a Reynolds number.

Usually, Kw and Kv values are obtained from the manufacturer, but for preliminary sizing, we can determine by Figure 3.

Liquid Sizing Example

According to a study, a process vessel’s standard spring-operated relief valve has to provide 300 gpm of water flow to function. Let’s say there is a predetermined pressure of 100 psig and an overpressure of 10%. Backpressure adjustment is not required for a standard relief valve (Kw = 1.0). 300 gpm is the volumetric discharge rate (Q) through the relief valve. There is no information regarding the discharge coefficient, Kd; as a rough approximation, use Kd = 0.65. It is unknown what Reynolds number passes through the relief valve. At 300 gpm volumetric discharge rate, though, the Reynolds number is most likely higher than 16, 000. Thus, assume Kv = 1.0. The liquid is water at 70°F, so G = (Þ / Þref) = 1.0.

Sizing for Gas Service

Choked flow via the relief orifice is envisaged for standard spring-operated relief devices in gas or vapor service. The following equation represents choked flow via an orifice:

PSV Sizing Equations for Gas Services
Fig. 4: PSV Sizing Equations for Gas Services

Where

  • P1 is the upstream relieving pressure for vapor service (absolute pressure);
  •  Kd is the discharge coefficient (unitless); 
  • W is the mass flow rate (mass/time).
  • Ƴ is the gas/vapor capacity ratio (Unitless).
  • The gravitational constant, or gc (mass/force/time2),
  • M is the gas’s molecular weight (mass/mol).
  • T is the absolute temperature (degrees),
  • and Rg is the ideal gas constant (pressure-volume/mol-deg.).

The word C, which is a function of simply the heat capacity ratio, is defined as follows to make the calculation simpler:

To compensate for nonideal gas behavior, equation 5 is adjusted by adding the compressibility factor, z, and the back-pressure correction, Kb. Equation 5 can be calculated for the relief area with the following modifications:

Typically, Kd and Kb are supplied by the valve maker. A discharge coefficient, Kd, of 0.975 is utilized for initial sizing. Figure 5 can be used to calculate the backpressure will correction factor, Kb, regardless of whether the relief device is a balanced-bellows valve or a traditional spring-operated device. The equation in Table 2 provided the data for Figure 5, while the equation in Table 3 provided the data for Figure 6.

In Figure 6, Kb is determined by the back pressure to set pressure ratio. As seen in Figure 5, Kb depends on the ratio of backpressure to Pmax, the highest permissible relieving pressure, which is established by the permissible accumulation: where PMAWP and Pmax are expressed in units of gauge pressure. The backpressure and Pmax need to be transformed to pressure in absolute units using an equation like this to use Figure 5.

Chart for Calculating Kb
Fig. 5: Chart for Calculating Kb
Table for calculating Kb
Fig. 6: Table for Calculating Kb

Gas Sizing Example:

The size of a spring-operated relief device needs to match the ideal hydrocarbon vapor pressure vessel. The mass discharge rate, W, in the controlling scenario, is 50.0 kg/s. Assume that the process temperature is 473 K, the vessel PMAWP is 8 barg, there is no superimposed backpressure, and the built-up backpressure is equal to 10% of the set pressure. After reviewing typical operating pressures, it is decided to employ a fixed pressure of 7 barg, or Ps. The vapor is perfect, with z = 1.0, and has a molecular weight in 100. Its heat capacity ratio is 1.3. Since this is an unfired pressure vessel, the maximum permissible relieving pressure in gauge units, derived from Equation 8, is:

References:

  1. Kelly, B. D., “What Pressure Relief Really Means,” Chem. Eng. Progress, 106 (9), pp. 25–30 (Sept. 2010).
  2. Crowl, D. A., and J. F. Louvar, “Relief Sizing,” Chapter 10
  3. in “Chemical Process Safety: Fundamentals with Applications,” 3rd ed., Prentice Hall, Englewood Cliffs, NJ, pp. 459–503 (May 2012).
  4. American Petroleum Institute, “Recommended Practice for the Sizing, Selection, and Installation of Pressure-Relieving Systems in Refineries,” API RP 520, Part 1, 8th ed., API, Washington, DC (2008).
  5. Fisher, H. G., et al., “Emergency Relief System Design Using DIERS Technology,” American Institute of Chemical Engineers, New York, NY (1992).
  6. Anderson Greenwood and Crosby, Technical Service Manual, www.andersongreenwood.com/literature.asp (Aug. 2013).
  7. American Society of Mechanical Engineers, “Boiler and Pressure Vessel Code,” Section VIII, “Rules for Construction of Pressure Vessels,” ASME, New York, NY (2013).

ADDITIONAL RESOURCES

  • American Institute of Chemical Engineers, “Guidelines for Pres- sure Relief and Effluent Handling Systems,” Center for Chemi- cal Process Safety (CCPS), New York, NY (1998).
  • Hellemans, M., “The Safety Relief Valve Handbook,” Elsevier, Oxford, U.K. (2009).
  • Malek, M., “Pressure Relief Devices,” Mc-Graw-Hill, New York, NY (2005).

What’s New in Caesar II-Version 14?

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

Some of you must be aware that Hexagon has released their new version of stress analysis software, Caesar II Version 14 recently. The latest software version has truly extended its capabilities by incorporating many changes based on user feedback from the Caesar II user community. The much-awaited Hydrogen piping and pipeline code (ASME B31.12) is included in Version 14 of Caesar II software. In this article, we will highlight some of the new capabilities that you will find when you install Caesar II Version 14 on your PC/laptop. So, let’s start with the changes in codes and standards.

Caesar II Version 14

Newly Added Codes and Standards

As already mentioned, support for ASME B31.12-2019 has already been added to the new software. Additionally, most of the codes are updated to have their latest available editions. Let’s have a look at all the code changes below:

ASME B31.12 – 2019 Hydrogen Piping and Pipelines, including Part IP Industrial Piping and Part PL Pipelines. The allowable stress auxiliary data tab has been updated to support this new code addition. The configuration editor is updated to use alternative rules for stress range evaluation for supporting ASME B31.12 Appendix-B.

ASME B31.3: Process Piping– 2022 edition: This means they must have included the stress range reduction factor calculation based on the recent changes in ASME B31.3-2022. Click here to learn all the major changes in ASME B31.3-2022 as compared to its earlier edition.

  • ASME B31.1: Power Piping – 2022 edition.
  • ASME B31.4: Pipeline Transportation Systems for Liquids and Slurries- 2022 edition.
  • ASME B31.8: Gas Transmission and Distribution Piping Systems- 2022 edition
  • ASME B31.5: Refrigeration Piping and Heat Transfer Components- 2022 edition

API 617: Centrifugal Compressors- 2022 edition (9th edition) for equipment analysis. Now users can use an allowable load multiplier greater than 2.0 with manufacturer approval.

ASCE 7 – 2022 edition for wind and seismic loads. The Seismic Wizard in piping input has been updated to support ASCE 7-22 and IBC 2021. Additionally, the Wind Loads Tab (Static Analysis – Load Case Editor Dialog) and the DLF/Spectrum Generator are also updated to support ASCE 7-22 and IBC 2021.

  • EN-13480-3:2017/A5:2022 (Metallic industrial piping – Part 3: Design and calculation).
  • IBC – 2021 edition for wind and seismic loads.

Updates in Material and Content Database

As the major code changes in Caesar II Version 14 are already stated, let’s learn the other changes that the software release in 2024 will provide:

  • Caesar II Version 14 is further enriched with the following additions:
  • Added 119 material records for B31.12-2019 into the material database. The physical property data is taken from ASME B31.3-2018 and ASME BPVC Section II Part D-2021. While the allowable stress data is taken from ASME B31.12-2019
  • Added fifth working range quadruple springs to the ANVIL hanger tables. Also added spring sizes 000 and 00 for the B-268 springs.
  • Added the fourth and fifth size springs to the PSSI Group hanger tables.
  • Added hanger tables for Rilco Manufacturing pipe supports.

Improvements in Static and Dynamic Analysis

The software version 14 has enhanced its capabilities to consider the thermal bowing load when defining a Thermal Bowing Delta Temperature and define an operating temperature that is the same as or close to the Ambient Temperature. A new technical discussion for thermal bowing is also added to help explain the condition thoroughly.

The program has updated the Dynamic Analysis calculations for the B31.4, B31.8, B31.4 Chapter IX & Chapter XI, and B31.8 Chapter VIII piping codes with multiple offshore and transportation code stresses. The changes have a significant impact on the time history and spectrum analysis.

Caesar II Version 14 now supports the MDMT calculations devised in the ASME B31.3-2022 edition.

Other Improvements

Other significant changes to Caesar II Version 14 as compared to Caesar II Version 13 are:

  • The SIF Multiplier for Sustained Stress Index option in the Configuration Editor is added for Piping codes that use ASME B31J.
  • The equipment analysis using NEMA SM23 for Steam turbines has been updated to allow the Allowable Load Multiplier to be greater than 2.0 with manufacturer approval.
  • The output report for for primary stress types (example: SUS, OCC, and HYD) now displays sustained intensification factors (SSI) for metallic piping codes.
  • The option for creating a combined PDF output report has been activated in the Output Viewer Wizard of the Static Output Processor.
  • The length for displaying your company name on output reports has been increased by 30 more characters.
  • A new offline version of help has been added for installations that do not have internet access to the online help. Offline help now opens in your default web browser.

So, from the above discussion, you can easily understand that Version 14 of Caesar II software comes with many advancements to help users perform their analysis with more accuracy following all the latest developments in codes and standards. It also fixed most of the issues that users have faced in Caesar II version 13. Some of the notable fixes made in Caesar II version 14 are:

  • The implementation of ISO 14692-2005 when a stress type has no envelope has been changed. The stress reports in the latest Caesar II software program will now display the maximum between hoop stress and longitudinal stress instead of always displaying the hoop stress.
  • Fixed the issue of requiring all flange yield strength field inputs (SY1 through SY9 when temperatures T1 through T9 were not defined) in the NC-3558.3 flange leakage checking.
  • The incorrect EN 10269:1999 material number for X2CrNiMo17-12-2 has been fixed.
  • The incorrect gasket diameters for the ASME-2009 and ASME-2009M – Class 900 databases have been updated with correct values.
  • Fixed the error of the Type list for B31J SIFs & Tees sometimes that did not display correctly.
  • Fixed the issue of B31J surface nodes not renumbering when renumbering all nodes.
  • Fixed Caesar ii import issues from Smart 3D/ SmartPlant Review .vue files, CADWorx .dwg file.

References and Further Studies:

https://docs.hexagonali.com/r/en-US/CAESAR-II-Quick-Reference/Version-14/328888

Pipeline Engineering Interview Questions

Written by Anup Kumar Dey in Pipeline

The following section will list some interview questions asked in the different interviews for a Pipeline Engineer Position. Readers are requested to provide the answers in the comment section which I will add in the main section in due course.

  1. Explain the basis of pipeline hydraulics and how will differentiate the gas and crude oil pipeline that is which method will perform to do the calculation.
  2. What are all the softwares available in the market to perform pipeline hydraulics and how will you check the input and output?
  3. What are the criteria for route selection of gas and crude oil pipelines?
  4. For the sloped pipeline, how to fill the water during the hydrostatic test and why?
  5. Explain the hydrostatic test pressure with respect to ASME B 31.8/31.4. How do they arrive the 90% of SMYS and what is the basis?
  6. Explain about one pipeline project lifecycle, starting from concept, FEED, Detail Design, and construction (Sequence).
  7. What is the difference between PSL-1 and PSL-2, what are all the tests involved during manufacturing?
  8. What is the procedure/sequence of linepipe manufacturing?
  9. What % of line pipe is radiographically tested during manufacturing?
  10. Spiral welding can be used in oil and gas, if No, why?
  11. Wadi crossing types and construction methods.
  12. Isolation joints internal and external coating requirements and temperature ranges.
  13. Draw and explain the pig launcher and receiver sequence.
  14. Pipeline Hydrotest procedure.
  15. What are the steps involved in pre-commissioning of the pipeline?
  16. Steps involved in pipeline construction.
  17. Distance between pipelines in the same trench and separate trench.
  18. What are the disadvantages of the pipelines in the same trench?
  19. Distance between the OHL line and the pipeline.
  20. GRE pipelines – explain the advantages and disadvantages compared to carbon steel pipelines.
  1. Specify Internal and external coating types with temperature limitations.
  2. What is the reason for choosing the DSS pipeline with respect to fluid properties?
  3. What are all the testing requirements for SOUR service pipeline items?
  4. What is PWHT and what is the limitation of thickness with respect to international codes?
  5. What is the philosophy of Pipeline supporting and anchor points for looped lines?
  6. What is Cathodic Protection? What are the Anodic materials used in the pipeline CP systems?
  7. What are the calculations performed during Hot tap design?
  8. Draw a Block Valve Station for gas and crude oil pipelines separately.
  9. What is the MPT requirement for Golden Joints?
  10. Explain the GRE wall thickness calculation basis and steps.
  11. Explain DPE and SPE on the ball valve.
  12. For high sour service, how you will provide grease point and sealant injection?
  13. During PE lining Wall Thickness calculation, what are the important factors you considered?
  14. During PE lining pulling how many bends are allowed?
  15. 3LPE /3LPP temperature minimum and maximum.
  16. Explain uni-directional and bi-directional pig traps.
  17. How you will consider corrosion allowance in pipeline systems?
  18. Explain upheaval bucking and how to avoid it.
  19. Briefly explain the pipeline routing considerations for Greenfield and Brownfield: Start with design and end with commissioning.
  20. Briefly explain the gauging.
  1. What is the double piston effect on pipeline ball valves?
  2. Explain upheaval buckling and its calculation methodology.
  3. What are Location classes with respect to ASME B 31.8 and ASME B31.4?
  4. Explain road crossing calculation methodology.
  5. Explain the Isolation Joint working principle.
  6. Specify the Types of pigs and their applications.
  7. What HIPPS valves? Explain about SIL level.
  8. Difference between transition and pup piece.
  9. What are all the required parameters for hydraulic analysis? As a pipeline engineer, what are the inputs needed to perform hydraulic analysis?
  10. What is your understanding of Environmental Impact Assessment (EIA)?
  11. What are the different types of tests involved in GRE pipes?
  12. Types of pigs and usage. Length of the intelligent pigs and MFL tools.
  13. Explain cathodic protection and Types of cathodic protection – in general.
  14. As a pipeline engineer, what do you know about line sizing?
  15. What is pipeline equivalent stress? What are all the stresses generated in a pipeline?
  16. How bending radius will affect the Pipeline Wall Thickness Calculation?
  17. What are the proximity distances and no. of buildings according to the location class?
  18. Where are Isolation joints to be installed and why? In IJ above 50 bar, what is the precaution?
  19. Draw the pig trap and explain pigging the procedure.
  20. Explain about CMA fittings and location, why?
  1. Compare a BVS requirement with EIA.
  2. What are the differences between restrained and un-restrained pipelines?
  3. What are the criteria for expansion loops for un-restrained pipelines? During A/G pipeline design how expansion loops will be fixed?
  4. What are the types of supports used for pig traps and why?
  5. Tell about allowable displacement values and if exceed the limit what are the other considerations to be taken care of to have a flexible pipeline system during design.
  6. What is Carbon Equivalent (CE) for line pipe and split tees? If two different CE pipes are needed to weld, which CE value has to be considered for qualification?
  7. DWTT and CVN tests – Explain.
  8. Explain the minimum branch sizes on pipelines.
  9. Golden weld joints – explain what tests need to be performed for golden joints.
  10. External coating types and temperature range.
  11. Velocity accepted during the design for liquids and gas?
  12. During End closure design what are the safety devices we have to consider?
  13. During the design of pipeline design life, what are the factors to be considered?
  14. PWHT requirement on the pipelines.
  15. How you will protect your pipeline and flowline: explain from the well to manifold and manifold to the station.
  16. Explain the pipeline design of the high temperature and pressure.
  17. What are the major differences between ASME B31.4 and ASME B31.8?
  18. A pipeline carries a fluid having a temperature of 250 Degrees C. Which ASME code will be used to design that pipeline?