Recent Posts

Comprehensive Piping Stress Analysis (Caesar II) Online Course (35+ hours)

Whatispiping Team, in association with Everyeng, is conducting an online pre-recorded Comprehensive Piping Stress Analysis Certificate course to help mechanical and piping engineers. Along with the regular content that the participants will be learning, there will be a dedicated 2-hour doubt-clearing session (/question-answer session) with the mentor.

Contents of Online Piping Stress Analysis with Caesar II Course

The program will be delivered using the most widely used pipe stress analysis software program, Caesar II. The full course is divided into 4 parts.

  • Part A will describe the basic requirements of pipe stress analysis and will help the participants to be prepared for the application of the software package.
  • Part B will describe all the basic static analysis methods that every pipe stress stress engineer must know.
  • Part C will give some understanding of dynamic analysis modules available in Caesar II; and
  • Part D will explain all other relevant details that will prepare a basic pipe stress engineer to become an advanced user. Additional modules will be added in this section as and when ready.
Comprehensive Piping Stress Analysis Online Course

In its present form, the full course will roughly cover the following details:

Part A: Basics of Pipe Stress Analysis

  • What is Pipe Stress Analysis?
  • Stress Critical Line List Preparation with Practical Case Study
  • Inputs Required for Pipe Stress Analysis
  • Basics of ASME B31 3 for a Piping Stress Engineer
    • ASME B31.3 Scopes and Exclusions
    • Why stress is generated in a piping system
    • Types of Pipe Stresses
    • Pipe Thickness Calculation
    • Reinforcement Requirements
    • ASME B31.3 Code Equations and Allowable
  • Introduction to Pipe Supports
    • Role of Pipe Supports in Piping Design
    • Types of Pipe Supports
    • List of Pipe Supports
    • Pipe Support Span
    • How to Support a Pipe?
    • Pipe Support Optimization Rules
    • Pipe Support Standard
    • Support Engineering Considerations
  • What is a Piping Isometric?
  • What is an Expansion Loop?
  • Bonus Lecture: Introduction to Pipe Stress
  • Bonus Lecture: Pressure Stresses in Piping

Part-B: Static Analysis in Caesar II

  • Introduction to Caesar II
  • Getting Started in Caesar II
  • Stress Analysis of Pump Piping System
  • Creating Load Cases
  • Wind and Seismic Analysis
  • Generating Stress Analysis Reports
  • Editing Stress Analysis Model
  • Spring Hanger Selection and Design in Caesar II
    • Introduction
    • Types of Spring Hangers
    • Components of a Spring Hanger
    • Selection of Variable and Constant Spring hangers
    • Case Study of Spring Hanger Design and Selection
    • Certain Salient Points
  • Flange Leakage Analysis in Caesar II
    • Introduction
    • Types of Flange Leakage Analysis and Background Theory
    • Case Study-Pressure Equivalent Analysis
    • Case Study-NC Method
    • Case Study-ASME Sec VIII method
  • Stress Analysis of PSV Piping System
    • Introduction
    • PSV Reaction Force Calculation
    • Applying PSV Reaction force
    • Practical Case Study
    • Certain best practices
  • Heat Exchanger Pipe Stress Analysis
    • Introduction
    • Creating Temperature Profile
    • Modeling the Heat Exchanger
    • Nozzle Load Qualification
    • Practical Case Study
    • Methodology for shell and tube inlet nozzle stress analysis
  • Vertical Tower Piping Stress Analysis
    • Introduction
    • Creating Temperature Profile
    • Equipment Modeling
    • Modeling Cleat Supports
    • Skirt temperature Calculation
    • Nozzle Load Qualification
    • Practical Example
  • Storage Tank Piping Stress Analysis
    • Introduction
    • Reason for Criticality of storage tank piping
    • Tank Settlement
    • Tank Bulging
    • Practical example of tank piping stress analysis
    • Nozzle Loading
  • Pump Piping Stress Analysis
    • API610 Pump nozzle evaluation using Caesar II

Part C: Dynamic Analysis is Caesar II

  • Introduction-Dynamic Analysis in Caesar II
  • Types of Dynamic Analysis
  • Static vs Dynamic Analysis
  • Dynamic Modal Analysis
  • Equivalent Static Slug Flow Analysis
  • Dynamic Response Spectrum Analysis

Part D: Miscellaneous other details

  • WRC 297/537 Calculation
    • What are WRC 537 and WRC 297?
    • Inputs for WRC Calculation
    • WRC Calculation with Practical Example
  • Underground Pipe Stress Analysis
  • Jacketed Piping Stress Analysis
  • Create Unit and configuration file in CAESAR II
  • ASME B31J for improved Method for i, k Calculation in Caesar II
  • Discussion about certain Questions and Answers
  • GRE/FRP Pipe stress analysis
    • GRE Pipe Stress Analysis using Caesar II
    • GRE Stress Analysis-Basics
    • FRP Pipe Stress Analysis Case Study
    • GRE Flange Leakage Analysis
    • Meaning of Stress Envelope; Understand it
  • Reviewing A Piping Stress System
    • Introduction
    • What to Review
    • Reviewing Steps
    • Case Study of Reviewing Pipe Stress Analysis Report
    • Reviewing Best Practices
  • FIV Study
    • Flow Induced Vibrations-Introduction
    • What is Flow-Induced Vibration (FIV)?
    • Flow-Induced Vibration Analysis
    • Corrective-Mitigation Options
  • AIV Study
    • Introduction
    • What is Acoustic-Induced Vibration (AIV)?
    • Acoustic-Induced Vibration Analysis
    • Corrective-Mitigation Options

How to Enroll for this Course

To join this course, simply click here and click on Buy Now. It will ask you to create your profile, complete the profile, and make the payment. As soon as the payment is complete, you will get full access to the course. If you face any difficulty, contact the Everyeng team using the Contact Us button on their website.

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

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

GRE Design Envelope and Failure Envelope

GRE Design Envelope (Failure envelope) is a 2-dimensional (2D) graphical plot of hoop stress and axial stress that provides safe operating conditions of GRE piping/pipeline system when subjected to combined stresses. The hoop stress is plotted in the horizontal axis (X-axis) and the axial stress is plotted in the vertical axis (Y-axis) as shown in Fig. 1. The area surrounded by the lines represents the strength of the GRE piping system. So, if the stress of any component falls within the boundary area, the system will be considered as safe and if the stress falls outside the boundaries, the system will be considered as failed. So, for failed systems pipe stress engineers have to reduce the component stress in some way to bring it within the envelope boundaries. The FRP design envelop is created from the short term and long-term failure envelopes.

For FRP/GRE pipe and pipeline stress analysis the GRP failure envelope curve is significant to extract datapoints for inputs in stress analysis software programs. In this article, we will explain how the GRE design envelope is generated and how to extract data for FRP pipe stress analysis.

GRE Failure Envelope and Design Envelope
Fig. 1: GRE Failure Envelope and Design Envelope

Development of GRE/FRP failure envelope starts with the GRE/FPR Qualification process which is covered in ISO 14692 Part 2. In general, several tests are performed, and those material test data are plotted for generating GRP failure envelope.

Development of Short-Term Failure Envelope:

The development of short-term failure envelope needs only two datapoints which are obtained from two different tests as explained below:

Test 1- Short Term Test following ASTM D1599:

For the short-term test according to ASTM D1599, the pressure inside the test sample is increased until failure. This test is also known as burst test. The pipe test samples are unrestrained, closed ends and the failure usually takes place in 60 to 80 seconds. This generates the first datapoint for short term failure envelope. From the burst test, we get the data for short term hoop stress σsh (2:1). Also, as the axial stress is half of hoop stress for pressurized pipes, we get data for σsa(2:1). Refer to Fig. 2 below:

First Data Point for Short-Term Failure Envelope
Fig. 2: First Data Point for Short-Term Failure Envelope

Test 2-Axial Test (Short-term uniaxial test) following ASTM D2105:

Axial tensile test is to be performed following ASTM D2105 which gives the second data point (Fig. 3) to be included in the FRP design envelope plot. σsa (0:1) is the short-term axial stress which is obtained from this test.

Second Data Point for Short-term Failure Envelope
Fig. 3: Second Data Point for Short-term Failure Envelope

From these two data, we can calculate the bi-axial stress ratio, r which is defined as twice the ratio of σsa(0:1) and  σsh(2:1).

r=2* σsa(0:1)/σsh(2:1)

The bi-axial stress ratio defines the slope of the top line in the GRP pipe failure envelope plot. So, the GRE short-term envelope is created which is defined by two points; short term axial stress σsa(0:1) and short term hoop stress  σsh(2:1). Refer to Fig. 4 below:

FRP Short-Term Failure Envelope
Fig. 4: FRP Short-Term Failure Envelope

The short term FRP envelope is generated to deduce the shape of the plot and slope of the top line as the long-term envelope will also follow the same slope.

Development of Long-Term Failure Envelope:

The first datapoint for the long-term GRE failure envelope is obtained from the Regression Test.

Test 3-Regression Test following ASTM D2992:

Full regression test is performed on 18+ GRE pipe samples with different pressures and their time to failure is recorded. The test is performed at 65 Deg C or design temperature when it is higher. The longest test duration is 10000 hours (417 days). The pipe pressure test data is usually plotted in a log stress (vertical axis) – log time (horizontal axis) graph and a line (regression line) is drawn through the cloud of points. Then that line is extrapolated to match 20 years (175400 hours) duration. It will provide the long-term hydrotest pressure (LTHP). The lower confidence limit (LCL) value is obtained by considering a 97.5% confidence limit of LTHP. The LCL signifies the pressure for which we can 97.5% sure that no failure/weepage/leakage will occur at this pressure if we run it for 20 years of lifetime.

Development of LCL/Qualified Pressure from Regression Curve Plot
Fig. 5: Development of LCL/Qualified Pressure from Regression Curve Plot

On other words, we can say the LCL is the allowable pressure for 20 years design life. It is also known as qualified pressure which can be easily converted to qualified stress using Barlow formula to get qualified stress (σqs). This point forms the first data point for the long term failure envelope σhl(2:1). The regression test is performed to find out LCL, qualified stress, and baseline gradient.

Test 4:

The second datapoint on the long-term failure envelope is obtained by performing a 1000-hour test with 1:1 load condition. Special arrangements are made to achieve 1:1 load condition. The results are then extrapolated for 20 years following the same regression line achieved during regression test. From this test we will get σhl(1:1). This is as per ISO 14692-2017. As per the earlier edition of ISO 14692, the datapoint is derived by finding the exact intersection of 1:1 line with the top line.

Datapoints for long-term failure envelope as per ISO 14692-2017
Fig. 6: Datapoints for long-term failure envelope as per ISO 14692-2017

The third datapoint for long-term failure envelope (σal(0:1)) is obtained by calculating using the following equation; σal(0:1)=r* σqs/2. In the latest edition of ISO 14692-2017, this data is derived by drawing a straight line connecting datapoint 1 and 2. Then the value obtained due to intersection of the drawn line with the vertical axis is multiplied by 0.8 to get σal(0:1).

To get the datapoint 4 for the long-term failure envelope, no material testing is performed. However, the uniaxial compression strength is calculated using the following equation:

σal(0:-1)=1.25* σal(0:1)         

The datapoint 5 is the pure hoop stress under pressurized 2:1 load condition.

GRE Design Envelop

The GRP design envelop is generated from the long-term failure envelop by reducing the long-term failure envelope by various factors. Initially the factored stress envelope is developed by applying partial factors A1 (temperature), A2 (chemical resistance), and A3 (cyclic condition) as shown below in Fig. 7:

Generation of Factored Stress Envelope from long-term failure envelope
Fig. 7: Generation of Factored Stress Envelope from long-term failure envelope

These partial factors are applied because of the differences between test condition and actual operating condition. Next, we apply part factors to get the design envelope from the factored stress envelope to actual FRP design envelope. Depending on loading condition, there are three values of part factors, f2 which signifies a safety factor for different types of loading.

Development of Design Envelope from long-term failure envelope
Fig. 8: Development of Design Envelope from long-term failure envelope

So, finally we get three design envelopes for three different types of loading conditions; sustained (f2=0.67), sustained with thermal (f2=0.83), and occasional (f2=0.89) loading condition.

So, the following curve shows all the envelopes in a single plot:

GRE Failure Envelope vs Design Envelope
Fig. 8: GRE Failure Envelope vs Design Envelope

The 1000 hr. survival test plot (orange color) in this group is only performed for verification purposes.

Typical Example:

Let’s take an example to find out the design envelop values that are required in pipe stress analysis as input. We have the following plot (Fig. 9) from the manufacturer.

Typical FRP Failure Envelope from Manufacturer
Fig. 9: Typical FRP Failure Envelope from Manufacturer

For Caesar ii GRE pipe stress analysis, we need to enter the following data which has to be extracted from the long-term failure envelope plot.

Data Required in Pipe Stress Analysis software Caesar II
Fig. 10: Data Required in Pipe Stress Analysis software Caesar II

You can easily measure the data from the above long-term failure envelope plot. In general, for accuracy purposes vendor provides these data in a tabular format.

References:

  • ISO-14692
  • Dynaflow webinar series

Special Thanks to Mr. Noel D’Souza and Mr. Altaf Patel for helping me to prepare this write-up.

Effect of Coating Factor on Buried Pipeline Stress Analysis

While performing buried or underground pipeline stress analysis, soil parameters must be entered in Caesar II software to help the software generate the bilinear restraints. The usual parameters that are required as the software input are presented in Fig. 1. Note that these parameters will vary depending on the soil type, soil compaction type, etc. Some typical values shown in Fig. 1 are considered for a case study to study the impact of coating factor.

Soil Parameters for a Typical Pipeline Stress Analysis in Caesar II
Fig. 1: Soil Parameters for a Typical Pipeline Stress Analysis in Caesar II

What is Pipeline Coating?

Pipeline coating refers to the application of protective materials on the surface of pipelines to prevent corrosion, mechanical damage, and other forms of deterioration. These coatings serve several important purposes:

  • Corrosion Protection
  • Mechanical Protection
  • Insulation
  • Environmental Protection

Types of Pipeline Coatings

There are several types of pipeline coatings available, each designed to address specific requirements and challenges. Some common types include:

1. Fusion-Bonded Epoxy (FBE) Pipeline Coatings:

FBE coatings are thermosetting resins that are applied to the surface of the pipeline and then heat-cured to form a hard, protective layer. They provide excellent corrosion resistance and are commonly used for both onshore and offshore pipelines.

2. Three-Layer Polyethylene (3LPE) and Three-Layer Polypropylene (3LPP) Coatings:

These coatings consist of a fusion-bonded epoxy primer, a copolymer adhesive layer, and a polyethylene or polypropylene outer layer. They offer good mechanical protection and are often used for buried pipelines.

3. Polyurethane (PU) Coatings:

PU coatings are typically applied as a topcoat over FBE or other primer coatings to provide additional mechanical protection and resistance to abrasion, chemicals, and weathering.

4. Coal Tar Enamel (CTE) Coatings:

CTE coatings are made from coal tar pitch and provide excellent resistance to corrosion, water, and chemicals. However, they are less commonly used today due to environmental concerns associated with coal tar.

5. Concrete Weight Coatings (CWC):

CWC consists of a layer of concrete applied to the pipeline to provide weight for stability and protection against buoyancy, particularly for offshore pipelines.

6. Polyethylene Terephthalate (PET) Wrapping:

PET wrapping involves wrapping the pipeline with a strong, flexible polyester film for mechanical protection and to prevent corrosion.

7. Abrasion Resistant Overcoat (ARO):

ARO coatings are designed to provide extra protection against abrasion and mechanical damage, commonly used in areas where the pipeline is exposed to high levels of wear and tear.

8. Ceramic Epoxy Coatings:

These coatings contain ceramic particles suspended in an epoxy resin matrix, offering enhanced abrasion resistance and durability compared to standard epoxy coatings.

What is Coating Factor?

Coating factor is the pipeline external coating dependent factor that relates the internal friction angle of the soil to the friction angle at the soil-pipe interface. This option will be available during buried pipe stress analysis if American Lifeline Alliance in the Soil Model Type list and Sand/Gravel as the Soil Classification is selected. This is basically a type of friction factor. The coating factors that are used for pipeline coating are provided in Table 1 taking a reference from American Lifeline Alliance document “Guidelines for the Design of Buried Steel Pipe”.

Pipe External CoatingCoating Factor, F
Concrete1.0
Coal Tar0.9
Rough Steel0.8
Smooth Steel0.7
Fusion Bonded Epoxy0.6
Polyethylene0.6
Table 1: Coating Factor for Various types of external pipeline coatings

Case Study to Find the Impact of Coating Factor

In this case study, we will investigate the impact of coating factor by making a case study of a sample pipeline model. Widely used software Caesar II is used for the case study and the pipeline parameters are considered as follows:

  • Governing Code: ASME B31.8
  • Pipeline Material: API 5L-X65
  • Soil Model Type: American Lifeline Alliance
  • Pipeline Design Temperature: 80 Deg. C buried part / 90 Deg. C aboveground part
  • Pipeline Design Pressure: 495 Bar
  • Pipe Size: 6″
  • Fluid Density: 420 Kg/m^3

Typical pipeline route is shown in Fig. 2 below:

Typical pipeline route for the case study
Fig. 2: Typical pipeline route for the case study

From node 100 to 980 is buried part and from node 980 to 1320 is aboveground part of the pipeline. In this pipeline we will study the following parameters:

  • Maximum expansion stress of the system
  • Maximum operating stress of the system
  • Thermal displacement (Load Case: W+T1+P1) at interface node 980, and
  • Thermal displacement at free end node 1320

Results of the Case Study

We have run the Caesar II program considering a coating factors of 0.6, 0.7, 0.8, 0.9 and 1.0. The following table summarizes the impact of various coating factors considered on the stress analysis output results.

Stress Analysis Results with varying Coating factor
Table 2: Stress Analysis Results with varying Coating factor

From the above results we can find that,

  1. With increase in coating factor, both the expansion and operating stress is decreasing.
  2. With an increase in coating factor, the free thermal movement at the interface node and free end is reducing.

Fig. 3 below shows the results in a graphical plot.

Effect of Coating factor on Stress and Displacements
Fig. 3: Effect of Coating factor on Stress and Displacements

Conclusions

From the above study, it is found that with increase in pipeline coating factor, the friction at the soil-pipe interface is increasing. This increase in friction is adding more resistance to the thermal movement of the pipe and hence a decreased end displacement is found.

However, even though for this specific example, the stress is reducing with increase in coating factor, it may not always be true as friction effect is non-linear and its impact can not be generalized. the effect of friction need to be studied minutely for each system. For more details regarding the impact of friction on pipe/pipeline stress analysis you can refer to the following technical paper by Mr L. C. Peng.

Process Optimization in Gas Processing Plants: Strategies for Maximizing Efficiency and Profitability

Gas processing plants play a critical role in the oil and gas industry, transforming raw natural gas into marketable products such as methane, ethane, propane, and natural gas liquids (NGLs). However, these plants often face challenges such as fluctuating feed compositions, energy inefficiencies, and operational bottlenecks. Process optimization is the key to addressing these challenges, improving plant performance, and maximizing profitability. This article explores advanced strategies for optimizing gas processing plants, with a focus on key unit operations and technologies.

Key Challenges in Gas Processing

  1. Variable Feed Composition: Natural gas feedstocks can vary significantly in terms of composition, pressure, and temperature, making it difficult to maintain consistent product quality.
  2. Energy Intensity: Gas processing plants are energy-intensive, with significant energy consumption in compression, refrigeration, and separation processes.
  3. Operational Bottlenecks: Inefficiencies in equipment or processes can lead to reduced throughput, higher operating costs, and increased downtime.
  4. Environmental Compliance: Stricter regulations on emissions and waste management require plants to adopt cleaner and more efficient technologies.

Strategies for Process Optimization

1. Advanced Process Simulation and Modeling

  • Objective: Predict plant performance under varying conditions and identify optimization opportunities.
  • Tools: Software like Aspen HYSYS, PRO/II, or UniSim can simulate entire gas processing plants, including separation, compression, and refrigeration units.
  • Application: Use dynamic simulation to test different operating scenarios, such as changes in feed composition or flow rates, and optimize process parameters like pressure, temperature, and reflux ratios.

2. Optimizing Dehydration Systems

  • Objective: Remove water vapor from natural gas to prevent hydrate formation and corrosion.
  • Strategies:
    • Optimize tri-ethylene glycol (TEG) circulation rates and contactor temperatures in glycol dehydration units.
    • Use advanced regeneration techniques, such as stripping gas or vacuum distillation, to improve TEG purity and reduce energy consumption.
  • Outcome: Enhanced dehydration efficiency and reduced operational costs.

3. Enhancing NGL Recovery

  • Objective: Maximize the recovery of valuable NGLs (ethane, propane, butane) from natural gas.
  • Strategies:
    • Optimize the operation of cryogenic turboexpander plants by adjusting expander inlet temperatures and pressures.
    • Use advanced heat integration techniques to improve the efficiency of heat exchangers and reduce refrigeration loads.
  • Outcome: Increased NGL recovery rates and higher product revenues.

4. Energy Efficiency Improvements

  • Objective: Reduce energy consumption in compression, refrigeration, and separation processes.
  • Strategies:
    • Retrofit compressors with variable frequency drives (VFDs) to match load requirements and reduce energy usage.
    • Implement waste heat recovery systems, such as Organic Rankine Cycle (ORC) units, to generate power from waste heat.
    • Optimize heat exchanger networks using pinch analysis to minimize energy losses.
  • Outcome: Lower operating costs and reduced carbon footprint.

5. Advanced Process Control (APC)

  • Objective: Automate and optimize plant operations in real-time.
  • Strategies:
    • Use APC systems to control key process variables, such as column pressures, temperatures, and reflux rates.
    • Implement predictive maintenance systems to monitor equipment health and prevent unplanned downtime.
  • Outcome: Improved process stability, higher throughput, and reduced operational risks.

6. Addressing Operational Bottlenecks

  • Objective: Identify and resolve inefficiencies in equipment or processes.
  • Strategies:
    • Conduct regular performance audits to identify bottlenecks in compressors, heat exchangers, or distillation columns.
    • Upgrade or replace outdated equipment with more efficient technologies.
    • Optimize maintenance schedules to minimize downtime and maximize equipment availability.
  • Outcome: Increased plant capacity and reduced operational costs.

Case Study: Optimizing a Gas Processing Plant in the Middle East

A gas processing plant in the Middle East faced challenges with low NGL recovery rates and high energy consumption. The following optimization strategies were implemented:

  1. Process Simulation: A detailed simulation model was developed to identify inefficiencies in the cryogenic turboexpander plant.
  2. Heat Integration: The heat exchanger network was optimized using pinch analysis, reducing refrigeration loads by 15%.
  3. Advanced Control: An APC system was installed to optimize column pressures and temperatures, improving NGL recovery by 5%.
  4. Energy Efficiency: Compressors were retrofitted with VFDs, reducing energy consumption by 10%.

Results:

  • 20% increase in NGL recovery.
  • 15% reduction in energy consumption.
  • Payback period of less than 2 years.

Environmental and Economic Benefits

  1. Reduced Emissions: Energy efficiency improvements and waste heat recovery systems lower greenhouse gas emissions.
  2. Cost Savings: Optimized processes reduce energy consumption, maintenance costs, and downtime.
  3. Increased Revenue: Higher NGL recovery rates and improved product quality generate additional revenue.
  4. Regulatory Compliance: Advanced technologies and optimized processes help plants meet stringent environmental regulations.

Conclusion

Process optimization is a powerful tool for enhancing the performance and profitability of gas processing plants. By leveraging advanced simulation tools, energy efficiency improvements, and advanced process control systems, operators can overcome challenges, reduce costs, and maximize product recovery. As the industry continues to evolve, process optimization will remain a critical focus area for achieving operational excellence and sustainability.

Minimum Distance Between Welds as per International Codes and Standards

Welding is a fundamental process in many industries like oil and gas, construction, manufacturing, shipbuilding, automotive, and aerospace. It is used to join metals together by applying heat, pressure, or both to form a strong, permanent bond. While welding is a reliable and efficient method of joining materials, it must be done correctly to ensure the structural integrity of the welded joint and to avoid defects or failures. One critical aspect of the welding process is maintaining the proper minimum distance between two welding operations.

In this article, we will explore the minimum distance requirements between two welding operations, why they matter, and the factors that influence this distance.

What Is the Minimum Distance Requirement?

The minimum distance between two welding operations refers to the space that must be maintained between two adjacent welds. This is important for several reasons, such as avoiding heat-affected zone (HAZ) overlap, ensuring adequate access for welding tools, and promoting the overall quality and strength of the weld.

Welding operations are generally separated by a certain distance to:

  1. Prevent Heat Interference: Overlapping heat-affected zones can weaken the material around the weld, compromising the joint strength.
  2. Minimize Distortion: If two welds are too close together, the heat from one weld can affect the other, causing distortion in the welded materials.
  3. Allow for Proper Cooling: Sufficient space allows the welded material to cool down between operations, reducing the risk of thermal stress and cracking.
  4. Ensure Accessibility: Proper spacing ensures that the welder can work efficiently and safely, reducing the risk of weld defects due to inadequate access.
  5. Compliance with Industry Standards: Certain industries or specific applications have strict welding standards that must be adhered to, including guidelines on the minimum distance between adjacent welds.

Why Is It Important to Maintain a Minimum Distance Between Two Welds?

Ensuring a proper distance between welds helps maintain the quality, strength, and safety of the structure being welded. Below are the key reasons why this distance is crucial:

Avoiding Overlapping Heat-Affected Zones (HAZ)

Welding creates a localized region of high heat, known as the heat-affected zone (HAZ), which can alter the microstructure and mechanical properties of the material. When two welds are made too close together, the HAZ of one weld can interfere with the HAZ of the adjacent weld. This can lead to reduced strength, increased brittleness, and a greater likelihood of cracking.

Prevention of Distortion and Warping

Welding generates significant heat, which causes the welded material to expand. As the weld cools, it contracts, leading to residual stresses. If two welds are too close, the thermal expansion and contraction of one weld can distort the adjacent weld, leading to warping or misalignment of the material.

Ensuring Proper Cooling

Cooling rates play a critical role in determining the final properties of a weld. The cooling process can be affected by the proximity of adjacent welds. When the cooling rate is not controlled or uniform, it can lead to issues such as weld cracking or inadequate solidification. Keeping an adequate distance between welds allows each weld to cool properly.

Providing Space for Inspection and Repair

Weld inspection is a critical part of the quality control process. A sufficient gap between two welding operations ensures that the inspector has the necessary space to assess each weld for defects such as porosity, undercuts, and cracks. Additionally, if a repair is needed, the welder will have enough space to carry out the repair work without damaging the surrounding area.

Reducing the Risk of Hydrogen-Induced Cracking

Hydrogen-induced cracking (HIC) is a common issue in welding, especially with high-strength steels. When the base metal is exposed to moisture or hydrogen during the welding process, it can lead to the formation of cracks. Maintaining a minimum distance between welds reduces the likelihood of hydrogen accumulating in one weld, which could then migrate to the other and cause cracking.

Factors Influencing Minimum Distance Requirements

Several factors influence the required distance between two welding operations. These include the material being welded, the welding process used, and the application’s requirements.

Material Type

The type of material being welded plays a significant role in determining the minimum distance between welds. For example:

  • Low-carbon steel: Low-carbon steels are more forgiving and may tolerate smaller gaps between welds.
  • High-strength steel: Higher-strength materials, such as high-carbon steels or alloys, are more sensitive to heat input and require more space between welds to prevent cracking or warping.
  • Non-ferrous metals: Materials like aluminum and titanium have different thermal properties and may require a different minimum distance compared to steel. For instance, aluminum requires a slower cooling rate to avoid brittleness, necessitating more space between welds.

Welding Process

The welding process used affects the heat input and cooling rate, which, in turn, influences the minimum distance between welds:

  • Arc Welding: Arc welding processes like Shielded Metal Arc Welding (SMAW) or Gas Tungsten Arc Welding (GTAW) tend to have higher heat input, requiring a larger minimum distance.
  • Laser Welding: Laser welding, which produces a concentrated heat source, may require smaller gaps due to the rapid cooling associated with the process.
  • TIG or MIG Welding: These processes offer more control over heat input and could potentially reduce the need for larger gaps between welds, depending on the material and application.

Weld Size

Larger welds produce more heat and can affect adjacent welds. As the size of the weld increases, the required minimum distance between welds also increases to prevent issues like distortion or overlapping HAZ.

Type of Joint

The configuration of the joint being welded can also influence the distance between adjacent welds. Butt joints, fillet welds, and lap joints each have different heat distribution characteristics, which will affect the recommended minimum distance.

Service Conditions

The intended service conditions of the welded structure can impact the minimum distance requirement. For example, structures subjected to high stress, pressure, or extreme temperatures may require more stringent requirements to maintain joint integrity.

Industry Standards and Codes for Minimum Distance Between Welds

Various organizations and standards bodies have developed guidelines for welding practices, including the minimum distance between welds. The minimum distance between welds is determined by the relevant codes and standards being followed. Below are some guidelines from commonly referenced codes and standards:

  • American Welding Society (AWS) D1.1: The minimum spacing between welds should be at least four times the thickness of the thinner part being joined, with a minimum of 1 inch (25 mm).
  • American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) Section VIII, Division 1: The minimum distance between welds should be at least three times the thickness of the thinner part being joined, with a minimum of 1 inch (25 mm).
  • European Welding Federation (EWF) and International Institute of Welding (IIW): The minimum distance between welds should be at least three times the thickness of the thinner part joined, but no less than 2 mm.

It is important to recognize that these guidelines are not comprehensive, and other codes and standards may have varying requirements. The actual minimum distance between welds can also depend on factors such as the materials used, the intended application, and the welding method employed. For precise guidance on the minimum distance between welds for a particular application, it is essential to refer to the relevant code or standard and/or consult a qualified welding engineer.

Minimum Distance Between Welds as per International Codes and Standards

The required minimum distance between welds is influenced by the welding process being employed. In most cases, this distance is determined by factors such as the material being welded, the joint design, and the parameters of the welding process. For instance, the typical minimum gap between fillet welds is around 1/16 inch (1.6 mm), though this value may change based on the material, joint configuration, and welding technique used.

Here is a table listing the minimum weld distance requirements by some of the widely used codes and standards:

Minimum Weld Distances as per International Codes
Table 1: Minimum Weld Distances as per International Codes

AWS vs CWB

The American Welding Society (AWS) and the Canadian Welding Bureau (CWB) are two important organizations in the welding industry, each serving their respective countries. Although they share a similar focus on promoting welding safety, education, and certification, they differ in several key areas.

Founded in 1919, the American Welding Society (AWS) is a non-profit organization based in Miami, Florida, with over 70,000 members globally. The AWS is dedicated to advancing welding science, technology, and applications, which include processes like brazing, soldering, and thermal spraying. To achieve this, the organization develops codes, standards, and educational initiatives while also certifying welding professionals and inspectors.

The AWS is responsible for more than 200 codes and standards related to welding and joining processes. One of the most well-known standards is the D1.1 Structural Welding Code for Steel. These documents provide essential guidelines for welding procedures, welder qualifications, and inspection protocols. In addition, the AWS offers various educational opportunities such as webinars, seminars, and online courses. It also provides certification programs for welders and welding inspectors to ensure competency in the field.

On the other hand, the Canadian Welding Bureau (CWB), a non-profit organization founded in 1947 and based in Milton, Ontario, focuses on welding safety, education, and certification within Canada. The CWB serves over 6,000 members worldwide and offers a range of certification services for welding personnel and welding inspectors.

Similar to the AWS, the CWB has its own set of codes and standards, including CSA W59 Welded Steel Construction, which is comparable to the AWS D1.1. The CWB also provides training and educational resources, such as seminars, courses, and online tools. Additionally, the CWB certifies welding professionals and inspection experts through its certification programs.

Despite many similarities between AWS and CWB, there are notable differences. The AWS has a broader international presence and its standards are used globally, while the CWB is primarily focused on the Canadian market. Moreover, while both organizations offer certification for welding personnel and inspectors, the criteria and requirements for certification may vary between them.

In summary, the AWS and the CWB are both key players in the welding industry within their respective countries. They emphasize welding safety, education, and certification, and each has a set of standards to guide welding practices. However, their global reach and certification procedures differ, reflecting their distinct roles in the industry.

In conclusion, the minimum distance between two welding operations is a critical factor in ensuring the quality, strength, and safety of the welded structure. By maintaining adequate spacing between welds, you can avoid overlapping heat-affected zones, minimize distortion, promote proper cooling, and facilitate effective inspection and repair.

To determine the specific minimum distance for a particular welding project, consider the material being welded, the welding process used, the joint type, and the service conditions. Adhering to industry standards and codes will help ensure that your welding operations meet the necessary requirements for safety and performance.

Ultimately, the right spacing between welds contributes to the long-term durability and reliability of the structure, ensuring that it can withstand the demands placed upon it.

Top Instrumentation Engineering Deliverables for the Oil and Gas Industry Projects

Instrumentation engineering plays a crucial role in the oil and gas industry, ensuring the safe, efficient, and reliable operation of facilities across exploration, production, refining, and distribution. Instrumentation engineers are responsible for the design, implementation, testing, and maintenance of various measurement, control, and automation systems that regulate operations. These engineers work on a broad range of projects, including offshore platforms, refineries, gas plants, and storage facilities, providing essential solutions for managing pressure, temperature, flow, and level controls, as well as gas detection and safety systems.

What are Instrumentation Engineering Deliverables?

The deliverables in instrumentation engineering for the oil and gas industry refer to the comprehensive technical documents, designs, and systems that outline the specifications, functionalities, and implementation procedures of the instrumentation systems. These deliverables are vital to ensuring that the facility meets safety standards, regulatory compliance, operational efficiency, and environmental protection. Let’s learn some of the key instrumentation engineering deliverables that are most frequently used in the oil and gas industry.

  1. Piping and Instrumentation Diagram (P&ID)
  2. Instrument Index
  3. I/O List
  4. Instrument Specification and Datasheet
  5. Instrument Loop Diagrams
  6. Instrument Hook-Up Diagrams
  7. Instrument Cable Schedule
  8. Instrument Logic Diagrams
  9. Cause and Effect Diagrams
  10. Field Instrument Layout
  11. Control System Architecture Documentation
  12. Hazardous Area Classification
  13. Testing and Commissioning Plans
  14. As-Built Drawings and Documentation

1. Piping and Instrumentation Diagram (P&ID)

A P&ID, or Piping & Instrumentation Diagram, is a schematic representation of the functional relationship of piping, instrumentation, and system equipment components. P&ID shows all piping, including the physical sequence of branches, reducers, valves, equipment, instrumentation & control interlocks. Even though it is prepared by process engineers, most of the instrument-related inputs are shared by instrumentation engineers. More details about P&ID are covered here: What is a P&ID Drawing | P&ID Symbols | How to Read P & ID Drawings

A snap of a Typical P&ID
Fig. 1: A snap of a Typical P&ID

2. Instrument Index

The Instrument Index is made to list all the instruments loop-wise on the basis of P&ID. It covers all the necessary information of the instruments in the loop. The major data that must be included in an Instrument Index are

  • Tag Number
  • Description of the Instrument
  • Service
  • Type of Instrument
  • Location of Instrument
  • P&ID Number
  • Instrument Specification Number
  • Hook-up Diagram Number
  • Instrument Layout Number
Instrument Index
Fig. 2: Instrument Index

3. I/O List (Input-Output List)

The I/O List is used for defining the type of signal inputs & outputs of the instruments used. The main function of I/O lists is to define the number & types of signals given to PLC / DCS. This is the basic document used to size PLC / DCS. The main data that must be included in an I/O List is as follows.

  • Instrument Tag Number
  • Service
  • Signal Type
  • Signal Level
  • Instrument Range
  • P&ID Number
Typical I/O List
Fig. 3: Typical I/O List

4. Instrument Specification and Datasheet

Instrument specifications are one of the foundational deliverables in the instrumentation engineering domain. These documents define the technical requirements of each instrument in the system. Instruments used in the oil and gas industry typically include flowmeters, pressure transmitters, temperature sensors, control valves, gas detectors, and control panels.

Both P&ID & Process Data are required to prepare Instrument specification documents. It helps in specifying the precise requirement of the process for which the instrument is to be used. Purchasing an instrument is mainly dependent on instrument specification. The major data that must be included in the Instrument Specification Sheet is as follows.

  • Tag Number
  • Service
  • Instrument Function
  • Performance Criteria
  • Environmental Conditions
  • Power Supply Requirements
  • Communication Protocols
  • Material Specifications
  • Type of Instrument
  • Range
  • Size
  • Location
  • Mounting
  • Protection
A Typical Instrument Datasheet
Fig. 4: A Typical Instrument Datasheet

Accurate and detailed specifications are necessary for selecting appropriate instruments and ensuring compliance with safety regulations, such as those set by the International Electrotechnical Commission (IEC), the American Petroleum Institute (API), or other international standards or specifications.

5. Instrument Loop Diagrams (ILD)

Instrument Loop Diagrams are the graphical representation of loops. ILDs are made using the help of P&ID, I/O List, & Cable Schedule. ILDs show the detailed flow of signal from the instrument to the control system cabinet. The major data that must be included in an ILD are:

  • Components used the loop
  • Location of the components
  • Termination details
  • Interlocks used
  • Alarms
  • Soft functions
A Typical Instrument Logic Diagram
Fig. 5: A Typical Instrument Logic Diagram

These loop diagrams show how individual instruments connect to control systems, including wiring, sensors, and controllers.

6. Instrument Hook-up Diagrams

Instrument Hook-up Diagrams are the graphical representation of the method of connecting instruments to the process lines, equipment, tanks, vessels, etc. The main data that must be included in a hook-up drawing are.

  • Physical mounting of the instrument in the field
  • Various items used for mounting the instruments
  • Size & material of various items used
  • List of Tag Numbers for which the Hook-up is applicable
A typical Instrument Hook-Up Diagram
Fig. 6: A typical Instrument Hook-Up Diagram

7. Instrument Cable Schedule

A cable schedule is a document that contains the list of instrument cables. Each cable should have a precise number according to the numbering scheme. It is the most important document used for cable laying purposes in project engineering The main data included in the Cable Schedule is as follows.

  • Cable Number
  • Cable Connectivity
  • Type of Cable
  • Length of Cable
  • Size of Cable
Typical Instrument Cable Schedule
Fig. 7: Typical Instrument Cable Schedule

8. Instrument Logic Diagrams

The major function of the Instrument Logic Diagram is to determine the operation of a given component or system as the various input signals change. The most common use of a Logic Diagram is to provide a simplified functional representation of an electrical circuit.

It is easier and faster to figure out how output functions and responds to various input signals by representing a circuit using logic symbols than using the electrical schematic with its complex relays and contacts.

A typical Instrument Logic Diagram
Fig. 8: A Typical Instrument Logic Diagram

9. Cause & Effect Diagrams

The Instrument Cause & Effect Document is a tabular chart of the functions of various instruments. This document indicates the cause as an instrument signal in one condition and its effects on other instruments connected in the loop as per the logic.

 Cause and Effect Diagram
Fig. 9: Cause and Effect Diagram

10. Field Instrument Layout

Instrumentation layout plans define where and how instruments will be physically positioned within the facility. These deliverables are critical for ensuring that instruments are accessible for maintenance, calibrated correctly, and located in safe zones. Layouts are especially significant in the oil and gas industry due to the high-risk environments involved.

Field instrument placement plans consider the following factors:

  • Accessibility: Instruments must be placed in locations that are easy to access for calibration, inspection, and repair.
  • Safety Zones: Placement in hazardous areas requires adherence to explosive-proof and weather-proof guidelines. Instrument placement must avoid areas that could lead to failure or danger in the event of fire or explosion.
  • Interference Avoidance: Instruments should be placed away from sources of vibration, excessive heat, or electromagnetic interference, which could affect measurement accuracy.
  • Environmental Considerations: Temperature, humidity, corrosion, and exposure to harsh chemicals must all be considered when positioning field instruments.

Proper instrument placement ensures ease of operation and minimizes downtime during maintenance or upgrades.

11. Control System Architecture Documentation

This deliverable provides an in-depth overview of the architecture of the control systems, which are the central nervous system of the entire oil and gas facility. The control system architecture typically includes:

  • Distributed Control System (DCS): A centralized control system that allows operators to monitor and control processes across various parts of the plant.
  • Programmable Logic Controllers (PLC): Used for local control of equipment, PLCs are often deployed in safety-critical applications where real-time decision-making is needed.
  • Human-Machine Interface (HMI): Provides operators with graphical interfaces to monitor system performance and intervene when necessary.
  • Redundancy Plans: These are critical for ensuring continuous operation, especially in oil and gas facilities where downtime can result in significant financial losses or safety hazards.
  • Communication Networks: Describes how devices will communicate with each other using protocols such as Ethernet, Modbus, or wireless technologies.

This documentation is vital for understanding how various systems will interact and ensuring the seamless operation of the entire plant.

12. Hazardous Area Classification and Equipment Certification

One of the critical deliverables in instrumentation engineering for the oil and gas industry is the classification of hazardous areas and the certification of equipment. The oil and gas industry often involves environments with explosive gases or vapors, particularly in offshore and underground drilling operations.

The deliverables in this category typically include:

  • Hazardous Area Classification: This process involves analyzing the facility to determine the likelihood of the presence of flammable gases or vapors. Areas are classified into zones (Zone 0, Zone 1, Zone 2) depending on the likelihood and frequency of a hazardous atmosphere.
  • Equipment Certification: Instruments and electrical equipment used in these zones must be certified to meet explosion-proof standards, such as IECEx or ATEX certifications, ensuring they are safe for use in hazardous conditions.
  • Explosion Protection Methods: The design and implementation of protection techniques like intrinsic safety (Ex i), flameproof (Ex d), and increased safety (Ex e).

Proper hazardous area classification and equipment certification ensure the safety of the facility, its workers, and the surrounding environment. More details about Hazardous Area Classification is covered here: What is Hazardous Area Classification? Steps and Guides

13. Testing and Commissioning Plans

Before the instrumentation systems are fully integrated and operational, testing and commissioning are necessary to ensure everything is working as expected. These deliverables consist of:

  • Factory Acceptance Test (FAT): This test is conducted at the manufacturer’s facility to ensure that the instruments meet the required specifications before shipping. Further details about FAT can be read from here: Factory Acceptance Test– What Is FAT, and How Does It Work?
  • Site Acceptance Test (SAT): Once the equipment is installed on-site, it undergoes testing to verify that it operates correctly in the actual environment.
  • Calibration Reports: Detailed reports on the calibration of each instrument, ensuring they meet accuracy and precision standards.
  • Performance Testing: Testing under operating conditions to confirm the entire system’s functionality, including communication protocols, control logic, and emergency shutdown systems.

A comprehensive testing and commissioning plan is essential for identifying potential issues early, minimizing risks, and ensuring the system is safe, efficient, and compliant with regulatory standards.

14. As-Built Drawings and Documentation

As-built drawings are one of the final deliverables in the instrumentation engineering phase. These documents provide a detailed, up-to-date representation of the system as it has been installed, including any changes or deviations from the original design. They include:

  • Revised P&IDs: Updated diagrams reflecting any changes during construction or installation.
  • Instrument Datasheets: Finalized datasheets with actual specifications of the installed instruments.
  • Loop Diagrams: Updated to reflect the actual wiring and instrument configurations used during installation.

As-built drawings are essential for future maintenance, troubleshooting, and potential upgrades, serving as a historical record of the project.

Some other deliverables generated by Instrumentation Engineers are:

  • Safety Instrumented System (SIS) Design: Includes the design of fail-safe systems, emergency shutdown (ESD) systems, and safety integrity levels (SIL) to protect against hazards and ensure personnel and equipment safety.
  • PSV Sizing Calculation
  • Control Valve Sizing Calculation
  • Instrument Location Plan
  • Junction Box grouping and Location Plan
  • Cable Tray Layout
  • Preparation of Material Requisition for Instrument Items
  • Technical Bid Evaluation or Technical Bid Analysis
  • Fire Alarm & CCTV Layout
  • Fire Alarm Block Diagram
  • CCTV Block Diagram
  • Instrument – Electrical Interface Drawing
  • Instrument – Piping Interface Drawing
  • Instrument Earthing Philosophy Drawing
  • Instrument Design Basis/Philosophy
  • Pipeline Leak Detection Philosophy
  • Metering Philosophy and Specification
  • Telecomms Philosophy
  • Control and Safety System Topology Diagram
  • Telecoms Block Diagram
  • EDS Philosophy
  • Telecommunication System Functional Specifications
  • Integrated Control & Safety System (ICSS) Specification
  • Package Equipment Specification
  • Control Panel Specification
  • Control Room Layout Drawing
  • Overall Telecommunication System Block Diagram
  • Bulk Instrument MTO
  • Technical Requisition for LLI’s
  • Control Narratives & Sequence Descriptions
  • Intrinsic Safety Calculations
  • Instrument Air Consumption Calculations
  • Electrical Power Consumption Calculations
  • Equipment Room Layout Drawings
  • Instrument Location Drawings
  • Cable/Tray Routing Drawings/Cable Block Diagrams/ Schedule
  • F&G Detector Layout Drawings
  • Interconnection/Termination Drawings
  • Instrument Installation Drawings
  • Demolition Study/Drawings
  • Telecommunication Design Basis / Philosophy / Systems Functional Specifications

If you know some other deliverables that I missed, kindly highlight in the comments section.

What is ASME B31.3 PRESSURE LEAK TEST?

ASME B31.3, the “process piping” code, provides guidelines for the pressure leak testing of piping systems. The primary goal of these tests is to ensure the integrity and safety of the piping system before it is put into service. As the name suggests, we just want to see if the piping we have designed and fabricated is not going to leak when put into operation. They basically serve two main purposes, as mentioned below:

  • Determine the leak tightness of the welded and flanged joints of the piping system and
  • Qualify joints that are not included in the UT or radiographic examination.

What are the methods of the Pressure Leak Test?

“Pressure Leak Test” is a general name. The more specific name depends on how you are going to execute the test. There are 6 types of methods stated in the code as below:

1. Hydrostatic Leak Test

Hydrostatic leak test, or simply Hydrotest, is the most common type of test that uses water as the test fluid. Tested at 1.5×Design Pressure×Ratio of Stress (that normally ends up as 1, unless operating at very high temperature). Only if a hydrostatic test could cause damage to the piping or is impractical, a pneumatic leak test be proposed as an alternative type of pressure leak test.

2. Pneumatic Leak Test

Using inert gas or air as the test fluid with 1.1×Design Pressure. This test must be carefully assessed as it presents hazards from the stored energy of compressed fluid during the test that could burst if a failure occurs.

3. Hydrostatic-Pneumatic Leak Test

Same as method 2, where a hydrostatic test may not be suitable; a combination of both hydrostatic & pneumatic tests could be proposed. However, I have never experienced such tests being conducted. If you have any insights about how it is done, please share them in the comment section.

ASME B31.3 Leak Pressure Test

4. Initial Service Leak Test

With the owner’s approval, this test is only applicable to Category D fluid service. It is tested during the initial operation of the system with the service fluid itself. Pressure testing is the same as operating pressure.

5. Sensitive Leak Test

Sometimes, it is also known as a bubble test. The test pressure is only 105 kPa, or 25%×Design Pressure. This test is required for Category M fluid service as an additional pressure leak test on top of the hydrostatic or pneumatic test.

6. Alternative Leak Test

Where both hydrostatic and pneumatic tests are not feasible, an alternative leak test can be proposed. It consists of 3 procedures:

  • Examination of all welds
  • Flexibility analysis to be passed
  • Performing a Sensitive Leak Test
Pressure Leak Test ASME B31.3

Requirements for Leak Pressure Tests

  • Piping that is open to the atmosphere does not need to be leak tested, UNLESS, of course, specified by the owner or engineering design. The reason is that it is not an enclosed pressurized piping; the system has no pressure to retain.
  • Category D piping systems can be tested using only the Initial Service Leak Test, PROVIDED; of course, it is approved by the Owner. So, if your projects face a setback schedule during testing, getting approval on this might make a difference in the overall progress.
  • The pressure during the leak test only needs to be maintained for AT LEAST 10 minutes! The setup, fluid filling, and staggered pressurization are what take the most time. That is why if you could get Category D tested with only the Initial Service Leak Test, it would save lots of time!
  • The pressure leak test shall be conducted after all required heat treatments have been completed. Yup, it’s kind of logic, isn’t it?
  • Once a pressure leak test has been completed, if any repairs or modifications are made, the piping system shall be retested. Can this be waived if the changes are minor? Of course, with the Owner’s approval. The trick is, how minor is considered minor? You will need to justify that.
  • All joints shall be exposed during the pressure leak test. Therefore, it is preferable that they are not painted beforehand. Paint may hinder any small leak point from being visible.
  • If a pneumatic pressure test is specified, the hazard from stored energy shall be assessed. One way to do this is by using calculations in ASME PCC-2. The code provides guidelines for safe distance from the piping that is being pneumatically tested. Did you know the lowest distance is 50 m?