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.
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 USD30 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.
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 (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.
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:
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.
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:
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.
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.
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:
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.
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:
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.
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.
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.
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 Coating
Coating Factor, F
Concrete
1.0
Coal Tar
0.9
Rough Steel
0.8
Smooth Steel
0.7
Fusion Bonded Epoxy
0.6
Polyethylene
0.6
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:
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.
Table 2: Stress Analysis Results with varying Coating factor
From the above results we can find that,
With increase in coating factor, both the expansion and operating stress is decreasing.
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.
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
Variable Feed Composition: Natural gas feedstocks can vary significantly in terms of composition, pressure, and temperature, making it difficult to maintain consistent product quality.
Energy Intensity: Gas processing plants are energy-intensive, with significant energy consumption in compression, refrigeration, and separation processes.
Operational Bottlenecks: Inefficiencies in equipment or processes can lead to reduced throughput, higher operating costs, and increased downtime.
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.
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:
Process Simulation: A detailed simulation model was developed to identify inefficiencies in the cryogenic turboexpander plant.
Heat Integration: The heat exchanger network was optimized using pinch analysis, reducing refrigeration loads by 15%.
Advanced Control: An APC system was installed to optimize column pressures and temperatures, improving NGL recovery by 5%.
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
Reduced Emissions: Energy efficiency improvements and waste heat recovery systems lower greenhouse gas emissions.
Cost Savings: Optimized processes reduce energy consumption, maintenance costs, and downtime.
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:
Prevent Heat Interference: Overlapping heat-affected zones can weaken the material around the weld, compromising the joint strength.
Minimize Distortion: If two welds are too close together, the heat from one weld can affect the other, causing distortion in the welded materials.
Allow for Proper Cooling: Sufficient space allows the welded material to cool down between operations, reducing the risk of thermal stress and cracking.
Ensure Accessibility: Proper spacing ensures that the welder can work efficiently and safely, reducing the risk of weld defects due to inadequate access.
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:
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.
Piping and Instrumentation Diagram (P&ID)
Instrument Index
I/O List
Instrument Specification and Datasheet
Instrument Loop Diagrams
Instrument Hook-Up Diagrams
Instrument Cable Schedule
Instrument Logic Diagrams
Cause and Effect Diagrams
Field Instrument Layout
Control System Architecture Documentation
Hazardous Area Classification
Testing and Commissioning Plans
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
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
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
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
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
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
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
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.
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.
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
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
“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.
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
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?
