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The Importance of Y Factor in ASME B31.3

Written by Kourosh Mashayekh in Piping Stress Analysis,Piping Stress Basics

The Y factor is a dimensionless coefficient used for calculating the required wall thickness (t) for thin-walled pipes under internal pressure. According to Equation 3a of ASME B31.3, for determining the design pipe thickness, the application of the Y factor results in a reduction in the calculated wall thickness. In this article, we will examine the significance of factor Y in pipe wall thickness calculations.

The equation for pipe wall thickness calculation as per ASME B31.3 is given as

ASME B31.3-(3a): t = P.D/[2.(SEW+PY)]

Where:

  • t = minimum required pipe wall thickness (excluding corrosion allowance)
  • P = internal design pressure
  • D = outside diameter of the pipe
  • S = allowable stress of the pipe material at design temperature
  • E = quality factor (depending on pipe manufacturing method)
  • Y = coefficient from B31.3
  • W = Weld Joint Strength Reduction Factor

Significance of Y-Factor in Pipe Thickness Calculation Formula

From the above equation, we can understand and interpret the reasons for using the Y factor as follows:

Simplification of thickness calculation: Instead of applying the equation for thick-walled pressure vessels, a simplified approach with a correction factor is used.

Design optimization: Prevents overestimation of the required wall thickness, thereby reducing project costs while maintaining compliance with safety requirements.

The pipe thickness is calculated based on the Lame’s hoop stress equation:

Lame’s hoop stress equation
Lame’s Equation

According to this equation, the stress across the pipe wall is not uniformly distributed. Therefore, to simplify the calculation and compensate for the non-uniform stress distribution, the Y factor is introduced.

Typical Values of Y-Factor in ASME B31.3

The value of Y is determined based on empirical data, allowing for some initial yielding at elevated temperature ranges.

Coefficient Y Values as per ASME B31.3
Coefficient Y Values as per ASME B31.3

According to the provided table, an increase in temperature leads to an increase in the Y factor for certain materials. This implies that the code allows greater flexibility in thickness calculations at elevated temperatures, which is attributed to the material behavior under such conditions. A detailed explanation is provided below:

Based on Lame’s equation, the hoop stress is higher at the inner wall of the pipe compared to the outer wall, resulting in a non-uniform stress distribution. If wall thickness were calculated solely based on this equation, no Y factor would be applied, and the design would be based on the maximum hoop stress.

However, experimental observations have shown that localized yielding initially occurs at the inner wall of the pipe. This yielding does not lead to failure but instead allows for stress redistribution to other regions (e.g., the middle and outer wall). This process leads to a more uniform stress distribution across the pipe wall. As a result, the actual stress experienced by the pipe is lower than the peak value predicted by Lamé’s equation.

At higher temperatures, materials become softer, localized yielding occurs earlier, and the material naturally redistributes stress more effectively. Therefore, the code allows for a higher Y factor at elevated temperatures, acknowledging that the risk of stress concentration decreases due to improved stress distribution in softer material conditions.

It is important to note that for gray iron, the Y factor is specified as zero. This is because gray iron is brittle, has low tensile strength, and tends to fail suddenly without significant deformation. Due to its poor ability to absorb and redistribute localized stresses, the code adopts a conservative approach, not allowing any reduction in thickness through the Y factor.

For other ductile non-ferrous metals, the Y factor is constant across all temperatures. This is because such materials are already softer and more ductile than ferrous metals even at low temperatures. Therefore, localized yielding and stress redistribution occur early, and temperature increase does not significantly improve stress distribution. So, the code assigns a fixed Y value for all temperature ranges.

If the Y factor is not applied and the wall thickness is calculated based solely on the maximum hoop stress, the following consequences may occur:

  • Increased material costs
  • Greater complexity in welding and fabrication
  • More challenging inspection and maintenance
  • In most practical cases, economic efficiency is compromised without providing a meaningful increase in safety

References

  • ASME B31.3 – Process Piping Code
  • Pipe Stress Engineering – L.C. Peng and T.L. Peng

Piping Material Engineer Interview Questions

Written by Anup Kumar Dey in Engineering Materials

Piping Materials Engineers work quietly to ensure the reliability, safety, and integrity of critical piping systems in the oil and gas, petrochemical, power generation, and other industrial sectors. They play a crucial part in the selection, specification, and management of piping materials, ensuring that every pipe, fitting, flange, valve, and gasket stands up to the operational demands and environmental challenges it faces.

A piping materials engineer is a mechanical, metallurgical, or chemical engineer specialized in selecting and specifying materials for piping systems used in industrial facilities such as refineries, offshore platforms, chemical plants, and power plants. Their decisions directly affect the safety, cost-efficiency, and longevity of piping networks, making their expertise essential during the engineering design phase of a project.

Good piping material engineers are always in demand, and frequently they face interviews for various engineering positions. In this article, I will list some of the most frequently asked questions to help them prepare for any upcoming interview.

Piping Material Engineer Interview Questions

Here is a list of some of the most common interview questions for a piping material engineer. If you know some more questions that need to be added to this list, please specify those in the comments section, and I will add them to the main list from time to time.

  1. As a piping materials engineer, what roles have you performed in your previous company?
  2. Have you performed pipe thickness calculation? Can you specify the pipe thickness calculation formula as per the ASME B31.3 code?
  3. What is the significance of the E factor and W factor in the pipe thickness calculation formula?
  4. What are the parameters on which the E factor and W factor depend?
  5. What is the meaning of mill tolerance? What do you understand when it is said that mill tolerance is 12.5%? Does mill tolerance always remain at 12.5% or does it vary?
  6. From where to get the values of mill tolerance for pipe thickness calculation?
  7. Do E, W, and Y factors change or remain constant? If changes, can you specify how?
  8. What is corrosion allowance, and from where to get the value of corrosion allowance? Who will decide the corrosion allowance value?
  9. What do you consider when there is a vacuum condition in a piping system?
  10. What is the branch thickness calculation philosophy?
  11. When and why do we perform branch thickness calculation?
  12. What is Piping Material Specification and Piping Class? Have you ever generated any PMS or Piping class? What are the considerations?
  13. What are the differences between a PMS and a piping class?
  14. What information is typically included in a piping material specification? What are the input documents to a PMS? What information does a PMS give?
  15. What do branch tables specify?
  16. What is the difference between a stub-in and stub-on connection? Which one is stronger?
  17. ASME B31.3 specifies two pipe thickness calculation formulas. How do you decide which one to follow?
  18. What are the assumptions for pipe thickness calculation based on ASME B31.3?
  19. Have you worked in power piping (B31.1)? For the same piping with the same temperature and pressure conditions, which code will provide thicker material, and why?
  20. What are the common pipe fittings, and what are their governing design codes/standards?
  21. What are the differences between a code, a standard, and a specification?
  22. Valves are designed based on which standard?
  23. What are the different types of valves, and how do you decide the materials forthe valve body?
  24. What is the meaning of valve trims? In general, valve trim is of which materials?
  25. What is the meaning of VMS?
  26. Explain the terms: MTO, BOQ, BOM
  27. What are the stages of MTO?
  28. For a design temperature of -46° C, which piping material is generally used?
  29. For a piping material of A-106 Gr B, what is the common fitting material?
  30. What is the impact of temperature on material selection?
  31. What are the major differences between A106 Gr B and Gr C?
  32. What is TBE, and what is the role of a piping material engineer in TBE?
  33. Have you heard the term, Piping Specialty Item? Can you please provide 5 examples of piping specialty items?
  34. What is the equation for Line Blank Thickness Calculation?
  35. Have you prepared any datasheets for piping specialty items? If yes, what are the contents of a datasheet?
  36. As a piping materials engineer, do you use any software?
  37. Are you aware of the term “SMAT” or “SPM”, AVEVA ERM, and PUMA?
  38. What are the different types of ferrous materials you know?
  39. What are the differences between low alloy steel, high alloy steel, and LTCS?
  40. How do you decide when to use seamless vs welded pipe?
  41. What is CE value? Have you heard the term PREN?
  42. What are the differences between SS and DSS, and when are they chosen?
  43. What is the meaning of dual-certified material?
  44. What are the piping flange standards for a 16-inch and 32-inch pipe?
  45. Can you specify some differences between ASME B16.47 series A and series B flanges?
  46. What is the meaning of galvanized steel? When do you choose galvanized steel?
  47. What is the major difference between ASTM A312 TP 304, TP 304L, and TP304H?
  48. What is the difference between different stainless steel grades?
  49. How do you select materials for sour service (H₂S environments)?
  50. What is the importance of NACE MR0175?
  51. What are the typical materials used for cryogenic services?
  52. What factors influence your selection of piping material for a high-temperature, high-pressure service?
  53. What is PWHT, and when is it required?
  54. Describe how you handle corrosion allowance in piping design.
  55. What is galvanic corrosion and how do you prevent it in piping systems?
  56. Can you describe the difference between duplex and super duplex stainless steels?
  57. What are typical issues encountered with DSS and SDSS in fabrication?
  58. Have you heard the term, MTC? What do you check in a Material Test Certificate (MTC)?
  59. Describe how you develop a piping material class from scratch.
  60. How do you link a piping material specification to 3D modeling software?
  61. How do you assign valve materials in piping classes?
  62. What is the meaning of LLI? How do you handle long lead items or material shortages?
  63. How do you track and control revisions in piping material specs?
  64. What is the importance of PMI (Positive Material Identification)? How do you ensure material traceability throughout a project?
  65. How do you manage piping material delivery for a brownfield revamp?
  66. What is the difference between CS and LTCS piping materials?
  67. Explain the difference between ASTM and ASME material specifications.
  68. What are your responsibilities during FAT (Factory Acceptance Testing)?
  69. What is the difference between DSS and CRA piping materials?
  70. Describe the selection criteria for cladding vs. solid alloy piping.
  71. How does hardness testing relate to material selection for sour service?
  72. What’s the significance of impact testing in low-temperature services?
  73. How do you manage material compatibility in dissimilar joints?
  74. How do you select gasket materials for high-pressure and high-temperature service?
  75. What’s the difference between NACE MR0175 and MR0103?
  76. What is HIC and how do you mitigate it?
  77. How do you deal with ambiguous specifications or missing information?
  78. How do you evaluate suppliers for piping materials?
  79. Describe your experience with VDRL (Vendor Document Requirement List).
  80. What are the metallurgical differences between forged and cast components?
  81. How do you coordinate with process and mechanical teams on material selection?
  82. What lessons have you learned from site execution involving piping materials?
  83. How do you handle conflict with vendors or procurement over specs?
  84. Have you ever challenged a design or spec due to material concerns?
  85. How do you ensure integration of MTO data across disciplines?
  86. How to decide the Hydrotest Pressure for oil and gas piping? What are the criteria for Hydrostatic testing and pneumatic testing?
  87. Have you used A106-Gr B material for (-)45 Deg C temperature? Can it be used? Under What condition?
  88. What is the type of corrosion allowance selected for a pipe subjected to internal pressure?
  89. Explain in detail the procedure to check whether the pipe is suitable when subjected to external pressure.
  90. What is the basic concept behind the Rpad calculation?
  91. How is the impact test considered for the ASTM 516 plates?
  92. What are the design requirements of a valve subjected to cryogenic service?
  93. Why is a spectacle blind generally not preferred or used in cryogenic service?
  94. What are the important points/clauses to be considered while preparing the Technical or Purchase or Supply specification?
  95. What is the procedure from MTO preparation to the issuance of Inquiry MR to TBE to Issuance of Purchase order?
  96. What are the documents required to be attached while issuing MR?
  97. What are the generally used design standards for gate, globe, check, ball valve, and plug valves?
  98. What is the standard to specify a valve as fire-safe? What is the fire-safe requirement in a valve?
  99. What are the general temperature limits for BUNA-lined, EPDM, PTFE, and metal seats used in valves?
  100. What is the difference between API 600 and ASME B16.34?
  101. What are the requirements to select a suitable trap size?
  102. What are the different types of strainers?
  103. For a 16” Tee type strainer, end connection with Flanges or Buttwelded which is more beneficial and why?
  104. What is the total amount of man-hours you worked on a single project, and the number of MR/POs handled?
  105. What were the earlier and present exemption thicknesses for carbon steel material subjected to PWHT as per ASME B31.3?
  106. What do you include in a component datasheet?

If you are aware of any additional questions that you have faced in any interview, kindly mention those in the comments section.

Extractive Distillation for Aromatics Separation

Written by Sujoy Maity in Process

What is Extractive Distillation?

Aromatics, such as benzene, toluene, xylene, and ethylbenzene, are crucial raw materials in the petrochemical industry. These compounds are used extensively in the production of plastics, synthetic fibers, pharmaceuticals, and a wide range of industrial chemicals. However, the separation of aromatics from complex hydrocarbon mixtures, such as naphtha or reformate, can be challenging due to their close boiling points and the presence of azeotropes.

Extractive distillation is a highly effective technique for separating aromatics from non-aromatic hydrocarbons. This process involves the use of a selective solvent that alters the relative volatility of the components in the mixture, thereby enabling their separation.

This report provides a detailed analysis of the principles of extractive distillation, its importance in aromatics separation, the solvent selection criteria, and the effect of molecular weight on solubility. It also examines the key challenges and benefits associated with the process, providing insight into its practical applications and future potential in the petrochemical industry.

Principles of Extractive Distillation

Extractive distillation is a variation of conventional distillation, where a selective solvent is added to the mixture to modify the relative volatilities of the components. This solvent interacts more strongly with the desired component (e.g., an aromatic compound) than with the other components (e.g., alkanes or cycloalkanes), thus making the desired compound less volatile compared to the remaining components. The solvent forms strong intermolecular bonds (e.g., hydrogen bonding, dipole-dipole interactions) with one of the components in the mixture. This strong interaction reduces the partial pressure of that component in the vapor phase, effectively decreasing its volatility. By selectively decreasing the volatility of one component, the relative volatility between the components is enhanced, making their separation easier in a distillation column. As a result, the aromatic compounds can be separated more efficiently from non-aromatic hydrocarbons.

Unlike simple distillation, which relies on differences in boiling points, extractive distillation works by altering the relative volatility between the components, making it possible to separate compounds with very close boiling points or those that form azeotropes.

Why is Extractive Distillation Needed for Aromatics Separation?

The separation of aromatics from other hydrocarbons, especially in complex mixtures such as naphtha or reformate, is often a challenge due to the following reasons:

Close Boiling Points:

Many aromatic compounds share similar boiling points with non-aromatic hydrocarbons. For example, benzene (80.1°C) and cyclohexane (80.7°C) are difficult to separate using conventional distillation due to their very close boiling points. It would require ~ 750-1000 separation stages or even more numbers of stages for a fractional distillation column, making it non-feasible.

Azeotrope Formation:

In some cases, azeotropes are formed between aromatic and non-aromatic hydrocarbons, making their separation impossible by standard distillation methods.

High Purity Requirements:

Aromatic compounds must often be separated with high purity, especially for downstream applications such as polymerization or pharmaceutical synthesis. Conventional distillation may not achieve the required purity levels.

Economic and Environmental Considerations:

Extractive distillation offers a more energy-efficient and sustainable alternative compared to other separation technologies. Using selective solvents reduces the energy required for separation, and the solvent can be regenerated and reused, minimizing waste.

Solvent Selection for Extractive Distillation

The selection of an appropriate solvent is critical in extractive distillation, as it directly influences the efficiency and economics of the separation process. The key criteria for selecting solvents include

  • Selectivity: The solvent should selectively interact with the desired aromatic compound and enhance its volatility. For example, N-Methyl-2-pyrrolidone (NMP) is a commonly used solvent due to its high selectivity for aromatic compounds.
  • Capacity: The solvent should have a high capacity to dissolve a large amount of the aromatic compound. The capacity of a solvent refers to its ability to absorb or extract the target compound from the mixture without excessive consumption of solvent.
  • Boiling Point and Volatility: The solvent should have a boiling point that is higher than that of the aromatic compounds to ensure efficient separation and easy solvent recovery after the process.
  • Solvent Regeneration: The solvent must be regenerable and reusable to minimize costs and environmental impact. Common solvents such as water, NMP, and ethylene glycol can be regenerated for repeated use in the process.
  • Solvent-Mixture Compatibility: The solvent should be compatible with the entire distillation system and should not react with other components in the mixture.

The Effect of Molecular Weight on Aromatic Solubility

The solubility of aromatics in solvents is significantly influenced by the molecular weight of the aromatic compounds. Generally, as the molecular weight of an aromatic compound increases, its solubility in most solvents tends to decrease. This is due to the increased hydrophobicity and larger molecular size, which makes it harder for solvents to interact with the aromatic molecules.

For example, xylene and ethylbenzene, which have higher molecular weights than benzene and toluene, show lower solubility in many common solvents. This means that solvent selection must also consider the molecular size of the aromatics to achieve effective separation.

Increasing the molecular weight of aromatics tends to reduce their solubility in many solvents, which requires careful consideration when designing extractive distillation processes for mixtures containing large aromatic compounds.

Solvent Capacity and Selectivity Balancing Efficiency

In extractive distillation, the balance between selectivity and capacity of the solvent is critical for achieving optimal separation efficiency. Selectivity refers to the solvent’s ability to preferentially extract the aromatic compounds over other hydrocarbons, while capacity refers to the solvent’s ability to dissolve or extract the desired compound.

By adjusting the solvent mix (e.g., a combination of NMP and water), it is possible to achieve a balance that maximizes both capacity and selectivity. NMP has high selectivity for aromatics like benzene, but its capacity can be limited by its relatively low solvent concentration. Combining NMP with water or another solvent can enhance the overall capacity of the solvent mix while maintaining high selectivity for aromatics. The same is true for BD extraction process-related technologies, e.g., the BASF NMP process.

Benefits of Extractive Distillation in Aromatics Separation

  • High-Purity Separation: Extractive distillation enables the separation of aromatics with high purity, which is crucial for downstream chemical processes.
  • Energy Efficiency: Extractive distillation requires less energy compared to traditional distillation methods, making it a cost-effective option for large-scale separation.
  • Sustainability: The use of regenerable solvents reduces waste and minimizes the environmental impact of the separation process.
  • Flexibility: Extractive distillation can be tailored to specific feedstocks and separation requirements, making it adaptable to a wide range of industrial applications.

Conclusion

Extractive distillation is an essential technology for the separation of aromatics from complex hydrocarbon mixtures, particularly when traditional distillation methods fail due to close boiling points or azeotrope formation. By using selective solvents, extractive distillation enhances the purity of the desired aromatic compounds and provides a cost-effective, energy-efficient, and sustainable solution for large-scale industrial applications.

The selectivity and capacity of the solvent, along with the influence of molecular weight on solubility, play critical roles in achieving optimal separation. As the demand for high-purity aromatics continues to grow, extractive distillation will remain a cornerstone technology in the petrochemical industry.

References

  • BASF Research Journal, 2019. “Solvent Selection and Efficiency in Aromatics Separation by Extractive Distillation.”
  • Schneider, T., et al., 2018. “Effect of Solvent Properties on the Separation of Aromatic Compounds in Extractive Distillation.” Journal of Chemical Engineering.
  • Park, S. et al., 2020. “Advancements in Extractive Distillation: Solvent Effects and Efficiency.” Chemical Engineering Science, 204: 233-245.
  • Chung, D., et al., 2021. “Molecular Weight and Solubility in Aromatic Separation.” Journal of Applied Polymer Science, 138: 41350.

GRE Design Envelope and Failure Envelope

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

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

Written by Anup Kumar Dey in Caesar II

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

Written by Hussein Elgenedy in Process

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.