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Design of Sub-Sea Pipelines

Written by Anup Kumar Dey in Pipeline

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

What is a Sebsea Pipeline?

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

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

Advantages and Disadvantages of Sub-Sea Pipelines

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

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

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

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

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

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

Subsea pipelines are subjected to various vertical and horizontal forces.

Design of Subsea Pipelines

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

Fig. 1: Steps for Subsea Pipeline Design

Identifying Requirements to Transport Product

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

Identification of Codes and Standards for Sub-sea Pipeline Systems

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

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

Pipeline Internal Diameter Calculation

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

Deciding Pipeline Material

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

Pipeline Wall Thickness Calculation

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

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

Pipeline Route Selection

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

On-Bottom Stability

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

Pipeline Stress Analysis

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

Pipeline Installation Analysis

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

Construction and Installation of Subsea Pipelines

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

Pipeline Fabrication:

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

Installation:

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

Subsea Infrastructure:

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

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

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

Written by Anup Kumar Dey in Pipeline

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

What is a Pipeline Block Valve?

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

How Do Pipeline Block Valves Work?

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

Types of Pipeline Block Valves

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

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

What is a Pipeline Block Valve Station?

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

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

Key features of a pipeline block valve station may include:

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

Importance of Pipeline Block Valves

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

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

Installation and Maintenance

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

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

Safety Considerations

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

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

Common Problems Associated with Pipeline Block Valves

The most common problems associated with pipeline block valves are

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

Design Guidelines for Pipeline Block Valve Stations

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

Components of a Pipeline Block Valve Station

The main components of a pipeline block valve station are:

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

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

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

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

Pressure Safety Valve Sizing | Relief Sizing Calculation

Written by Rakesh Sutrave in Process

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

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

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

Design and Sizing Terms

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

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

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

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

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

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

Relief Device Sizing:

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

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

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

Sizing for Liquid service:

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

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

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

Where

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

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

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

In Equation 4,

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

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

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

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

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

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

Liquid Sizing Example

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

Sizing for Gas Service

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

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

Where

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

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

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

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

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

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

Gas Sizing Example:

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

References:

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

ADDITIONAL RESOURCES

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

What’s New in Caesar II-Version 14?

Written by Anup Kumar Dey in Caesar II

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

Caesar II Version 14

Newly Added Codes and Standards

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

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

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

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

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

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

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

Updates in Material and Content Database

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

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

Improvements in Static and Dynamic Analysis

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

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

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

Other Improvements

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

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

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

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

References and Further Studies:

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

Pipeline Engineering Interview Questions

Written by Anup Kumar Dey in Pipeline

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

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

Reciprocating Compressor Sizing

Written by Rakesh Sutrave in Mechanical

A reciprocating compressor is a kind of positive displacement compressor that compresses and delivers air or gas at high pressure using a reciprocating component, such as a piston or plunger. The piston of the reciprocating compressor moves forward and backward, compressing the gas or air. For this reason, another name for it is a piston compressor.  The gas or air in this compressor is drawn into the chamber and compressed by a reciprocating piston. The working fluid volume is moved by this piston to function. Applications requiring both high gas pressure and low flow rate are often served by reciprocating air compressors. Fig. 1 below shows the working of a reciprocating compressor.

Working of a Reciprocating Compressor
Fig. 1: Working of a Reciprocating Compressor

Codes and Standards for Reciprocating Compressor:

Various codes and standards govern the design and manufacture of reciprocating compressors:

  • API Standards: API-11P (Packaged Reciprocating Compressors) and API-618 (Reciprocating Compressors for Petroleum, Chemical, and Gas Industry Services)
  • ISO Standards: ISO-13707 and ISO-13631
  • Shell DEP: DEP 31.29.40.31
  • API RP 688 for Pulsation and Vibration Control

Reciprocating Compressor Sizing:

Reciprocal compressor sizing has been a task for many decades.  Engineers, packagers, and end users can benefit from the robust sizing software offered by the majority of reciprocating compressor OEMs nowadays.  However, these sizing tools might produce inappropriate and deceptive hardware suggestions if not used carefully and with attention to detail.

A typical compressor sizing methodology proceeds as follows:

  • Inlet and discharge pressures and a desired flow rate are specified by the Client.
  • A gas analysis or equivalent is specified by the Client.

Steps for selecting the proper compressor:

  1. Calculate the compression ratio.
  2. Choose the number of stages of the compressor.
  3. Calculate Estimated BHP.
  4. Calculate estimated Discharge Pressure.
  5. Calculate the discharge temperature.
  6. Determine the suction volumetric efficiency.
  7. Calculate the required piston displacement.
  8. Determine the Velocity of Valves
  9. Determine the Gas rod loads.
  10. Selecting of Reciprocating Compressor cylinder and Frame by using the OEM Design Data

OEMs typically carry out steps 1 through 10 using sophisticated software, however hand calculations are frequently sufficient.

Step 1: Calculate the Compression Ratio (CR):

A single-stage compressor has only a single R-value. Whereas a typical two-stage compressor has three R values.

  • CR (or) R = total compression ratio for the compressor
  • R1 = compression ratio for the first stage
  • R2 = compression ratio for the second stage

R = Pd/Ps, R1 = Pi/Ps, R2 = Pd/Pi

Here,

  • Ps=Suction pressure,
  • Pd=Discharge pressure,
  • Pi=Interstage pressure – the pressure between the 1st and 2nd stages of the compressor.

Step 2: Calculate / Choose no. of stages of the compressor:

The number of stages can also be determined using the thumb rule, which is shown in Fig. 2, however, it depends on the OEMs.

R-value vs Number of Stages
Fig. 2: R-value vs Number of Stages

Step 3: Calculate Estimated Power (BHP):

Where, Ƹad = Volumetric adiabatic Efficiency (From Figure 3); k = specific heat of the gas.  Compression Ratio R= (P2/P1); Flow Rate (MMSCFD)

Compression Ratio vs Estimated Efficiency
Fig. 3: Compression Ratio vs Estimated Efficiency

Step 4: Calculate estimated Discharge Pressure (Psia)

It is crucial to estimate the number of stages, power required, and interstage pressures.  Every OEM has a set number of frames and a family of standard cylinders that are predesigned to fit those frames.  As a result, the number of possible frame/cylinder combinations is limited.  The best option any specific OEM can offer is at least one of the potential combinations.

Step 5: Calculate the discharge temperature (oR)

The life of the valves and piston rings is directly impacted by the compressor’s discharge temperature. The discharge temperature of an air-cooled single-stage compressor can be determined using the following formula:

  • Ts Suction temperature °R (°K)
  • Ps Suction pressure PSIA (Bar-a)
  • Pd Discharge pressure PSIA (Bar-a)
  • R Compression Ratio (Pd/Ps)
  • n specific heat ratio of the gas.

Step 6: Determine the suction volumetric efficiency

Volumetric efficiency includes many factors that help explain the differences between ideal gas behavior and real gas behavior. In general, volumetric efficiency depends upon compression ratio, cylinder clearances, gas compressibility values, and the ratio of specific heats (k or N value) (Z1, Z2, and k values are specified in Gas properties). CL might be 15% (CL = 0.15) for normal cylinders and 65% (CL = 0.65) for pipeline cylinders.

*Where L is taken from Figure 4.

Ratio of Compression vs Loss Correction
Fig. 4: Ratio of Compression vs Loss Correction

Step 7: Calculate the required piston displacement

Piston displacement is the actual volume displaced by the piston as it travels the length of its stroke from Position 1, bottom dead center, to Position 3, top dead center.  Piston displacement is normally expressed as the volume displaced per minute or cubic feet per minute. 

Step 8: Determine the Velocity for Valves

Compressor valves are the most critical part of a reciprocating compressor.  Generally, they require the most maintenance of any part.  They are sensitive both to liquids and solids in the gas stream, causing plate and spring damage and breakage.  When the valve lifts, it can strike the guard and rebound to the seat several times in one stroke.  This is called valve flutter and leads to breakage of valve plates.

Where,

  • V = average velocity in feet/minute.
  • D = cylinder displacement in cubic feet/minute.
  • A = total inlet valve area per cylinder, calculated by valve lift times valve opening periphery, times the number of suction valves per cylinder, in square inches.

Step 9: Determine the Gas rod loads

Gas rod loads are calculated based on internal cylinder pressures. The equations below are based on pressures in gauge units. If absolute units are applied, then additional terms for Patm being applied on the piston rod diameter must be included.

Thumb Rules for good Compressor sizing:

  1. Rod loads < 100%
  2. Rod reversal Degree (Xhd pin degree / % Rvrsl Lbf) > 30% & Force > 25%.
  3. Cylinder Discharge Temperature < 300oF (Some OEMs allow < 350 oF)
  4. Volumetric Efficiency >15%
  5. Discharge Events > 4.5ms; >2.5ms (With Speed Reversal).
  6. Ideal BHP load is 75-100%
  7. Pressure Ratio F/F ideally should be < 3:1

Step 10: Selecting of Reciprocating Compressor cylinder and Frame by using the OEM Design Data

Once the above steps are calculated, use the calculated Volumetric Efficiency, Maximum HP, Displacement, Discharge Temperature, and Gas Rod Loads and check with respective OEMs design data to determine the number of Strokes and speed (RPM). Using these Strokes and speed calculate the Cylinder Area as per below.

By this, the Cylinder area is determined which helps in finding out the right Cylinder bore and Cylinder model. It also helps us in deciding the number of Cylinders used in the multistage compressor. Attached below is the Performance chart for reference where it satisfies all the user criteria and with cost cost-effective selection of the reciprocating compressor and its frames and cylinder Models.

A Typical OEM software compressor Sizing outputs for Reference
Fig. 5: A Typical OEM software compressor Sizing outputs for Reference