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Dry Gas Sealing Systems

Written by Anup Kumar Dey in Mechanical,Piping Design Basics,Piping Interface

Dry Gas Seals (DGS) are basically mechanical face seals consisting of a mating (rotating) ring and a primary (stationary) ring. During operation, grooves in the mating ring generate a fluid-dynamic force causing the primary ring to separate from the mating ring, thus, creating a “running gap” between the two rings.  The running gap varies from 3 to 10 microns depending on the seal type.

A sealing gas is injected into the seal, providing the working fluid for the running gap and the seal between the atmosphere or flare system and the compressor internal process gas.

  • Primary Dry Gas Seal: Preventing leakage of working gas from a machine’s inner side.
  • Secondary Dry Gas Seal: Backing up the first dry gas seal.

Application of Dry Gas Sealing

Dry Gas Sealing is widely used on

  • Compressors for pipelines
  • Off-shore applications
  • Oil refineries
  • Petrochemicals &
  • Gas processing plants
Dry Gas Sealing

Principle of Dry Gas Sealing operation

Hydro-dynamic pressure- Tiny grooves cut into the face of the rotating ring scoop gas in between the seal faces creating enough pressure to overcome the tension of the spring holding the faces together.

Gas is scooped into this tight space forcing it to overflow outwards into the gap between the faces forcing them apart

The seals are kept from touching by the generation of hydro-dynamic pressure, created by small grooves cut into the face of the rotating ring which draws gas into the seal, forcing the two surfaces apart.

Because the space between the seals is less than human hair, the sealing gas used must be completely dry and free from grit, dust, or moisture. An external source of sealing gas is therefore used to ensure cleanliness.

dry gas sealing operation

The tandem seal system is designed so that after the failure of the primary seal, the machine can be safely shut down using the containment provided by the secondary seal without a hazardous release of gas into the atmosphere.

Although these dry gas seals are able to handle high levels of vibration without damage, reverse rotation of the shaft at high speeds will damage the seals as they are not able to develop the hydro-dynamic pressure required to push the sealing faces apart.

Single Seal, double seal and tandem seal

Seal Gas

The supply of filtered buffer gas is injected into the cavity between the primary gas seal and the inboard labyrinth. This supply of gas will leak past the inboard labyrinth back into the compressor which will ensure that the cavity is free from liquids or particles that could damage the gas seal. The supply gas will also leak past the primary gas seal, into the cavity between the primary and secondary gas seals which is directed to an approved vent or flare system.

Labyrinth Seals

Labyrinth seals are used in conjunction with dry gas seals in order to restrict the leakage between chambers around the seal. A labyrinth seal works like a maze, creating a torturous path  which the fluid needs to flow through in order to escape

Lubricating oil from the compressor bearings is prevented from entering the dry gas seal by the use of a simple labyrinth seal supplied with separation gas to create a barrier to the migration of lube oil. The labyrinth seals are a “non-contact” type of seal with very fine clearances. Using a system of notches and grooves, the pressure is broken down little, by little so that leakage is minimized (not stopped)

Pressure Balancing

The thrust created by the high-pressure discharge pushing the compressor rotor back towards the suction is canceled by creating opposing thrust using a balance drum.

This pressure balancing system also means the compressor seals are only ever exposed to suction pressure!

Primary Gas

Primary gas is injected in front of the seal to create a positive flow. It is used to ensure the gas entering the seal is completely dry and clean, completely free from dirt, dust, and moisture.

Secondary Gas

Secondary gas is nitrogen used to provide a clean source of gas to the secondary seal faces. The 2 seals are separated by another labyrinth and the leakage gas is lead to an atmospheric vent in a safe location (above the building)

Separation Gas

Separation gas is nitrogen used to keep lube oil from the adjacent bearing housing from leaking into the dry gas seal system

The typical control scheme for dry gas sealing

A controller maintains a constant differential pressure above suction pressure, while the flows to each seal are also monitored to check seal integrity.

typical control scheme for dry gas sealing

Seal gas vent

  • The vent system is kept under back pressure bypassing the flow through a restriction orifice. A secondary path is opened by bursting a ruptured disc to safely vent the higher flows caused by seal failure.
  • A differential pressure transmitter monitors the pressure between the seal supply and the low-pressure vent.  When the seal is healthy, this dP is high (Primary Seal Gas supply pressure on one side and Flare pressure on the other side). This high dP is used as a start permissive for the compressor. When the seal fails, the dP becomes low, initiating a compressor trip.
  • In addition, we measure the pressure in the vent line, upstream of the orifice. In the event of seal failure, this pressure becomes high due to the increased flow to the flare. This high-pressure alarm is also used to trip the compressor.

Seal gas filters

It is extremely important the seal gas is clean and dry. A 2-micron fine filter is fitted with a standby element ready for the changeover.

A “smart ring” sequencing system is used to prevent the maloperation of filter valves.

Types of Dry Gas Seals

Dry Gas Seals have mainly configured in four types.

(a) DGS Single seal: These seals shall be used where product leakages to the atmosphere are recognized as safe Example: Nitrogen or CO2 compressors.

(b) DGS Tandem seal: Where small product leakages of process gas are admissible. Example: on gas pipeline compressors.     

(c) DGS Tandem seal with intermediate labyrinth: These seals shall be used where product leakages to the atmosphere as well as buffer gas leakages to the product are admissible. Example: on H2, ethylene or propylene compressors.

(d) DGS Double seal: These seals shall be used where product leakages to the atmosphere are inadmissible. However, buffer gas leakages into the product gas is admissible. Example: Petrochemical compressors

–   Seal on the atmosphere side acting as a safety seal. Tandem seals are mostly used in process gas service mainly in high-pressure and/or hazardous gas applications.

Seal Gas sources: (a) External seal gas &  (b) Compressor discharge gas.

Normally the seal gas is injected about 10 psi above the process gas.

Barriers shaft sealing system

It is necessary to avoid allowing the bearing lubrication oil to reach the

seal faces. Barrier gas is injected into the barrier seal chamber to separate the bearing housing

  • -In most cases, Nitrogen shall be used as barrier gas for safety reasons.
  • A barrier seal is incorporated in the outboard end of the dry gas seal assembly.

Dry Gas Sealing design considerations

(a) Design pressure of seal (static/dynamic)

(b) Process pressure in the compressor at normal operation

(c) Process settle out pressure in the compressor

(d) Pressure of seal gas

(e) Design minimum temperature (static/dynamic)

(f) Design maximum temperature (static/dynamic)

(g) Normal seal gas supply temperature in operation

(h) Filter size seal gas: 3 – 5 microns

DGS Operating Range

  • Temp: -140 to +315°C
  • Pressure: to 350 Barg
  • Speed: to 200m/s
  • Shaft: to 350mm dia

Advantages of DGS over Wet seals:

The following can be eliminated

  • Process contamination and catalyst poisoning with oil.
  • Unscheduled shutdowns caused by loss of control of the seal oil system and/or seal oil pumps/driven failures.
  • Lube oil contamination with the process gas.

Things to remember on replacement of oil seals with Dry Gas Seals

The following points shall be thoroughly analyzed prior to the replacement of Liquid seals with DGS.

  • Seal chamber dimensions & ports
  • Compressor rotor dynamics
  • Compressor operating conditions & variations
  • Seal gas & barrier gas supply source
  • Reverse rotation & surge occurrence
  • Idle operations at low speeds
  • Maintenance facilities & spare parts availability.

Codes / Standards for Dry Gas Seals

  • API 614 – Lubrication, shaft sealing & Control oil system & auxiliaries
  • API 617 – Centrifugal compressors for Oil, Gas & Petrochemicals

Dry Gas Seal leakage rates

Seal leakage rates in operation (on-site)

(a) Seal medium: Process gas- Seal leakage rates for seal testing conditions

(b) Seal medium: air

–  Expected leakage rates shall always lower the values of guaranteed leakage rates. And outboard leakage rates shall be lower than inboard leakage rates.

Static sealing pressure shall be equal to the compressor casing design pressure.

Acceptance criteria for seal leakage rates

The seal leakage is considered to be stable and acceptable for Stable guarantee points if it varies within +/-5% around an average level.

Gas seal contamination

Liquid drop-out/condensation from the seal gas due to inadequate gas conditioning and filtration

Ingress of raw process gas due to poor gas monitoring and control

Ingress of bearing oil due to loss of separation gas or product failure

Inadequate gas seal monitoring

Outboard (OB) seals are often not monitored:

A failed OB stage can be undetected leading to catastrophic damage to the seal/compressor

If the inboard stage should fail during this situation, it will result in the leakage of untreated process gas into the atmosphere

Improve gas conditioning by one or more of the following:

  • Removing liquids from the sealed gas
  • Heating the seal gas
  • Filtering the seal gas
  • Boosting the seal gas
  • Improve gas seal monitoring in order to:
  • Detect the condition of the gas seal, both inboard and outboard stages
  • Ensure no ingress of raw process gas or bearing oil
  • Ensure no reverse pressurization

Flange Bolt Tightening Procedure | Bolt Tightening Steps

Written by Anup Kumar Dey in Engineering Materials,Mechanical,Piping Design Basics,Piping Interface

The correct placement of the gasket and proper tightening of bolts in a flanged joint will ensure a leak-free joint. Proper bolt tightening will ensure uniform load distribution in all bolts without damaging the gaskets. The following procedure describes how to tighten flange bolts.

Flange Bolt Tightening Procedure

Before actual tightening starts, the flange, gasket, and bolts/nuts need to be observed as below:

Flange checking points before flange bolt up

Leakage through a flanged joint is prevented as gasket material flows inside the flange surface imperfections and seals them. But there are limitations that a gasket can successfully seal. Hence, Flange surfaces must be checked thoroughly to ensure the absence of large nicks, dents, or gouges. So the flange surface finish must be as per the manufacturer’s recommendation for particular gasket materials. Recommended values of flange surface roughness are as follows:

  • Solid Metal Gaskets: 63-80 rms
  • Spiral Wound Gaskets: 125-250 rms
  • Jacketed or Metal Clad Gaskets: 63-80 rms

Here, RMS stands for root mean square. Roughness is normally specified in millionths of an inch as the average of the peaks and valleys measured from a midline of the flange surface.

A flange is recommended to be machined using a 1/16″ radius, round-nosed tool to have 30-55 serrations per inch in a concentric or spiral pattern.

Bolted Flanged Joints at operating plant
Fig. 1: Bolted Flanged Joints at the operating plant

Check the following points prior to flange bolting.

  • Before inserting the gasket in between the pipe flanges, check the flanges are parallel and co-axial (When none of the bolts is installed in the flange).
  • As per ANSI B31.3 clause no. 335-C, permitted tolerances are as follows: Flange faces shall be aligned to the design plane within 1 mm in 200 mm(1/16 in. /ft) measured across any diameter; flange bolts holes shall be aligned within 3 mm (1/8 inch) maximum offset.
  • If pipe flanges are not meeting the ANSI B31.3 requirement, the piping shall be rectified.
  • All gasket seating areas shall be cleaned properly before gasket insertion. If serration is damaged, re-serration must be done.

Checkpoints for Gasket prior to tightening flange bolts

  • Ensure the gasket of the correct dimension and of specified material is used.
  • The gasket shall be located correctly to ensure full sealing as indicated in the drawing. For example – a gasket on the tube sheet of an exchanger needs to be located so that the outer periphery of the gasket matches the OD of the tube sheet at all points.
  • Examine the gasket in advance and ensure that it is free from defects.

Bolts for Pipe Flanges

Bolts create compressive pressure on the flanges and gasket so that leakage is prevented. So, while selecting, the temperature variations in service must be considered. Recommended values of flange bolting temperature are as under.

Recommended Bolt Temperatures with respect to materials
Fig. 2: Recommended Bolt Temperatures with respect to materials
  • Ensure that the material of all bolts and nuts is as specified.
  • Bolts & nuts shall be cleaned with suitable solvents like Diesel / CTC using a wire brush, especially in the threaded portion.
  • The bolt shall be lubricated with molybdenum disulfide and it is essential, especially in all bolts of size 7/8” and above to check the application as the bolt load developed by torque is dependent on the lubrication of threads.
  • It is recommended to avoid the use of short bolts on the flange joints.

Flange Bolt Tightening Procedure

It is important that all bolted joints are tightened uniformly and in a diametrically staggered pattern (A typical sketch is attached in Fig. 3).

Typical sketch showing bolt tightening pattern.
Fig. 3: Typical sketch showing bolt tightening pattern.

In the case of pipe flanges 8″ NB & up to 12″NB and having a pipe with a spacer piece and a minimum of two gaskets (which are getting compressed simultaneously during tightening) the distance between two flanges should be measured at four locations like 12’o clock, 3’o clock’ 6’o clock and 9’on clock positions and maintained equal for even tightening. The tightening shall be gradual and uniform. In case of flanges above 12” NB distance between the flanges shall be measured in 8 locations for uniform tightening.

All stud bolts of 7/8″ and above shall be tightened using a torque wrench. While tightening the bolt with torque wrenches (for pipe / Manway flanges) ensure that the tightening load to each bolt is applied as uniformly as possible. The tightening shall be carried out in three or four stages in steps of 30, 50 & 70 percent of the final torque value. The fourth stage again uses 70 percent of the final torque value.

For heat exchangers flange’s torque values are to be 30,70,100 and 100 percent of the final torque value.

Where recommended use a hydraulic tensioner for bolt tightening following the manufacturer’s recommendations.

A table is provided in Fig. 4 below to show an example of torques applied for bolt tightening.

Suggested Applied Torque for ANSI 150 lb Flanges
Fig. 4: Suggested Applied Torque for ANSI 150 lb Flanges

Wrong Practices followed during Flange Bolt Tightening

Many a time, plant operators use wrong practices while flange bolt tightening as follows

  • Improper sequence of bolt tightening.
  • Reuse of old gasket.
  • Procurement of un-specified material.
  • Improper storage of gaskets.
  • Use of many gaskets to fill a large gap between flanges.
  • Use of ordinary fasteners instead of high-tensile fasteners
  • Use of dirty/rusted fasteners without lubrication.

Few more related articles.

How to Select a Bolt: A definite Guide
Bolting Features in Bolted Connections/Bolted Joints
Guide for Coating Selection for External Bolting to Reduce Corrosion
Collar Bolts To Maintain Removable Bundles in Heat Exchangers

What is a RePAD, RF Pad, or Reinforcement Pad?

Written by Anup Kumar Dey in Piping Design Basics

What is a Reinforcement PAD?

Reinforcing Pad, Reinforcement Pad, RePAD, or RF Pad is a donut-shaped pad that goes around the branch of a branch joint to add strength to the joint. It resembles a round metal washer that has been bent to conform to the curvature of the pipe.

With the increase in pipe size, the cost of branch connection fittings increases. Sometimes, such fittings are not readily available as standard pieces. So, it is a standard method to fabricate the tee by cutting a hole in the header and welding the branch in the pipe. However, the section where the straight pipe is punctured becomes a weak section due to the presence of that hole. So to handle the pressure and reduce the stress concentration in that region, the thickness is increased locally in the form of a reinforcement pad, or RF pad.

A similar situation arises for Pressure Vessel Nozzle Connections. To increase the pressure and load-carrying capability of the equipment nozzles, the RF pad is welded. These reinforcement pads provide additional strength and capability to the pipe or nozzle as per application.

Why is the Reinforcement Pad or Repad required?

RePADs, or RF Pads, are plates used to reinforce components and/or nozzles by increasing the thickness local to the component in high-stressed zones. These are made from the same size and material as the pipe header to which they are welded. On pipes or pressure vessels, holes are made in the form of a nozzle or branch intersection, and thus the parent pipe or vessel is weakened and high-stress zones are created. Hence, it is obvious to compensate for this weakness with a reinforcing pad to reduce the possibility of failure, as it strengthens the piping branch connection or the pressure vessel nozzle. The main functions of RF pads can be summarized as follows:

Added Reinforcement:

RF pads provide structural support to piping systems and equipment nozzles. They help distribute the stress and load from the nozzle or pipe across a larger area of the equipment, reducing the risk of localized stress that could lead to cracks or failures.

Better Protection:

By shielding the underlying equipment from direct contact with piping or other elements, RF pads prevent damage from abrasive or corrosive substances. They also help protect against thermal stresses and mechanical vibrations.

Improved Stress Distribution:

RF pads are designed to mitigate the impact of thermal expansion and contraction. They help distribute the mechanical stresses generated by temperature fluctuations, which is crucial for maintaining the integrity of piping and equipment over time.

Maintenance and Longevity:

RF pads can extend the life of both the nozzle and the piping system. By minimizing wear and tear on critical components, they reduce the need for frequent maintenance and replacement.

Uses of Reinforcing PAD

The main applications of RF pads are listed below

1. Normally Reinforcing pads are used at stub-on and stub-in branch connections if required per the line list or if required per the branch chart in the piping material specification. By using reinforcing pads, it is not required to strengthen the complete header pipe. Clause 304.3.3 of ASME B 31.3 provides equations to check if any welded piping branch connection requires reinforcement.

2. Support trunnions are provided with reinforcement when specified by piping stress engineers. When support loads of trunnions are greater than the bearing capability of the trunnion, reinforcing pads are welded at the parent pipe and trunnion junction to enhance its load-carrying capability.

However, please keep in mind that reinforcement on trunnions from elbows is not suggested as standard practice, so it should be avoided to the maximum extent possible. The requirement of reinforcement must be specifically mentioned in the piping isometric drawing for conveying to the construction team.

3. Equipment nozzle connections are normally reinforced so that nozzles can carry more loads and moments from the piping side.

4. Sometimes, reinforcing pads are provided in between the pipe shoe or saddle support and the parent pipe when the parent pipe thickness is less than required.

Typical Reinforcing PAD
Fig. 1: Typical Reinforcing PADs

Design Features of RF PAD

The thickness of the RF pad should match the pressure design thickness required for the branch, based on the stress generated at the piping branch connection.

Normally, the maximum thickness that is used in engineering companies as reinforcing pad thickness is 1.5 times the parent pipe thickness. Standard practice is to use the same thickness as the parent pipe.

The reinforcement material must be compatible with the parent and branch pipe material. Normally the same material as the header pipe is used for the RF pad.

Clause 328.5.4.g of ASME B31.3 mentions that Reinforcing pads and saddles shall have a good fit with the parts to which they are attached.

Proper design and size are essential for effective stress distribution and protection. Engineers should carefully consider the dimensions, thickness, and reinforcement pattern to match the specific application.

A vent hole shall be provided at the side (not at the crotch) of any pad or saddle to reveal leakage in the weld between the branch and run and to allow venting during welding and heat treatment. Normally two vent holes are provided, which must be sealed with mastic or silicone gel to restrict the water flow inside the RF Pad. Vent holes are also known as weep holes or telltale holes. The normal size of the weep hole is 6 mm. If the reinforcement pad is made of multiple pipe cuts, then a vent hole should be provided in each cut piece.

A pad or saddle may be made in more than one piece if joints between pieces have strength equivalent to pad or saddle parent metal, and if each piece has a vent hole.

Repad Symbol | Reinforcing Pad symbol in Drawings

Fig. 2 shows the normal RF Pad symbol that is used in piping drawings.

Fig. 2: Reinforcing PAD symbol

The reinforcing pad is a ring cut from a steel plate that has a hole in the center equal to the outside diameter of the branch connection. It is slipped onto the branch pipe before the branch pipe is welded to the header. Once the branch has been welded to the header, the reinforcing pad is slid down the branch to cover the weld connection. The reinforcing pad is then welded to both the branch and the header.

Advantages of Using RF Pads

The use of RePADs in piping or equipment nozzles offers several benefits, including

  1. Enhanced Durability: The primary advantage of RF pads is their ability to enhance the durability of piping systems and equipment nozzles. Their robust design helps resist high temperatures, pressures, and corrosive environments.
  2. Cost-Effectiveness: While the initial investment in RF pads may be higher, they can lead to significant savings in the long run by reducing maintenance costs and extending the lifespan of equipment.
  3. Versatility: RF pads are suitable for a wide range of applications and industries, including chemical processing, oil and gas, and power generation. They can be customized to meet specific requirements based on the operating conditions.
  4. Reduced Vibration and Noise: RF pads can help dampen vibrations and reduce noise, contributing to a quieter and more stable operation.

Differences Between Wear Pad and Reinforcement PAD

Wear pad in piping is one additional term that might sound confusing and often seems the same as reinforcement pad. However, the main application of both wear pads and RF pads is quite different. Wear pads are mainly used to protect against wear, erosion, tear, and abrasion, whereas RePADs are more about structural integrity. The following table outlines the key differences between wear pads and reinforcement pads in the context of piping applications:

AspectWear PadReinforcement Pad
Primary PurposeWear Pads protect against abrasion and erosion caused by the movement or flow of materials.RF Pads provide structural support to distribute stress and prevent damage to the piping or equipment.
FunctionA wear pad shields the surface from wear and tear, extending the life of the underlying pipe or equipment.A reinforcement pad distributes mechanical loads and stresses to prevent localized failures and enhance structural integrity.
ApplicationCommonly used in areas where high friction or abrasive materials are present, such as piping supports due to thermal movement.Used in locations requiring reinforcement against mechanical stress, thermal expansion, or pressure, such as nozzle connections and pipe branch connections.
InstallationWear pads are often attached directly to the surface that is exposed to wear, often with bolts, welding, or adhesive.RF pads are installed around or near nozzles and supports to distribute loads; may require precise alignment and secure attachment.
Design FocusDesigned to endure abrasion, impact, and erosion.Designed to handle stress, pressure, strain, and thermal expansion, often with a focus on load distribution.
Wear Pads vs Reinforcement Pads

Part of this article is prepared by Mr. Satish Atmanathan, a senior oil, and gas professional with extensive work experience. For a more detailed explanation of all the above parts and visualization, listen directly to him in the following video:

Reinforcing PAD Video

Few More Useful Resources for you…

Article related to Piping Design and Layout basics
Piping Stress Analysis Basics
Piping materials Basics
Piping Design Softwares

Stress Analysis Features of the Tall Pipe Risers

Written by Alex Matveev in Caesar II,Piping Stress Analysis,Piping Stress Basics,Start-Prof

Tall pipe risers are used in skyscrapers, mines, etc. There are two points that the piping stress engineer should consider:

  • Fluid weight load distribution
  • Pipe longitudinal stability

Fluid weight load distribution

The most of widely used piping stress analysis software, including START-PROF, applies fluid weight as a uniform load along the pipe. This approach is correct for horizontal piping and short vertical pipes. But it is incorrect for tall risers and may lead to incorrect support loads and incorrect stress distribution along the vertical pipe length.

The picture below (a) shows the axial force F diagram caused by uniform load q at the vertical pipe that is supported at the bottom. If fluid weight is applied as uniform load q, the axial force diagram is incorrect. The software will show great axial stresses from sustained loads q*L/A, A – pipe cross-section area. But in real-world fluid pressure will act only on the bottom of the pipe and axial stresses along the pipe should be zero. The correct results can be obtained by applying of concentrated force at the bottom of the pipe instead of a uniform load.

Vertical Pipe Supported at the Bottom

In the case of pipe supporting at the top, uniform load gives incorrect results too. Application of fluid weight as uniform load leads to underestimation of axial stresses at the lower part of the pipe.

Vertical Pipe Supported at the Top

In the case of supporting the riser with several springs, the application of fluid weight as a uniform load will lead to uniform load distribution between supports. But in real-world fluid weight will act in the bottom bend and the lowest support will hold the greatest weight load.

Vertical Pipe Supported by Several Springs

Now let’s see how to model the vertical riser correctly in PASS/START-PROF piping stress analysis software:

  • Fluid density should be zero
  • Add concentrated force q*L in the lower bend

Pipe Longitudinal Stability

The second problem concerns vertical risers that are supported at the bottom. The pipe is compressed by a big pipe and insulation weight. Compression force may lead to pipe buckling as shown in the drawing (a) below.

To avoid buckling we should add additional V-stop supports (d) to decrease the compressive force or add guides (c) to prevent buckling.

The START-Elements has a special procedure that allows checking to buckle of vertical or horizontal pipe. For vertical pipe, we should set the sliding support friction factor to zero and enter the compressive load N value. The software will calculate the span between guides Lcr needed to prevent buckling.

Spring Hanger Selection and Design Guidelines in Caesar II

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

Spring hangers are an integrated part of the Piping Industry. The use of spring hangers for supporting pipe weights is well-known to every piping engineer. Whenever some rigid supports are not taking load due to their thermal movement or rigid supports are creating bad effects on equipment connection Piping engineers suggest the use of a spring hanger to share some of the loads and to keep the piping system safe.

The selection of the appropriate type of hanger support for any given application is governed by the individual piping configuration and job requirements.

There are two types of Spring hangers.

  1. Variable Spring Hanger- Loads vary throughout its operating range and
  2. Constant Spring hanger- The load remains constant throughout its operating range.  

The following write-up will provide a simple guideline for the selection of both Variable and constant Spring hangers while analyzing a piping system using Caesar II.

Selection Procedure of Variable Springs

spring hanger
Variable Spring Hanger

1. Determine the hot load required and the pipe movement (up or down).

2. Estimate the travel range from the catalog.

3. Select the smallest spring size which has the hot load within the working travel (mid-range).

4. Ensure that the cold load lies within the working range of the spring i.e. between the two dark black lines shown in the selection chart.   Calculate the cold load as follows:    

  • Cold Load = Operating Load + Movement x Spring Rate (For pipe movement up)  or
  • Cold Load = Operating Load – Movement x Spring Rate (For pipe movement down)  

5. If the Cold load lies beyond the working range in the selection chart, then select a higher spring size or the next travel range.

 6. Check the variability in selected spring  

Spring Hanger Variability Calculation
Spring Hanger Variability Calculation

Generally, for non-critical systems, the variability is limited to 25% throughout the total travel. For critical systems such as steam connections terminating at turbines and pipes connected to rotating equipment Like compressors etc. variability is limited to 10%. If the variation exceeds the allowed value, choose a higher-size spring or smaller spring rate at the same load range.    

7. Select the type and check the feasibility of the spring depending on the space available and the type of structure available.  

Selection procedure of Constant spring hanger

Constant Effort spring shall be selected where the vertical movement exceeds 50 mm, where it is necessary to restrict the transfer of load to the adjacent terminal of equipment, or where the Spring variability exceeds 25%.  

constant spring hanger
Constant Spring Hanger

1. Determine the load and total movement.            

Total movement = design movement + overtravel Overtravel = 20% of the design movement or 25 mm whichever is higher.  

2. Select the spring from the load chart keeping in mind that the spring selected must lie within the working range (Between red and black lines)  

3. Select the type and check the feasibility of the spring depending on the space available and the type of structure available.  

4. The Spring box must be able to move freely without any restriction.  

5.  Stress Engineer must check the eccentricity (See Fig 1 below) of the spring load flange and the spring base plate while providing foundation information to the Civil team.    

Eccentricity between Spring Load Flange and Spring Base Plate

Spring Hanger Selection procedure in Caesar II

1.    CAESAR-II Default Setting for Hanger Selection: Before making input for spring selection it is always better to make a default Caesar setting for the hanger design.

Caesar II Default hanger setting
Fig 2. Caesar II Default hanger setting

  2.    CAESAR-II Auxiliary Spreadsheet setting for Hanger Selection   During spring selection at a particular node, the following auxiliary spreadsheet appears. The setting of this spreadsheet is to be done as illustrated in the below diagram.  

Caesar II Auxiliary spreadsheet for hanger selection
Fig. 3 Caesar II Auxiliary spreadsheet for hanger selection

NOTE-1: Maximum Allowed Travel Limit:   This field is used to specify a limit on the amount of travel a variable support hanger may undergo.  CAESAR will be forced to select a Constant Effort Spring if the movement exceeds the limit in this field, even though a variable effort spring would have fulfilled our purpose.   Constant effort hangers can be designed forcefully by inputting a very small number i.e. 0.001 in this field.    

NOTE-2: Free Code:   Anchor or Restraints from equipment connections which are very near to the hangers are usually freed during the hanger design restrained weight run so that loads normally going to the equipment nozzle is carried by the hanger. The hanger can be designed to take almost the full weight of the pipe between the anchor and the hanger Using this field enter the node number & the direction in which free code is to be used.  

Free Codes are:-

  1. Free the anchor or restraint in the Y direction only.
  2. Free the anchor or restraint in the Y and X directions only.
  3. Free the anchor or restraint in the Y and Z directions only.
  4. Free all translational degrees of freedom for the anchor or restraint. (X, Y, and Z)
  5. Free all translational and rotational degrees of freedom for the anchor or restraint. (X, Y, Z, RX, RY, and RZ).Refer to the Figure below.  

Option 5 above usually results in the highest adjacent hanger loads, but should only be used when the horizontal distance between the hanger and the anchor is within about 4 pipe diameters as shown in Fig 4.  

Maximum Spring distance for using Free Code
Fig. 4 Maximum Spring distance for using Free Code

NOTE-3:  Number of hangers at location:   For better stability, the base type spring support of 24″ and larger are used with 2 spring cans.  

Few important points to keep in mind while Spring selection

  • For the can type springs the spring height should be kept minimum from a stability point of view. If the spring height is less the moment of spring will reduce and the tilting of the spring (Fig. 5) can be avoided or significantly minimized.
  • The spring which has a lower spring rate will have lower load variation.
  • While designing the spring hanger the sustained sagging should be minimized within +/-1 mm so that the original piping system is not strained much.
Effect of Spring Height
Fig. 5 Effect of Spring Height

   

Few more useful Resources for you…

Technical and General requirements for Spring Hangers while purchasing.
TBE of vendor Spring hangers: Main points to consider before placing an order
Spring hangers: Common Interview Questions with Answers
Spring hanger selection and design guidelines for a Piping engineer using Caesar II
Basics of Pipe Stress Analysis

Snubber Modelling in Pipe Stress Analysis in Caesar II

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

A Piping Snubber is a Dynamic Restraint that protects the piping system against impulse loading conditions from Seismic or Surge Events. It is basically a mechanical device that allows pipe operating displacement but restricts the sudden movement of dynamic events.

Refer to my earlier article on Dynamic Restraint that explains details about Snubbers, their working, types of snubbers, etc. In this article, I will explain the step-by-step procedure of Snubber Modeling in the software Caesar II.    

Snubber Modeling in Caesar II

“Static” snubbers have a support restraint called SNB following a translational direction in the restraint type field. When a snubber is entered, the restraint fields in Ceasar II change as follows: Gap and Mu are disabled.  

Snubbers are the translational restraints that provide resistance to displacement in static analysis of occasional loads only. It is assumed that occasional loading is dynamic in nature, similar to static seismic or static wind loading.

THESE SNUBBERS ARE INACTIVE FOR ALL EXPANSION SUSTAINED, AND OPERATING STATIC CASES, AND ARE ACTIVE FOR ALL TYPES OF TRUE DYNAMIC ANALYSES, i.e. HARMONIC, MODAL, OR SPECTRAL.

These restraints will be active in all static load cases defined as occasional in the load case list.   Static snubbers may be directional, i.e. may be preceded by a minus or plus sign.

Steps for Snubber Modeling

The steps for modeling Snubber are mentioned below:    

  • Create a node where snubber is required to add. (Node 10)
  • Run the operating cases without defining a snubber at that node.
  • Note the displacement in all six degrees of freedom at the location (Node 10) where to add the snubbers (Assume D1 is the displacement at that node at T1 temp and D2 at T2 temp).
  • From input, the piping spreadsheet clicks on the restraint checkbox and defines XSNB/ZSNB, etc as per requirement at node 10 with a distinct C-Node 11. It will appear as a guide in Caesar Sketch.
  • Place displacements on the CNode (CNode 11) by activating the displacement checkbox.
  • Modify the load cases by including D1 everywhere T1 displays and D2 where T2 appears for Operating load cases.
  • For defining occasional stresses create the following load cases as given in Fig. 1.
  • Run the analysis to obtain results.
Load Cases for systems having a Snubber
   Fig. 1: Load Cases for systems having a Snubber.

Application of Snubber

Snubbers are normally used for reducing the damaging effects of earthquakes, turbine trips, relief valve discharges, and surge events.

Few more Resources for You…

Brief Description of Sway Brace, Strut and Snubber (Dynamic Restraints)
Modeling of Sway Braces in Caesar II
Modeling of Rigid Strut in Caesar II
Snubber Modeling in Caesar II
Piping Stress Analysis Basics
Piping Design and Layout basics
Piping Materials Basics
Few Jobs for You.

Video Explaining Snubber Installation

The following video by LISEGA explains the Snubber Installation Tips in detail

Snubber Installation Tips Video