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What is Chemical Cleaning? Procedure and Examples

Written by Subash Sandar Nagarajan in Construction,Engineering Materials,Maintenance,Piping Design Basics,Piping Interface,Process

Chemical Cleaning is the procedure for field cleaning of the piping systems especially Steam lines inlet for Turbines and Steam Drums. These pipelines after cleaning shall be free from hydrocarbons, greases, oils, rust, scale, and other impurities. In Chemical cleaning, chemicals are used to dissolve or loosen the hard deposits from process equipment or piping surfaces and removed them.

Why is it necessary to do Chemical Cleaning?

Most of the steam systems have carbon steel pipelines which will have a lot of rust, welding spatters, and slags inside during the construction. The chemical cleaning will reduce the duration of Steam lines flushing by 1/3rd of the actual duration. This will reduce the Project schedule and improve the quality inside the pipelines.

Chemical Cleaning Flow Chart

The following image (Fig. 1) shows a typical flowchart used for the chemical cleaning operation of the steam piping.

Flow Chart for Chemical Cleaning
Fig. 1: Flow Chart for Chemical Cleaning

Technical details of chemical cleaning

According to the above Flow chart (Fig. 1), install the required equipment and lines (such as a chemical cleaning circulatory system). The complete system has to be chemically cleaned following several steps. The system has to be divided as per the following P&ID considering the volume. Refer to the below images (Fig. 2, Fig. 3, and Fig. 4) which show the loops and steps in the P&ID for HP, MP Steam System.

Step-1

Typical procedure for Chemical Cleaning Step-1
Fig. 2: Typical loop for Chemical Cleaning Step-1

Step-2

Typical loop for Chemical Cleaning Step-1
Fig. 3: Typical loop for Chemical Cleaning Step-2

Step-3

Typical loop for Chemical Cleaning Step-3
Fig. 4: Typical loop for Chemical Cleaning Step-3

Chemical Cleaning Works shall be performed in accordance with the standard, regulations, and laws of the country of the Project. The mentioned procedure is followed as per the local regulation of Russia.

The following conditions shall be required prior to chemical cleaning.

  1. Isolation of cleaning system: The cleaning system shall be isolated from the other piping by closing valves. And those valves shall be locked with steel wire and clearly stated: “DON’T OPEN”.
  2. Instruments: Instrument and instrument leading shall be removed and isolated from systems to be cleaned. If the leading is not able to be removed, the inlet valve of the instrument shall be exactly closed, and the drain valve on the instrument leading shall be opened.
  3. Unsuitable materials for cleaning: Materials such as aluminum, zinc, copper, and copper alloy are unsuitable for chemical cleaning. So these materials must be removed or changed prior to cleaning.

Chemical Cleaning Procedure

The whole chemical cleaning procedure can be parted into the following steps:

Preparation work for Chemical Cleaning:

The following works shall be completed before starting the chemical cleaning activities;

  • a. Erection and installation of temporary equipment such as:
    • – Circulation pump
    • – Chemical injection pump, chemical dissolving tank, and ejector
    • – Steam mixing heater
    • – Hydrazine injection system
    • – Waste neutralizing tank and wastewater pump
  • b. Temporary piping between the tie-in point on the permanent facility and temporary equipment. (For the purpose of by-pass, circulation, and so on)
  • c. Installation of solution recovery line onto drain and vent by a rubber hose.
  • d. Blind plates shall be inserted at safety valves and non-necessary items.  
  • e. Installation of the restrictive orifice on the system.
  • f. Line/valve check of the system to be cleaned including temporary piping.
  • g. Utility piping from the supply point to the cleaning system.

Water flushing and leak test:

Water flushing shall be performed using a temporary circulation pump until the drainage has been clear visually. The water flushing shall be conducted in accordance with the following steps 1 to 3.

  • 1) Temporary Piping (water Supply Line): From the water supply connection to the inlet of the cleaning loop.
  • 2) Temporary Piping (Circulation Pump Suction and Discharge Line) Flushing route:
Temporary Piping flushing Route
  • 3) Piping System, Temporary piping (Return Line) Flushing route:
Temporary Piping Return line Flushing Route

After water flushing, water circulation shall be established in the cleaning loop and pressurized to the maximum pressure of the Circulation Pump. Leaks shall be rectified if any.

Heating up:

  • To establish water circulation, steam shall be introduced into the cleaning system from the existing steam line.
  • Heating shall be continued till the temperature becomes up to 70℃.

Degreasing:

The required quantity of chemicals shall be provided by the contractor in Chemical Injection Tank while the heating up is going on. After completion of heating up, the chemical solution shall be fed into the system to be cleaned by operating of Chemical Injection Pump.

Degreasing shall be performed under the following conditions with continuous circulation. (If the following condition is different from the contractor’s procedure, an alternative procedure shall be submitted.)

  1. Chemicals:
    • Sodium hydroxide (NaOH)-0.05 %     
    • Sodium carbonate (Na2CO3)-0.3 %       
    • Trisodium phosphate (Na3PO4)-0.3 %    
    • Detergent- 0.05 %
  2. Temperature: 70 – 85°C
  3. Treating time: 12 hours

Alkalinity shall be monitored every hour to identify of quality of the cleaning solution.

Rinsing:

The cleaning solution shall be drained out from all of the low points under atmospheric pressure. Effluent including the following rinsing effluent shall be transferred into Neutralization facilities provided by the contractor.

Water shall be fed to the cleaning system until the system becomes full water. Before filling, initial flushing shall be done by Down Flow. Rinsing operation shall be performed in accordance with the following step.

  1. Water filling with initial flushing
  2. Circulation for 1 hour
  3. Drain out

This operation shall be repeated until circulating water becomes pH less than 10.

Re-Heating:

To establish water circulation, steam shall be introduced into the cleaning system from the existing steam line. Heating shall be continued till the temperature becomes up to 70℃.

Acid cleaning:

The required quantity of chemicals shall be provided by the contractor in Chemical Injection Tank while the heating up is going on.

After completion of heating up, the chemical solution shall be fed into the system to be cleaned by operating Chemical Injection Pump.

Acid cleaning shall be performed under the following conditions with continuous circulation. (If the following condition is different from the contractor’s procedure, an alternative procedure shall be submitted.)

  • a.    Chemicals :
    • The citric acid (C6H8O7) – 3 %   
    • Ammonia (NH3)- Adjusting amount to pH 3 – 3.5 
    • Corrosion inhibitor (IBIT 30AR is recommendable)-0.3 %
    • Suspending agent (Ammonium bifluoride, NH4HF2)-0.3 %
  • b.    Temperature: 70 – 85℃
  • c.    Treating time: 6 – 8 hours

Fe-ion concentration, acidity, and pH shall be monitored every hour. When the Fe-ion concentration reached equilibrium for 1 to 2 hours, the acid cleaning shall be finished. During the acid cleaning, the distribution of the flow rate shall be controlled and partial circulation and reverse circulation shall be carried out at a suitable time.

Cooling down:

Steaming into the cleaning loop shall be stopped and the system shall be allowed to cool down to 60℃ by natural radiation with continuous circulation.

Ammoniation:

The circulating solution shall be ammoniated to a pH of 8.5 to 9.0 with a gradual injection of ammonia. The identification of pH shall be done at every point of the cleaning loop.

Passivation:

Sodium nitrite as a passivation agent shall be prepared in Chemical Dissolving Tank and this chemical solution shall be injected into the chemical cleaning loop.

The treating conditions are as follows (If the following condition is different from the contractor’s procedure, an alternative procedure shall be submitted.)

  • a. Chemical: Sodium nitrite (NaNO2) -0.5%
  • b. Temperature: Approx. 60°C
  • c.  Treating time: 2 hours or more

Final rinsing:

The cleaning solution shall be drained out from all of the low points under positive nitrogen pressure. Effluent including the following rinsing effluent shall be transferred into the Neutralization facility provided by the contractor.

Before filling, initial flushing shall be done by Down Flow. Rinsing operation shall be performed in accordance with the following steps.

  1. Water filling with initial flushing
  2. Circulation for 1 hour
  3. Drain out under nitrogen pressure excluding the final drain out

This operation shall be repeated until the circulating water becomes clean.

Rinsing shall be performed with freshwater containing 100 mg/L of hydrazine (N2H4,) and 50 mg/L of ammonia. In the final stage of rinsing, flushing of drain lines shall be carried out.

Final Drain Out:

Rinsing water shall be drained out and air blowing need to be done. After completion Nitrogen purging should be carried out for prevention.

Final Inspection and Evaluation

The condition of the cleaned pipelines will be checked visually to make a comprehensive evaluation. According to the cleaning feedback, further actions will be taken.

Inspection after Chemical Cleaning
Fig. 5: Inspection after Chemical Cleaning

After chemical cleaning, Wastewater management is very important due to chemicals that are used are highly toxic. Chemical cleaning can be carried out after getting Client approval.

Few more related articles to enhance your knowledge.

An article on “Internal Cleaning of Piping System”
Cleaning Requirements of Piping Systems

Stress Analysis of Surface Laid Pipelines

Written by Jimmy Mathew in Caesar II,Pipeline,Piping Stress Analysis,Piping Stress Basics

Surface Laid Pipelines, as the name suggests, are Pipelines that are laid on the surface of the loose desert sand without any restraints. These unrestrained pipelines, unlike the other unrestrained pipelines, do not have pipe supports to restrain the displacements, hence different approaches and techniques are implemented while analyzing such lines.

The purpose of this article is to illustrate the method to model and analyze surface-laid pipelines using Caesar II and the considerations to be taken care of during the Stress Analysis.

The surface laying of the pipelines is opted for by the client for Cost-benefit. It saves construction costs, maintenance costs, and operational costs largely.

Sites for Surface Laid Pipelines

Surface-laid pipelines have basically opted for the desert sites, where the pipelines are laid in the corridor from the Wellhead up to the Gathering Facility.

Above Ground Surface Laid Pipelines

The above-ground surface laid pipelines (Fig. 1) shall be routed in a manner such that no excessive movement occurs on the pipes due to the effects of thermal expansion and/or contraction, internal pressure, and other design internal or external loads. The axial and lateral expansions of above-ground pipelines shall be limited as far as possible. Expansion loops are to be designed to accommodate the axial movements based on CAESAR II stress analysis recommendations for above-ground pipelines.

The above-ground pipeline shall be modeled as “Unrestrained” in the CAESAR II software and should be analyzed using ASME B31.4/B31.8 code calculations.

The unsupported surface laid pipelines shall be installed as unrestrained pipelines & shall follow natural grade elevation

Fig. 1 and Fig. 2 show typical site images explaining how surface-laid pipelines would look.

Typical Surface Laid Pipeline in Desert Area
Fig. 1: Typical Surface Laid Pipeline in Desert Area

Considerable Points for Surface Laid Pipelines

The below-mentioned points must be considered while designing Surface Laid Pipelines.

  1. Wall Thinning of Hot Bends
  2. Wall Thickness at Road Crossings
  3. Minimum Radius of Elastic and Cold Field Bends
  4. Longitudinal Stress, Anchor Force and Free End Expansion Calculation
  5. Equivalent/Longitudinal Stress Calculation
  6. Upheaval Buckling
  7. Stability
Site Photo of Surface Laid Pipelines
Fig. 2: Site Photo of Surface Laid Pipelines

1. WALL THINNING OF HOT BENDS:

The process used for bending a hot bend results in some thinning of the pipe wall thickness. An indication of this thinning as a percentage of wall thickness may be determined by the empirical formula stated in BS 8010-2.8 para 2.8.3.9

n= is the radius of the inner bends divided by the pipe diameter

2. WALL THICKNESS AT ROAD CROSSINGS:

This calculation determines the minimum wall thickness required at road crossings to withstand normal vehicular loads. The calculation will be based on the method used in API RP 1102.

3. MINIMUM RADIUS OF ELASTIC AND COLD FIELD BENDS:

For liquid lines, the minimum radius of curvature for cold field bends is determined as per the requirement of ASME B31.4 clause 404.2.2 to ensure that the bend will not be overstressed. For gas lines, the minimum radius of curvature for cold field bends is determined as per the requirement of ASME B31.8 table 841.2.3-1 to ensure that the bend will not be overstressed.

4. LONGITUDINAL STRESS, ANCHOR FORCE, AND FREE-END EXPANSION CALCULATION

The aim of this calculation is to determine the longitudinal stress induced in a restrained/unrestrained pipeline as a result of the difference between the installation temperature and the operating pressure and also to calculate the potential anchor force; free end expansion and the virtual anchor length.

ASME B31.8 states that the sum of the expansion stress, longitudinal pressure stress, and applied bending stress must not exceed the 90% specified minimum yield strength of the material. In addition, the longitudinal pressure stress and the applied bending stress must not exceed 75% of the SMYS for the gas pipelines.

5. EQUIVALENT/LONGITUDINAL STRESS CALCULATIONS:

ASME B31.4 uses a term called the Equivalent Tensile Stress to control the combined stresses in the liquid pipelines. The Equivalent Tensile Stress is equal to the sum of the hoop stress and the longitudinal stress imposed on the pipeline. The limit for equivalent tensile stress is set at 90% of SMYS.

6. UPHEAVAL BUCKLING:

An upheaval buckling calculation may be performed to ensure that the longitudinal forces are not sufficient to force the pipelines out of the ground. The required downforce will be calculated using the method described in OTC 6335 – Design of Submarine Pipelines Against Upheaval Buckling, 1990. The required downforce is dependent on the axial force, which is calculated in the Thermal Expansion Calculation Sheet.

7. STABILITY:

The method used to determine the vertical stability of the pipeline through water courses is to calculate the total weight of the pipeline and compare it with the weight of the external fluid (water) it would displace. In order for the pipeline to be considered stable, the pipeline weight must be 10% greater than the weight of the water displaced

Major points during Stress Analysis

1. During the stress analysis, the analyst shall check the maximum lateral deflections in the system to make sure that the adjacent flow line does not cross each other while in operation considering the spacing between the flowlines mentioned in the specifications.

2. The design shall be adopted to add flexibility by introducing offsets/expansion loops across the route while the lateral deflections of the line shall be within the limits so that the group of lines will not interfere with adjacent lines.

Procedure for modeling in CAESAR II

The methodology for modeling the Surface Laid flowlines are bit tricky and tedious, so proper care has to be taken while modeling the same in the CAESAR II. Since the entire system is without restraint, a slight error might give improper results.

Below is the basic methodology for modeling the Surface laid flowline.

Since the pipeline is surface laid (except at road/track/ other pipelines crossings where it is U/G), a direct method for modeling surface laid lines are not available in CAESAR II (or any other such software) due to the continuous supporting (equivalent to say an infinite number of supports) by natural soil along pipeline routes. The continuous soil supports are therefore taken care of by discrete soil springs and also by selecting such close springs at a distance not more than 5D (i.e 5*219.1 = 1095.5 mm as an example for 8”). Support spacing shall be taken to the nearest round figure (say for 8” as an example at every 1000 mm), using the approximate stiffness in the vertical direction and also using friction value of 0.5 (which varies with the location for such modeling).

This modeling approach has been recommended by COADE (Developer of CAESAR II).

Fig. 3: Surface Laid Pipeline Modeling

The CAESAR II procedure for finding the soil support stiffness is as given below:

A small stress model of the pipeline shall be created using the actual design data. The small model could be with 25 nodes, with each node spaced at the 5D distance of the line. The model shall be buried using the buried modeler of CAESAR II®, with an assumed soil depth of half the diameter of the pipeline and using the typical soil design parameters. Upon buried conversion, the program inserts soil springs in the converted model of the sample model. The Y2 stiffness shall be read as seen in the converted sample model corresponding to a mid-node number (made free from the end conditions). This is the stiffness to be used in the actual pipeline model as normal rest support.

In case the stress model with 5D support spacing creates a convergence issue due to a large number of soil restraints, the option of removing the friction at several non-convergent supports would lead to inaccuracy of the results. To overcome this issue, a stress model with a larger support spacing (<50D Typical) may be utilized. In this case, the vertical support stiffness to be used shall be determined using the above-mentioned procedure for finding the soil support stiffness with the increased support spacing. In the alternate method, the representative vertical stiffness values as per the Geotechnical report, after consulting the Civil, can be used to simulate the soil springs for surface-laid lines.

To obtain near-realistic results, it is suggested to model with the actual profile of the flowline so as to gain the proper axial and lateral displacements.

The above article gives a broader perspective of general considerations to be taken care of.

Online Video Courses related to Pipeline Engineering

If you wish to explore more about pipeline engineering, you can opt for the following video courses

Difference between ASME B16.47 Series A and Series B Flanges

Written by Anup Kumar Dey in Piping Design Basics

ASME B16.47 is an American standard for large-diameter steel flanges. This standard covers the design of flanges from NPS 26 to NPS 60. For lower sizes i.e., up to NPS 24, ASME B16.5 has to be referred. ASME B16.47 provides pressure-temperature ratings, materials, dimensions, tolerances, marking, and testing for pipe flanges with rating class designations 75, 150, 300, 400, 600, and 900. The Standard also includes the requirements and recommendations regarding flange bolting, flange gaskets, and flange joints.

What is ASME B16.47 Flange Series?

The ASME B16.47 standard provides the use of two types of flange series.

  • Series A flanges and
  • Series B flanges.

Series A specifies flange dimensions for general-use flanges whereas Series B specifies flange dimensions for compact flanges. Series A flanges have larger bolt circle diameters than Series B flanges.

This is to be noted that Series A and Series B flanges are not interchangeable. So, the user must take care of the compatibility issues that may arise by mistake. In most cases, flanged valves, equipment bolted between flanges, and flanged equipment are compatible with only one series of these flanges.

Difference between ASME B16.47 Series A and Series B Flanges

The major differences between Series A and Series B can be decided based on the following parameters:

1. Physical Attributes:

Series A Flanges:

  • Thickness and Weight: Series A flanges are thicker and heavier compared to Series B flanges. This increased thickness provides greater strength and durability.
  • Bolt Holes: They have larger diameter bolt holes, which generally require larger fasteners.
  • Bolt Circle Diameter: Series A flanges have a larger bolt circle diameter, which means they have fewer but larger fasteners.

Series B Flanges:

  • Thickness and Weight: These flanges are thinner and lighter than Series A flanges, making them less robust.
  • Bolt Holes: Series B flanges feature smaller diameter bolt holes that necessitate the use of smaller fasteners.
  • Bolt Circle Diameter: They have a smaller bolt circle diameter, which results in more bolt holes and generally requires smaller bolting hardware.

2. Strength and Load Handling:

Series A Flanges:

Strength: Due to their increased thickness and material weight, Series A flanges are stronger and can handle more external loading compared to Series B flanges.

Series B Flanges:

Strength: These are relatively weaker and can handle less external loading due to their reduced thickness and lighter weight.

Refer to Fig. 1 below, which highlights some of the differences:

Series A vs Series B ASME B16.47 Flanges
Fig. 1: Series A vs Series B ASME B16.47 Flanges

3. Fasteners and Installation:

Series A Flanges:

Fasteners: The quantity of fasteners is fewer but larger fasteners are required. This generally leads to a larger bolt circle diameter.

Series B Flanges:

Fasteners: They require more quantities but smaller fasteners. This results in a smaller bolt circle diameter.

4. Flange Types and Standards:

Series A Flanges:

  • Types: Includes weld neck flanges, blind flanges, and ring-type joint (RTJ) flanges from Class 300 through Class 900.
  • Application: Series A flanges are generally used in new pipeline projects or equipment installations.

Series B Flanges:

  • Types: Also includes weld neck flanges and blind flanges but does not include RTJ flanges in the standard.
  • Application: More commonly used for refurbishment or replacement jobs in existing pipelines.

5. Cost:

Series A Flanges:

Price: Typically more expensive due to the higher steel content and thicker design. The increased material weight contributes to higher costs.

Series B Flanges:

Price: Generally less costly because of the reduced steel weight and thinner design, which results in lower material and manufacturing costs.

6. Compatibility and Usage:

Series A Flanges:

  • Compatibility: Not compatible with Series B flanges in terms of bolting due to differences in bolt-hole sizes and patterns.
  • Typical Uses: Industrial connectors such as valves, pumps, and pipeline separations.

Series B Flanges:

  • Compatibility: Not compatible with Series A flanges for the same reasons mentioned above.
  • Typical Uses: Often used in pipeline applications where cost-efficiency and weight considerations are more critical.

The following table provides the major differences between ASME B16.47 Series A and Series B flanges.

Sr. NoParameterASME B16.47 Series A FlangesASME B16.47 Series B Flanges
1OriginEarlier Series A flanges were known as MSS SP 44 flanges.These flanges were known as API 605 flanges.
2DimensionFlange Outer diameter, Bolt Circle Diameter, Flange Thickness, Bolt Diameter, etc. are larger for Series A Flanges for the same pressure rating class.B16.47 Series B flanges are compact as compared to Series A flanges.
3StrengthASME B16.47 Series A flanges are comparatively stronger. Hence, can handle more external loading before leakage.Load bearing for the same pressure class is relatively less.
4Fastener RequirementThe quality requirement is less but bigger size. For example, as seen in Fig. 1, a 30-inch class 150 series A flange needs 28 bolts of 1-1/4 inch diameter.The quantity of fasteners is more. For example, a 30-inch class 150 Series B flange requires 44 bolts with a diameter of 3/4 inch.
5Ring type joint TypesAvailable from Class 300 through Class 900Does not exist.
6Pressure Class 75Not available for series A flangesAvailable for Series B flanges
7Flange WeightThe weight of ASME B16.47, series A flanges is more. So, they exert more load on piping supports.Weight is comparatively less
8CostMore expensive.cheaper.
9Industry UseMore frequently used. Used for critical applications.Less frequently used. Normally used for non-critical applications.
ASME B 16.47 Series A vs Series B

Dimensional Comparison for ASME B16.47 Series A and Series B Flanges

Refer to Fig. 2, which shows the comparative dimensions for 30″ (150 class) Series A and Series B ASME B16.47 flanges.

ASME B 16.47 Series A vs Series B Flange Dimensions
Fig. 2: ASME B 16.47 Series A vs Series B Flange Dimensions

What is the flange standard for flanges above 60″ sizes?

Ans: Flanges above 60″ sizes are usually designed based on the AWWA C207 standards, or they are specifically designed by manufacturers considering the specific requirements of the users/purchasers.

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Vacuum Breaker: Uses, Working, Function, Installation

Written by Sherif Hosny in Mechanical,Piping Design Basics,Piping Interface,Process

A Vacuum Breaker is a device that helps the air to fill the vacuum created inside a steam piping system. As the name suggests, the vacuum breaker breaks the unwanted vacuum inside a closed system. There are many instances when a vacuum can be created inside a steam piping system, for example during steam condensation. If the piping system is not designed properly (piping thicknesses need to be checked for vacuum pressure condition) to take care of that vacuum situation, it may lead to a sudden collapse of the piping system.

In such a situation, Vacuum breakers play an important role to safeguard the piping system by allowing air to fill the vacuum. Vacuum breakers help in protection against freezing and water hammer and allow gravity drainage in condensing equipment under modulated control.

Use of Vacuum Breaker

The proper use and the reason for having a vacuum breaker in a steam system are illustrated with an example as follows:

Illustration of Vacuum Breaker in Steam Piping System
Fig. 1: Illustration of Vacuum Breaker in Steam Piping System

Assume the way this is piped is:

We’ve got boiler pressure steam at 10 psi or a little more. Then a control valve, from here it’s piped into the top of a heat exchanger.

We’ve got a condensate line that comes down to a steam trap. Then it goes to a check valve and from there it goes to our atmospheric condensate return system. So if we’ve got the control valve wide open, we’ve got a little bit of differential pressure across the control valve and the heat exchanger. But we’ll see that there is still plenty of differential pressure down here to push the condensate through the primary trap and everything works just fine as the product inside the heat exchange starts to warm up, of course, our control valve is going to modulate down so you can see our pressure starts to drop off.

Also, the pressure will drop off at the condensate line as well. Problems will arise if the condensate pressure is not enough to drive the condensate through the steam trap, or if there is further modulation in the control valve which can lead to backflow to the heat exchanger itself, or even worse, it can create a vacuum pressure.

That either leads to temperature control issues downstream or we can have a water hammer or we can have the potential for freezing or the long term will corrode our system so the solution to the issue is a vacuum breaker.

Now if we have a vacuum breaker installed right before the heat exchanger when this valve is opened, you’ll hear atmospheric pressure air entering that breaker and you can watch the gauge go from vacuum pressure up to zero so now we’ve got zero psi in our system.

No matter if we have positive pressure or we if we go all the way down to zero, we can never get below zero. Now if we mount our trap 14 or 18 inches below our heat exchanger we can always make sure that we generate positive pressure proper installation of a vacuum breaker will ensure that we have positive drainage.

What does a vacuum breaker do?

So to sum up the advantages, here are the top 4 reasons for including a vacuum breaker in your system:

  1. It helps allow for complete condensate drainage under all operating conditions: on/off or modulating applications.
  2. It protects against a water hammer.
  3. It helps reduce temperature fluctuations and uneven temperatures.
  4. It helps to reduce product waste.

How does a steam vacuum breaker work?

Working Philosophy of Vacuum Breaker
Fig. 2: Working Philosophy of Vacuum Breaker

The Vacuum Breaker functions like a simple check valve. Outside air is allowed to enter the system through the air inlet. However, when steam or water tries to escape, the vacuum breaker closes off tightly.

Vacuum Breaker Installation

The unit must be installed in a vertical position and should be placed at the highest point in the system. Fig. 3 shows a typical vacuum breaker that can be used in steam piping systems.

Sample Vacuum Breaker for Steam Piping
Fig. 3: Sample Vacuum Breaker for Steam Piping

Nozzle Reinforcement Calculation for a Cylindrical Nozzle

Written by Said Hallouche in Mechanical,Piping Design Basics,Piping Interface,Piping Stress Analysis,Piping Stress Basics

Equipment nozzles are the openings through which fluid enters or exit the equipment. To create the path for fluid a part of the equipment must be cut, which weakens the equipment. So nozzle connections are weaker sections of any equipment. So design must be checked to safeguard the weak nozzle section. This is normally done by adding extra metal in form of reinforcement known as nozzle reinforcement.

The need for the provision of a reinforcing pad around the such opening is ascertained and the pad thickness is arrived at using the area compensation method stipulated by the codes. In this article, we will explore the Nozzle reinforcement pad calculation methodology for a cylindrical Nozzle provided on any shape of a vessel or a closure.

A Typical Equipment Nozzle
Fig. 0: A Typical Equipment Nozzle

Area Compensation Method for Nozzle Reinforcement

The philosophy of the area compensation method is very simple. The load-bearing metal cross-sectional area that is lost due to the opening is identified. It attempts to compensate for this area loss by providing extra thickness (i.e, nozzle reinforcement) in the affected vicinity of the hole.

It is important to get a correct picture of the area that is purported to be lost due to an opening. Consider the flat plate shown in Fig. 1. Let it be stretched in one direction such that the stresses are just equal to the allowable stress. Let the plate thickness be “t” everywhere. We now contemplate removing a circular area of diameter “d” in a lane of width “d” as shown in Fig. 1A.

Flat Plat with a circular opening
Fig. 1: Flat Plat with a circular opening

The load-bearing metal cross-section lost due to the removal of the disc of diameter “d” is clearly not the area of the circle. Instead, it is a rectangle of width “d” and thickness “t” as shown in Fig. 1B above.

This lost area can be compensated back to the plate by welding a disc of thickness “t” of outer diameter “2d” and inner diameter “d”. This would provide an extra area of “d*t /2” on either side of the lost area “d*t” as shown in Fig. 2 below.

Area Compensation for lost area
Fig. 2: Area Compensation for lost area

This is the essence of the concept of area compensation. We place, if necessary, a plate around the circular opening of the diameter of the opening, and suitable thickness. It offers an extra load-bearing cross-section in the affected vicinity which reduces stress intensification.

The actual calculations are more elaborate. The calculation incorporates the decision steps that lead to the wall thickness calculations. The regulation thickness is then corrected for corrosion/erosion allowance and mill tolerance on plate thickness. And finally, the next available commercial thickness is recommended to select.

Nozzle Reinforcement Calculation Methodology

Let us consider a cylindrical vessel/pipe of outer diameter Do subject to an internal design pressure of P. Let the corrosion allowance be € and mill tolerance ± M %. Let the recommended plate thickness be T.

 Let a nozzle (or branch connection) of outer diameter (OD) do, Inner Diameter (ID) di, and nominal thickness t =(OD-ID)/2 ) be required to be provided on this vessel/pipe (header). Let the mill tolerance be m%. Corrosion allowance and design pressure would be € and P for the header as the vessel and nozzle face identical service conditions.

Self-Compensating Nozzle

It helps to consider the steps that go into recommending the header and branch thickness. The minimum thickness for pressure is calculated, corrosion/erosion/mill tolerance allowances are added and the next higher commercial thickness is recommended. Most of the time, there is an extra thickness available in the header design to handle stress intensification of the affected zone. The compensation area can take advantage of this discount. Often, this extra area available is more than the area lost and in such cases, No extra area by way of reinforcing pad is required. Such a nozzle is called a “self-compensating nozzle”.

In a similar way, The nozzle thickness is calculated. So some extra thickness (and hence area) is available in the nozzle itself. This available extra nozzle thickness up to a height of H1 above the header OD can be accounted for in the area available in the original design. This thickness can be discounted in the calculations of the actual area that is lost and which must be compensated through the provision of a reinforcement pad.

Stub Nozzle and Protruding Nozzle

The basic nozzle types are two. We can have a nozzle that is protruding. In this case, the nozzle pipe actually extends into the vessel or header to a certain extent. This could be a process requirement. For example, if such a nozzle is used for the inlet to a vessel, the liquid coming in would nicely fall into the vessel Rather than trickle along its wall. If that is what the process requires, we could provide such a nozzle.

Another type is a flush or stub nozzle. It does not protrude. Fig. 3 explains the Flush (Stub) Nozzle and Protruding Nozzle definitions.

Stub Nozzle vs Protruding Nozzle
Fig. 3: Stub Nozzle vs Protruding Nozzle

If the nozzle is protruding inside the header, its portion up to a depth of H2  is also considered as providing an extra area to handle stress intensification.

Basically, the feeling here is that once the nozzle is in place, the header/nozzle is a single assembly and any extra provision of the load-bearing cross-section in the assembly in the affected zone can be counted upon to offer help in stress management.

The affected zone is simply up to a width of double the opening diameter on the header, a height of H1 along the nozzle portion outside the header, and a depth of H2 on the nozzle portion protruding into the vessel as shown in Fig. 4.

Nozzle reinforcement calculation
Fig. 4: Nozzle reinforcement calculation

A reinforcing pad on the nozzle is provided when the area “lost” due to cutting the opening is more than the area “available” in the header portion and the nozzle portion (above the header and inside the header). This area of accounting has several nuances further to try and avoid the provision of a reinforcing pad.

The area that is lost is considered as a rectangle of width equal to the “diameter” of the hole and height equal to the “thickness”. Each term requires one to be qualified further.

We would like our design to be functional right through service life. Corrosion would have caused an increase of the nozzle ID (which is the size of the opening also) to di  + 2€  over this period. This, therefore, is considered the design basis for the diameter of the opening to be used in reinforcement calculations. As a consequence, the affected area on the header extends to a circle of diameter 2(di  + 2€). The Reinforcing pad if provided will have this as its OD.

The “thickness” to be used in calculating the area lost is also important. What is indeed lost is the regulation thickness. The rest which comprised of the allowances, tolerances, and extra is not a consequence here. The regulation thickness would have helped keep the stresses at the allowable level. This thickness is what is “missed” as an opening is made.

A couple of other points are also very important. The opening of the nozzle is normally not located on an existing weld joint of the header or its vicinity. A weld as well as an opening is a weakness in the structure and fabrication rules dictate that both should not occur simultaneously. If this is so, then the regulation thickness for the header should be calculated using the Weld Joint Efficiency value as 1 in the appropriate regulation thickness formula for the header shape. The regulation thickness thus may not be imported directly from previous calculations done at the time of header design. Note that, this considerably reduces the value of regulation thickness, thereby lowering the estimate of the area lost.

Another point is regarding choosing the formula for the regulation thickness itself. It is the code formula for a shape “seen” by the nozzle. It may not make a difference if the nozzle is placed on a sphere, hemisphere, cylinder, flat plate, or ellipsoidal closure. For a dished (tori-spherical) closure or a cone housing a nozzle, it does make a difference.

If the nozzle is on the “crown” of a dished closure, the shape around it is actually a sphere with a diameter double that of the vessel. While designing the closure, the formula pertaining to the dished closure would have been used. While calculating regulation thickness to be used in calculating area lost, one should use the formula for a sphere instead. Note that this consideration also reduces the value of regulation thickness, thereby lowering the estimate of the area lost.

In a similar way, the nozzle thickness of a cone is arrived at using the base diameter of the cone. While moving towards the tip of the cone, the code thickness requirement decreases, and extra thickness increases. So to take benefit of this extra thickness in reinforcement calculation, one should calculate the regulation thickness using cone diameter at a level near to the center of the opening. Note that this consideration also reduces the value of regulation thickness, thereby lowering the estimate of the area lost. In fact, a properly located nozzle on a cone can often be made “self-compensating”.

Calculation of Load-Bearing Area

Let us now calculate the load-bearing metal area affected due to the presence of an opening. Refer to Fig. 5.

Calculation of Area Lost and Area Available
Fig. 5: Calculation of Area Lost and Area Available

The last expression needs some clarification. The protruding portion of the nozzle is subject to the same pressure on either side of its wall. The differential pressure is thus zero on this wall and no requirement for regulation thickness. But, corrosion is eating into this wall from both inside and outside. Corrosion is thus twice the corrosion allowance for the expected service life.

The participating heights of the nozzle, H1, and H2,(participating in sharing the extra stresses ) are given as follows:

Note that for a non-protruding nozzle, H2 =0. The regulation thickness of the nozzle, tR, is imported directly from its previous calculations done for deciding nozzle thickness. As the entire nozzle with its seam welding is in the affected area, no correction for weld joint efficiency is required for this calculation.

The balance sheet attempts to hammer down the estimate of the area lost.

The available is calculated by looking at the area available in the vicinity. In fact, even the “weldment” area in the affected rectangle is accounted for in the area available if such estimates are available.

The formula is self-explanatory in view of the discussions above and the figure (Fig. 6) below.

Area Calculation Reference Image
Fig. 6: Area Lost and Area Available

Although not explicitly stated, it is presumed that the reinforcing pad is of the same material as that of the header/nozzle as welding together dissimilar metal could lead to galvanic corrosion. However, as the pad is not exposed to the corrosive process fluid, if a dissimilar material is chosen for the pad for economic considerations, an appropriate correction to the pad thickness should be called for.

Codes recommend an upward revision of the thickness if the pad material’s allowable stress ( Sa pad ) is lower than that of the header/nozzle (S). Logically, the revision is as follows.

Note that Fabrication consideration does not recommend a pad thickness of less than 5 mm.

Few more useful resources for you.

A short briefing about REINFORCING PAD
Dish and Nozzle Centerline Distance Calculation from Nozzle Orientation of Pressure Vessel
A short Presentation on Basics of Pressure Vessels
Brief Explanation of Major Pressure Vessel Parts
10 points to keep in mind while using project-specific pressure vessel nozzle load tables during stress analysis.

Stress Intensity Factor (SIF), Flexibility Factor: ASME B31.3 vs ASME B31J

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

A piping system consists of many different components such as bends, elbows, reducers, tees, valves, and flanges. However, in the pipe stress analysis, these various components are idealized into two types of elements:

  • The first ones are the straight pipe beam element and
  • others are the curved pipe beam element

A piping system depends mainly on its bending flexure to absorb thermal expansion and other displacement loads. When a straight pipe is subject to bending, it behaves like any straight beam i.e. its cross-section remains circular and the maximum stress occurs at the extreme outer fiber. However, under a bending moment, the piping component behaves differently from that of a solid curved beam. When subject to a bending moment, the circular cross-section of the bend becomes oval.

To accommodate this behavior of piping component which is different from a straight pipe, SIF and flexibility factors are used.

ASME code requires the use of stress intensification factors (SIFs or i-factors) and flexibility factors (k-factors) when checking the adequacy of components and joints in piping subject to various loads, including cyclic loads, that may produce fatigue failures.

In this article, we will explore the terms Stress Intensity Factor, Flexibility Factor, ASME B31J, etc. in more detail. At the end of the article registration link for a webinar recording on the same subject is provided. Kindly register and listen to the same for more insights on the subject from AutoPIPE expert Mr. Manoj Kale.

What is the Flexibility Factor?

For branch connections and reducers, the Flexibility Factor is a ratio of rotation of one end of a zero- or negligible-length element with respect to the opposite end of the same element when equal and opposite moments are applied at each end;

For bends, the Flexibility Factor is a factor based on an effective length of matching pipe that increases the element flexibility to simulate the effect of bend ovalization that applies over the entire arc length of the bend.

What is the Stress Intensity Factor (SIF)

Stress Intensity factor or SIF is a piping component fatigue strength factor that is the ratio of the elastically calculated nominal stress in a matching pipe that causes a through-wall crack to appear in a given number of cycles in a straight pipe butt weld to the elastically calculated nominal stress in the matching pipe used with the component that produces a through-wall crack in the same number of cycles in the component or attached pipe.

SIF is intended to be used for evaluating self-limiting stresses, derived from low-cycle fatigue tests.

Each code has tables that list and explain the flexibility factors and SIFs for most of the common components used in a piping system.

Although flexibility factors, used to calculate the piping forces and moments, are all similar, SIFs differ slightly between the codes.

To show the function of these tables, we use ASME B31.3 tables D300 as an example. The B31.3 table is more complicated than the others. It shows in-plane and out-plane categories of SIFs for each type of component.

The purpose is to apply different stress intensifications on the different orientations of the moment.

These tables are used as follows. For each component, we first have to calculate the flexibility characteristic, h. From this flexibility characteristic, the flexibility factor and SIFs are calculated.

It is clear from the table that for all the different components only the flexibility characteristics are calculated differently. The flexibility factor and SIFs are calculated more or less the same way for all components.

ASME B31.1 provides only one stress intensification for each component which is greater of in-plane and out-plane values. Hence it is not necessary to distinguish in-plane moment or out-plane moment for B31.1 calculations

What is the Pressure Stiffening of Bends?

In large-diameter, thin-wall elbows and bends, pressure can significantly affect the magnitudes of the flexibility factor.

B31.3 Excerpt related to Pressure Stiffening of Bend
Fig. 1: B31.3 Excerpt related to Pressure Stiffening of Bend

This correction in Stress intensification factor and flexibility factors can be considered by modification factors adopted from ASME codes as shown above in Fig. 1

What is ASME B31J?

ASME B 31J provides a standard approach for the development of SIFs, k-factors, and sustained stress multipliers for piping components and joints of all types, including standard, nonstandard, and proprietary fittings

The aim of using ASME B31J is to improve upon existing SIF and k-factors to get experimentally evaluated more accurate values to get realistic results.

The B31J 2008 edition provided a series of testing procedures to determine the SIFs. The 2015 edition brings experimentally-evaluated definitions based on component geometry, whereas the 2017 edition brings updates on the same.

All SIF and flexibility factor values are evaluated by calculations based on empirical, experimental, and FEA data from the observation of testing procedures.

B31.1 & B31.3 provide guidelines for to use of B31J. ASME B31J evaluation methods can be used in conjunction with ASME B31.1 and ASME B31.3 with 2012 and later editions. AMSE B31J can be used for metallic piping to calculate SIF and k-factors.

This code provides a standard approach for the development of SIFs, k-factors, and sustained stress multipliers for piping components and joints of all types, including standard, nonstandard, and proprietary fittings.

These SIF and k factors in ASME B31J are defined by performing multiple tests on pipe specimens by manufacturers or piping component users

Typical tests conducted as part of a piping component evaluation include,

  1. burst test
  2. SIF test
  3. k-factor test
  4. sustained load test

Nonmandatory Appendix A provides the standard method to develop stress intensification factors. Nonmandatory Appendix B provides the standard method to develop branch connection flexibility factors. Nonmandatory Appendix C demonstrates how the new branch connection k-factors should be used in the elastic analysis of piping systems, and Nonmandatory Appendix D provides a standard method to develop sustained stress factors.

Stress intensification and flexibility factors for most applications currently available metallic piping components were developed using the test procedures and numerical methods in this Standard and those are included in Table 1-1. These values should be used with the section modulus of the matching pipe

ASME B31.3 SIF vs AMSE B31J SIF

For each component, AMSE B31J provides 3 sets of equations or we can say that unique equations in each of 3 different directions for SIFs and flexibility i.e. in-plane, out-of-the-plane, and torsional.

ASME B31.3 SIF vs ASME B31J SIF
Fig. 2: ASME B31.3 SIF vs ASME B31J SIF

We can see the same in Fig. 2 for Welding Tee.

ASME B31.3 has the same equation for the branch and run leg of the welding tee in in-plane and out-of-plane direction SIF. So there are only 2 equations. Whereas ASME B31J provides unique equations in each direction for both branch and run of the tee. When the design Code requires the use of a single stress intensification factor, the largest of the directional stress intensification factors shall be used.

Run and Branch SIF
Fig. 3: Run and Branch SIF

The Branch Stress intensification factor applied is dependent or independent of the image (Fig. 3) shown here at the bottom and the location of stress is dependent on the relation of geometry between the branch and the header.

Torsional SIF

ASME B31.3 has torsional SIF considerations in sustained, expansion, and occasional stress for some time, but previously it was always using a value of 1. The introduction of B31J will support torsional SIF values other than 1 for AMSE B31.3 stress calculations.

So if you’re using B31.3 without B31J you will be able to enter user-defined torsional SIF values.

Flexibility factors as per AMSE B31J and ASME B31.3

Firstly, only Tee components are affected by the updated flexibility factors as per B31J whereas flexibility factors are the same for other components. Tee flexibility factors themselves were evaluated using static analysis for each Tee in the model. During our main static analysis system processor, we actually re-structure the stiffness matrices. The flexibility factors themselves are based on Tee geometry and joint definitions.

As the same with SIF calculations, branch flexibility values are now independent of the header. Here’s an example of the flexibility factors for both the run and the branch leg (Fig. 4) of a welding Tee as ASME 16.9.

Flexibility Factors B31.3 vs B31J
Fig. 4: Flexibility Factors B31.3 vs. B31J

So, each tee will produce six independent flexibility factors one for each direction, i.e. in-plane, out-plane, and torsional.

Run and Branch Flexibility Factor
Fig. 5: Run and Branch Flexibility Factor

So B31.3 is currently restricting the flexibility factors to a very small value which makes the piping tee more rigid and what this code aims to do is to provide a more detailed flexibility analysis by using accurate flexibility factors as per tee geometry.

SIF and Flexibility Factor Webinar using AutoPIPE

Please listen to the following recorded webinar for more detailed insight on SIF, Flexibility factor, and ASME B31J which was conducted on Wednesday, May 27, 2020, at 10:00 AM IST. Click here to register and view the recording of the SIF webinar.

Summary

  • ASME B31J provides more realistic and more accurate SIF and flexibility factors and hence provides more realistic code stresses than existing ASME B31.1 and B31.3 codes.
  • As I already explained additional geometric restrictions should be reviewed by the designer prior to accepting stress results. Those can be seen in model consistency checks and code themselves. Needs to review them before actually reporting your results.
  • ASME B31J can be applied to ASME B31.1 and B31.3, 2012, and later edition models. This is sort of an initial step and later it will be expanded further.
  • And finally in AutoPIPE AMSE B31J SIF and flexibility calculations are enabled with simple clicks. Then you just have to provide some additional geometry information, then run an analysis, and review the results.
  • Flexibilities used for piping and nozzle connections by most piping and pressure vessel designers or stress analysts are based on old technology. These flexibilities have a significant impact on displacements, forces, and stresses, often skewing results from reality.
  • Using B31J one can find many opportunities to reduce design time, construction costs, analysis time, and lifecycle maintenance costs.

Few more related articles to increase your knowledge.

Piping Elbow or Bend SIF (Stress Intensification Factor)
Importance & Impact of Stress Intensification Factor (SIF): A Presentation
How to use ASME B31J-2017 and FEM for SIF and k-factors for Stress Analysis
ASME B 31J & B 31J Essentials: Why these are useful in Piping Stress Analysis?
Applicability of Caesar II for stress analysis of lines having D/t ratio more than 100
11 most important questions & answers from ASME B 31.3 which a Piping stress engineer must know.