Modeling Fired Heater Piping Connection is a bit tricky as the pipe is not welded to a fired heater shell similar to ordinary equipment. The heater has a hole, the pipe runs through that hole inside the heater body.
There are two techniques for modeling fired heater piping connection:
First method: Use an anchor at the point where the piping goes inside the heater. The heater vendor must provide the allowable loads for this anchor point. Or the API 560 code may be used
Second Method: Model the whole or part of the furnace coil that is inside the heater. The vendor should provide allowable displacements at the point where the pipe goes inside the heater (+dx, -dx, +dy, -dy, +dz, -dz). Usually, it’s the gap values between the pipe and heater shell
You can choose one of these two methods.
First Method – Allowable Loads
The first method is very conservative. The loads on the fired heater usually are very huge, but allowable loads are very small and can’t be met.
In START-PROF software the “Fired Heater” Object can be used.
Allowable Nozzle Loading Method of Fired Heater Piping Connection Model
Second Method – Allowable Displacements
Using the second method it is easier to satisfy the vendor requirements. There’s no need to model the whole furnace coil, just 3-4 U-Tubes are enough.
Allowable displacement model of Fired Heater Piping Connection model
The supports in the furnace coil should be modeled correctly.
The following conditions should be met:
Pipe displacements at the point where pipe hoes inside the heater should be less than the vendor’s allowable
All stresses both in the pipe and in the furnace coil should be less than allowable according to the selected code
Loads on the furnace coil supports should be less than allowable
Pipe Color Coding and Pipe Marking Criteria with Examples
Pipe color coding is a system of using different colors to identify the contents and the function of pipes in a piping system. The colors used in the pipe color coding system are standardized and recognized by various organizations, including the American National Standards Institute (ANSI), the Occupational Safety and Health Administration (OSHA), and the International Organization for Standardization (ISO).
The pipe color coding system is an important safety measure in industrial settings, as it helps to prevent accidents and ensure that workers can quickly and easily identify the contents and function of pipes in a piping system. By following the pipe color coding system, workers can avoid potentially dangerous situations, such as accidentally connecting pipes carrying different types of fluids or gases.
Industrial Pipe Color Coding and Pipe markings are used to differentiate and keep track of fluids transported inside the pipes; Mainly to identify pipes carrying hazardous fluids. While in a plant, most of you must have seen in operating process plants that pipes are colored in various colors.
Importance of Pipe Color Codes
There are two main reasons behind industrial pipe color coding and pipe marking:
To allow the metallurgy of each pipe spool to be easily identified in the warehouse before the erection
Process and utility piping can be properly and clearly identified for use by plant personnel
So pipe color coding will help in identifying the Piping components shipped individually to the construction site and Material identification shall not be required for pipe spools that have been verified by the shop and have mark-piece numbers associated with them.
Permanent color pipe service markers shall be used for process and utility services. The fabricator shall provide service markers for the spools produced. Placing the marker on the spool shall be done after the piping has been installed, coated, or insulated if required.
Pipe Color Coding and Pipe Marking of Systems
Pipe Material Color Coding
Piping Material color coding is developed to differentiate between various grades or specifications of materials. Color markings are assigned on the basis of nominal chemical compositions. The location of pipe marking shall be as follows:
The pipe shall be marked with, for example, paint, dye, or tape for its full-length
Flanges shall be banded (Refer to Fig. 1) on the back of the flange at the intersection of the back face and the hub
Miscellaneous material shall be color-marked so as to provide proper identity
The paint shall not cover welded surfaces, heat marks, or any other identification
Fig. 1: Figure showing Pipe Color Band Locations
Pipe Service Markers
Permanent color pipe service markers shall be used for all process and utility piping systems within the plant.
Piping systems for pipe color coding shall include utility pipes of any kind and, in addition, fittings, valves, and pipe coverings. Piping systems shall be painted a neutral background color, for example, aluminum or grey, which shall not detract from the high visibility of the colors and lettering of the service markers.
Permanent color markers for piping systems shall be placed at the battery limit and at vertical risers at utility stations. Service markers shall be applied close to valves or flanges, and adjacent to changes in direction, branches, and where pipes pass over or through walls, floors, fences, or roads, and on straight pipe runs, sufficient for identification.
A service marker in English shall be used as the primary and explicit means of identification for the contents of all aboveground piping. Positive identification of the contents of a piping system shall be by a lettered legend giving the name of the contents in full or abbreviated form. Arrows shall be used to indicate the direction of flow. Additional details, for example, temperature or pressure, shall be added as necessary to highlight the degree of hazard.
Shutdown, emergency, or car-sealed valves shall be labeled with P&ID and valve numbers and any descriptive labeling needed to permit easy identification. Firewater system sectionalizing block valves shall be identified by their firewater system identification number.
Contrast shall be provided between the color field and legend for readability. For identification of materials in pipes of less than 3/4 inch (19 mm) in diameter, and for valve and fitting identification, the use of a permanently legible tag is recommended. The size of the service marker letters shall neither be less than 13 mm nor greater than 89 mm, varying in size depending on the outside diameter of the pipe.
For piping 2-inch NPS and smaller running between equipment, where the total length is less than 15 m, no pipe marking shall be necessary. For piping on pipe racks, pipe service marking shall be oriented in a way that it is visible from grade level and from any nearby platform.
The color of the service marker letters shall be black or white, whichever provides a greater contrast to the background color.
Pipe markings shall be clearly visible. Where pipelines are located above or below the normal line of vision, the lettering shall be placed below or above the horizontal centreline of the pipe.
Pipe Marking materials for stainless steel and nickel alloy piping shall not contain any harmful substances, for example, chlorides, fluorides, sulfur, and low melting point metals.
Pipe Color Coding and Marking Execution Process
Surface Preparation: Surfaces to be color-coded or marked shall be free from oil, grease, dirt, and other surface contaminants that might be detrimental to the adhesion of the paint used for color coding and marking.
Application of Pipe Color Coding and Pipe Marking
Whenever color coding or marking paint is to be applied to a primed surface, the primer shall be dried completely before the color coding or marking paint is applied.
Color coding, marking, and identification paint shall be applied to dry, clean surfaces in accordance with the manufacturer’s instructions.
Unless otherwise recommended by the manufacturer, color coding and marking shall not be undertaken when the ambient temperature is less than 10 °C (50 °F), or the relative humidity is more than 90 percent.
Color coding and marking paint shall be applied in 1 coat.
Industrial Pipe Color Coding Standards
There are several pipe color coding standards used around the world. Here are some of the most common ones:
ANSI/ASME A13.1: This is a standard used in the United States to identify the contents of pipes in industrial settings. It recommends the use of specific colors and labeling requirements to indicate the type of fluid or gas being transported in the pipe.
BS 1710: This is a British standard that provides guidance on the use of colors to identify the contents of pipes in buildings and industrial facilities. It recommends the use of specific colors and labeling requirements to indicate the type of fluid or gas being transported in the pipe.
ISO 14726: This is an international standard that provides guidance on the use of colors to identify the contents of pipes in marine and offshore environments. It recommends the use of specific colors and labeling requirements to indicate the type of fluid or gas being transported in the pipe.
DIN 2403: This is a German standard that provides guidance on the use of colors to identify the contents of pipes in industrial settings. It recommends the use of specific colors and labeling requirements to indicate the type of fluid or gas being transported in the pipe.
AS 1345: This is an Australian standard that provides guidance on the use of colors to identify the contents of pipes in buildings and industrial facilities. It recommends the use of specific colors and labeling requirements to indicate the type of fluid or gas being transported in the pipe.
PFI ES-22 – Recommended Practice for Color Coding of Piping Materials
IS 2379 – Pipelines Identification Color Code
These standards provide guidance on the use of colors to identify the contents of pipes and ensure consistency and safety across different industries and regions.
Different codes mentioned above use different philosophies with respect to pipe color coding and pipe marking systems. For example, As per ASME A13.1, the following pipe color code system is followed:
Fig. 2: Pipe Color Codes
The pipe color coding system uses different colors to represent different types of fluids or gases, as well as to indicate the direction and function of the pipe. Here are some examples of the colors used in the pipe color coding system:
Red: Used to indicate fire protection piping, as well as piping carrying flammable gases and liquids.
Yellow: Used to indicate fuel gas piping.
Green: Used to indicate piping carrying compressed air and other non-toxic gases.
Blue: Used to indicate piping carrying potable water.
Orange: Used to indicate piping carrying toxic or corrosive fluids.
Brown: Used to indicate sewage and other waste materials.
Black: Used to indicate piping carrying process gases and liquids.
White: Used to indicate piping carrying steam.
Pipe Color Coding Chart
A pipe color coding chart is a reference tool that lists the recommended colors and labeling requirements for different types of pipes in a piping system. The chart helps workers quickly and easily identify the contents and function of pipes in industrial settings, which is important for safety and efficiency.
The pipe color coding chart typically includes the following information:
Color coding: The chart lists the colors used to identify different types of pipes, such as red for fire protection, yellow for fuel gas, green for compressed air, and so on.
Labeling requirements: The chart provides guidance on the labeling requirements for each type of pipe, including the information that should be included on the label, such as the contents of the pipe, the direction of flow, and any hazards associated with the pipe.
Pipe types: The chart may also include information on the different types of pipes used in a piping system, such as metal, plastic, or composite pipes, and how they should be identified.
Pipe color coding charts are often based on industry standards, such as ANSI/ASME A13.1 in the United States or BS 1710 in the United Kingdom. By using a pipe color coding chart, workers can quickly and easily identify the contents and function of pipes in a piping system, which can help to prevent accidents and ensure that the system operates safely and efficiently.
Typical Examples of Pipe Color Codes
Industrial pipe color coding conventions may vary by region, industry, local codes, standards, and safety regulations. Here are some of the typical examples of pipe color codes.
Ammonia Piping Color Code:
Pipe Color: Light Blue
Label or Tape Color: White
Purpose: Light blue is commonly used to indicate ammonia piping. White labels or tapes may be used for additional information or identification.
Utility Piping Color Code:
Pipe Color: Green
Label or Tape Color: Yellow
Purpose: Green is typically used to identify utility piping, which can carry various non-hazardous fluids like air, compressed air, or cooling water. Yellow labels or tapes may be used to convey additional information.
Water Piping Color Code:
Pipe Color: Blue
Label or Tape Color: White
Purpose: Blue is a universal color for water piping. White labels or tapes can be used to provide further details, such as the type of water (e.g., cold water, hot water) or other relevant information.
Oil and Gas Piping Color Code:
Oil Pipe Color: Orange
Gas Pipe Color: Yellow
Label or Tape Color: Black
Purpose: Orange is often used for oil pipelines, while yellow is the standard color for gas pipelines. Black labels or tapes may be used for identification and additional information.
Gas Pipe Color Code:
Pipe Color: Yellow
Label or Tape Color: Black
Purpose: Yellow is the established color for gas piping, and black labels or tapes can be used to provide specific details or warnings.
Sewer Pipe Color Code:
Pipe Color: Green (for non-potable sewage)
Label or Tape Color: White
Purpose: Green is used to signify sewer pipes carrying non-potable sewage. White labels or tapes can be used for additional information.
Plastic Pipe Color Code:
Pipe Color: Various Colors (depending on the material and purpose)
Label or Tape Color: Often matches the pipe color or follows standard conventions
Purpose: Plastic pipes come in various colors based on the material and intended use. Labels or tapes usually match the pipe color or adhere to industry standards.
Steam Pipe Color Code:
Pipe Color: Silver or Aluminum
Label or Tape Color: Black
Purpose: Silver or aluminum pipes are often used for steam, and black labels or tapes can be added for clarity and identification.
Power plant pipe color coding vs. Process/Chemical plant pipe color coding
There are differences between power plant pipe color coding and process plant pipe color coding, although there may be some overlap between the two systems.
In general, power plant pipe color coding tends to be more focused on identifying pipes carrying specific types of fluids or gases that are used in the power generation process. For example, power plant pipe color coding may use specific colors to indicate pipes carrying steam, condensate, feedwater, and cooling water.
Process plant pipe color coding, on the other hand, may be more focused on identifying the contents of pipes based on their chemical composition and physical properties. For example, process plant pipe color coding may use specific colors to indicate pipes carrying acids, bases, solvents, and other chemicals.
The specific colors used in power plant and process plant pipe color coding may also differ depending on the region and industry. For example, the colors used in power plant pipe color coding in the United States may be different from those used in Europe or Asia.
It’s important for workers in power plants and process plants to be familiar with the pipe color coding system used in their specific industry and region, as this can help prevent accidents and ensure the safe and efficient operation of the plant.
Start-Prof can estimate the support loads and stresses caused by slug flow loads using the static method.
Additional dynamic loads caused by the slugs hitting the bends and tees must be considered. It can lead to the dropping of piping from the supports, exceeding the allowable nozzle and pump loads, etc.
One of the methods for calculating the effect of slug flow loads is the static method. Vertical, horizontal, and resultant forces F can be determined by the formulas:
where
θ – bend angle (90 degrees, 45 degrees, etc.) ρ – fluid density v – slug velocity at the moment then it hits the bend A – internal pipe cross-section area DLF – dynamic load factor. For the static method recommended value is DLF=2 For straight tees load is calculated the same as for a 90-degree bend. Calculated forces should be applied to the bends that the slug heats step by step.
A=p∙(D-2t)²/4 = 3.14159∙(0.219-2∙0.016)²/4 = 0.027465 m² Loads on bend 2 will be: F=DLF*ρ*v*v*A*(1-cos 90)=2*0.001*40*40*274.65*(1-cos 90)=8790 N=879 kgf F=2*1000*12.65*12.65*0.027465*sin 90=8790 N=879 kgf Loads on bend 3 will be: F=DLF*ρ*v*v*A*(1-cos 90)=2*1000*12.65*12.65*0.027465*(1-cos 90)=8790 N=879 kgf F=2*1000*12.65*12.65*0.027465*sin 90=8790 N=879 kgf Loads on the bend 4: F=DLF*ρ*v*v*A*(1-cos 60)=2*1000*12.65*12.65*0.027465*(1-0.5)=4390 N=439 kgf F=2*1000*12.65*12.65*0.027465*sin 60=7610 N=761 kgf The smaller the angle of the bend, the less the load on the bend, because the direction change angle of the slug is smaller.
Using operation mode editor we should create one main operating mode (1) and three additional modes that will model slug loads on bends 2,3,4 (1.1, 1.2, 1.3). The mode type should be occasional.
In the picture below three load modes are shown:
To apply loads we should add an additional node near bend 2 and apply calculated loads:
The same for bend 3:
And for bend 4:
Piping stress caused by slug impact at the bend 3:
Support loads caused by slug impact at the bend 3:
In order to prevent the piping from falling from the supports, reduce the support loads, and reduce the stresses, you need:
Add limit supports (limit stop supports with a gap, sway brace, and snubber), that will take the huge dynamic loads
Stress Analysis of Buried or Underground piping seems to be difficult for many stress engineers due to the complex soil-pipe interaction. But the software Caesar II easily handles that part. In this article, we will learn the various buried piping analysis methods that are available in Caesar II. The points that will be covered in this article are:
The various analysis method of Underground piping
Overview of Soil Classification
Discuss the current practice of Underground pipe modeling & analysis
Examine the data inputs for buried piping and pipeline stress analysis
Make a suggestion for sound input data, especially where information is not known or available
Learn the inputs, generate some results & conclusions
Fig. 1 below provides the soil classification for the most basic soil types used for underground piping stress analysis.
The most basic classification of soil is based on grain size.
Soils with large grains are called “gravel” and soils with small grains are “sand”.
Internationally it is defined that sand contains grains larger than 0.063 mm and smaller than 2 mm.
Gravel contains grains with sizes between 2 mm and 63 mm.
Grains smaller than 0.063 mm are called “silt”.
Grains smaller than 0.002 mm are called “clay”.
Fig. 1: Soil Classification
Shear Stress in Soils
The ability to resist shear stresses depends on friction and cohesion.
When cohesionless soils are poured to the ground from above they will spread due to gravity. Because of friction, the area of spread is limited creating an angle of repose (φ) at the balanced state.
From this experiment, the friction force that resists the shear loads may be calculated and the internal friction coefficient (µ) of the soil may be determined:
f = µ ⋅n = µ ⋅w⋅cosϕ —-where f=wsinϕ
µ = tanϕ
The friction resistance (s) of any soil in any plane is then expressed as Sliding force ( s ) + Cohesion ( c )
s = n⋅tan(ϕ) + c
The angle (φ) is also called the soil angle of internal friction.
Axial Soil Resistance
Frictional Force on the Top of the Pipe and at the Bottom Of the pipe are different
In the case of an idealized model the axial resistance (f) can be determined by the following expression:
Fig. 2: Axial Soil Resistance equations
Lateral Soil Resistance
Lateral Soil Resistance is divided into 3 parts viz. Upward, Downward and Sideways
Upward Resistance (Fig. 3):
Upward soil resistance can be described by the application of the “soil prism theory” also known as “Marston’s load theory”! This theory states that the soil resistance is determined by (a) the weight of a soil prism above the pipe and (b) the shear forces exerted on either side of the prism. ! The shear conditions depend on the installation layout of the pipe and soil, but in this case, negative shear will be assumed. ! Next to the soil prism, the weight of the pipe needs to be taken into consideration as well.
Shear stresses can be found by integrating the friction along both side surfaces of the prism.
Let’s assume cohesionless soil (c=0, e.g. sand); ϕ is the friction angle of the soil.
q = ρDH + 2H (c + 0.5 ρ H Ka tanФ) + Wpipe = ρDH + ρH2 Ka tanФ
Downward Resistance (Fig. 3):
When the pipe moves downwards the soil resistance can be determined from the “vertical bearing capacity”.
Detailed geotechnical evaluation is required to determine the vertical bearing capacity.
For a general idea, the downward resistance can be roughly estimated to be as twice the horizontal resistance. ! The vertical bearing capacity is the vertical load required to break the soil underneath the pipe over the full width of the pipe.
Horizontal Resistance (Fig. 3):
When a pipe moves horizontally, it experiences
Passive Force from Front
Active Force from Back
Active force is ineffective as the pipe moves and a void is created.
qh = ½* ρ (H+D)2 tan2 (45 + Ф/2)
For cohesive soil (clay) ф = 0, hence less resistance
Fig. 3: Upward, Downward and Horizontal Resistance
How Caesar II models soil?
Soil is modeled as a ‘Bilinear Spring’ having ‘initial stiffness, ultimate load, and Yield Stiffness’
Ultimate load: Maximum load on the soil beyond which load does not increase but displacement can.
Ultimate loads are different in axial, lateral, and vertical directions
Modeling Soils in Caesar II
Caesar II simulates the soil surrounding the pipeline using springs of varying stiffness as shown in Fig. 4.
Fig. 4: Modeling Soils in Caesar II
About CII Buried Pipe Modeler
Refer Fig. 5
Fig. 5: Underground modeling in Caesar II
CAESAR-II Basic method by LC Peng
Fig. 6: Caesar II Basic Buried Model
American Lifelines Alliance-ALA
Fig. 7: Caesar II American Lifeline Alliance Buried Model
ALA method with 31J
B31J provides a set of calculations for revised SIFs and flexibility factors, as defined in the upcoming revision to ASME B31J. By using these revised SIFs and flexibilities, your stress analyses produce more accurate results. B31J provides the “more applicable data” referenced in recent editions of the piping codes.
Result Comparison with Various method:
Fig. 8: Caesar II Results Comparison for the same model
Conclusions
Results obtained by ALA Method are more reliable
ALA considers more variables based on published data
Better method if the soil is changing through the run
Peng’s Method gives a very good understanding of the subject and gives quick results for non-critical
If the buried pipe is modeled just as a reference in the Above ground Piping Analysis then suggested going for the ‘CAESAR II Basic Model’
For Pipeline analysis use ‘ALA Method with user-defined stiffness input
You can attend an online course on buried/underground pipe/pipeline stress analysis that covers the underground pipe stress analysis details using a practical case study by clicking here.
Author: This presentation is prepared by Mr. Deepak Sethia who is working in ImageGrafix Software FZCO, the Hexagon CAS Global Network Partner in the Middle East and Egypt. He has extensive experience in using Caesar II and PV Elite software and troubleshooting.
This article is intended to serve as a guide in the development of equipment layout and piping layout for centrifugal compressors and their associated equipment, with the goal of producing safe, operable, economical, and maintainable installations.
Compressors are machines, which are used to increase the pressure of a gas by mechanically reducing its volume within the compressor casing.
Compressor Types
Positive Displacement Compressors
Reciprocating compressor
Screw Compressors
Centrifugal compressors
Pipeline compressors
Type of Compressor Drives
Following are the various types of Compressor drives:
Electric Motor Drives
AC Squirrel Cage Induction Motor
Synchronous AC Motor
Gas Turbines
Steam Turbines
Variable Speed Drives
Variable Frequency Drive
Variable speed (Hydraulic Coupling) Drives
Auxiliary Equipment’s
Lube Oil Cooler (Supplied by Compressor Vendor)
Lube Oil / Seal Oil Console (Supplied by Compressor Vendor)
Surface Condenser
Condensate Pump
Inlet Air Filters (Supplied by Compressor Vendor)
Suction Scrubber (Upstream of Compressor)
Air Cooler (Downstream of Compressor)
Discharge Scrubber (Downstream of Air Cooler)
Compressor Layout
When locating compressors, consideration must be given to accessibility, maintenance, and loss prevention requirements.
There must be a Vehicular (Crane / Fork Lift Truck) Access-way on at least one side of the installation. Refer Fig. 1
Fig. 1: Figure showing the requirement of Crane Access
A compressor is generally located inside Shed with the provision of a Mono-Rail or EOT Crane for Maintenance. The capacity of the crane is to be decided based on 150% of the highest weight of the component to be lifted. To be checked with the compressor vendor.
A compressor can be installed in a Series and Parallel arrangement.
The minimum Distance between two Adjacent Compressors shall be 10m.
Generally, Compressors are Grade Mounted (Fig. 2). But Process criteria/requirements will decide if it should be grade mounted or elevated
Fig. 2: Grade-mounted Centrifugal Compressor
Compressor Piping Layout
Suction & Discharge Piping (Fig. 3)
Compressor Suction Piping Shall be as Short as Possible.
Compressor Suction Piping should have Inlet Filter / Strainer. It can be Temporary or Permanent
Suction Piping should be sloping/free draining towards Inlet Scrubber
Suction lines require a minimum straight run of piping upstream of the suction nozzle which varies between 3 and 8 times the normal pipe size. (Vendor requirement)
All operating valves must be readily accessible, preferably from grade.
All lines to the Compressor shall be provided with break-up flanges for Maintenance.
Compressor Suction Line Flowmeter: Suction routing shall be such that Upstream and Downstream straight lengths shall be sufficient for the performance of the Flowmeter
Anti-Surge Valve Is Designed and Supplied by Compressor Vendor.
Input to Compressor Vendor for Designing / Sizing the Anti-Surge Valve is given by piping, by providing suction and discharge length.
Anti-Surge Valve is located on the Anti-Surge line which is basically a by-pass / recirculation line between Compressor Suction and Discharge Piping for Surge control
Anti-Surge Valve shall be located at Highest Point and shall be free draining on both side
Lube Oil Cooler & Piping (Fig. 4)
Lube Oil Cooler Shall be Accessible from Road.
Lube Oil Cooler Shall be located as close to Compressor as Possible.
Lube Oil Cooler Piping Should Not Interfere with Access and Maintenance space.
Lube Oil Cooler line must be Free Gravity flow requirements.
Lube Oil Cooler Piping Should have Break-up Flanges for Maintenance purposes.
Lube Oil Cooler Isometric should also have noted for “Pickling and Passivation” i.e. Chemical cleaning of Lines before commissioning.
Supporting Compressor Piping
The first support from Compressor Suction and Discharge nozzle is either Spring support or Adjustable support for Alignment during Construction / Erection.
Fig. 4: Lube Oil Cooler
Compressor piping should never be supported by the Compressor foundation. Pipe supports must be provided with independent foundations to avoid transmission of vibration.
Compressor Suction / Discharge Piping should be routed in such a way that it has enough flexibility to accommodate Thermal Expansion and Reduce the Nozzle Load.
Compressor Suction / Discharge Piping should be adequately supported as per Stress Engineers’ Support requirements.
Process Should be consulted for any possibility of two-phase flow/slug flow and the line should be supported accordingly
As compressors are meant for Gaseous fluid, the Hydro-test load on supports may be very high for big bore lines. Hence we can recommend Temporary supports to be erected during Hydro-testing with the help of a Stress Engineer.
Utility Requirements
The following are the utilities required for the Compressor:
External Fuel gas for seal gas system
Instrument Air for the Instruments/Control system/Seal gas system
External loads on static equipment nozzle flange joints must be assessed in order to comply with code requirements. In general, except for the flanged joints at high temperatures, the external forces and bending moments have little effect on the joint integrity of a properly assembled joint as long as the loads are within allowable design stress levels. It is a standard engineering practice to limit the external loads on flanged joints. So, selecting an appropriate method for assessing the effect of piping bending moments and external loads during the design phase becomes a task in trying to set a limit that encourages good piping design. There are various methods available for assessing the effects of external loads on nozzle flanges. In this article, we will discuss some of those methods. The points that will be covered in this article are:
ASME Interpretation BPV VIII-1-16-85
ANSI Flange Pressure Reduction Options In PV Elite
Code Case 2901
What Code Interpretation BPV VIII-1-16-85 States
This interpretation states that if you have external loadings acting on a nozzle you have to consider them on the flange too.
In 2013, however, PVP2013-97814 was written to address this issue. But many users complained that their jurisdictions did not/would not accept such a published (peer-reviewed) paper by a reputable author, because it did not have the approval of the ASME Boiler and Pressure Vessel Code Committee.
Compliance With ASME VIII-1, Paragraph UG-22:
Internal and external design pressures are not the only criteria used when designing pressure vessels. ASME VIII-1, paragraph UG-22, requires that all external loads acting on the pressure vessel be taken into account as well.
These include forces and moments that arise from attached piping and equipment, the weight of the vessel and its contents, liquid static head as well as wind and seismic induced reactions.
ANSI Flange Pressure Reduction Options:
Select a method for ANSI flange pressure reduction. Several methods are available to de-rate the flange MAWP based on external loads. If flanges are externally loaded they have the potential to leak. To keep this from occurring, it might be necessary to choose a heavier class of flange than one that is good for the design pressure per the B16.5/47 standard.
At the time of this writing (November 2017), the ASME Code has no rules on a particular method to use. They do however state (in a Code Case) that the external loadings must be considered.
Methods Available in PV Elite:
Kellogg Method
PVP Method
50% Stress Method
DNV Method
Assessing the flange MAWP reduction method in PV Elite:
Kellogg Method –
The Kellogg method is well-known and conservative. The axial load and moment are used to compute an equivalent pressure that is then deducted from the flange rating from the B16/47 table.
PVP Method –
This method is taken from the paper: ‘Improved Analysis of External Loads on Flanged Joints’ PVP2013-97814 by Dr. Warren Brown delivered in Paris July 14-18 2013 published by ASME. MAWP of the flange is adjusted so that the following equation is observed:
Sustained forces and moments must be entered for those results to be meaningful. Otherwise, the computed flange rating is zero.
50% Stress Method –
If the computed stress/allowable stress is < 0.5 on the pipe wall, then the allowable pressure is the full rating from the ANSI/ASME standard. If the stress ratio is >= 0.5, then the full equivalent pressure based on the Kellogg method is subtracted from the flange rating. This method looks at the stress in the nozzle wall to determine the MAWP. These are the data:
DNV Method –
The DNV method is considered to be a bit unconservative. It is essentially 1.3 times the flange rating minus the equivalent pressure based on the Kellogg method. The idea is that because the flanges will be a hydro test at elevated pressure and because there will loading applied (flanges in the piping system), then their rating can be elevated using the above equation. Most piping is tested to 1.5 times the design pressure, but we use a factor of 1.3 for conservatism because 1.3 is the factor used in Division 1 for hydro testing pressure vessels.
Note- The equivalent pressure is the pressure derived from the Kellogg Equation.
Analysis result-
ASME BPVC Code Case 2901:
Does Code Case 2901 available in PV Elite?
Yes, the PVP method in PV Elite is essentially the same thing as the Code Case.
ASME BPVC Code Case 2901-
The PVP MAWP Reduction Method-
What’s New in PV Elite 2019:
This presentation is prepared by Mr. Deepak Sethia who is working in ImageGrafix Software FZCO, the Hexagon CAS Global Network Partner in the Middle East and Egypt. He has extensive experience in using Caesar II and PV Elite software and troubleshooting.
