Questions need to be answered by Meena Rezkallah, P.Eng.

Questions need to be answered by Meena Rezkallah, P.Eng.

lots of engineers, contractors, EPC companies, Clients keep asking about

  1. Pressure vessels
  2. pipe stress analysis
  4. Design Pressure
  5. Valves

So I listed some of the common questions and Their common and most approvable answers.

How do you review piping stress analysis?

How do you calculate stress in a pipe?

How do you do a pipe stress analysis in Caesar?

How do you perform a stress analysis?

What is design pressure in pressure vessel?

What are the necessary documents required for stress analysis?

What are valves and their functions?

How do you review piping stress analysis?

How do you calculate stress in a pipe?

How do you do a pipe stress analysis in Caesar?

How do you perform a stress analysis?

What is design pressure in pressure vessel?

What are the necessary documents required for stress analysis?

What are valves and their functions?

How do you review piping stress analysis?

How do you calculate stress in a pipe?

How do you do a pipe stress analysis in Caesar?

How do you perform a stress analysis?

What is design pressure in pressure vessel?

What are the necessary documents required for stress analysis?

What are valves and their functions?

The Canadian Pipe Stress Analysis Design Manual for Owners, Engineers and Contractors

The Canadian Pipe Stress Analysis Design Manual for Owners, Engineers and Contractors for a premium piping engineering & full-service pipe design and pipeline / pipe stress analysis services across Canada & globally. Using CAESAR II and pipe stress calculations as per API, ASME B31.3, B31.1, B31.8, B31.4, CSA Z662.

The Canadian Pipe Stress Analysis Design Manual for Owners, Engineers and Contractors

The Canadian Pipe Stress Analysis Design Manual for Owners, Engineers and Contractors







5.1 Pumps

5.2 Compressors

5.3 Turbines

5. 4 Airfans

5.5 Heaters

5.6 Buried Piping

5.7 Cryogenic & Low Temperature Piping


6.1 Allowable Pipe Spans

6.2 Allowable Pipe Overhang

6.3 Pipe Guide Spacing

6. 4 Instrument Strong Back Flexibility

6.5 In-Line Pumps

6.6 Expansion Loop Design

6.7 Pipe Anchors

6.8 Stacked Exchangers

6.9 Off Plot Pipeways


7.01 Slug Flow

7.02 Mitered Elbows

7.03 Tee Connections

7.04 Injection Connections

7.05 Heater Coil Decoking

7.06 Catalyst Regeneration

7.07 Reformer Furnace Pigtail Design

7.08 Cold Spring

7.09 Blowdown Systems

7.10 Field Checkout

7.11 Soot Blowers

7.12 Settlement and Frost Heave

7.13 Ambient Temperature Effect on Bare Piping

7.14 Control Valve Piping

7.15 Hydrotest of Large Low Pressure Piping

7.16 Pipe Supports

7.17 Tank Field Piping

7.18 Steam Trace and Steam Trap Piping

7.19 Plastic Piping

7.20 Rotations, Reactions and Stresses at Nozzle Connections to Vessels

7.21 Bowing of Pipe

7.22 Compressor Bottle Support

7.23 Tank Nozzle Movements Due to Pressure and Temperature



1.1 This Design Guide is intended to aid stress personnel / Piping Stress Engineer in following approved procedures and techniques to complete their work (Pipe Stress Analysis) on an assigned project.

1 .2 Although it is recommended that the standards be followed closely, individual thought and sound engineering judge­ment must be used at all times.

1.3 In reviewing piping isometrics, models or drawings, the Pipe Stress Analysis Engineer should keep in mind that the aesthetic de­sign of the piping systems is the responsibility of the piping design groups and therefore he should review them from a stress and support standpoint only. Exceptions to the above should only be made when a situation ridiculously improper or a large economic saving is involved, keeping in mind lost time in making revisions and their affect on schedules.

1 .4 All piping systems reviewed by the Piping Stress Analysis Group shall be considered for all the “Design Conditions” as listed under Section 301 of the Code for Pressure Piping ANSI B31 .3, latest revision, or other applicable codes. As a general rule most computer analyses of piping should include only the effects of thermal expansion, restraints and effects of support, anchor and terminal movements. Effects of dead load on a well supported system are generally small. Other effects are to be studied by special calculations only when engineering judgement deems them to be possibly severe.


The following normal procedures may be adjusted for particular projects or office locations to suit the special conditions and requirements of those projects and locations.

2.1 The assigned Piping Stress Analysis Engineer shall confer with the Pressure Vessel Job Supervisor and indicate his preference of draw­ings which should be distributed to him. These drawings should generally be plot plans, P&ID’s, paving and grading, underground piping, pipe way stanchions, line designation tables, basic data, flow diagrams, piping drawings and piping isometrics. When vessel drawings and structural drawings are included, the filing of drawings becomes a major problem. In fact, much filing would be avoided if P&ID’s and paving grading drawings were not included. This judgment is left to each individual.

2.2 The routing of piping isometrics between the Plant Design Group and the stress group has been standardized to increase efficiency of all groups concerned and to reduce the amount of paper handling. Isometrics will be referred to as iso’s in further discussions. The presently adopted procedure for iso distribution on modelled jobs is:

a) After isometrics are drawn up and checked within the Plant Design Group and are ready to issue for construction, a print of each together with a transmittal list shall be sent to the Pipe Stress Analysis Engineer one week before date to be issued for construction.

b) The Piping Stress Analysis Engineer then places a design data stamp on all iso’s except those which can be approved for stress by inspection without specific design data. The stamped iso’s should then be filled in with the necessary design data from piping specifications and line design tables. An efficient and acceptable method of recording the expansion temperatures is to prepare a list of maximum “exp” temperatures for each particular service as shown in the Line Designation Table, i.e.:

IA (instr. air)——–100°F

UA (util. air)——–100°F

N (nitrogen)——–100°F

DW (drinking water)——–100°F

PW (potable water)——–100°F

RW (raw water)——–100°F

CW (cooling water)——–120°F

LS (low press. steam)—-40# sat stm temp.

MS (med press. steam)-150# sat stm temp

HS (high press. steam)-600# sat stm temp

But process lines require individual temperature assignment from the line tables.

Likewise, a list can be prepared for pipe specifications which are repeated often that are of carbon steel and the same schedule. Alloy spec.’s and their schedules should be specially listed for ease of identification.

c) The iso’s are then reviewed at the models and passed by judgment as much as possible, leaving only a few to verify by computer calculation. All iso’s passed by inspection should be marked up with support designations during the review of each iso. This in general will be the most efficient operation except where a group of iso’s must be immediately released by the Plant Design Group for prompt delivery to the fabricator to meet a schedule. After all the iso’s listed on a particular transmittal have been reviewed, those which can be field-supported, or require no supports, or which can be supported by wholly standard support details, are indicated on the transmittal and the blue print of the iso itself with the designations FTS, NS or STD respectively. The Plant Design Group can stamp the original iso’s accordingly without need of their passing through the pipe support groups. Technicians, will be retained by The Plant Design Group for the purpose of assigning proper designations to the “STD” supports required on every iso. This should expedite the preparation of iso’s to be issued for construction on the Rev. 0 issue. All other iso’s are checked off on the original transmittal as being approved for stress with an engineered support designation ES except where a flexibility change or calculation is needed. The symbol HFS indicating “Hold For Stress” will be tagged on the transmittal opposite the iso involved. Two copies of the trans­mittal with the above notations should then be given to the Plant Design Supervisor.

d) All iso’s as they are approved by the Pipe Stress Analysis Engineer, should be initialed on the tracing by the Pipe Stress Analysis Engineer or his designated alternate. Where iso’s require a calculation, the tracing should be detained by the Plant Design Group until the Piping Stress Analysis Engineer finalizes his study of them. The Piping Stress Analysis Engineer should assign the highest priority to finalizing these iso’s.

e) When iso’s are verified as satisfactory by calculation, the Plant Design Group should be immediately notified for its release. And if iso’s require a revision, the print should be marked up with the required change and a copy of the print should be given to the plant Design Group. After the iso revisions have been made, a new print should be again issued to the Pipe Stress Analysis Engineer for final review. If the iso is correct the Pipe Stress Analysis Engineer will initial the tracing as approved.

f) All prints marked up by the Piping Stress Analysis Engineer with the support require­ment symbol £S are then turned over to the Support Group. If iso’s are stamped for review of critical support details, the pipe support designer must return the iso and support details to the Piping Stress Analysis Engineer who, upon approval of the detail, initials the stamped area on the iso.

g) The Support Group then adds the “PS” numbers and locations to the iso tracing and initials the tracing. The tracing is then returned to the Plant Design Supervisor for issue.

h) If after an iso is issued for construction, the Plant Design Group makes a revision to the piping, it is the responsibility of the Plant Design Supervisor to stop the support group from further work on the iso and reclaim the print marked up by the Pipe Stress Analysis Engineer. The Piping Supervisor then reissues the iso and the originally marked up print to the Pipe Stress Analysis Engineer who reviews the iso for further approval and support mark-up. Where piping revisions are judged insignificant by the Plant Design Supervisors, (i.e. not affecting flexibility or support of the system) the iso is then just reissued for construction, by-passing the Stress Group.

i) If piping isometric numbers are revised by the Plant Design Group, a cross reference list of new numbers versus old numbers must be provided to the Stress Group to keep records straight. To keep better control of iso’s marked up by the Stress Group, the Plant Design and Support Groups should also keep a check list of iso’s received.

j) The stress markups are then kept in alphabetical and numerical order in special long binders by the Ripe Support Group for reference.

k) When the job is complete the marked isometrics are returned to the Piping Stress Analysis Engineer who keeps them close at hand for approximately 1 year, then files them in storage.

2.3 A sepia of all orthographic drawings of piping on-plot or off­ plot should be issued to the project Pipe Stress Analysis Engineer prior to being issued for construction. The sepia shall be stamped and distributed per owner‘s standards upon stress review completion. The Piping Stress Analysis Engineer shall convert sepias of the piping drawings into stress STR drawings and maintain a drawing control of all STR drawings per Owner‘s standards.


3.1 Study preliminary plot plan and pipe way layouts for troublesome arrangements.

a) Indicate pump placements which will aid in achieving flexible piping arrangements. Avoid placing pumps directly opposite connecting equipment.

b) Estimate the number and position of pipe way expansion loops for steam, condensate and other long, high-temperature systems.

c) Keep movements in steam lines to generally 4 inches or a maximum of 6 inches by judicious number and location of loops. Determine the loop size to help in positioning the header in the pipe way to avoid large overhangs or the necessity of auxiliary means of supporting loops. Design /rests of loops as early as possible and give exact layout to Plant Design Group. Expansion movements, insulation thickness, effect of cold spring and extra clearance should all be included. Generally keep a minimum of 1^ to 2″ extra clearance from adjacent piping or other obstructions for worst case of design temperatures or differential pipe movements.

3.2 Review preliminary alloy piping isometrics or layouts by inspec­tion for material commitment. Generally this is done to avoid large differences between material commitment and final purchase of alloy pipe and fittings required; therefore, an exact analysis should not be made. Retain the preliminary study for comparison with the final iso to be issued-for-construction At this time many iso’s can still be passed for stress by inspection, but it is recommended that piping to pumps, compressors and possibly heaters, exchangers or reactors when high reactions are suspected, should be run as a formal calculation on the computer.


4.1 The Pressure Vessel Job Supervisor will provide a list of all stress relieved vessels on the job and all established dates from the fabricator for stress relief of each particular vessel. These dates will be marked on tags put on the vessel models by the vessel department. Normally the model should be completed and “checked” a minimum of (6) weeks ahead of the stress relief date. This gives the Pipe Stress Analysis Engineer and support group (2) weeks to complete their work and get details sent to the fabricator(4) weeks prior to actual stress relief.

4.2 It is very important that the Plant Design Supervisor remind all his designers that the piping should not be revised thereafter. If the change must be made, the revision has to be coordinated with the vessel fabricator immediately to avoid serious problems such as re-stress relieving and delay in delivery.

4.3 Piping requiring stress relief generally is drawn up and issued to the shop together with the required pipe supports which are to be welded on and stress relieved with the pipe. Occasionally, support details are held up for one reason or another and fail to reach the shop in time. The supports must then be welded to the pipe in the field. Welding of supports to stress relieved piping in the field is to be avoided. The stress relief kits are not only costly in themselves (sometimes amounting to several hundred dollars) but require many manhours for their installation, application and removal. Stress relief must still be applied where process reasons dictate (i.e. stress corrosion or other), but for P1 material, non-pressure parts or external attachments are not required by A.N.S.I. Code to be stress relieved as long as the throat of the attachment fillet does not exceed 3/4″.For any questions regarding welding of supports to stress re­lieved pipe refer to the general welding instructions for pipe supports.


The following equipment 6 conditions involving critical piping require special treatment, and are briefly discussed within each classification.


5.101 Pumps, turbines and compressors have common sources of concern. The greatest concern is for keeping proper alignment of the pumps and compressors in relation to their turbine or motor drivers. Improper alignment causes hot bearings with resulting wear and/or serious vibration. Reactions to the cast steel nozzle and casing structure is generally of secondary concern. Whenever the casings are made of cast iron the allowable loadings should be reduced 25%.

5.102 Acceptable loadings on most centrifugal and rotary pumps which are base, frame, flange or centerline mounted, are shown in owner‘s standards. When the loadings are higher than permissible every effort should be made to meet the allowable loadings by increasing the flexibility of the piping system rather than employing expansion joints.

5.103 Owner‘s standards (k sheets) shows some common configura­tions of pump piping. The tables accompanying the various figures show the maximum operating temperature of the system without overstressing the pipe. When the maximum allowable temperature is greater than 150°F, the system is OK for 300°F steam out or steam tracing.

5.104 Piping reactions on in-line, deep well, vertical frame mounted, reciprocating pumps, heavy barrel type, or other specialized pumps must be reviewed on an individual basis. The primary rule regarding any piping system to pumps is that the allowable stress of the pipe at the nozzle must not be exceeded, and that reactions in lbs should generally not exceed 150 x the nozzle diameter in inches or that permitted by the pump manufacturer in loadings published on his vendor prints, or by agreement, or per specifications.

5.105 In-line pumps should be capable of withstanding equivalent pipe allowable stress based on the minimum nozzle size and re­duced to material allowable stress for the cast body. These pumps should be supported by the adjoining piping only, except, where the horsepower of the pump exceeds 75H.P.,the pump itself should also be supported on a pier. See owner‘s standards Generally, none of these supports re­quire bolting, in fact, if the pump can slide it provides relief for thermal expansion. (Refer Par. 6.05) .

5.106 Deep well pumps generally have a cylindrical plate steel casing which is flanged and bolted to a concrete founda­tion. Loadings to nozzles of this type of equipment are limited to the allowable stresses of the pipe and/or casing.

5.107 Pump piping can be designed to twice the normal allowable stress as per owner‘s standards when considering steam-out or upset steam trace temperatures. When the pump and/or piping is being steamed out, the pump is not running and therefore misalignment does not dictate.

5.108 Pressure rating of pumps is indicative of ability of pump casing and supports to withstand piping reactions. As the pump pressure rating is increased, it is built more sturdily; it has heavier walls, weighs more and is more stable with sturdier supports. Naturally, therefore, it can withstand higher piping reactions.

5.109 Where pumps are top suction and/or top discharge, the only manner of removing eccentric loads on the pumps would be from beams above. For pumps handling hot materials the piping should be spring supported to beams above. Therefore, for ease of supporting pump piping in this case, the pump should be located under the stanchion struts, (i.e. those running parallel to and on each side of the pipe way).

5-110 Whenever possible the pump suction lines should be supported to a concrete pad extension of the pump foundation. Where this is not possible, beams should be embedded in the foundation and projected out the sides or front far enough to support the piping under the vertical riser. In the case of plants located in regions of frost heave, these beams must adequately clear the maximum estimated heave of the area slab. Where differential vertical expansion of the pump versus the piping permits, the supports discussed above should be solid, sliding type supports. Spring sup­ports should only be used when this vertical differential expansion is high or questionable.


The types of compressors usually found in refineries and chemical plants are as follows:


Centrifugal, Rotary and Screw 5.21

Reciprocating 5.22

In-Line 5.23

Blowers and Fans (Below 1 psig EAP) 5.24

The allowable loadings, methods of calculating them, types of support, and piping design considerations for each of the above compressor types, are discussed individually in the paragraphs noted.

5.21 Centrifugal, Rotary and Screw Type Compressors Allowable loads on centrifugal compressors shall be covered by Owner Standard specifications. These specifi­cations shall state that the equipment shall be designed to withstand the following external loadings:

Vertical Component

The allowable vertical reaction from combined forces, and mo­ments due to all piping connections, or to any one piping connection (either upward or downward) at any support point shall be at least one half the dead weight reaction of the compressor at the support point.

Horizontal Transverse Component

The allowable horizontal reaction from combined forces and moments due to all piping connections, or to any indivi­dual piping connection, in a horizontal transverse direction at any support point shall be at least one third the total dead weight reaction of the compressor at the support point.

Axial Component

The allowable axial force from combined axial forces piping connections, or axial force of any one piping connection, in an axial direction on the compressor casing be at least one-sixth the compressor weight.

a) For calculation preparation set up the individual systems connected to the compressor casing and support structures as indicated in owner‘s standards, or by some other equivalent system. To avoid moment restraints, all restraints used should be simple couples. The layout of the problem and the subsequent computer run should be based on the coordinate system as shown in the Standards.

b) Generally, centrifugal compressors are not sources of serious vibration and therefore, the piping is given only a cursory review for resonance. Large frameworks of free standing pipe or large overhangs should be snubbed to prevent large amplitude vibration.

c) Piping to centrifugal compressors need not have a machined spool piece to makeup the last connection to the compressor. For years the construction department has displayed the capability to mate flanges by bringing misaligned piping into proper position by the heat and quench method. How­ever, where cold spring is employed the field should be instructed carefully as to the proper procedure to produce the results desired.

5.22 Reciprocating Compressors

Piping reactions on reciprocating compressors are not cri­tical from the standpoint of misalignment of equipment, but due to piping vibrations, the piping stresses should not crowd the allowable stress range. Although higher stresses can be allowed at the nozzle than for centrifugal compressors, it is not unreasonable to keep axial and shear forces within those shown in owner‘s standards, and as a conservative rule, keep stresses to within twice those permitted for turbines in the same standard.

a) Generally there is no need to combine pipe system loadings for reciprocating compressors as was required for centrifugal compressors since piping is usually small and reactions are negligible relative to the sturdy equipment. In fact, most piping systems to this type of equipment can be reviewed by inspection.

b) Vibration is a rather serious problem within piping to recip­rocating compressors. The piping generally should be guided, held down and possibly restrained with hydraulic type vibration snubbers when unsupported lengths or spans fall into the range of the first or second harmonic of the compressor operating frequency.

c) Pulsating compressor discharge requires that special cylindrical “bottles” be designed to prevent surge vibra­tion. These bottles are often large diameter and heavy. Therefore, to reduce the possibility of a fatigue failure between the discharge bottle nozzle and the cylinder head nozzle, the dead load of the bottle should be supported by elastic supports as described in paragraph 7.22. Sometimes the compressor manufacturer recommends a wedge type solid support. These have been widely used but don’t allow any room for error of installation. The wedges have to be adjusted when the compressor is at operating tempera­ture. For upset temperatures the wedge type may be danger­ous since no further expansion can be absorbed. Owner Refinery Division practice usually avoids using wedge supports. Suction bottles can utilize solid supports since suction temperatures vary negligibly.

5.23 In-Line Compressors

Misalignment of in-line compressors obviously is no problem, since their driver is bolted to their casing. Permissible loadings on their nozzles can approach the allowable of the piping system, but should be reduced by the allowable stress for the cast material of the equipment when nozzle and pipe thicknesses are comparable. Whether the in-line compressor is supported or not depends on ability of piping to support it. The analyst must be sure to take vibration into consideration.

5.24 Blowers and Fans

Due to the possible light weight construction of this type of equipment the allowable nozzle load tables should not be used. The vendors prints should be examined for clues rela­tive to strength and manner of supports, and/or other pertinent data. If no allowable loads are published, the intake and/or discharge lines might require impregnated cloth or neoprene expansion joints. This type of joint is banded on to the exterior of the adjacent pipes with suitable small gap between the pipe elements. Generally, the sheet should have a slight circumferential bulge between bands to absorb tensile movements. Generally, piping or ducts to blowers and fans are large and thin walled, requiring direct routing. These may require expansion joints made of rubber or stainless steel and be rectangular, oval or circular in shape. Allowable loadings on this type of equipment are based on engineering judgement, since allowables are not usually published or known by the manufacturer.

5.25 To reduce operating reactions from piping to compressors the most generally used methods are to employ cold spring or by increasing the flexibility of the piping. Expansion joints are virtually forbidden since they suffer from vibration fatigue.

If a system is to be cold sprung it should follow the rules of the ANSI B31-3. The cold spring should be located at a convenient place in the system, generally a flanged connec­tion or a field weld. See owner‘s standards for cold spring notations.

It is important that no rotation at the welded joint is per­mitted to assure that proper counter moments are built into the system. Instructions on this procedure should be sent to the field for critical systems. Where cold spring is in­effective or impractical, the piping should be rerouted to improve its flexibility.


Centrifugal turbines with pedestal, base or flange mountings, are the only types considered herein.

5.31 Flange mounted steam turbines are used as in-line pump dri­vers and are therefore not misaligned by piping reactions. Piping stresses can approach the maximum piping allowable except where cast iron casings are encountered, then the stresses should be reviewed considering the lower allowable stress of cast iron.

5.32 Piping reactions on pedestal and base mounted centrifugal turbines are governed by two conditions. First, if the tur­bine is a pump driver and is single stage, the allowable loadings as noted in owner‘s standards should apply. Secondly, where the turbine is multi-staged or is used as the driver to a compressor, the allowable loads will be in accordance with the Owner Standard Turbine Drive Specification as previously described under Centrifugal Compressors.

5.33 For preparation of calculations to verify loading conditions on the turbine, use the procedure as outlined under paragraph 5.21(a) for centrifugal compressors.


Airfan heat exchangers have gained widespread popularity and use over the last several years. At least three major problems confront the Piping Stress Analysis Engineer.

5.41 First, where the inlet and outlet header boxes have two or more nozzles per unit, a difference in expansion exists bet­ween it and the attached pipe header. For years many such units have been connected together using only fitting makeup with no apparent ill effects. (Very similar to cylindri­cal exchangers being connected by their nozzles being bolted together directly.) Therefore, a practical standard is need­ed for determining when additional flexibility is required and how to compute it. Owner‘s standards suggests that fitting makeup is tolerable until the difference in horizontal expan­sion between the nozzles of the pipe header and header box exceeds 1/16″. This applies to either the inlet or discharge sides but not when several units are joined together and the inlet and discharge nozzles are at the same end. Where the expansion difference exceeds 1/16″ use the formula indicated to compute length “Q ” required between manifolds.

5.42 Second, overall expansion of the pipe header joining several airfan units together must be accommodated by allowing the header box to slide on its clip supports within the unit side- channel supports. Normally the gap between each end of the header box and the support channel should be 5/16″ or more. This is now generally accepted and appears in Owner speci­fications issued to manufacturers who are to bid on the jobs. Where more than 5/16″ movement is required, the pipe header can be cold sprung, as shown on owner‘s standards, pulling the units together as much as 5/16″, whereby the permissible expansion can be increased from 2 x 5/16″ or 5/8″ at each end of the units to 2 x 5/8″ or 1 1/4″ total for the overall length of all units connected together.

5.43 Thirdly, where inlet and outlet piping are at the same end of the airfan units, extra flexibility of the outlet piping is generally required and should be routed as shown on owner‘s standards or in some equivalent manner. External piping loads affecting the equipment nozzles additionally should conform approximately to those loadings published by each manufacturer.

Another manner in which difference in expansion between inlet and outlet pipe headers can be absorbed is by requesting the airfan manufacturer to supply horizontally split header boxes that slip individually to absorb the difference in movements. This method would generally permit fitting makeup between the pipe header and the header boxes for both inlet and outlet connections even though both are located at the same end of the airfan.


Early in the design of a plant, specifications are drawn up and material requisitions are prepared regarding the types of heaters to be used. It is at this stage that the stress group should confer with the project engineers regarding support requirements of external piping to the heaters. The material requisition should state that it will be the responsibility of the heater manufacturer to provide adequate platform framing or other means to accommodate all external piping loads of the inlet and/or outlet piping.

5.51 A preliminary piping load estimate should be sent to the selected manufacturer for completion of his platform design. Unless this is done at an early stage, it might prove costly to arrange for piping to be supported to the heater after the design and/or fabrication is completed.

5-52 In general, piping to the heaters should first be studied for inherent flexibility without alteration of heater inter­nal supports or openings into the heater. If the proposed piping is either overstressed or creates unacceptable, high reactions on the heater nozzles, then either the piping should be rerouted to produce a desired flexibility or the heater manufacturer should be requested to absorb some reasonable lateral movement of the heater tubes. This movement may re­quire some alteration of the tube support castings on hori­zontal, rectangular (box type) heaters and some possible enlargement of the openings to either the horizontal or ver­tical (cylindrical) heaters.

5.53 When a horizontal, rectangular heater is being used, the radiant and convection section tubing is generally anchored (axially only) at the front of the heater with allowable loadings indicated. Where the manufacturer does not indicate an anchor, he should be requested to add an anchor to all nozzles and submit their allowable reactions. It is better to have the piping anchored and the movements therefore con­trolled rather than to let systems float and be in doubt as to ultimate movements. In some cases, such as heaters used in ammonia plants, the heater tubes are anchored internally, whereby large movements are indicated at the nozzle and are imposed on the external piping. By judicious location of equipment these movements can be counteracted by expansion of external piping.

5.54 Cylindrical heaters (axis vertical) have their tube coils running vertically. They can be supported either at the top or the bottom of the tubes. The tubes are guided periodi­cally to the heater shell. The inlet and outlet nozzles generally hang free, being supported to the adjacent tube through the 180° return bend at one of the ends. Therefore, these tubes can be moved laterally in a horizontal plane, to relieve external piping stresses and reactions if necessary. But the manufacturer must be agreeable to the particular re­lief movements requested. If the piping is amply flexible, no modifications are necessary by the heater manufacturer, but the reactions on the nozzle must be reasonable. These allowable loadings as indicated on their drawings generally are 500 to 1000 pounds.

5.55 When considering the design of piping to cylindrical heaters the location of the tube supports can be critical. When top supported, with inlet and outlet nozzles at the bottom of the heater, large vertical movements occur and are im­posed on the external piping below. This may require costly additional pipe for flexibility and the use of expensive constant load spring supports.

5.56 If the tubes are top supported with inlet and outlet nozzles at the top, then the external piping can be supported to the platforms or shell at the same level as the tube supports. This would reduce the need for constant load spring supports but external piping flexibility is still required between the heater and other equipment or the pipe way. When the tubes are supported at the bottom and the nozzles are at either the bottom or the top, the need for external piping flexibility or constant load spring supports can both be mini­mized.

5.57 Additional care must be used when considering 2 phase flow in heater piping. The inlet will generally be 100% liquid at .50 to .85 specific gravity but the material in the outlet will vary from the inlet liquid density to a nearly 100% vapor flow. This creates special support problems and the differential load must be minimized on connecting piping by pre-setting springs for an intermediate load condition.


Buried piping, regardless of depth of burial or soil in which it is buried, has the tendency to expand or contract with temper­ature changes whether from flow temperatures or surrounding soil temperature changes. The total change in length it undergoes depends on the restraint of the soil both from friction and pas­sive resistance.

5-61 Computing Growth of Buried Pipe

A reasonable approach to calculating buried pipe movements is based on resistance to movement from soil friction in a rect­angular load pattern as shown in owner‘s standards. This has been found to be slightly unconservative by roughly 20% since cyclic expansion and cooling tend to increase end movements. The choice of a proper coefficient of soil friction is of great importance since the value can vary from .4 to greater than 1.0.

5.62 Results of Jacking Tests

From Jacking tests made by P.G.S-E. Co. (see Sept. 1933 issue of “Western Gas”) on 37,_4″ length of 22″ pipe with 2′-6″ of cover (assume average cohesion less soil) shewed a soil friction of 0.40 psi or closely a co-efficient of friction of 0.4.

5.63 Method of Restraining Expansion of Buried Piping

At corners (right angle turns) of buried piping systems, large expansions might cause a failure at the elbow, due to restricted flexibility, or similarly at branch connec­tion of underground header.

For small temperature changes the system can be fully restrained to prevent the above failures. Methods of providing full restraint are by anchoring the pipe with concrete blocks which encircle the pipe or by dead men with struts attached to the pipe. (owner‘s standards) Also the line can be fully restrained using very large bends in the pipe through the principle of hoop compression. (See owner‘s standards.)

5.64 Stress Analysis of Buried Piping Systems

5.641 General

As in above ground piping systems, thermal expansion stresses are induced in buried piping systems when the temperature of the systems changes. However, the thermal stress condition of buried piping systems is much more complex than that of above ground piping systems due to restriction of the piping movement by the surrounding soil. The stress level in the pipe depends on the temperature change, pipe size, piping configuration, soil characteristics, depth of burial, skin friction, operating pressure, etc. For a long straight buried pipe under temperature change, the thermal expansion of the middle portion is completely restrained by the soil friction and only the end portions, generally a few hundred feet long, show some movement. See the Sample Problem, as herein after referred to, of owner‘s standards. The length of the end portions, which expand under partial restraint, and the resulting end movements may be calculated by the formula shown in owner‘s standards and is shown on Page 2 of the Sample Problem. Buried piping systems under temperature change may be moved laterally near the bends and branch connec­tions. It is assumed that the pipe moves against a soil spring and the maximum spring force is equal to the passive soil resistance. A buried piping system may be analyzed for thermal expansion efforts to include soil friction and soil resistance by the piping flexibility program ME632 or ME 10

5.642 Input Data Preparation

a) Dimensions of Calculation Model

After determining the length of the partially restrained portions of the buried pipe system, the calculation model can be set up as shown on Page 4 of the Sample Problem. As can be seen, only 8001 of the 5000′ run of the complete system, as shown on Page 1 of the Sample Problem is included in the model since the remainder is totally restrained. To achieve the 3.^9″ deflec­tion of Data Point 33 either the anchor at Data Point 80 can be moved in the “-X” direction or an equivalent rate of expansion can be applied to the 800′ length to produce the same result. Actually, the length of the partially restrained run of pipe as calculated by Owner‘s Design Guide does not include the soil resistance on the pipe at right angles to the main run as shown by Data Points 8 through 33. A more accurate result may be obtained by a rerun with a new partially restrained length, Data Point 33 through 80, including the lateral soil resistance on Data Points 2 through 33.

b) Soil Resistance “Springs”

A buried piping system under temperature change moves against a soil spring force (subgrade reaction) which has a limiting value equal to the passive soil resistance. It is found from tests that the buried pipe moves against the soil a certain amount or displacement before developing a maximum passive soil resistance. This displacement depends on the soil property and the depth of the burial. From the Foundation Engineering Handbook, the displacement is about 0.05 H for sand and 0.10 H for clay, where H is the depth of the burial to the bottom of the pipe in inches. In the absence of the subgrade reaction data for the jobsite, the displacement of 0.03 H has been used as the necessary movement to develop a passive state and it is used generally for conservatism. The soil spring constant Kg is calculated as follows;

Ks=passive soil resistance/0.03 H

The soil springs are treated as translational restraints with a flexibility of KA #/in. from Ks x length of pipe affected. The restraints are spaced such that the passive soil resistance on the pipe is adequately represented. In general a closer restraint spacing is required for the area where high stresses and movements are anticipated. However, the spacing should not be closer than two times the pipe diameter. Since the soil resistance must not be higher than the passive soil resistance on the pipe, the analysis shall be carried out by a trial- and-error method. More than one computer run may be needed to obtain a satisfactory answer. The forces of the soil spring restraints from the computer result must be below the passive soil resistance. Otherwise, the soil spring restraints must be changed to the restraints with constant force whose magnitude is equal to the passive soil resistance. Another computer run with the new restraints should be made until no restraint reactions from computer result are significantly higher than the passive soil resistance.


Cryogenic piping is understood generally to include the range of operating temperatures from (-150 F) to absolute zero (-459.4 F). Cryogenic piping is more critical than normal refrigeration and other low temperature piping for several reasons. Greater care in design Is required to prevent water vapor from entering the insulating media where it would freeze and cause an insulation breakdown. Special anchors and supports also are required to prevent low temperatures from affecting carbon steel support beams and causing brittle fracture. The pipe stress analysis engineer’s responsibility covers thermal construction and design basis for supports, guides and anchors, etc. Project engineering shall specify the insulation and vapor barrier requirements.

5.71 Support Design

Special saddles have been designed within the stress group for cradling the insulating media. It was found that for 24″ pipe containing LNG (liquid methane at -258°f) a 6″ thickness of polyurethane (density 2 lbs/cu ft) or foam glass is usually required for insulation. At support points, a higher density of the polyurethane has been used instead of low density polyurethane or foamglass because of better abrasion and shear resistance. The limit of 1% deformation under dead load is a reasonable criteria to determine the proper density of the poly­urethane block. A recent installation required 7#/cu ft density for a 24″ pipe and supports spaced up to 26*apart. The cost of polyurethane increases with density, so it is suggested that a practical minimum be arrived at. See owner‘s standards for a recommended saddle design. Saddle supports have been either clamped to the insulating media or cemented to the insulating block with polyurethane elastomer, both have been found to work satisfactorily. Likewise, the special support block of insulation between the saddle support and the pipe has satisfactorily been cemented to the pipe itself to ensure movement of the support with the piping system. Until feedback from operating plants or engineering design proves otherwise, all support blocks should be cemented to the pipe with Adiprene or its equivalent, #2050 Adhesive (Polyurethane Elastomer), by CFR Division of the Upjohn Company or other suitable compound. The above adhesive has been tested to -423 F (liquid hydrogen) by the research division of one of the aircraft companies and found to maintain its adhesive qualities at those low temperatures.

5.72 Anchor and Guide Details

Wherever it is felt that below freezing temperatures can affect support, guide or anchor members constructed of carbon steel stressed to values of 5000 psi or greater, special details should be provided to insure that the structural members are not detrimentally affected by those temperatures. Special carbon steels or alloy steels should be used having proper impact value where tempera­tures dictate. See owner‘s standards for recommended anchor and guide designs.

5.73 Reduction of Friction at Support Surfaces

Whenever the anchor forces or frictional forces at supports might prove detrimental to the system’s design, special sliding or roller supports should be provided. Teflon slide plates bonded to the under surface of the pipe saddle support channel have been successfully used. These slide plates bear on a similar slide plate bonded to a metal plate which is tack welded to the support beam. The overall thickness of the two slide plates commonly is 7/16″ total. Their usefulness does have temperature limitations which vary with each manufacturer.

5.74 Flexibility Design of the Piping System

The materials used in Cryogenic piping systems increase in strength as the system gets colder and brittle fracture is avoided by the proper selection of special materials of construction. Therefore, conservatively, the same allowable bending stress is permitted as if the system was at 100°F. To absorb the contraction of the piping system, the first consideration should be to use expansion loops or offsets. Where this is not possible, bellows type expansion joints should be utilized in tandem within a minimum offset in the piping. The use of the bellows type in direct extension or compression should be avoided but are not prohibited. Bellows expansion joints must be very carefully protected from icing up and ultimately being crushed. This is their main draw­back. Other methods of absorbing the systems contraction are as follows:

a) Jacketed piping with internal axial expansion joints. This may require expansion joints periodically in the external jacket pipe, if the system has long runs. This system incorporates insulation in the jacket space.

b) In very special cases, the line might be prestressed to absorb contraction. This requires no expansion joints but suffers from large expansion forces and requires very special installation procedures. The use of hydraulic jacks or liquid gas cooldown might be employed.


6.01 Allowable Pipe Spans

a) The spans in owner‘s standards are limited by longitudinal bending stress or a midspan deflection which has proven accept­able from past experience, whichever governs. Although the spans are the maximum allowable, they are limited to a practical span for general pipe way use of 20 to 25 feet. These and other limitations are explained in the Standard itself. Alos, read “Use of Standard Weight Spans

b) Where it is impractical or very costly to install special stanchions for support of small line branches from the pipeway headers or the support of long runs of very small piping, consideration should be given to supporting the lines from a single large diameter header by cantilevered structural members welded on, or by a trapeze beam hung between larger lines. Normally, the supporting of pipe to any other piping system is not a good policy and should be generally avoided.

c) Occasionally groups of very small diameter piping, such as chemical injection lines, can be banded together whereby the moment of inertia of the group as a whole reduces the bending stress or deflection of the system to a permissible amount.

6.02 Allowable Pipe Overhang

At turning points of pipe way stanchions, the supported piping systems have varying lengths of pipe overrunning the last support beam and rise up or turn down to join similar “overhangs” of piping from the adjacent pipe way at right angles to the first one. These overhangs within certain limitations are permissible without support. But, when the overhang is such that stress or deflection limitations are exceeded (See owner‘s standards) then, the overhang requires a special support. Dummy legs welded to the piping elbow and extended until it crosses the next stanchion beam is the most commonly used method of supporting the overhang. Essentially, it supports the system by extending the pipe as a “beam” across two supports. (See owner‘s standards for dummy legs required.) Where the dummy leg becomes too long, special beams should be added to the stanchion to support the overhang.

6.03 Pipe Guide Spacing

Pipe guides are used for several purposes. They keep lines essentially straight for good general appearance, or they prevent buckling due to high axial loads from friction or expansion loop forces. Guides can also be used to react against lateral line connections thereby con­stituting an anchor for the branch pipe. When anchoring branch piping by this method the guides are placed on the main header at the beams on adjacent stanchion column lines. The lateral reaction is taken by “beam” action of the 20′ to 25′ pipe span. Under high loads the stress or deflection of the pipe should be checked.

a) Guide spacing varies for the different areas of application. On vessels, guide spacing is reduced from those permitted in on-plot or off-plot piping. This is due to higher wind loads with in­creased elevation and load limitations of the various guide details used. See the pipe support manual for these allowable spacings.

b) On-plot and off-plot guide spacings could be essentially the same except that within a guide range for any pipe size, it is pre­ferable to use the low side of the range for on-plot pipe ways and to use the high side of the range for off-plot pipe ways. The reason for this is that on-plot piping, being more critical in nature due to branch connections, should have a more conservative design.

c) The suggested guide space ranges are:

Line Size Guide Space Range

2″ 40′ – 50′

3″ 40′ – 50′

4″ 40′ – 60′

6″ 60′ – 80′

8″ 80′ – 100′

10″ 100′ – 120′

12″ 120′ – 150′

14″ 120′ – 150′

16″ 150′ – 200′

18″ 150′ – 200′

20″ 200′ Max.

24″ 200′ Max.

The guide space ranges are a general rule and in situations where high axial loads exist these guide spacings should be reduced, after checking for buckling in column action.

6.04 Instrument Strong Back Flexibility

a) During normal operation instrument strong backs heat up with the attached vessel and since no differential expansion exists between the two there is no flexibility problem. But, if some faulty operation develops within the instruments, the block valves at the vessel nozzles can be shut and the instruments removed for repair. The strong back at this time cools down to ambient temperatures. At this time there is a differential expansion that exists between the strong back and the vessel. Unless the nozzles or the offsets in the piping to the strong back are flexible enough a failure could occur in the vessel nozzle or in the strong back proper and connect­ing instruments. owner‘s standards has been developed to give the Piping Designer a reasonable approach in providing flexibility in the system before it is reviewed by the Stress Group. These systems should be approved by the Stress Group by checking with the above standard.

b ) Support of Instrument Strong Back

Where long strong backs are offset and “Christmas Trees” are hung from vessel nozzles there is a need of supporting these assemblies to the vessel shell or platforms. Generally this is done by inspection without taking time to go into lengthy calculations. If in doubt, add a support, always taking notice of affects of differential expansion between supports and nozzle connections.

6.05 In-Line Pumps

As a general rule, in-line pumps exceeding 75 HP should be supported on a foundation regardless of whether the piping is supported separately or not. On pumps of this size, base flanges may or may not be provided, but this need not dictate that flanged pumps be bolted down. If sliding is required, provide base plates and either eliminate bolting or add notes to pertinent drawings or isometrics to adjust nuts hand tight. Sleeves may possibly be used to assure that nuts will not bear tightly on flanges. The pipe stress analysis engineer should note that holes are to be oversized or slotted to allow for movement required. Pumps smaller than 75 H.P. may be supported to the adjacent piping. See owner‘s standards for suggested support techniques.

6.06 Expansion Loop Design

The design of expansion loops for pipe ways or any pipe system has been programmed to produce a book of “Loop Tables”. These tables enable a piping stress analysis engineer to closely design by inspection a loop to any desired stress or reaction force. A complete description of the method used to arrive at a design is found within the Owner‘s Design Guide.

a) A design pad (form 149) is available for recording all pertinent information regarding the design and location of the expansion loop. To arrive at the minimum sized expansion loop required, the maximum allowable stress for the piping system has to be determined from the limitations in the code on the material at the operating temperature. The actual size of the expansion loop is equal to or greater than the minimum loop size to fit properly on a supporting media. The spring constant and the resulting bending force within the system are then tabulated on the design pad for reference.

6.07 Pipe Anchors

The anchors described herein are for above ground piping. Anchors are used to direct the expansions or contractions of piping systems and thereby prevent interferences with other piping or structures, and/or control reactions to attached equipment. The reactions at anchors are taken by support beams made of braced or unbraced struc­tural steel or precast concrete. These anchor reactions shall be placed on an ozalid of the pipe way, specifically reduced for use by the stress group, and a print of it passed on to the structural group for review of their stanchion design.

a) It is suggested that these anchor loads be calculated and faith­fully tabulated on a form for later reference. The client upon occasion has requested these loadings, therefore, the tabulation may be very important. The individual pipe stress analysis engineer may compute them one by one, as he comes to an anchor tentatively and compute all the loadings at once when the piping is finally completed. Standard calculation sheets are available for these anchor cal­culations (form 149).

b) The calculation sheet for expansion loop data and anchor force determination does not include a listing of every item for tab­ulation but covers key items for final summation to obtain the anchor force. It is suggested that the auxiliary sheet of pipe weights (form 188) will be used by the pipe stress analysis engineer to mentally add up incremental weights for a particular system under “Wt”.The coefficient of friction to be commonly used for steel on steel shall be 0.2 unless special surfaces are applied or additional factor of safety is desired. Where piping is supported on round bars the coefficient of friction should be raised to 0.3.

c) Anchor loads for buried piping can be computed by formulas re­commended in the section on “Buried Piping”. (Par.5.6)

d) When computing anchor loads for above ground piping, the loadings on each side of the anchor generally tend to balance out to some degree. In some cases a long run of piping will be anchored near the center of the run just to prevent gradual creeping of the system. The frictional force on each side of such an anchor may theoretically balance or cancel out. The load to assign to such an anchor should never be less than 25% of the frictional force from one side alone.

6. 08 Stacked Exchangers

a) When exchangers are stacked it is customary to use radial nozzles directly connecting the two channel sections and the two shells. The hotter shell expands more than its adjacent shell and tends to be constrained by the inter-connections. Some deformation of the nozzles takes place and when the temperature difference and resulting stresses are large enough they can cause a failure in service. This failure not only results in a plant shutdown but could be the cause of a disastrous fire or explosion.

b) Owner‘s standards has been established to give analysts a common approach in reviewing the problem. As can be seen, when the difference between mean temperatures of the adjoining shells is greater than 100 r some provision should be made to add flex­ibility to the nozzle connections. These studies should be made early in the job such that nozzle orientations can be corrected before fabrication is started. Nozzle and piping arrangements to improve flexibility are shown on the Standard.

c) To reduce movements of piping from exchangers leading into unit pipe ways, hot exchangers should be anchored at the support closest to the pipe way. The exchanger expansion tends to cancel the expansion of the connected piping and its affect on pipe way clear­ances. Where cooling water from below grade is connected to the channel end of the exchanger the exchanger should be anchored to the support closest to the channel end. For a dimensional guide see owner‘s standards.

6.09 Off Plot Pipeways

6.091 General

a) Prior to the design and layout of off plot pipeways the project piping stress analysis engineer should meet with the off plot project engineer to discuss and establish proper temperatures for the expansion de­sign of off plot piping. The temperature range shall be realistic, and it shall include reasonable ambient temperature variations at the job site, but unless the client insists, remote upset condi­tions should not be stipulated.

b) Review should be made with Project Engineer and the Client, regarding the use of steam-out. Usually off plot piping is not steamed out and is therefore not designed for that condition. Normal operating and maximum or upset design temperatures should be listed for all lines on the off plot line designation tables which should be completed prior to making the stress studies.

c) Methods of absorbing pipe expansion should be reviewed with the off plot project engineer to see if the client might have restrictions on the use of expansion joints or couplings, etc.

d) When the design conditions have been established and if no formal memorandum has been issued by the project engineer, the piping stress analysis engineer should prepare a memorandum covering all final decisions and issue it to both the Chief Pressure Vessel Engineer and the Off plot Project Engineer, who should be requested to transmit such information to the client for information and record.

6.092 Expansion Studies

a) The design approach to off plot piping should not be as strin­gent as that for on-plot piping, therefore systems should be designed up to the maximum stress allowed by ANSI code for the upset condition except where reactions dictate otherwise. Additional lengths may be required to nest loops or use common supports. In some cases where only few stress cycles may occur, Article 5~ 1 of ASME Section VIII, Div.2, Design based on Fatigue Analysis might be employed. This criteria allows up to 3 times the allowable stress intensity for secondary stresses, thereby permitting close to 60,000 psi for A106 or A53 GRB pipe materials.

b) The expansion review of off plot piping is essentially a clearance check of pipes as they move relative to one another or whether they interfere with the structural appurtenances of sleepers or stanchions. See owner‘s standards for other than 90 corner move­ments.

c) The tie-in temperature used as the calculation basis should consider the specific time of year for plant construction. Also care should be exercised to consider the clearances and stresses for both expansion and contraction of all adjacent piping systems.

d) Except in the vicinity of off plot pump manifolds or other equip­ment limiting reactions or stresses, the systems should be allowed to expand up to a practical limitation of 12″ at a corner of the pipe way or at each leg of expansion loops. This means that ex­pansion loops should normally absorb up to 24″ of expansion.

e) Support shoes for insulated piping in pipe ways now are ordered in two standard sizes, 18″ 6- 30″. The 18″ shoe permits 6″ and the 30″ permits 12″ of movement each way from their 4 with 3″ of overhang for assurance that the system won’t hang up on the support. This 3″ overhang is a standard allowance to be used at any support after maximum movement of an insulated piping system. As an aid to the pipe support design group, the supports at which pipe expansions exceed 6″ and 12″ should be noted to assure that shoes of proper lengths are assigned to each support.

f ) Design of pipe guides and anchors is covered in paragraphs 6.03 and 6.07.

g ) Cold spring of systems should be avoided unless absolutely nec­essary to reduce reactions at equipment or provide necessary clearance. See owner‘s standards for method of noting cold spring.

h ) Branch piping from the off plot pipe ways leading into diked tank fields must be reviewed for restriction of lateral movement due to small clearance in the sleeve buried in the dike. Sometimes the pipe is just coated, wrapped and buried in the dike which there­fore permits negligible lateral movement. Anchors may therefore be required close to these branch connections to protect them against excessive lateral movement. Expansion of these branches whether from dike sleeves or pump manifolds can be allowed to deflect the headers laterally, therefore, the guides in the headers should be located far enough apart to keep reactions back to the pumps or sleeve seals to a reasonably low value. Axial movement of these branches is generally prevented by either the burial of the pipe in the dike or by a link seal between the sleeve and the pipe on the tank side of the dike. Piping within the diked area is described in paragraph 7.17 on “Tank Field Piping.”

6.093 Pump Manifolds

Pump manifolds can be quite complicated and “tight” but when near ambient operating temperatures the expansion movements are usually small. Such movements can be directed away from the pumps if anchors and restraints are properly located. See owner‘s standards for an example of a properly anchored system. Offsets in the branches to the pumps should be avoided wherever possible. Normally no offsets are required in these branches on systems at temperatures of 150 F or less. Where temperatures exceed say 150 F, then offsets in the branches to the pumps may be required to improve flexi­bility and reduce reactions on the pumps. Where the suction or discharge lines leading to or from the pumps are eccentric by several feet from the pump centerline it may not only be required to support the overhang, but also restrain movement in the axial direction of the branch pipe. Several support-restraints of this type are shown in owner‘s standards.


7.01 Slug Flow

a) In two-phase gas-liquid flows where the phases are unevenly distributed and pass through a restriction, such as a valve or an expanded section, or a turn such as an elbow, there is a variable force exerted on the containing walls. This variable force creates impact loadings on the guides and supports of the system which must be adequately accounted for in their design. The magnitude of this variable force cannot be accurately evaluated due to the complexity of the flow. Therefore the design loads of the supports and guides should include an addi­tional design factor which might be classed as an impact factor.

In lieu of some definitely calculable factor it is suggested that this impact factor be 3.0 times the weight of a slug of liquid that might pass separately through the pipe as approxi­mated by the Project Process Engineer.

b) These variable flow conditions also can affect the system detrimentally by setting up severe vibrations. The system should be carefully reviewed with this in mind and if necessary hydraulic type shock absorbers should be utilized to prevent large amplitude vibrations. Within one of our recent refinery projects slug flow caused large diameter piping to vibrate continuously and though the amplitude was small (1/8″ peak to peak) it resulted in a failure at a 30″ diameter tee connection. The tee connection was reinforced considerably and a hydraulic damper was used to reduce the amplitude of vibration. Although guides and hydraulic struts can reduce slug flow effects, best results are obtained in reducing slug flow internally or routing pipe to permit a more uniform and smooth flow.7-02 Mitered Elbows

7.02 Mitered Elbows

a) Mitered elbows are used many times in low pressure piping systems for economy since the cost of welded or seamless elbows becomes prohibitive in the larger size pipes. Two of the drawbacks to mitered ells are high stress concentrations and poorer flow characteristics. As more pieces are used to make up a metered ell flexibility increases and stress intensifications decrease. In other words the miter with more pieces approaches the flexi­bility of a smooth elbow of the same radius.

b) For flexibility studies using some computer Programs the mitered ell must be replaced by an equivalent elbow with the same flexibi­lity. The method to be used in obtaining the equivalent elbow is shown in owner‘s standards. In most of the more recently developed programs the mitered elbow is handled automatically.

c) Before using miters in a flexibility calculation, they should be checked for permissible pressure by the formulas in paragraph 304.2.3 of the ANSI B31 -3 Code.

7.03 Tee Connections

a) The history of failures in piping systems points to tee connections as being particularly vulnerable. Tee connec­tions have high hoop stress patterns around them which are non-uniform and involve stress raisers or intensification factors. Vibration causes cyclic stresses which may be low in magnitude, but can be troublesome when acting through medium to high frequency. When piping systems are studied by the computer flexibility program, care should be taken to always include the stress intensifica­tion factor at all tee connections. If the specific computer program doesn’t have this capability, then add them manually to the output. Although no strict rule can be given regarding allowable stresses at tee connections in vibrating systems, good engineering judgment should dictate that the analyst use less than the maximum allowable stress.

b) The stress concentration factors for tee connections have been calculated by a computer program and the resulting values have been plotted on graphs for easy reference. The graphs are shown in owner‘s standards. They give stress factors for unreinforced tees, tees reinforced with pads both equal to the header thickness and 1.5 times the header thickness and for forged tees. It is suggested that all questionable stress levels at tee connections in flexibility calculations include the proper stress factor read from one of the graphs pro­vided. An accuracy of 2 decimal places is sufficient. When calling for a reinforcing pad the minimum width shall be 0.2 x branch outside diameter, which results in equal stress at both the crotch and the outside of the reinforc­ing pad.

7.04 Injection Connections

Whenever piping connections, involving injections of near ambient temperature fluids, are made into piping systems operating at elevated temperatures, say above 500 F, a critical stress condition exists at the nozzle connection whether reinforced or not. Failures have already been brought to our attention. To avoid the sudden transition of temperature change the small pipe should first enter a larger nozzle at a blind flange or weld cap attached to its end. This should be brought to the attention of the Project Engineer who in turn should locate these for review by the Project Stress Analyst. A standard will be developed to cover this problem.

7.05 Heater Coil Decoking

a) During normal operations of most heaters a layer of coke gradually builds up on the inner wall of heater tubes. As the thickness of the layer increases the firing rate must also be increased. This increase in firing rate results in an increase in the tube wall temperature and could eventually exceed the maximum allowable temperature for the stress level in the tube. To prevent this condition the coke must be removed periodically or whenever operating conditions indicate excessive coke build­up.

b) The coke is removed by using a steam-air or thermal decoking method. This method involves heating the tubes first and then passing steam through them at a specific mass velocity and then introducing a mixture of steam and air. The effluent is water quenched and discharged to the sewer, and the gas is vented from the quench drum stack. The temperature affecting the external decoking manifold and effluent piping during this time is generally 1000°F. Flue gas temperatures gener­ally reach 400 to 450°F.

c) Supports for piping to the heaters must be properly located and designed for the disengagement of both normal piping and the connection to decoking effluent or steam piping.

7.06 Catalyst Regeneration

Catalyst regeneration is required periodically in Catalytic Reformer Plants to reactivate the catalyst for efficient plant operation. At the time of regeneration the hydrocarbons are stripped or burned off of the catalyst and the entire system is made as free as possible of residual hydrocarbons. This is done by heating the system to normally greater than operating temperatures by nitrogen until a specific temperature level is reached and oxygen is then gradually added in small volumes further increasing the temperature. This burns off the hydrocarbons and is continued until a system gas analysis shows that little hydrocarbon remains. Regeneration tempera­tures usually read as high as 900 to I000°F for a period lasting several days.

Obviously these increased temperatures create an additional condition within the external piping system that must be accounted for in both piping flexibility and support.

7-07 Reformer Furnace Pigtail Design

The piping connections of both the inlet and outlet piping to the vertical tubes of Reformer Furnaces are subjected to both vertical expansions of the tubes and the horizontal expansions of the inlet and outlet collection headers. The large vertical expansions require that the outlet collection header be spring supported to move up and down with the furnace tubes. These furnace tubes are generally supported solidly near their base and expand upward several inches. The piping connections from the furnace tubes to these collection headers are called pigtails because of their design shape. Unfortunately there is a space limitation and these pigtails are somewhat restricted in their flexibility. In the analysis of any pigtail dead load stresses of the loop must be considered along with stress concentration fac­tors at tee connections.

7.08 Cold Spring

a) Cold Springing of piping systems originally was utilized to reduce stresses and reactions in piping systems, and to equalize somewhat the displacements of piping about a neutral axis, or reduce interferences.

b) The modern piping code no longer permits the reduction of stress, as such, but permits allowable stresses within a “stress range”. Therefore, if a system is cold sprung, a certain portion of the stress range is already utilized and only the remainder is permitted for the expansion beyond the amount of cold spring.

c) Since cold springing is an additional operation for the field to complete, it is suggested that cold springing should only be requested where it is critical to the systems design. For example, piping to turbines or compressors might require cold spring to reduce reactions to an acceptable level. Generally, in pipe ways, the design of expansion loops should not involve cold springing although the loops may still be designed right up to the maximum allowable stress. Other systems between columns, exchangers, drums, or connections to other piping should not be cold sprung unless absolutely necessary to avoid the additional operation. It has been found that cold spring notations have been overlooked or cold springing has been improperly applied in the field, un­less great care has been taken to flag and describe the manner in which it is to be applied. If equipment must be protected by cold springing of its piping systems and the manner of procedure of cold springing is felt to be particularly important, the Pipe Stress Analysis Engineer should write step by step pro­cedures and send them to the Field Engineer in charge.

d) Typical cold spring notations are shown on owner‘s standards.

7.09 Blowdown Systems

a) Blowdown piping as a general rule operates at low pressures with medium to high temperatures (i.e. 300°F – 1000°F) and close to 100% vapor. The main headers are usually large diameter pipes up to as much as 4 or 5 feet in diameter. The systems become operative upon sudden release of vapors from safety relief valves and therefore are subject to sudden surges of gas flow. This tends to set up large am­plitude vibrations or shaking of the system. To protect against the piping from bouncing off supports or damaging adjacent equipment, hold down guides should be judiciously located through tout the system. The system should be amply anchored to direct its thermal movements and where movements are too large to absorb within the inherent offsets of the piping, loops, or offsets with tandem expansion joints, are recommended. Direct axial expansion joints are undesirable because of large anchor forces required to contain the system. There is no limit to the total expansion which the above devices can take except that sound engineering judgement shall be applied to limiting anchor forces, lengths of support saddles, and spacing required to other pipe or equip­ment.

b) Branch connections, expanding thermally between relief valve and the blowdown headers, may require the addition of flexible offsets to absorb such movements. The allowable stress of the pipe at the connection to the relief valve should be limited to prevent any distortion at the valve which would render it inoperative. As a rule of thumb the resultant bending stress at the connection should be kept below a maximum of 10,000 psi. Large weight reactions should be removed from the relief

valve by use of spring supports or equivalent. Welding of gussets from the valve discharge pipe to the valve inlet nozzle as a solid support is not recommended and shall not be used on systems exceeding 150°F.

c) When gas flow through blowdown systems has a velocity at tee connections above .2 Mach, the pipe wall for at least 5 diameters on each side of the tee connections should be in­creased in thickness to prevent cracking by ovaling vibrations. The branch pipe should likewise be increased in thickness for a short distance back from the tee.

d) The reactive forces resulting from the discharge of relief valves can be computed from the following formulas:

The reactive forces resulting from the discharge of relief valves

The reactive forces resulting from the discharge of relief valves

7.10 Field Checkout

a) Field Checking has become an important part of the Project Stress Analyst’s responsibility. Errors in the Field due to omission or improper interpretation of design drawings have necessitated that critical piping be reviewed just prior to unit startup. A moan list should be developed at the field covering any items yet to be completed by the construction department (to cover possible omiss­ions) and to itemize in detail any corrections or modifications required on any support or piping installations where the design intent was not met. Exceptions may be made where the system as installed will function adequately and every effort should be made to avoid requesting corrections unless there is danger of failure of some component of the system. The moan list should become part of a report which is then given to the Job Superin­tendent and the Supervising Field Engineer.

7.11 Soot Blowers

a) In today’s high performance steam generators, “Controlled Cleanliness” of horizontal and pendant tube surfaces must be maintained to assure proper heat absorption and optimum steam temperatures. Soot blowers are needed for the specific pur­pose of cleaning tubes in the convection section of heaters and boilers. The soot blowers are constructed of long hooded frames which support horizontal lances up to 24′ long.

The lance (or female pipe) is extended into the heater or boiler convection section by retracting it from its internal “male” feeder pipe. The soot blower assembly is fed by air or steam at a flanged nozzle 15′ or 20′ out from the wall of the convection section. It is not rigidly held at this point but can be moved laterally a small amount (say 1″ +) and even slightly rotated.

b) If several units are to be connected together by a common steam header, the above movements can normally be tolerated. The soot blower frame is supported at each end to the platform structures of the heater or boiler.

7.12 Settlement and Frost Heave

a) Differential settlement between pieces of equipment, or structures and equipment, can induce damaging reactions or stresses to both piping and the equipment to which it is attached.

b) It is essential that specific settlement or heave deflections are obtained from the structural department for critical locations such as around pumps, tanks, and at all vessels and columns. These deflections must then be incorporated into the design analysis of all affected piping. Where these deflections cannot be easily absorbed it may require that pipe supports be extended below the frost line or that piles be driven to prevent settlement.

c) To avoid special piles for foundations, pump piping may be supported to the pump foundation itself by extending a portion of the foundation under the piping. Also, a beam can be em­bedded into the pump foundation with a short section cantilevered out to support the eccentric pipe system. This cantilever section should be sufficiently above the grade slab so that anticipated frost heave will not affect it. Support lugs maybe cinch anchored into the side of the foundation. The method

of supporting the pump piping must therefore be agreed upon early in design stages of the plant.

d) At plant sites where frost heave is a problem, the support of piping manifolds alongside exchangers can be supported to structural members fastened to the sonotube or pier supports of the exchanger itself rather than provide deep separate foundations for the piping separately.

e) Where piping systems below grade are subject to settlement piled supports should be provided to prevent detrimental deflections of branch piping to pumps or other equipment. Deep burial of these headers are required in areas affected by frost heave.

7.13 Ambient Temperature Effect on Bare Piping

a) Empty piping in long pipe ways can be greatly affected by atmos­pheric temperature (ambient) changes. Stagnant systems in 100-110°F temperatures can reach effective wall temperatures of 130° to 140°F depending on pipe surface coloration or cover­ing. It is suggested that 130°F minimum be used for the high temperature design of systems affected by ambient changes only. For the contraction of systems below the tie-in temperature the basic design data of the locale should be reviewed to de­termine the minimum temperatures that the systems will be subjected to. It is very important that contraction from a tie-in temperature be considered when checking clearances, or designing expansion joints with limit stops or internal sleeves. Severe failures in systems have already occurred where this was not properly accounted for.

b) The tie-in temperature should realistically be chosen for the time of the year of installation and the locale of the plant. For example, if piping is to be installed in Alaska during the winter months the tie-in temperature might range from below zero to freezing (32°F), whereas piping installed in Canada in the winter months would range from 40° to 80°F. For long pipe ways this can result in a considerable difference in ex­pansion movements.

7.14 Control Valve Piping

a) Piping to control valves or let down valves are subject to vibration which sometimes reaches dangerous amplitudes or destructive frequencies. In general the connecting piping systems should be guided whenever possible to eliminate large amplitude vibrations. But, where sonic vibrations occur with high energy input, the pipe tends to oval or wave patterns develop circumferentially dictating that rigid attachments should be avoided since failure at points of rigidity on the pipe wall will generally occur.

b) It is the responsibility of the Control Systems Group to flag systems with those critical tendencies for special study and corrective design. When the pipe stress analysis engineer is confronted with this type of problem he should contact the Control Systems Specialist for the proper solution to the problem.

7.15 Hydrotest of Large Low Pressure Piping

a) The design of supports for large diameter piping systems can be greatly affected by whether or not the system will be filled with a liquid, since the filled weight can be many times the empty weight. Therefore in the early stages of plant design it is extremely important to get agreement with the client and our construction department on the basis of support design of large diameter piping systems normally handling gas flow. If a hydrotest is imperative then the structural group must design supports for liquid load. If the system will be air tested, or by similar alternate gas test, then all parties concerned must agree in writing in order to protect Owner‘s interest, and avoid design checking or modifications near job completion.

b) Ring girders or thick saddle plates may be required at support points for hydrotested systems.

7.16 Pipe Supports

a) When marking up piping isometrics or drawings for required supports, the list of Standard Support Symbols as shown on owner‘s standards should be utilized. This will help the support group to interpret the markings of each piping stress analysis engineer in a commonly understood fashion.

b) Elaborate, highly detailed, and non-standard supports should be avoided. Supports should be as simple as possible.

c) Some basic precepts on where, when and how to support piping are:

1) Avoid supporting one pipe to another except for small utility lines being routed to off plot facilities alongside a large line high above grade. Occasionally individual branch lines of small diameter are routed between the pipe ways and process vessels at an excessive span and at elevations in excess of 10′ above grade. In cases like this, the support to a larger line nearby is acceptable.

2) Spring supports should be specified only when important to the safe or proper design of a piping system. A great number of spring supports are often rather casually de­signed into the piping in a plant. Upon closer inspection, however, it will usually be found that the system could be designed with solid supports. The use of shims in pre-­springing pipe will permit minor expansion movements.

3) Maintenance Supports should not be provided unless required by clients specifications. During plant shutdowns any system that is to be repaired can be temporarily shored up.

4) Piping to vertical vessels that are flanged at the vessel nozzle should be provided with a bracket support. This is more for installation and maintenance generally than for stress purposes. Non-flanged piping to vessels may not re­quire these bracket supports, stress permitting.

5) Where rigid guides or struts would restrict the free expansion of a piping system in such a way as to affect it detrimentally, the system should be guided with truck shock absorbers (see support group details of acceptable units) or in the case of large, critical piping the more specialized hydraulic cylinders should be installed. (i.e. Bergen, Grinnell, Barco, Marpak or equivalent types). Piping expansion occurs generally at a slow enough rate to permit the gradual adjustment within the hydraulic unit.

d) Spring Supports

l) Spring supports, when properly used, fulfill a very important need in the support of piping systems. However, they should not be used indiscriminately or as an easy solution for the support of piping which is affected by vertical expansions or other mechanical movements. For proper installation procedures for the construction department a structural owner‘s standards is available for their use.

2) Solid supports are usually practical when the support lug on the inlet or outlet piping is at the proper elevation to balance out vertical expansion of the equipment and its pedestal supports. In other cases as a general rule, it is better to make a calculation if it will prove that a solid support is acceptable. If calculation time does not exceed about four hours it is probably worth making the calculation in order to eliminate the spring supports.

3) When spring supports are used in pump systems the pipe stress analysis engineer must review the effect of the spring reaction on the system based on a spring preset reaction which has been calculated for a liquid filled system. Prior to start-up this reaction is applied to an empty pipe system. If the liquid weight portion of the reaction can’t be tolerated by the pump or piping, the spring may have to be preset at some value between the full and half full pipe weight reactions. When the liquid weight affect is intolerable for even a 50% weight change, the piping will have to be rerouted to provide an acceptable design. See Specification M-504 for field installation instructions for spring supports and ensure that design of spring supported systems is consistent with the requirements of that specification.

4) When to Use Spring Supports

If vertical expansions or mechanical movements (imposed on a piping system restricted by solid type supports) result in intolerable stresses or reactions, then spring supports may be required. Spring supports permit the piping system’s flexibility to be used to absorb system movements within tolerable limits; they must be used on hot piping systems adjacent to pumps, turbines and compressors when solid supports cannot be tolerated. Wherever variable spring hangers are used, the piping stress analysis engineer must check to assure that the total variation in support effect does not result in harmful stresses and forces within the piping system. Otherwise constant spring supports or counter weight supports should be considered. Generally for non-critical systems, varia­tion of support force up to +. 25% and movements up to 3″ may be allowed.

5) How to Avoid Using Spring Supports

If a support is not adjacent to a piece of rotating equipment or some other similarly delicate apparatus, a piping system subjected to 3/8″ or less movement might well be shimmed at supports after the system has been completely welded in place or bolted up. If the flexibility of the piping permits, and the dead load of the pipe will not keep the expanded system on its supports, the use of nominal shims, from 1/8″ up to 1/2″ thick, should be utilized rather than specify spring supports. left up to the field forces and therefore it is the duty of the Pipe Stress Analysis Engineer during Field Check to review these connections.

b) Steam trace branches and condensate return lines are often banded together in plants located in freezing climates. Obviously differ­ential expansions of the steam and condensate headers may detrimentally affect these connections. Therefore, a horizontal loop must be extended from the smaller condensate branch before rejoining the steam line for banding together. The extended loop is separately insulated and is allowed to cantilever out unsupported except by the banding upon return to the steam line. Drip legs of steam headers have been routed directly to a stanchion beam or other structural member and clamped tightly to a fixed support permitting no movement at all. Standard drawing for drip leg details in owner‘s standards, has been revised to alert the field of this problem.

7.17 Tank Field Piping

a) The piping in tank fields is subject to several special design considerations such as:

  • Tank settlement
  • Earthquake movements
  • Containment within diked areas

b) Where tank settlement is a problem the first pipe support should be located, say, 20 feet away from the nozzle and be of an adjust­able type. Adjustable supports can be made up of wood block layers 1/2 inch or 1 inch thick that can be retracted as the tank settles. Where adjustable supports do not fit into the design, flexible couplings or joints can be used in a tandem arrangement. A tandem unit involves a length of pipe with a flexible connector at each end which absorbs deflections by angulating the unit at right angles to the axis of the pipe.

c) Earthquake movements can be accommodated by providing a pipe offset at the tank. This offset can be used for both settle­ment and earthquake movements. The routing of a long line without offsets directly connected to a tank nozzle should be avoided.

d) Piping routed between and anchored in dikes of a tank field generally requires either loops or offsets to absorb its expansion and contraction, even though only affected by ambient temperature changes. The burial of the pipe in the dike pro­vides sufficient restraint generally to anchor the pipe. Where sleeves are used, a link is generally provided between the pipe and the sleeve.

7.18 Steam Trace and Steam Trap Piping

a) Steam trace piping details are provided to the field by an Engineering owner‘s standards. A problem arises in the connect­ions from the steam headers to the steam traced pipe. The expansions of the steam header requires that the interconnecting branch pipe to the steam traced pipe be of sufficient flex­ibility to absorb the deflection without failure. Also the clearance of the branch pipe to other piping or structures must be considered. The location of these steam trace branches is.

b) On return to the main office, the Piping Stress Analysis Engineer should make a brief trip report to the Project Engineering Manager, and send copies of the report with the moan list attached to the Project Superintendent, the Supervising Field Engineer, the Unit Project Engineer, and the Chief Vessel-Stress Engineer. See owner‘s standards.

c) A typical check list of items for field review might include:

1) Clearances between piping systems or between critical piping and structural members or any equipment. This includes review of critical cold springing.

2) Sufficient overhang of pipe support shoes on beams to allow for maximum pipe movement.

3) Movement of piping as affecting instrument or electrical connections.

4) Spring supports adjusted to proper loadings and stops removed after hydro test of system.

5) Pipe anchors located and installed correctly.

6) Expansion joint assemblies installed properly including orientation of hinges or tie rods, if any. Sizing bars to be removed.

7) Critical Piping:

  • Steam lines, including Turbine piping.
  • Reactor piping.
  • Furnace Transfer lines.
  • Blowdown Systems.
  • Compressor Piping.
  • Pump Piping.
  • Hot process piping (generally over 350°F).
  • Cryogenic and refrigeration piping.
  • Steam trace connections.

7.19 Plastic Piping

a) Because of the need within refineries and chemical plants for piping to carry alkalies or acids, various metals are used in the fabrica­tion of special piping for this use. Some of the materials used are rubber lined or glass lined steel pipe, and solid plastic or reinforced plastic pipe, usually known as reinforced thermo-setting resin pipe, filament wound, either hand laid, bag molded, or cast. In the case of lined steel pipe, its flexibility and support are similar to unlined pipe. But, where plastic or reinforced plastic pipe is used the support and flexibility requirements should closely follow the recommendations of the specific manufacturer. As a guidance, refer to ASME Code Case N115-1.

b) It has been noted that different manufacturers of PVC (Poly Vinyl Chloride) pipe recommend different methods of supporting and restrain­ing the systems. The Pipe Stress Analysis Engineer is urged to consider expansion and and contraction forces and stresses in systems before agreeing to totally restrain the systems with thrust blocks as recommended by one of the plastic manufacturers. In fact, all manufacturers agree on the cemented joints as being equal to or better in strength than the pipe itself. Therefore allow the free expansion of the system normally with the suggestion that the field be notified to exercise great care in installing the cemented joints for complete adequacy. Also, the manufacturers allowable support spans should not be exceeded

c) Because of the considerably lower values of Young’s modulus of elasticity (1.5 to 1.0 x 10^6) of the plastic materials, the pressure elongation of the pipe line may be a significant factor in the flexibility or displacement stress analysis of FRP pipes. To take this into consideration, an equivalent coefficient of expansion that will include the pressure strain effect should be used in the owner piping stress programs.

7.20 Rotation, Reactions and Stresses at Nozzle Connections to Vessels

a) Most piping systems connected to shells of columns, exchangers drums and tanks are analyzed conservatively without consider­ing the rotational relief afforded at the nozzle connections. Generally, as long as the stresses in the piping and loadings on other attached equipment are within allowable limits, the systems as a whole is deemed acceptable. However, when the reactions on the shell nozzle appear high, then the Engineering Design Owner‘s Guide “Local Stresses in Cylindrical Shells due to External Loadings” may be used to approximate the vessel stresses due to the fixed end reactions. If this stress is too high, a calculation can be made employing the spring constant of the nozzle attachment whereby the reduced loadings on the vessel shell may be acceptable when compared to allowables in Owner‘s Guide.

If a system is obviously very tight, the spring constant “K” of any nozzle attachment should be evaluated from the owner‘s standards and incorporated in the calculation from the beginning.

b) If two vessels are interconnected by radial nozzles, such as stacked exchangers, and the shells are at different temperatures, the difference in longitudinal expansion must be absorbed mostly by a rotation of the joined nozzles at each shell connection, (i.e., nozzle rotation = differential expansion / total nozzle length). See owner‘s standards for condition requiring this evaluation and for the procedure to be followed.

c) The spring constants of owner‘s standards can also be used to find the deflection or rotation of pipe supports (i.e., cantilevers or brackets, etc.) attached to shells, due to the flexibility of the shell under the applied loads and moments.

d) Storage tanks present a unique problem involving rotation and deflection of shell nozzles close to the tank bottom during filling of the tank. These movements affect attached piping and should therefore be considered when locating external pipe supports or routing the pipe itself in a proper manner. See owner‘s standards for design criteria.

7.21 Bowing of Pipe

a) Bowing in piping systems is due to unequal heating of the pipe wall from side to side along its length. This type of bowing is unrelated to column instability from compressive axial loads. As one side of a pipe becomes hotter than the opposite, its longitudinal elements expand more than those of the colder side and bowing occurs.

b) Bowing may occur when:

1. Hot or cold fluid flows in partially filled pipes.

2. Sun’s radiation heats the tops of large empty pipes laying close to the frozen ground.

3. Unequal surface heating of furnace tubes.

4. LNG in partially filled loading lines.

5. Channelling occurs in tubes filled with packing.

6. The burner flames in a furnace are not equally dis­tributed across the tube diameter.

c) If a piping system is not restrained and is considered weightless, bowing does not induce stresses in the pipe. Weight, friction and restraint, however, will induce stresses in the pipe, and the restraints may be subjected to very high reactions.

d) Bowing can usually be tolerated when it is of only short dura­tion. If bowing is considered detrimental, and it is not possible to improve the uniformity of the temperature in the pipe, then external restraints must be designed and provided.

7.22 Compressor Bottle Support

a) As explained in paragraph 5.22 (c), there is a need for an elastic support for compressor bottle to allow for vertical expansion downward from the cylinder support level. From design data for rubber bearing pads, a design procedure has been set up to properly size bearing pads. The pads can be placed between the support lug or saddle on the compressor bottle and the load adjustment plate underneath. This load adjustment plate is supported by four or more bolts embedded in a concrete pier. The plate is suspended about 3 inches above the top of the concrete pier to allow for tuning of the support to inhibit vibration.

The design procedure to size the bearing pad and the adjust­ment plate is explained herein and the rubber bearing pad physical data is shown on owner‘s standards. The support assembly detail is a structural standard. The size of the rubber bearing pad in the detail shall be determined by the Piping Stress Group by completing Form No. 70 of the Pressure Vessel Standards.

The suction bottles resting on the compressor cylinders need no support, except for eccentric or overhanging portions of the bottles, since the load is in compression. The discharge bottles hang from the cylinders putting tension into the nozzles which, under constant vibration, are more likely to fail. See Bearing Pad size calculation procedure below.

Bearing Pad size calculation procedure

Bearing Pad size calculation procedure

Bottom Plate Thickness “T”

Design the bottom plate as a simple beam of cross-section “C” x “T” with supports spaced “F” apart and with a central concentrated load equal to “2R” (2 x (11) from above).

7.23 Tank Nozzle Movements Due to Pressure and Temperature

With the advent of larger diameter and taller storage tanks, a problem of shell deformation close to the bottom of tank due to product storage pressure has been magnified. Under pressure the tank wall will stretch and will move radially outward if unre­strained. At the juncture of this shell to the tank bottom the pressure creates a shear load which tends to stretch the tank bottom. This stretch is negligible compared to the shell radial distortion, therefore, the shell is nearly totally restrained at its juncture to the tank bottom plate. From this point a vertical section would show that the shell gradually follows an elastic curve to a point closely equal to 1.56x(Rt)^0.5 above the tank bottom where the radial deformation is equal to PR^2/Et nozzle on the tank located in this bulge area will exhibit both a downward rotation and an outward deflection. This results in a bending and shifting of the piping system connected to the nozzle which must be accommodated by its inherent flexibility considering all restraints acting on the piping system especially the location of the first pipe support adjacent to the tank. Where tank settlement is also involved adjustable supports or couplings can be employed as described in Section 7.17. When necessary to study the nozzle rotation effect on external piping to the tank refer to Engineering owner‘s standards for the conservative values of both rotation and deflection and input them into a flexibility calculation. Differences in expansion of the tank shell and tank bottom, which is reacted on by friction and may have minor buckling effects, are considered negligible.


The following list of work items is provided as a check list for Project Stress Analysts. It lists items essentially in their chronological sequence as they will occur on a project and is intended to draw attention to critical items, some of which must be reviewed and pre-planned at specific stages of a job in order to avoid delays and changes in other engineering work.

8.01 Design Data (Ref. Par. No.)

Obtain from the Project Engineer:

a) Basic design data for job site, i.e., Wind Loads, E. Q. Loading, Temperature Variations, etc.

b) Steam-out temp. – Project Engineer must issue memo to all Unit Engineers. (6.09)

c) Steam-trace temp. – Project Engineer must issue memo to all Unit Engineers. (7.18)

d) Steam-trace temp. -Project Engineer must issue memo to all Unit Engineers. (7.12)

8.02 Drawing Distribution

See that name is on Distribution of Documents, schedules, etc. for items required for stress work. (2.1)

8.03 Initial Piping Studies (3.0)

8.04 Alloy Piping (3.2.)

a) Give preliminary approval for material commitment.

b) Make final studies so that detailed supports can be issued for shop ISO’s.

8.05 Stress Relieved Vessels & Piping (4.0)

a) Obtain dates from the Pressure Vessel Supervisor for scheduled shop stress relief of each vessel.

b) Complete stress studies of piping and send ISO’s to Support Group six weeks ahead of scheduled |SU issued- for-construction date. Coordinate this with the Piping Supervisor.

8.06 Heaters (5.5)

The Piping Stress Analyst shall arrange a meeting with the Project Engineer 5- Heater Specialist and supply all infor­mation required on the heater bid specification, including the following:

a) Anchor nozzles – Yes or No.

b) Nozzle Movement – Amount and Direction.

c) Support of tubes – Top or Bottom -Effect on external piping.

d) Need for brackets on heater shell for pipe supports and plat­forms, etc. (Loads, details, etc.).

8.07 Compressors & Their Turbine Drivers (5.2 & 5.3)

a) Check with equipment specialists to assure that Mfrs. agree to our specified loading conditions, as related to equipment dead load.

b) Send piping ISO’s with support locations to Mfr. with request for an analog vibration study for each reciprocating compressor.

8.08 Pumps (5.1)

a) Locate large bottom out pumps with respect to vessels to give best arrangements for flexible pipe configuration.

b) Avoid direct piping from equipment to pump.

8.09 Loops in Pipeways (6.06)

a) Place loops in headers to limit their expansion or affect on branches to turbines, pumps or compressors.

b) Locate off-plot pipeway loops as soon as possible as an aide to the Construction Dept, for field “fill-in” work. (6.09)

c) Locate and size anchors and loops for systems which are to be used during construction (steam and other utilities) when requested. (6.07)

8.10 Airfans (5.4)

a) Check with Project Engineer to assure that the specifications require a lateral movement tolerance of 5/16″ min.

b) Acquaint pipe designers with flexibility requirements when several units are joined together.

8.11 Auxiliary Pipe Stanchions

Establish all additional auxiliary stanchions or special supports requiring piles or foundations, as soon as possible – when sufficient branch piping is modelled, so that field crews can complete pile driving operations and advance to later operations without concern for the need for additional piling in an area.

8.12 Tank Field Piping (7.17)

8.13 Field Checking (7.10)

8.14 Special Design Criteria

a) When complete thermal cycles within a piping system exceed 7000 and the expansion stress anywhere within the system exceeds 1.25 Sc, the overstressed section requires full examination in accordance with 336.5.1 (b) (2) (ANSI B31.3)

b) For piping in cold climates it is important to see that those constructed from carbon, low alloy and high alloy steels are not stressed higher than 6000 psi based on a combination of longitudinal stresses due to pressure, dead load and displacement strains. The operating pressure should be no greater than 15% of the maximum design pressure at that time nor should the temperature be below -50 F. If any of the above are exceeded an impact test is required . (See paragraph 323.2.2)

Read Also: The Canadian Piping Flexibility Stress Analysis Standard


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The Canadian Piping Flexibility Stress Analysis Standard

The Canadian Piping Flexibility Stress Analysis Standard

The Canadian Piping Flexibility Stress Analysis Standard. By Meena Rezkallah, P.Eng. Piping Stress Engineer. professional engineer in canada

The Canadian Piping Flexibility Stress Analysis Standard. By Meena Rezkallah, P.Eng.

The Canadian Piping Flexibility Stress Analysis Standard for a premium piping engineering & full-service pipe design and pipeline / pipe stress analysis services across Canada & globally. Using CAESAR II and pipe stress calculations as per API, ASME B31.3, B31.1, B31.8, B31.4, CSA Z662.



2.1 API (American Petroleum Institute)

2.2 ASME (American Society of Mechanical Engineers)

2.3 NEMA (National Electrical Manufacturers Association)

2.4 NBC (National Building Code of Canada)

2.5 CSA Group


3.1 Quality Assurance


4.1 Piping Systems

4.2 External Load Limits on Equipment

4.3 Allowable Forces and Moments on Flanges

4.4 Friction Effects

4.5 Supporting

4.6 Wind Loads

4.7 Seismic Loads

4.8 Vibration

4.9 Existing Lines


This standard prescribes the basic requirements for the engineering of piping systems and components

for thermal flexibility, support, pressure, vibration, fluid, or gas flow reactions and environmental factors,

including effects on equipment.


The publications listed below form part of this standard. Each publication shall be the latest revision and

addendum in effect on the date this standard is issued for construction unless noted otherwise. Except as modified by the requirements specified herein or the details of the drawings, work included in this

standard shall conform to the applicable provisions of these publications.

2.1 API (American Petroleum Institute)

2.2 ASME (American Society of Mechanical Engineers)

2.3 NEMA (National Electrical Manufacturers Association)

  • SM23 Part 8

2.4 NBC (National Building Code of Canada)

2.5 CSA Group


3.1 Quality Assurance

3.1.1 The practices outlined herein establish the minimum requirements to which the Piping Stress Analyst shall adhere in the performance of quality assurance activities to ensure adequate engineering review of piping systems. Pipe flexibility and stress analysis shall conform to the governing piping code. The pipe line list for the project shall be the controlling document establishing individual line parameters, with the piping drawings defining line configurations.

3.1.2 Calculations shall be retained by the Engineering Contractor or Engineering Consultant for a period of 15 years.

3.1.3 Formal computer analysis shall be performed on the following piping systems:

• Process lines to and from steam generators.

• 2 inches and larger diameter process lines to and from pumps, compressors, turbo-expanders, and blowers.

• Lines with design temperatures over 260°C.

• Piping systems that are selected by the Lead Piping Stress Engineer.

• Steam lines to and from turbines.

3.1.4 As a minimum, engineering analysis by visual inspection and short-cut manual calculations shall be performed on the following systems:

• 16 inches and larger diameter lines.

• Lines to vessels that cannot be disconnected for purging or steam out.

• 3 inches and larger diameter lines at design temperature over 150°C.

• Piping systems selected by the Lead Piping Stress Engineer, which do not require formal computer analysis.

• Relief systems, whether closed or relieving to atmosphere, with considerations for attached or detached discharge pipes.

• Vacuum lines.

• Nonmetallic piping.

• Lines subject to excessive settlement.

3.1.5 Special consideration shall be given to piping systems in the following categories:

• 3 inches and larger diameter lines subject to greater than 25 mm differential settlement of equipment, or supports.

• Lines designated as “Category M,” according to ASME B31.3, shall be so identified in the line list.

• Lines subject to mixed-phase flow (liquid and vapor), and lines identified as vibrating service on the flow diagrams.

• Lines subject to external pressure by reason of vacuum or jacketing.

• Piping connected to reaction sensitive equipment.

3.1.6 Lines to be considered for analysis shall be so marked on the line list.


4.1 Piping Systems

4.1.1 Piping flexibility shall be obtained through pipe routing or expansion loops. Expansion loops, when installed in a horizontal plane, shall be offset vertically to clear adjacent piping whenever possible. Expansion Joints / Flexible connectors shall be used only when it is not feasible to provide flexibility by other means. Expansion joints / flexible connectors shall be marked on the P&IDs and approved by the project Owner.

4.1.2 The flexibility analysis shall consider the most severe operating temperature condition sustained during startup, normal operation, shutdown, or regeneration. The analysis shall be performed for the maximum temperature differential. The effect of minimum installation and solar temperatures shall be considered in determining the maximum temperature differential.

Note: Hydrocarbon lines within units, areas, and unit pipeways shall be considered subject to steam purge. Interconnecting pipeway lines shall not be considered subject to steam purge. Lines subject to steam purge shall be designed for the steam temperatures or the design temperatures of the line, whichever is higher. Consult the process engineer at the beginning of the job for the correct temperatures.

4.1.3 Lines to purged vessels that cannot be disconnected during purging shall be designed with sufficient flexibility to accommodate the thermal displacement of the vessel.

4.1.4 The mean installation temperature shall be assumed as -10°C for above ground and +10° for underground.

4.1.5 The metal temperature from the effect of solar radiation shall be assumed as 65°C for pipe stress analysis purposes.

4.1.6 If the line is a vapor line, hydrotest weight shall be considered in the analysis.

4.2 External Load Limits on Equipment

4.2.1 Rotating Equipment

Upset/design temperatures are considered transient. For allowable loads the normal operating temperature and the maximum temperature differential shall be used to check the stress in the system.

4.2.2 Vertical In-Line Pumps Piping to small vertical in-line pumps (20 horsepower or less) shall be supported immediately adjacent to suction and discharge flanges by means of conventional pipe supports. Piping loads shall be determined with the pump considered as a rigid but unanchored segment of the piping system. Piping to larger vertical pumps furnished with casing footmounts shall be supported on suitable foundations. The allowable force and moment limitations at pump nozzles shall be per API 610.

4.2.3 Centrifugal Pumps

For pumps that are single-stage, centerline mounted, 2-point support, the allowable

forces and moments published in API Standard 610 shall be used, unless higher loads

are permitted by the Supplier.

For pumps that are multistage, centerline mounted, or barrel type horizontal cases with 4-point

supports, force and moment limitations shall be per API 610, unless higher loads

are permitted by the Supplier.

4.2.4 Centrifugal Compressors

The maximum allowable forces and moments that may be applied to compressor flanges

by the piping shall be per API Standard 617 Section 2.5, unless higher loads are

permitted by the Supplier.

4.2.5 Reciprocating Equipment

Allowable forces and moments shall be as permitted by the Vendor and agreed by the

Engineering Contractor.

4.2.6 Heat Exchangers (Shell and Tube)

Allowable external forces and moments shall be limited to those that produce a limiting

stress as set by ASME B31.3, for the exchanger nozzle/shell material recognizing stress

intensification factors as determined by the applicable code.

4.2.7 Air Cooled Heat Exchangers

The maximum allowable forces and moments that may be applied to air cooler process

nozzle flanges shall be per API Standard 661, unless higher loads are permitted by the


4.2.8 Pressure Vessels and Miscellaneous

Allowable loads shall be calculated in accordance with criteria given by the API

Recommended Practices, API Standards, or ASME sponsored codes that apply to the

specific equipment or system, unless higher loads are permitted by the Supplier.

4.2.9 Fiberglass Vessels / Glass Lined Vessels

There shall be loads developed on these vessel nozzles. Allowable forces and moments

on nozzles shall be calculated in accordance with standard pipe stress analysis methods.

Allowable loads cannot be zero and shall be as agreed to by the Vessel Supplier.

4.3 Allowable Forces and Moments on Flanges

To avoid leakage in flanges, bending moments and forces on flanges shall be limited by the formulas listed in the ASME Boiler and Pressure Vessel Codes, Section VIII.

4.4 Friction Effects

4.4.1 The effect of frictional resistance to thermal movement of the pipe shall be included in the anchor design of piping systems. Assume a coefficient of friction of 0.3 for steel-to-steel contact, 0.1 for teflon to stainless steel contact surfaces and 0.4 for steel to concrete.

4.4.2 Frictionless unrestrained movement of the piping system shall be assumed only when the entire system is supported by means of rod or spring hangers.

4.4.3 Friction shall be considered a short-term transient load. Allowable load limits on equipment may be increased by a factor of 1.5 when considering normal loading plus friction loads. Supports immediately adjacent to equipment nozzles shall be assumed frictionless.

4.5 Supporting

4.5.1 Lines shall be supported in accordance with the limitations set by the applicable codes

listed herein. Deflection between supports shall be limited to 25 mm or less if accumulation of small quantities of liquids is not acceptable.

4.5.2 NPS 20 and larger carbon steel lines and thin-wall lines (D/T ≥ 100) shall be analyzed for crushing loads at support points, and shall be reinforced as necessary.

4.5.3 Systems including tanks / vessels shall be analyzed. These tanks / vessels shall not have springs directly under equipment lugs without the approval of Lead Piping Stress

Engineer. Flexible connectors may also be considered with the approval of Lead Piping Stress Engineer and the project Owner.

4.6 Wind Loads

Design wind pressure and height zones shall be according to NBC.

4.7 Seismic Loads

Seismic loads shall be considered for piping design according to NBC or other local building codes, as required by the project.

4.8 Vibration

Dampeners, restraints, or both shall be provided for lines subject to mixed-phase flow, as required.

4.9 Existing Lines

In verifying stress levels of existing lines due consideration shall be given to requirements of API 570 ‘Piping Inspection Code’. Connections to existing lines or changes in temperatures and pressures of existing lines shall be

analyzed as follows:

4.9.1 Ultrasonic measurements shall be taken for thickness at critical points on all subject lines. This thickness shall be assumed to prevail throughout these lines.

4.9.2 Calculations shall be performed to determine the integrity of pipe wall thickness for the new design conditions or continued operation under original design conditions.

4.9.3 Field sketches shall be drawn of the entire as-built systems for existing lines, subject to a change in operating or design temperature of more than plus or minus 15°C.

4.9.4 Field sketches shall be drawn of as-built systems from new connection points, both upstream and downstream of the connection, to the nearest anchor point or logical discontinuity when anchors are not available.

4.9.5 Type of flexibility analysis required shall be determined by the Engineering Contractor and agreed to by the project Owner.

Read Also: The Canadian Pipe Stress Analysis Design Manual for Owners, Engineers and Contractors


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The Canadian Piping Stress Analysis Criteria for ASME B31.3 / CSA Z662 Metallic Piping

The Canadian Piping Stress Analysis Criteria for ASME B31.3 / CSA Z662 Metallic Piping

The Canadian Piping Stress Analysis Criteria for ASME B31.3 / CSA Z662 Metallic Piping by Little P.Eng. for engineering services across Canada specialized at piping stress analysis and piping design.

1.  Introduction

1.1 Purpose

1.2 Scope  

2.  References

2.1 Process Industry Practices

2.2 Industry Codes and Standards

3.  Requirements

3.1 General

3.2 Analysis Parameters

3.3 External Load Limits on Equipment

3.4 Analysis Applications

3.5 Documentation

1. Introduction

1.1 Purpose

This Practice provides minimum requirements for analyzing the flexibility of aboveground metallic piping systems.

1.2 Scope

This Practice describes the piping flexibility analysis parameters and applications, and documentation requirements.

2. References

Applicable parts of the following Practices and industry codes and standards shall be considered

an integral part of this Practice. The edition in effect on the date of contract award shall be used,

except as otherwise noted. Short titles will be used herein where appropriate.

2.1 Process Industry Practices (PIP)

– PIP PNFS0001 – Miscellaneous Pipe Support Details

– PIP RESE002 – Allowable Piping Loads on Rotating Machinery Nozzles

2.2 Industry Codes and Standards

American Petroleum Institute (API)

– API 618 – Reciprocating Compressors for Petroleum, Chemical, and Gas Industry Services

– API 661 – Air-Cooled Heat Exchangers for General Refinery Services

American Society of Civil Engineers (ASCE)

– ASCE 7 – Minimum Design Loads for Buildings and Other Structures

– NBC – The National Building Code of Canada

American Society of Mechanical Engineers (ASME)

– ASME Boiler and Pressure Vessel Code

– Section VIII – Pressure Vessels

– ASME B31.1 – Power Piping

– ASME B31.3 – Process Piping

Canadian Standards Association (CSA

CSA Z662 – Oil and gas pipeline systems

Welding Research Council (WRC)

– WRC 107 (see WRC 537)

– WRC 537 – Precision equations and enhanced diagrams for local stresses in spherical and cylindrical shells due to external loadings for implementation of WRC Bulletin 107

– WRC 297 – Local Stresses in Cylindrical Shells Due to External Loadings on Nozzles – Supplement to WRC 107

3. Requirements

3.1 General

3.1.1 All piping systems shall be evaluated and, if appropriate, analyzed for applicable conditions in accordance with ASME B31.3 and this Practice. The designer shall be qualified in accordance with the B31.3 Code para. 301.1.

3.1.2 The most severe, anticipated, coincident pressure and temperature conditions shall be considered to evaluate the flexibility and sustained load analyses for each anticipated operating condition. Design conditions (pressure and temperature) shall be set in accordance with ASME B31.3 paras. 301.2 and 301.3 with consideration to approved variations above same as set forth in ASME B31.3 para. 302.2.4. The sole uses for design conditions shall be in accordance with ASME B31.3 Appendix S, Example 1.

3.1.3 The flexibility analysis can require the combination of more than one load case to

determine the total displacement stress range.

3.1.4 Any computerized pipe flexibility calculations shall be performed using owner-approved software.

3.1.5 Piping systems shall be analyzed for expansion, contraction, differential settlement, relief valve reactions, and effects due to weight, wind, seismic, and other mechanical loading in accordance with ASME B31.3.

3.1.6 Expansion joints shall not be permitted unless approved by owner.

3.2 Analysis Parameters

3.2.1 Displacement Strains The flexibility analysis for each stress range to be evaluated for each anticipated operating condition shall be based on the maximum operating temperature for that condition unless calculations are supplied to and approved by the owner that better predict for the pipe metal temperature for the condition. Climatic effects shall be considered in determining the maximum differential temperature. The metal temperature from the effect of solar radiation in the summer and the winter dry bulb design temperature should be used. When more than one stress range is anticipated for a piping system with multiple operating conditions, as stated in Section 3.1.3 of this Practice, it may be necessary to determine the difference between displacement stress ranges (or compute the operating stress range, i.e., ASME B31.3 Appendix P). See ASME B31.3 Appendix S Example 3.

Comment: Cold branch includes cases dealing with parallel lines where at least one line (not always the same one) may be cold at any time. An example is three parallel pumps where one pump (not always the same one) is usually not in service.

3.2.2 Pressure, Weight, and Other Sustained Loads The weight of piping, piping components, refractory lining, piping insulation, fluid transported, and fluid used for testing shall be considered. Snow and ice loads shall be considered if specified by owner. If piping lifts off a support during an ambient to operating condition flexibility (stress range) evaluation, the support shall either be removed for sustained load calculations or spring supports shall be considered.

See ASME B31.3 Appendix S Example 2 for the potentially multiple sustained load analyses required by Code for each anticipated operating condition.

3.2.3 Friction The frictional resistance to thermal movement of the pipe shall be considered. The greater loads of those evaluated with friction and those evaluated without friction shall be used for reaction loads, flexibility based stress range analyses, and sustained load analyses and shall be documented. Frictionless unrestrained movement of the piping system shall be assumed only if the entire system is supported by means of rod or spring hangers.

3.2.4 Wind

The wind loads on piping systems shall be determined in accordance with the procedure outlined in ASCE 7 or as specified by owner.

3.2.5 Seismic

If specified by owner or required by jurisdiction, seismic loads on piping systems shall be considered.

3.2.6 Pressure Relief Systems Pressure relief discharge piping shall be restrained to contain the thrust loads. Forces and moments due to relief valve discharge may be calculated by any method approved by owner.

Comment: ASME B31.1, Appendix II is an example of a calculation method.

3.2.7 Water Hammer Piping systems subject to water hammer shall be considered. Forces due to water hammer shall be determined and suitable pipe restraints shall be provided.

3.2.8 Flanges External bending moments on flanges shall be considered. External loads may be analyzed by the equivalent pressure method or other methods approved by owner. Acceptance criteria shall be in accordance with owner’s requirements.

3.2.9 Maximum Pipe Spans and Deflections For determining pipe spans, maximum sag deflections shall be limited to 16 mm (5/8 in). Any deviations to Section shall be approved by owner.

3.2.10 Refractory The increased stiffness of a piping systems caused by a refractory lining shall be considered when determining reaction loads. To protect a piping system against collapse due to creep, the increased stiffness due to a refractory lining shall not be included in the span calculations, any sustained load analysis, and flexibility analysis.

3.2.11 Piping Fittings Reduced flexibility shall be considered where attachments exist on welded ells or within two pipe diameters of the welds of an ell.

  • 1. In the absence of better information, decreased flexibility may be simulated (in a computer analysis) by placing a flange pair at the nearest weld.
  • 2. Although not addressed directly by ASME B31.3, Appendix D, 45-degree ells shall have their flexibility reduced by placing a flange pair at each end. In the absence of applicable data or rigorous analysis, branches at angles other than 90 degrees may be modeled by doubling the default stress intensification factor for unreinforced fabricated tees.

Comment: Branches at angles other than 90 degrees are not addressed by ASME B31.3, Appendix D. For flexibility purposes, testing has shown that these branches act like unreinforced connections. The stress intensification factor for tees with aspect ratios of 3:4 shall be increased by 25%.

Comment: The ASME B31.3 Appendix D Stress Intensification Factors for tees with this aspect ratio have been found to be non-conservative.

3.2.12 Other Parameters Large diameter thin wall (D/T  100) lines shall be analyzed for crushing loads at local stress points and reinforced as necessary. Piping systems supported primarily by rod hangers shall accommodate the rod’s rotation and the consequent load impact on nearby equipment nozzles. Rod hanger lengths shall be modeled in the piping stress analysis. The rotation of the rod hanger shall be checked and shall not exceed 5 degrees during any of the operating, upset, relieving, etc., conditions. External Loads on Equipment shall be considered for impact due to support rod rotation. Unless otherwise approved by owner, use of cold spring for piping systems that connect to rotating machinery (compressors, turbines, pumps) shall not be permitted. If the use of cold spring is approved for use in a piping system by the Owner Engineer experienced in stress analysis, the piping shall be analyzed. No credit shall be taken for cold spring in the fatigue based flexibility evaluation(s) at operating conditions (i.e., when computing SE). Reaction load evaluation(s) may reflect the use of cold spring at the more severe of either any anticipated operating conditions, B31.3 para. 302.2.4 approved variations, or design condition(s).

3.3 External Load Limits on Equipment

3.3.1 Unless otherwise approved by owner, loads imposed on equipment by the piping shall not exceed the lesser of that allowed by the equipment manufacturer or that listed in the applicable references in this Practice.

3.3.2 Allowable nozzle loads for rotating machinery shall be in accordance with PIP RESE002.

3.3.3 Reciprocating compressor piping shall be analyzed in accordance with API 618.

3.3.4 Unless otherwise specified by owner, loads on air cooled heat exchanger nozzles shall be in accordance with the load criteria of API 661.

3.3.5 For pressure vessels and heat exchangers:

  • a. If the vessel/nozzle aspect ratios are within limits of the bulletins, WRC 107 and WRC 297 may be used in the evaluation unless otherwise specified by the owner.
  • b. If the nozzle/vessel geometry is outside the limit of WRC 107 or WRC 297, other owner-approved local stress analysis methods shall be used. Extrapolation of the curves in WRC 107 or WRC 297 shall not be permitted.
  • c. If applicable, allowable stresses shall be based on ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 or 2.

3.3.6 Tank nozzle loads shall be evaluated in accordance with the owner’s requirements.

3.4 Analysis Applications

3.4.1 A formal flexibility analysis shall be performed on all of the following piping systems (reference ASME B31.3, Paragraph 319.4.2):

  • a. Piping connected to load/stress-sensitive equipment
  • b. Process, regeneration, and decoking piping to and from steam generators and fired heaters
  • c. Process piping to and from centrifugal compressors, turbo-expanders, and blowers
  • d. Working fluid piping to and from turbines
  • e. Suction and discharge piping to and from reciprocating pumps and compressors
  • f. Piping NPS 3 and larger to and from centrifugal pump nozzles
  • g. Piping NPS 4 and larger to air cooled heat exchangers
  • h. Relief systems, whether closed or relieving to atmosphere, with considerations for attached or detached tail pipes
  • i. Piping requiring proprietary expansion devices (e.g., bellows expansion joints)
  • j. Piping NPS 3 and larger subject to stresses from significant differential settlement of associated vessels, tanks, equipment, or supports
  • k. Piping subjected to mixed phase flow (liquid and vapor)
  • l. Piping subject to slug flow
  • m. Piping identified as severe cyclic or vibrating service
  • n. Jacketed piping systems
  • o. Piping as required by applicable codes and standards (e.g., ASME B31.3
  • Category M)
  • p. Plastic lined piping systems
  • q. Piping that requires support for occasional loadings (e.g., seismic, wind, steam out, steam tracing)

3.4.2 All piping systems shall be reviewed to identify those systems that are outside the requirements of Section 3.4.1 but may still require flexibility analysis.

3.4.3 In addition to the requirements in Section 3.4.1, flexibility analysis for carbon, low and intermediate alloy, and stainless steel piping systems shall be performed in accordance with Figures 1 and 2.

3.4.4 Flexibility analysis shall be performed for other piping materials in accordance with owner’s requirements.

3.5 Documentation

3.5.1 Calculation numbers shall be assigned to identify each analysis and the flexibility analysis files shall be stored.

3.5.2 Upon project completion, all stress calculations and documentation shall be provided in accordance with the owner’s requirements.


1. Visual Analysis: Piping in this category may be analyzed by the use of engineering experience or

approximate methods.

2. Formal Analysis: Piping in this category requires formal analysis. Analysis may be performed by

approximate, comprehensive, or computer methods. Documentation is required.

3. Comprehensive Analysis: Piping in this category requires a comprehensive analysis (typically by computer).

Other methods may be used with owner’s approval. Documentation is required.


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Canada Piping Engineering Services

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Piping Engineering is a discipline that is rarely taught in a university setting, but is extremely important for the safety of plant personnel, safety of the public, and reliability of a facility.

The Goal of Piping Engineering is:




When plant evaluations and repairs of existing pipe, are being performed, often plant operations and maintenance personnel ask, “Is it going to be safe to work around here?” An answer they always appreciate from the piping engineer; “I’ll be out here checking on the pipe when the plant starts up.” The plant personnel just want to be assured that we are doing everything in our power to make the piping system safe to operate. This experience leads to a more personal definition of Piping Engineering:


To the uninitiated, this personal definition may seem a little alarmist, but it is based on reality. Pipes do fail, and sometimes with catastrophic results. Operations and maintenance personnel at plants understand the potential risks. While some major failures of high pressure lines have killed personnel, sometimes even relatively low pressure releases can cause injury and extended plant shutdowns. A release of toxic, flammable fluids or hazardous chemicals is a tremendous risk to personnel and neighbors and a large financial risk to operators.

Engineers sometimes get caught up in the numbers and minute detail of the designs. While details are important, it is also important to personalize the work and think about the full picture of the installation, and the long – term equipment’s use. While you may not be standing next to that pipe or equipment, someone will be – and their safety should always be in your mind when considering if all appropriate considerations have been made, and the calculations are accurate.


On the surface, pipe is pretty simple – a round bar with a hole in it to transport a fluid or gas. However, there is no other equipment within a typical plant that is subjected to so many different loading conditions over its life.

  • Pipe is supported at point locations, and must be able to support itself without undue sagging or bowing.
  • The weight of the pipe may change from empty to full at times, which on large diameter pipes can create dead weight double or triple the empty weight.
  • Temperatures vary from ambient to operating, sometimes greater than 1200F in process or steam systems, or less than -300F in a cryogenic application.
  • As the pipe heats and cools it moves due to thermal expansion. Pipe flexibility and pipe supports must accommodate this movement.
  • Pipe is attached to equipment, which has a limited capacity to support the pipe.
  • As the pipe ages, it tries to find its lowest stress level, and thus it “relaxes” – almost always into a different position than the theoretical analysis calculates.
  • Flexible pipe is sometimes analogous to supporting spaghetti, as it bends and twists from all of its various loading conditions. Changing a support in one location sometimes has a major effect on pipe movement 80 feet away.
  • Depending on the operating conditions, the pipe material may degrade over time due to creep, embrittlement or some other metallurgical phenomena.
  • Pipe stress analysis is not very exact. There is a great deal of judgment that is required in evaluating the results.
  • Standard pipe specifications allow +, – 12.5% variation in wall thickness. While most pipe thickness is within 1% to 2% of nominal; at any welded joints, the actual wall thickness may be 12.5% different than expected.
  • There are a high number of different components in each piping system: elbows, straight pipe, reducers, valves, flow meters, thermowells, pressure taps, branch connections, flanges, gaskets, bolts, etc. In a typical plant, when the sizes and schedules of all these components are counted, there may be much more than 10,000 different components.

This represents a large quantity of data to understand, and to properly identify and track through the design, installation and operation of plants.

  • Even with great engineering and design, the installation is subject to irregularities in the fabrication and erection of the pipe. Pipe fitters will rotate weld joints and pull pipe to “make the pipe fit”. While some of this can be controlled with very strict Quality Assurance, the reality is that it will occur. Engineering must try to control and then assure enough conservatism in the design that fabrication tolerances do not create significant problems.
  • Pipe has its limitations in age and usage. Pipe may corrode, erode, metallurgical characteristics may age; all of which will change its strength and flexibility characteristics.
  • Pipe supports springs can wear out, or fail due to overload, corrosion or other external factors.
  • Modifications have often been made to existing piping systems without sufficient consideration, and the result has been damaged pipe and an unreliable plant.

The specification is designed to introduce you to the basic concepts of piping engineering. By reading the specifications, manuals and codes you should know

  • The location of information on the design, engineering, fabrication and inspection of pipe.
  • Understand how to identify a piping system
  • Understand the basic loading conditions
  • Understand the basic failure modes
  • Identify the different types of pipe supports and their purposes
  • Understand the information required to perform a pipe stress analysis.

There are several basic principles that will be described and stressed throughout this course.

  1. Piping systems can and do fail. Engineering should always consider possible failure modes and work to avoid the possibility that the piping system will fail.
  2. Even in the best-engineered systems, there are assumptions built into the design. The engineer and designer should recognize these assumptions and allow appropriate allowances.
  3. Pipe stress analysis is only one portion of piping engineering. There are other major considerations before performing the stress analysis. If the preparation work has been done well, very few piping system designs will fail the pipe stress evaluation criteria.
  4. Because of the high number of possible loading conditions, and the numerous variations in components that make up a typical piping system, it is doubtful if the pipe stress is accurate by better than plus – minus 20%. Do not design to the limit of the pipe allowable stress unless there is a good understanding of the loading conditions and a strong quality assurance program.
  5. Pipe must always be viewed as a system from equipment to equipment, including branch lines, and pipe supports.
  6. As with all engineering design, understand the purpose and operation of the system before performing the detailed design.
  7. Pipe is an industrial plant must be maintained. It is commonly thought that properly engineered and installed pipe is “good forever” and can be left as is. The vast majority of pipe will operate successfully for decades, but some systems are known to be susceptible to damage and failure. Periodic inspections and repairs should be planned and performed on the appropriate piping systems to assure safe and reliable operation.

Typically a Piping & Instrumentation Diagram (P&ID) drawing sets the fundamental requirements showing the pipe size, schematic of the equipment connections and primary branch connections. This is considered the starting point for Piping Engineering.

Before routing and engineering the pipe, a design basis must be set. In this section the basic requirements are defined. Later sections describe some of the requirement details.


The design basis for any project should state the required design codes for materials and equipment. This is usually set by the client, and the engineer should review the requirements to assure they are complete and not contradictory. Local laws may require special requirements for hurricanes, earthquakes or other public safety issues.

The base rules for piping engineering are the ASME B31 Codes (herein referred to as the Codes). Each Code provides the typical loading conditions to be considered; allowable stresses; minimum wall thickness calculations; and minimum fabrication, inspection and testing requirements. Other major codes are listed that may apply in certain situations. This is not an all-inclusive list

Depending on the plant location and the type of facility, it may be legally mandatory to comply with ASME and other codes. Even if there is no legal requirement, the client, and insurance underwriters may require compliance/with ASME codes. And at a minimum, good engineering practices should be followed that are described in the Codes.

If a facility is outside the United States there may be a set of international Codes that are prescribed.

In most plants, one piping code applies to all piping systems, but sometimes it is not appropriate to take this approach. A petrochemical plant may be designed to B31.3, but there may be a power boiler supplying power, and that piping should be designed to B31.1 and parts may be designed to ASME Boiler & Pressure Vessel Code. Pipelines designed to B31.4 and B31.8 may change to B31.3 when brought out of the ground for a compressor station or processing facility.

In the history of the B31 Codes before the 1960’s, all facility pipes were covered by one code. As plants became larger and more complicated, the attributes of typical plants lead to different loading conditions, and different methods of defining safety factors. If all pipe rules had been left in one Code, it is likely that undue conservatism would have been applied to large numbers of pipe in order to create a Code that “One size fits all.” Some of the driving factors to different approaches include:

  • Power piping is focused on high pressure and high temperature water and steam with very few chemicals. The plants tend to be vertical, which creates high thermal vertical movements that must be accommodated by spring supports. Plants are usually away from residential areas and the potential for damage to nearby landowners is typically insignificant.
  • Petrochemical plants typically operate at much lower pressures and temperatures than power plants, but the various chemicals result in corrosion issues, and the use of many special alloy materials. These plants are also laid out horizontally with most pipe supports being rigid on pipe racks. Plants are often in large industrial areas. If there is a fire or explosion, there is always a concern in minimizing the damage to the local area of a plant or unit within a plant. Explosions may release hazardous chemicals in the air or in water, and thus mechanical integrity must always be a primary design criterion.
  • Pipelines are typically underground with no thermal considerations. The pipes are not put in bending at supports, and thus design rules allow thinner pipe for the same pressure compared to B31.1 and B31.3. Pipelines may be in unpopulated areas, or running through suburban and urban areas. Because of the potential for damage to nearby landowners, rules are different based on the pipe’s proximity to populated areas.

There are a number of similarities in each Code, such as in the calculation of minimum wall thickness, inspection and testing. But the exact rules are different, depending on the type of facility. Allowable stresses are different in each code, reflecting a different factor of safety based on the expected use and operation of the facility.

The Codes contain some rules and minimum standards, but for the most part, they provide guidance and items to consider. For example, B31.1, says the “Design shall consider seismic events” but it provides no methodology to perform the calculations, or even a design basis to create the seismic loads.

Since the Codes provide minimum acceptance levels based on simplified approaches, more rigorous analysis, inspection and testing methods can be applied when appropriate.

The Codes are design codes and are not intended for maintenance and operation of piping systems. In the past few years some non-mandatory appendices have been adopted concerning maintenance, and it is expected that maintenance and inspection guidelines will be added in coming years. See for example, B31.1, Appendix V, Recommended Practice for Operations, Maintenance and Modifications of Power Piping Systems. API has several Recommended Practices for inspection and evaluation of piping, such as API 570, 574, 579 and 580.

Once a Code has been selected to apply to a particular piping system, only that code should be applied. For example, it is not allowed to use a minimum wall thickness calculation from B31.3, an allowable stress value from B31.8, and an inspection method from B31.1. While it appears obvious that we cannot “cherry pick” the aspects we like from each Code, there are many times that the Codes are incomplete or give no guidance for certain conditions. In these situations it is appropriate to research other codes, technical papers and other published documents for guidelines to properly engineer the piping system. With this information, a rational engineering judgment can be made that is at least as conservative as the governing Code.

Other standards that are often referenced in piping engineering are:

The rules and guidance in the Codes and standards are based on experience, laboratory tests, theoretical stress analysis, and good engineering judgment. Those who practice piping engineering must understand the applications of the rules, and be cognizant of types of fabrication, loading conditions and other factors that need to be considered in each piping system.

As with most Codes, rules and guidelines, there is almost no method to adequately provide rules for all possible loading conditions, piping configurations and applications. Even the most experienced piping engineers must consider the loading conditions that could apply to each piping system to assure that everything reasonable has been done to assure “It is safe for you to stand next to that pipe.”


Defining the appropriate loading conditions to be applied to each piping system is often the most difficult portion of the work. As will be clear in the later discussions, the routing of the pipe and the types of pipe supports and other considerations are based on the loading conditions. It is imperative that the loading conditions to be considered and the magnitude be defined before starting the detailed design. Otherwise, detail design may be a waste of time, and may lock in design constraints that cannot be resolved.

The loading conditions can be split into two groups, static and dynamic. The static loads also have a transition loading as pipe moves from one condition to another, but in most cases, the transition loading is not separately considered, unless it is so rapid as to be a dynamic load. Dynamic loads may be design requirements, such as safety valve thrust, but they may also be conditions that need to be avoided by proper engineering of valve operating speeds, proper draining, fluid velocities or other considerations.

Static Loading:
  1. Temperature – may be multiple operating temperatures and temperature cycles.
  2. Pressure – may be standard operating pressure, upset condition pressures and design pressure
  3. Equipment Movements – typically related to the thermal movement of the pipe as the equipment heats up and cools down. Equipment movement must also be considered in wind and seismic loading conditions.
  4. Dead weight, to include pipe, fluid, in-line components, insulation, branch lines, pipe support attachments, and any other attachments.
  5. Wind – while this is technically a dynamic condition, it is usually analyzed as an “equivalent static” condition.
  6. Cyclic conditions created by “batch” operations in which a pipe may be alternately filled and emptied many times a day. Depending on the process, this may need to be considered a “static fatigue” such as thermal, or a Dynamic Loading Condition.
Dynamic Loading:
  1. Steam hammer created by sudden closure of valves creating pressure waves in the pipe. These are typically very fast acting valves at 0.5 to 0.05 seconds, installed to protect turbine generators from over speed conditions.
  2. Surge or pressure waves caused by opening or closing in-line valves. This condition is differentiated from steam hammer, as this situation is often in pipelines, or other long pipes in which it may take minutes to establish or stop flow. If the valves operate too quickly, large unbalanced pressure forces can create a “surge”.
  3. Thrust created by safety valve, rupture disk or other devices openings for pressure relief of a system.
  4. Water hammer or other condition created by two phase flow. There are multiple definitions of water hammer, but some of the worst conditions are created by high temperature steam suddenly impacting water in a pipe. The sudden flashing of water to steam can be so great that there is no practical way to design for the loads. The engineering solution is to avoid the possibility of such a situation.
  5. Thermal shock from rapid cooling or heating of a pipe surface. Again this situation should be avoided by proper design, as most materials will crack and fail from thermal shock.
  6. Seismic event
  7. Pipe whip created by sudden fracturing of a pipe. This is a nuclear power plant consideration and not discussed in this course.
  8. Various upset conditions that can be created by an out of control chemical reaction. The usual consideration is temporary high temperature and/or high pressure operation. Depending on the transition speed during the upset condition, this might be analyzed as a static loading condition.
  9. Various upset conditions that can be caused by loss of controls to valves and other devices that may cause a sudden fail close or fail open condition that can create the pressure waves and thermal shock conditions.
  10. Flow induced vibrations can be created by various sources. A reciprocating compressor discharge pipe must be specifically designed with “bottles” to dampen the

vibration. Other sources of vibrations can be pumps, cycling valves, batch operation or multiple sources of fluids that may be mixed together. Except for the reciprocating compressor issue, rarely are flow induced vibrations analyzed, but reliance is made of using appropriate “Rules of thumb for velocities in pipes. If problems are observed in the field, then remedial methods are used.


The interface between pipe and equipment is extremely important and must be properly managed throughout the design process.

  • Location, size and type of each nozzle on the equipment match the piping design.
  • Design conditions (temperature and pressure) are consistent with the pipe.
  • Safety valve set pressure is set to be consistent with the pipe operating conditions.
  • Equipment nozzle movements due to temperature can be accommodated by the pipe flexibility and supports.
  • Loads applied by the piping on the nozzles are acceptable to the equipment manufacturer.
  • If the equipment manufacturer insists on expansion joints at the nozzle, is the pipe routed, and the pipe supports arranged to make this acceptable?

Equipment manufacturers are primarily focused on producing a product that will do its job, i.e. a pump that creates the correct head and flow rate over the operating conditions, vessels that create the correct internal chemical reactions, etc. Pipe connections are necessary, but are not the vendor’s focus. Over the years, some manufacturers have developed standards that are so thoroughly focused on minimizing the loads from pipe, that it is almost impossible to meet the required loads. One of the best protections for proper piping engineering is to set reasonable allowable loads in the Request For Proposal for rotating equipment. Vendors can often accept higher loads safely, but they need to understand the requirement when the request for equipment is first made.

There is a second set of equipment requirements that is discussed in the Section, “System Approach”. Some vendors provide piping on a skid or as part of their equipment that connects to the remainder of the plant piping. The piping on the equipment must be considered as part of the piping system in all loading conditions. Depending on the situation, this can be a difficult process to manage technically, and contractually.


It is expected that a client that is paying millions or hundreds of millions of dollars for a plant has specific features that are desired. Most of these preferences are focused on equipment performance. However, there are often preferences on types of valves, plant arrangement, valve manufacturers, material specifications, corrosion allowance and even pipe supports.

The piping engineer should have a discussion with written direction on each of these preferences prior to starting design. Discussion should also focus on general approach to design, what the deliverable drawings will look like and contain, and specifics on all components. Keep these discussions going as detailed design decisions are made.

Often acceptable designs are considered unacceptable by the client because these preferences were not properly discussed and agreed to early in the process. Likewise, sometimes client preferences are based on an individual or group’s experience that has little to do with the current design. This leads to some dictates such as “No spring hangers”, “Install expansion joints on every pump suction and discharge nozzle”, or other requirements that waste client money, make the design very difficult to develop and actually make the design less safe. Sometimes clients will listen to logic, and sometimes they can adequately explain the reason for their preference, but sometimes long term client dissatisfaction with an engineer is created by such arbitrary rules.


The selection of the proper materials is a complex task that must occur before detail design begins. This is even more important now than in the past, since most major pipe is designed using 3D modeling techniques, and the model is specification driven.

These specifications may derive from client standards, a design engineering company’s standards, a previous project or even a standard industry database. No matter the source, it must be carefully checked to assure it matches the requirements for this particular project and service. Older specifications may be out of date due to changes in Code requirements, changes in valve manufacturer available models, and changes in standard available pipe sizes and fittings.

Some standards allow multiple choices for certain components, such as flanged or butt welded, socket welded or flanged, multiple choices for valves, and multiple choices for inspection and testing. It is strongly recommended that choices be limited before beginning design. If there are different requirements for different systems, create more material specifications. This reduces confusion at the design, engineering, material purchase, fabrication and construction steps in a project.

If there are critical chemical requirements that can create corrosion, assure a metallurgical specialist reviews the specifications in detail. Assure all components are reviewed, as the pipe may be correct, but if the wrong gasket is specified the pipe may still leak.

Method of pipe manufacture can be important in the long-term reliability of a system. In particular, seamless pipe is usually preferred over seam welded pipe for reliability and safety. When a seamless pipe fails at a circumferential weld, typically a crack opens up in one portion of the weld around the circumference. Usually, this opening relieves some of the stresses that are propagating the crack, limiting the opening size. Obviously this can still be a dangerous situation, but the leak is “limited”. In a seam welded pipe, if a crack develops in a seam weld, it can propagate the full length of the seam weld between circumferential welds. This is referred to as a “catastrophic failure” and results in a “nearly total, instantaneous release” of the contained fluid. Large diameter pipes are expensive to purchase in seamless configuration, and thus seam welded pipe is commonly supplied.


One issue that seems to continually cause confusion in material specifications is the design conditions, primarily the design and operating temperatures and pressures. Material specifications are typically split into classes based on type of material, pressure and temperature. It is common to see materials that indicate a group of materials are adequate from -20F to 600F up to 700 psig, and the next group of materials is satisfactory from -20F to 600F and 1200 psig. This is all very reasonable to minimize material costs as the largest possible group of standard materials is ordered.

However, there can be a serious misunderstanding when individual piping systems are considered. Table 2.1 shows three line numbers all designed to material specification A1. Each line has a completely different set of operating and upset conditions for design.

When engineering a system, the line design conditions should be used for analyzing for thermal conditions. Just because a material specification is satisfactory for all components at 600 psig @ 650F, does not mean that the piping system should be engineered for the maximum material specification temperature. If so designed, it would be a large waste of money in designing pipe and supports to conditions the piping system will never experience.

Unfortunately some practitioners have applied the material specification values in a line list for the operating and /or design conditions. This practice should not be done. When performing retrofit work, it needs to be recognized that the existing design and operating conditions on a line list may not represent the conditions the piping systems were engineered for.



In every piping system there are multiple potential failure modes. As noted initially, most piping systems operate decades with little or no damage. But of those systems that have failed, usually they have root cause(s) in which some basic fundamental issues were not adequately understood, considered, and/or designed for.

A special caution for plant modifications: A system that is modified needs to be completely reconsidered, even if only a small section of pipe is being replaced. The assumptions that may have been entirely appropriate for the original design may be violated by what is seemingly a minor change. Most petrochemical plants have a formal Management of Change (MOC) procedure to consider these issues. The procedure is extremely important. If an engineer is working on a plant without a formal MOC approval procedure, the engineer should assure that the entire piping system is still acceptable when a design or operational change is being made.

In other sections there are discussions of corrosion, thermal, pressure, and dynamic loading conditions that need to be evaluated. Some of the other failure modes that should be considered include:

  1. Velocities of fluid are extremely important in determining whether a piping system will erode. In fluid conditions, velocities of 15 feet per second in straight pipe, is a general standard. However, every change in direction, reducer or branch will locally accelerate the flow. Some major failures have occurred when multiple components were tied together, (a branch to a reducer to an elbow) and the pipe eroded when the local velocity was more than 3 times greater than expected. One of the industry solutions has been to use a hardened material, such as a chrome-moly alloy to reduce the erosion at locations that might be susceptible. Steam and gas velocities are usually an order of magnitude greater than fluid flow before any concern of erosion exists.
  2. Hardened pipe is often also specified on systems such as condensate drains in which two phase flow may be expected. This failure mode is often described as Flow Accelerated Corrosion (FAC) in which the corrosion layer is removed by locally high fluid velocity; the corrosion layer is re-established and then removed again by the fast moving fluid. Over time, the corrosion reestablishes and is then removed again, eventually creating very thin pipe in local areas around bends and branches.
  3. At low temperatures, embrittlement of normal steels can occur. Special low temperature alloys need to be specified.
  4. At high temperatures (above 800F for carbon steel and higher temperatures for certain alloys) creep damage can degrade the pipe. Creep is a time – stress – temperature dependent process that creates voids in the grain boundaries and has been the root cause of some of the worst piping failures in power plants.
  5. A special consideration for high temperature pipe. Catastrophic failures have occurred in seam welded high temperature pipes due to creep degradation, high stress intensification at the seam weld and other issues. Many studies have been performed by the Electric Power Research Institute (EPRI), Materials Properties Council (MPC), and other organizations, to determine the root causes of high temperature seam welded pipe failures. While knowledge and understanding has been advanced, there is not a set of exact root cause(s), and design recommendations have never been achieved. Large numbers of these pipes have been replaced with seamless pipe because the industry is not capable of guaranteeing the condition of seam welded pipe. Seam welded pipe should not be specified for installation in which it will be operating in the material’s creep range. The long term strength of the pipe cannot be adequately analyzed and assessed based on information available today. If seam welded pipe is used in such applications, Owner must understand that 100% inspection should be performed periodically over the life of the system.
  6. Embrittlement can also happen at high temperatures when hydrogen in the fluid travels in the grain boundary and creates hydrogen embrittlement. Depending on the material and fluid, this can happen at relatively low temperatures or high temperatures.
  7. Dissimilar metals welds can cause failure in piping systems. At times, it was common in the industry to install stainless steel thermowells and other components in carbon steel or alloy piping systems. As experience has found, any dissimilar metal weld that operates at elevated temperatures, can be susceptible to thermal cracking. Dissimilar metals may have different thermal expansion rates. Even on small welds, with time cracking may develop and installed components such as thermowells, have been known to “shoot out of the pipe.” Dissimilar metal welds can be safely made using the correct weld material and base materials, but they must be selected with care.
  8. Any component inserted into the flow has the potential to create vortices that can create vibrations and fail the component. This is called vortex shedding and improperly designed components can break off. One example is a thermowell inserted into the flow.
  9. Branch connections in high flow can also create vortex shedding at the opening. The result is often an audible “whistling” and can result in erosion of the nozzle, and ultimately failure. The design solutions usually are to reduce the flow rate locally in the area of the branch, and to round the contour so that there are no sharp edges.

All piping systems are engineered to transport a fluid or gas safely and reliably from one piece of equipment to another. The system may be easy to define as the pipe and supports from one pump to a tank or multiple pumps to multiple tanks. However, there are almost always other pipe branches in a system for drains, vents, safety relief, introduction of chemicals, extraction for other purposes, etc. It is also necessary to include all pipe supports in the definition of a piping system, as the design and functioning of these supports have a great deal to do with the reliability and safety of any piping system.

Sometimes system boundaries are confused by contractual limits. For example, if a skid mounted pump is supplied with several feet of pipe by the skid supplier, and a different engineer ties in to route the pipe to a tank, “What is the end of the piping system?” From an engineering perspective, the system is still from the pump to the tank. The coordination and political issues may be more difficult when multiple vendors are designing one piping system, but it is imperative that one entity have responsibility to assure the entire piping system has been engineered properly.


Fig. 3.1 depicts an even more complicated scenario in which a boiler and turbine vendor supply some of the pipe that is primarily engineered by the Balance of Plant Engineer. In these cases, both equipment pipes must be analyzed with the connecting pipe, and the pipe supports properly sized for the system.

A major consideration is how to consider branch connections on a piping system. A general rule of thumb is “Include all branches in the analysis if the ratio of the mainline section modulus to the branch line section is less than a factor of 7. The logic is that if the branch line is much smaller than the main line, then the small line cannot significantly affect the main line. One exception is if the small line is supported such that it restricts the movement of the main line.

The consideration of branch connections and equipment piping can be difficult when evaluating static loads. If dynamic loads are also significant, then the coordination and analysis issues are multiplied.

Sometimes it is impractical to include all of the piping system in one analysis because of the timing of the design and construction, the number of branch lines, or the complexity of multiple design conditions. A method that is commonly used is to install an anchor in a piping system. (See Section 6 for the definition of an anchor.) The pipe on either side of the anchor can be analyzed as totally separate systems. There are often advantages to this approach in limiting pipe movement, controlling the number of design conditions, and even in limiting pipe support loads and pipe stresses. If it is expected that future branch connections will be added later, it is a great benefit to locate an anchor on the pipe near this branch point. It will facilitate the future design and engineering.

If a support is included in the analysis, then it must be designed and installed in the piping system to match the analysis.

This rule seems so obvious that it should not need to be stated, but due to poor communication between piping engineers, designers and structural engineers, this fundamental rule has been violated an amazing number of times.



Depending on the normal service conditions, possible upset conditions, types of equipment it is connected to, and external sources, there are a number of possible pressure loading conditions that need to be considered, and the pipe engineered to contain the fluid safely and reliably.

Virtually every pipe must contain an internal or external pressure. Internal pressure is defined as,”The pressure inside the pipe is greater than the external pressure around the pipe.” This is the most common occurrence and the rules in the B31 codes are very specific on the rules for calculating minimum pipe wall thickness.

When pressure is applied to the inside of the pipe, there are two primary stresses created, Longitudinal Pressure Stress = Slp = P(D2- d2) /d2

Where P= Design Pressure

D= Outside Pipe Diameter, nominal d = Inside Pipe Diameter, nominal

S = Allowable Stress at design temperature

E = Quality factor based upon fabrication technique and /or inspection quality y = Design Factor for temperature

CA = Corrosion Allowance (Ref. B31.1, Section 102.3.2)

The other Codes have slightly different variations on this same equation.

Slp is the stress created attempting to pull the pipe along its length. As shown in Figure 4.1, the pipe is pulled apart along its length, and each of the formulas approximates the stress in the pipe along its axial direction.

An analogy that is often useful to consider is a fire hose. When the valve is opened the hose may jump and move violently on the ground as flow is established. This hose movement is caused by an unbalanced pressure force, in each length of the hose, as the flow is initiated. Once a steady state flow is established, the hose is stable as all pressure forces are balanced by the forces at all the other bends in the hose.

At the hose nozzle, there is a sudden pressure drop from the hose pressure to near atmospheric pressure, and the nozzle must be restrained or it will swing around in an unpredictable pattern.

This hose analogy will be used in discussing some of the dynamic loading conditions and expansion joints.


The second pressure stress is the Hoop Stress, which is created by the pressure expanding the pipe circumferentially. The hoop stress is approximately twice the longitudinal pressure stress. Except for ASME B31.8, the Codes do not specifically calculate the hoop stress. Instead it is included in the method to calculate the minimum wall thickness, tm.

tm = (P D/ 2 (SE+Py)) + CA

The equations again vary somewhat between the Codes, but the basic equation is similar.

These wall thickness and longitudinal pressure stress calculations appear straight forward, but there are important considerations.

Design Pressure may be set based on different criteria:

  • Set at the maximum expected operating pressure, or perhaps the operating pressure plus 3% to 10%. Most safety valves can be set at 3% to 10% accumulation and this factor matches the Design Pressure to the safety valve release pressure.
  • Set at the design pressure for a group of standard materials. For example, there may be a standard carbon steel material set up for all pipe operated up to 500 psig. While the operating pressure may be only 100 psi, the system design pressure may be 500 psi. This system makes the purchase and control of materials much easier than creating a different material specification for relatively minor changes in pressure.
  • There may be an upset condition that the pressure (and temperature) can temporarily spike above normal operation. Both B31.1 and B31.3 allow temporary loading conditions for minutes or even hours at these higher conditions. If the event pressure spike is small enough and short enough duration, then perhaps the design pressure does not have to be increased. But if either time or magnitude limits are exceeded, the design pressure must be increased to assure the pipe design meets Code requirements. Note that B31.4 and B31.8 do not have this temporary upset limitation.
  • Maximum pressure may be set by equipment limitations, such as the dead head pressure of a pump, or the maximum allowable pressure in an attached pressure vessel.
  • Maximum pressure may be set by in-line or attached equipment pressure limitations, such as the maximum allowable pressure on a valve.

Corrosion Allowance (CA) is often defined by the owner. CA should be based on the environment that can create external corrosion, and the fluid that may create internal corrosion and /or erosion. Typical values are 0.0” for superheated steam systems, to 1/32” to 1/8” for chemical systems.

External pressure on pipe exists on a small percentage of piping systems. In some cases the pipe may typically be subjected to external pressure, but an upset condition can create a vacuum that can collapse the pipe. None of the B31 Codes provide rules for calculating minimum wall thickness and reinforcement for this condition. Typically, thickness calculations are made by referring to the ASME Boiler and Pressure Vessel Code, Section VIII, Section ULT. This section defines calculations for pressure vessels subject to a vacuum pressure, and the equations can be adapted for pipes.


When a material is heated, it expands. B31.1 and B31.3 contain Tables in the Appendices that define the expansion rate for most metals. These are averages based on classes of materials. For most steels, a useful approximation is

Expansion in inches/ 100 feet of length = (Oper Temp – 100)/100.

For a pipe operating from an ambient temperature of 70F to an operating temperature of 1000F, a 100 foot length of pipe will lengthen approximately (1000-100)/100 = 9”, and a line operating at 500F would expand 4” over 100 feet. The more exact values provided in the codes should be used in any detailed calculations.

This thermal expansion is absorbed in the pipe by bending at elbows, branch connections, and other changes in pipe direction. The temperature differential creates pipe stresses that must be maintained within allowable limits, creates thermal loads on pipe supports, and creates loads on equipment. See Figure 4.2 for an example of movements in a piping system.


Pipe with any significant temperature difference from ambient should be routed with some changes in direction to relieve the pipe stresses. If pipe is routed straight, such as from a pump discharge to a tank wall, the axial stresses would probably be so excessive that cracks will develop in the tank wall connection, or overload the pump nozzles.

Thermal stress in the ASME codes is considered a fatigue stress and the allowable pipe stress is specified as a stress range. The change in stress at ambient temperature to the operating temperature is the stress range, and the allowable is based on the number of expected cycles.

This is the definition of a “Secondary Stress”, in which the pipe may self stress relieve due to thermal loading.

Most equipment manufacturers provide allowable loads on their nozzles that should not be exceeded without specific approval by the vendor. In most cases, the equipment allowable loads will be a more critical design factor than the stress range allowable in B31.1 and B31.3.

4.2.1 Cold Spring

ASME B31.1 refers to cold spring and it may be proposed by some people to solve a thermal expansion issue on pipe. Cold spring is the intentional cutting short of pipe lengths so that a load is induced on equipment in the ambient condition, and when the pipe heats up, the force and moment on the equipment nozzle is 0 pounds and 0 foot pounds. On the surface this sounds like a good idea, but most engineering companies do not allow the use of cold spring in the analysis and design for a number of reasons, as follows:

  1. The Codes compare calculated thermal pipe stresses to the range of stress. The calculated stress range does not change no matter how much cold spring is incorporated in a design.
  2. The theory is that by cutting each pipe length short, the loads on the equipment will be exactly countered by the thermal growth. This is a very simplistic view of the pipe, because there are usually rigid supports, spring supports, guides and other devices which affect the loads. To determine how to arrange each of these supports during erection and after final welding to achieve the goal of cold spring is virtually impossible.
  3. Even if objection 2 could be overcome, pipe is erected from equipment to equipment, and eventually all the cold spring is centered on one weld in which the pipe must be pulled together to make a weld. It is almost impossible to pull the pipe and create the loading comparable to the loads created in the thermal heat up and cool down.
  4. High temperature pipe will relax with time. After 3 or 4 cycles, the pipe will probably relax to a position similar to the theoretical cold pull position, without going through all that effort.
  5. Pipe fabrication and erection is an inexact process. Pipe fitters can and will adjust rotations at welds to make the pipe fit to the next weld. As usually happens, the fits are not perfect, and some pulling of the pipe is necessary. If the pull is minimal, then usually it is acceptable on the pipe stress and equipment loads, particularly if there is no cold spring. However, if a pull is already set for several inches, and then more pulling is necessary, the welding may have to be re-done because the pipe is too far out of tolerance.
4.2.2 Expansion Joints

It is somewhat common to hear requests from non-piping engineers to take care of all the thermal issues by “Just add some expansion joints.” Occasionally expansion joints are the most efficient solution, but that is only in specific cases. In general the use of expansion joints should be considered a last resort.

Expansion joints are thin convolutions of metal or cloth that are installed in a piping system to absorb the thermal movement, and sometimes to try to isolate equipment vibrations. Should an expansion joint fail, fluid is released, which can cause a shutdown, collateral damage and injury to personnel. While such failures can occur in hard piping, they are much rarer than in expansion joints.

But the main problem with expansion joints is the number of design issues and costs that are associated with them.

  1. Expansion joints must be limited to fairly low pressures, or else the pipe would literally pull apart at the expansion joint. There are some solutions described below, but the solutions tend to negate the effectiveness of the expansion joint.
  2. Tie-rods, gimbal joints and other devices can be installed across an expansion joint to transfer the pressure from one side of the joint to the other without damaging the expansion joint. However, with tie rods the expansion joint has no flexibility in the axial direction, only in the angular and lateral directions, which greatly limits its effectiveness to absorb pipe movements.
  3. If no tie rods are installed, then the pipe must be anchored, upstream and downstream to limit the axial growth of the pipe and keep the expansion joint from over expanding. Again, this limits its effectiveness to absorb movements.
  4. There are strict rules on guiding expansion joints upstream and downstream to avoid damage from over rotation and squirm. Again this limits its effectiveness.
  5. If expansion joints are designed with tie-rods and movement in all 3 directions must be absorbed, then often multiple joints must be installed.
  6. Cost of an expansion joint is high compared with pipe, and each expansion joint must be maintained and inspected. Life expectancy is at best 10 to 20 years.


Pipe weight is typically supported at point locations by either rigid or spring supports. The spacing of the supports should be based on criteria for sag, and for pipe stress. In most engineering companies and on the internet, support spacing tables are available based on the pipe size. In most cases, it is not clear what criteria for sag, insulation weight, pipe schedule, fluid weight and changes in pipe direction has been used to set the spacing, and thus any guidelines should be used only with caution. Some suggested pipe support spacing criteria that serve well in most cases.

  1. Set spacing based on a maximum of 0.1” sag between supports.
  2. Support all risers directly if greater than 15 feet in height.
  3. If risers are greater than 50 feet in height, add guides every 30 feet.
  4. Support all changes in directions such as elbows or bends within 3 pipe diameters of the end of a bend.
  5. Support every major in-line component within 5 pipe diameters. This rule applies to valves, and other heavy components.
  6. See Figure 4.4 for examples of special branch components that are unusually heavy and would create pipe sag without nearby supports.
  7. In line components such as the WYE and lateral in Fig. 4.4, elbows, reducers and specialty components may have high stress intensification. To minimize dead weight pipe stresses additional pipe supports are needed near these components.
  8. Support all pipe attached to rotating equipment (compressors, pumps, turbines) within 3 pipe diameters if at all possible. In most cases use a variable spring support at the first location off the rotating equipment. This approach minimizes the load on the equipment nozzles, usually a primary concern.

If a pipe stress analysis is performed, it is usually found that these criteria are conservative, and spacing can be expanded if supported by the analysis.


Dead weight pipe stresses and longitudinal pressure stresses are considered static primary stresses. That is, stresses due to dead weight do not self stress relieve as do thermal stresses. The calculated stress of the dead weight bending with longitudinal pressure stress is compared to an allowable stress that is a percentage of material yield stress.

Pipe stress evaluation is not included in this introduction, but a general caution needs to be very clear to all involved. A stress analysis will provide stresses, loads and deflections for any system. When the distance between supports is extended to very long spans, the piping system may be unstable, but the calculated loads and stresses may appear acceptable. In evaluating any dead weight analysis, the following results should always be checked

  1. Any conditions in which a pipe support is inactive. Load goes to 0 lbs or less. This most often occurs at rigid supports in which there is some thermal movement and the pipe tends to lift up off a support. The piping engineer needs to consider revisions to pipe support spacing, locations and types. It may be an indication that this support is not needed.
  2. If there are any horizontal movements due to dead weight only that are greater than 0.25”, it is a warning that the system is unstable, and additional supports and guides are needed. In virtually all the stress – strain formulas studied in textbooks, there is an assumption of small displacements. In the piping weight case, this limitation applies in the pipe stress analysis programs.
4.4 WIND

Wind on piping systems is generally not a serious problem. Recognizing that piping systems are outside and that wind can occur should lead to an automatic reaction that the pipe should be guided periodically for lateral loads created by the wind. Wind loading can be included in a pipe stress analysis program to assure that the supports are adequately sized for the expected loads.


When dynamic loads must be accounted for, the pipe support / restraint system becomes much more difficult to design, particularly if there are significant thermal movements. In general, dynamic loads are restrained by various types of rigid supports. Often it is difficult to locate rigid supports on high temperature systems, and hydraulic snubbers, limit stops or other types of restraints are used.

Pipe stress is sometimes a criterion for acceptance of dynamic loads, but because of the very short duration of the load, the loads on the restraints and the movement of the pipe are usually the controlling criteria.


Any type of pressure relief device is included in this discussion, to include safety valves, relief valves, safety relief valves and rupture disks. All of these devices are specifically designed to release the internal fluid suddenly when the pressure exceeds a pre-set level. These devices are extremely important in protecting personnel and equipment from an overpressure situation, no matter what the cause.

In considering safety valves forces it is useful to re-consider the fire hose analogy. There is typically no flow at the safety valve branch. The flow is “dead headed” against the valve. As the valve opens, flow is established and there is a short term unbalanced flow in the valve and the downstream pipe. At the discharge point there is a large pressure drop, and often a large pressure drop in the safety valve also. This pressure drop creates a thrust force that may last for several minutes.

Thrust forces can be calculated by standard flow formulas. Most safety valve manufacturers calculate the thrust if the pressure, temperature and flow rates are set. ASME B31.1, Appendix II provides a detailed calculation method that can be performed by hand.

For the Piping Engineer, once the proper safety valve has been selected, and the thrust calculated, the problem is to determine the proper support. Under normal operation, there is virtually no load on the safety valve and its discharge nozzle. However, when it opens, very high stresses may exist.

The most common arrangement is shown in Fig. 5.1. The safety valve discharges into an elbow, and then into an open vent stack to atmosphere. The discharge elbow and vent stack are independent of each other. (The dripping shown in the photo is welded to the discharge elbow.) The thrust force operates downward through the elbow, and tries to bend the safety valve branch off the pipe. Also, the pressure on the nozzle is at or greater than the pipe design pressure.

These nozzles should generally be integral to the pipe and re-enforced. In high pressure applications, the standard branch design is not acceptable and special nozzles need to be designed, analyzed and installed.


Assuring the nozzle will not fail (and they sometimes did in the 1960s and 1970s before the criteria was well understood) is only part of the solution. The thrust force is now pushing down on the pipe, often with as much or more load than the dead weight load. The pipe generally must be supported to assure it does not deflect too far and fail supports, or create a high pipe stress away from the nozzle due to the thrust.

If thermal pipe movements are minimal and structural steel is available, then a rigid support, or set of rigid supports, can be installed at or near the safety valve nozzle. However, if there is a large amount of vertical movement, and particularly if the movement is up from ambient to operating condition, then specially designed limit stops or snubbers are required to adequately support the thrust load.

The vent stack pipe must also be adequately supported. Typically this is not too difficult as the thrust loads are much less than in the safety valve discharge nozzle, and the vent stack is not attached to any equipment. Vent stack pipe is usually supported rigidly in at least one location, and guided in multiple locations to control any lateral movement.

The top of the vent stack is often chamfered at an angle. A straight cut would make a very distinctive set of natural frequencies and modes of this pipe, which can be excited when the flow is established. By chamfering the outlet nozzle, the natural frequencies are made less distinct and vibration is rarely an issue.


Engineering piping for earthquakes needs to be based on well thought out criteria and end goals. In the 1960s and 1970s, nuclear plants were being built and seismic considerations were a major factor in piping design. At the time, computer codes were not very sophisticated, and the seismic loading considerations were not well defined. Some of the nuclear seismic considerations were partially incorporated into fossil plants and even industrial plants. However, looking at these non-nuclear plants in hindsight, it is not clear what the goal was. Some major pipes are restrained, but other nearby pipes containing the same fluid, are not engineered for seismic events. Hydraulic snubbers must be maintained with hydraulic fluid and seal replacement to be operational. But many snubbers have obviously not been touched since installation.

Evans Goodling presented “Effects of Support Stiffness Variations on Seismic Inertia Stresses in Pipe” at the ASME1990 PV&P conference, (PVP Vol. 198), which brought a perspective to the entire seismic engineering situation. Some of the most important conclusions:

  1. In an earthquake, pipe generally sways and moves due to the excitations, and this is the most efficient method to dissipate the forces.
  2. Pipe in actual industrial applications, in the laboratory, and in detailed theoretical analysis does not fail due to earthquakes, except for the following exceptions:
  3. A branch line is rigidly supported near the main pipe, and the movement of the main pipe damages the branch pipe or its support.
  4. Loads on restraints are exceeded, damaging the restraints.
  5. Pipe is excited by the seismic event and moves into another pipe, steel or other piece of equipment that damages the plant.
  6. If seismic engineering is to be performed on piping, then the only two significant criteria are pipe movement and support loads. /

If a plant is about to be designed, then the consideration of seismic must be considered per the Codes. Seismic analysis does not have to be performed if there is a rational consideration of the risks. Some of the questions that should be asked as the design basis is being developed are:


Steam hammer is a term used to describe a pressure wave created in a steam pipe when valves are suddenly shut to protect a piece of equipment. Steam hammer is typically analyzed in large steam turbine electrical generating plants. If there is a sudden loss of load on the generator end of a turbine generator, very quickly an over speed condition can occur that literally tears the turbine – generator apart. To protect the equipment, large, very fast acting valves are installed on the steam inlet pipes. These valves may go from full open to fully closed, in 0.05 seconds. Any closing speed faster than 0.5 seconds should be analyzed for steam hammer loads.

Since the boiler cannot possibly be shut down this fast, there is a pressure wave from the turbine back to the boiler and a partial reflection wave from the boiler back towards the turbine.

Dynamic loads on large power plant piping may be greater than 50,000 lbs, and these loads are created on every leg of the pipe as the pressure wave moves through. Since the pressure wave has a finite length, and thus a specific unbalanced pressure force, the forces are greatest on long lengths of pipe, and relatively insignificant on short lengths.

With today’s computer models, a time history dynamic analysis can usually be performed to assess the displacements and support loads. Pipe stress is not a significant concern as the entire event may last 1 to 2 seconds. As with seismic, careful selection of support locations and restraint types can minimize the cost of restraining the pipe.


Water hammer is a term used to describe several different flow – induced dynamic events. Almost all of these phenomena need to be avoided by proper pipe sizing, proper draining, correct valve sizing and valve speeds, and proper operation and maintenance.

For purposes of this course, the most serious water hammer is when a line contains water and is suddenly impacted by superheated steam. The flashing of steam to water can create a pressure wave of several hundred thousand pounds, move the pipe several feet and damage every support in a piping system. The solution is generally to assure no undrainable low points in a system, and to assure proper operation to open drain valves during startup and shutdown operations.

This is also why on steam piping; designers usually build in a constant 1/16” to 1/8” per foot slope on all horizontal pipe legs.


Surge is crated by the startup or shutdown of a liquid system. The forces are dependent on the pressure, length of pipe, and the acceleration of the fluid. The practical consideration is usually long pipelines, and the best solution is to intentionally limit valve opening and closings to very slow openings, perhaps several minutes from fully closed to fully open.


Thermal shock is the sudden heating or cooling of metal. The sudden change in temperature can create a significant difference in the outside and inside temperature of a component, and thermal cracking. On large heavy wall components, such as boiler headers, large compressors and turbines there should be a limitation on the speed of heat up and cool down. If this is adhered to, then most pipes will not be harmed.

One other typical problem that must be avoided is the introduction of cold fluid in an existing operating system. This is sometimes done intentionally at a desuperheater (or attemperator), in which water is introduced into a superheated steam line to reduce the downstream temperature. If the fluid is properly atomized in a few feet, then the pipe is not damaged. However, if full atomization is not achieved, then the downstream pipe is susceptible to damage. Any systems of this type need to be carefully engineered for all expected operating conditions to assure thermal shocking can not occur.


There are a number of typical pipe supports that can be installed to support dead weight loads, and restrain the pipe for thermal and dynamic loads. While some typical supports are shown in these pictures, the designs are only limited by the imagination of the engineer and designer, as literally thousands of different designs have been used for special purposes.

There is often confusion created by mis-communication about types of supports between engineers, designers and the field. Following are the proper definitions that should be used. If there is any confusion in communication, assure that each person is thinking the same type of support when the term hanger, spring, anchor, etc is used.

Pipe support: Global classification of all pipe supports and restraints.

Hanger: A vertical pipe support that incorporates a rod. It may be a rigid, variable spring or constant support hanger. Hanger is a term that often means quite different things to different people.

Variable spring support: Often called a variable spring hanger (VSH) by the suppliers. A helical coil that supports dead weight load. The support load changes as the spring moves through its range at a specified spring rate. This support can be a hanger above the pipe, or a floor support below the pipe.

Constant support hanger: A specially engineered hanger that is designed to travel through many inches of vertical travel with a minimal change in support load. There are different styles and types depending on the manufacturers. Per MSS SP-58 a constant support hanger can be within specification and still have a load variation of plus minus 6% through the travel range.

Some suppliers claim a tighter tolerance on the load variation.

Rigid: Any type of support designed to allow no movement in at least one direction.

Rigid hanger: A hanger with a rod support.

Anchor: A rigid support that restricts movement in all three orthogonal directions and all three rotational directions. This usually is a welded stanchion that is welded or bolted to steel or concrete.

Axial restraint: A support designed to restrict movement down the centerline of the pipe. This is usually reserved to reference a horizontal pipe restraint.

Lateral Restraint (synonymous with Guide): A support designed to restrict movement of the pipe in a direction perpendicular to the pipe axis.

Hydraulic Snubber: A support with a piston and hydraulic reservoir designed to restrict dynamic movement, but allows nearly free movement due to thermal loads.

Mechanical Snubber: A support designed to restrict dynamic pipe movement by a mechanical device internal to the snubber. Mechanical snubbers were prone to failure that restricted pipe movement, and they are rarely found in use anymore.

Sway Brace: A variable spring designed to have no load in the center of the springs and restricts movement in either direction from the spring centerline.

Limit Stop: A restraint in any direction that allows a defined movement before acting as a rigid restraint.

Stanchion: A pipe support made of pipe that is welded to the pipe to be supported. Usually installed below a horizontal pipe.

Dummy Leg: A stanchion support attached to an elbow on a horizontal pipe. Commonly used on pipe in pipe racks to extend the support point to existing rack steel.

There are a myriad of methods of combining supports, such as a dummy leg with a rigid rod hanger, or an axial limit stop with a lateral restraint, etc.

As noted previously, whatever supports are assumed in an analysis, they must be included in the actual design.

Variable spring hangers, constant support hangers and hydraulic snubbers are all shipped with travel stops (or shipping plug for a hydraulic snubber). These stops and plugs are necessary for shipment and ease of installation. The supports are pre-set at the specified ambient condition displacement. After installation of the pipe, these stops and plugs must be removed before operation. If travel stops are not removed, the support acts as a rigid support, and does not function as designed. After removal, the travel stops should be safely tied down and saved at the pipe supports for possible later use. They are helpful if the pipe or supports are ever repaired, in the case of re-hydrotest, or other unusual situations.



Pipe stress analysis is a topic that requires its own training program. This section provides some limited considerations, and a checklist of the information that is needed for a complete analysis.

When starting the design of a plant, there may be a number of layout considerations, and in some cases the routing of the large diameter pipe may be a major limitation. In these cases, some preliminary analyses may be performed based on very conservative criteria to identify the best routing of the pipe. Conservative criterion is needed to assure that detailed design does not create changes that make the original routing unacceptable.

As the detailed design is developed, the analysis needs to be refined until it matches the actual design of the pipe. It is entirely appropriate to “optimize” the system by analysis, trying various routings and support configurations. The degree of optimization required is dependent on the complexity of the loading conditions and routing, the cost of the installed pipe, and the need to minimize operating and maintenance costs.

Less critical systems may be completely designed with design “rules of thumb” and the analysis is performed to confirm the detail design is acceptable.

As implied throughout this course, pipe stress results need to be evaluated based on allowable stresses, allowable equipment loads, reasonable pipe support loads, and pipe displacement for all loading conditions.

Pipe stress analysis results are only approximate models compared to actual installed systems. The great variety in components, materials, fabrication and supports leads to this inherent inaccuracy. For this reason, it is always recommended to be conservative in evaluating pipe stresses and movements. If a small increase in pipe stress would cause an excessive stress, or a small increase in loads would over load a nozzle, if at all possible, it is best to make modifications to increase the safety margin.

See Table 7.1 for a list of information that a Piping Engineer needs for a final detailed analysis. Preliminary analyses can be made with assumed data, when appropriate.



Piping Engineering in industrial plants requires solutions to a complex set of problems. A thorough understanding of the design conditions is required to start a detailed design. Client preferences, industry standards, standard material tolerances, expected operating procedures and expected maintenance procedures should be included in engineering considerations.

While the overall goal of Piping Engineering is

“To assure the installed pipe will perform reliably and safely in all expected conditions for its design life”

In the final analysis, the piping engineer and those working on the engineering team at any engineering Company should always be thinking,


Our professional piping stress engineers have a bachelor’s degree in mechanical / structural engineering and province licence (P.Eng.) in Alberta, Saskatchewan, British Columbia and Ontario. We review, validate, certify and stamp piping and structural packages.

We offer the most affordable on a timely manner


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Introduction to Pipe Stress Analysis

1.0 Introduction to Pipe Stress Analysis

In order to properly design a piping system, the engineer must understand both a system’s behavior under potential loadings, as well as the regulatory requirements imposed upon it by the governing codes.

A system’s behavior can be quantified through the aggregate values of numerous physical parameters, such as accelerations, velocities, displacements, internal forces and moments, stresses, and external reactions developed under applied loads. Allowable values for each of these parameters are set after review of the appropriate failure criteria for the system. System response and failure criteria are dependent on the type of loadings, which can be classified by various distinctions, such as primary vs. secondary, sustained vs. occasional, or static vs. dynamic.

The ASME/ANSIB31 piping codes are the result of approximately 8 decades of work by the American Society of Mechanical Engineers and the American National Standards Institute (formerly American Standards Association) aimed at the codification of design and engineering standards for piping systems. The B31 pressure piping codes (and their successors, such as the ASME Boiler and Pressure Vessel Section III nuclear piping codes) prescribe minimum design, materials, fabrication, assembly, erection, test, and inspection requirements for piping systems intended for use in power, petrochemical/refinery, fuel gas, gas transmission, and nuclear applications.

Due to the extensive calculations required during the analysis of a piping system, this field of engineering provides a natural application for computerized calculations, especially during the last two to three decades. The proliferation of easy-to-use pipe stress software has had a two-fold effect: first, it has taken pipe stress analysis out of the hands of the highly-paid specialists and made it accessible to the engineering generalist, but likewise it has made everyone, even those with inadequate piping backgrounds, capable of turning out official-looking results.

The intention of this course is to provide the appropriate background for engineers entering the world of pipe stress analysis. The course concentrates on the design requirements (particularly from a stress analysis point of view) of the codes, as well as the techniques to be applied in order to satisfy those requirements. Although the course is taught using the CAESAR II Pipe Stress Analysis Software, the skills learned here are directly applicable to any means of pipe stress analysis, whether the engineer uses a competing software program or even manual calculational methods.

Why do we Perform Pipe Stress Analysis?

There are a number of reasons for performing stress analysis on a piping system. A few of these follow:

  1. In order to keep stresses in the pipe and fittings within code allowable levels.
  2. In order to keep nozzle loadings on attached equipment within allowables of manufacturers or recognized standards (NEMA SM23, API 610, API 617, etc.).
  3. In order to keep vessel stresses at piping connections within ASME Section VIII allowable levels.
  4. In order to calculate design loads for sizing supports and restraints.
  5. In order to determine piping displacements for interference checks.
  6. In order to solve dynamic problems in piping, such as those due to mechanical vibration, acoustic vibration, fluid hammer, pulsation, transient flow, and relief valve discharge.
  7. In order to help optimize piping design.

Typical Pipe Stress Documentation

Documentation typically associated with stress analysis problems consists of the stress isometric, the stress analysis input echo, and the stress analysis results output. Examples of these documents are shown in Figures 1-1 through 1-5 on subsequent pages.

The stress isometric (Figure 1-1) is a sketch, drawn in an isometric coordinate system, which gives the viewer a rough 3-D idea of the piping system. The stress isometric often summarizes the piping design data, as gathered from other documents, such as the line list, piping specification, piping drawing, Appendix A (Figure 1-2) of the applicable piping code, etc. Design data typically required in order to do pipe stress analysis consists of pipe materials and sizes; operating parameters, such as temperature, pressure, and fluid contents; code stress allowables; and loading parameters, such as insulation weight, external equipment movements, and wind and earthquake criteria.

Points of interest on the stress isometric are identified by node points. Node points are required at any location where it is necessary to provide information to, or obtain information from, the pipe stress software. Typically, node points are located as required in order to:

  1. define geometry (system start, end, direction changes, intersection, etc.)
  2. note changes in operating conditions (system start, isolation or pressure reduction valves, etc.)
  3. define element stiffness parameters (changes in pipe cross section or material, rigid elements, or expansion joints)
  4. designate boundary conditions (restraints and imposed displacements)
  5. specify mass points (for refinement of dynamic model)
  6. note loading conditions (insulation weight, imposed forces, response spectra, earthquake g-factors, wind exposure, snow, etc.)
  7. retrieve information from the stress analysis (stresses at piping mid spans, displacements at wall penetrations, etc.)

The input echo (Figure 1-3) provides more detailed information on the system, and is meant to be used by the pipe stress engineer in conjunction with the stress isometric.

The analysis output provides results, such as displacements, internal forces and moments, stresses, and restraint loadings at each node point of the pipe, acting under the specified loading conditions. CAESAR II provides results in either graphic or text format; Figures 1-4 and 1-5 present stress and displacement results graphically. The output also provides a code check calculation for the appropriate piping code, from which the analyst can determine which locations are over stressed.

stress isometric
ASME B31.3 & ASME B31.1 Appendix A
CAESAR II input echo
CAESAR II stress and displacement result

What are these Stresses?

The stresses calculated are not necessarily real stresses (such as could be measured by a strain gauge, for example), but are rather “code” stresses. Code stress calculations are based upon specific equations, which are the result of 8 decades of compromise and simplification. The calculations reflect:

  1. Inclusion or exclusion of piping loads, based upon convenience of calculation or selected failure. In fact the result may not even represent an absolute stress value, but rather a RANGE of values.
  2. Loading type — these are segregated, and analyzed separately, as though they occur in isolation, even though they actually are present simultaneously.
  3. Magnification, due to local fitting configuration, which may in reality reflect a decrease in fatigue strength, rather than an increase in actual stress.
  4. Code committee tradition — every code is a result of a different set of concerns and compromises, and therefore may appear to be on a different branch of the evolutionary ladder. Because of this, every code gives different results when calculating stresses.

A summary of significant dates in the history of the development of the piping codes is presented below:

1915 – Power Piping Society provides the first national code for pressure piping.

1926 – The American Standards Association initiates project B31 to govern pressure piping. 1955 – Markl publishes his paper “Piping Flexibility Analysis”, introducing piping analysis methods based on the “stress range”. 1957 – First computerized analysis of piping systems. 1968 – Congress enacts the Natural Pipeline Safety Act, establishing CFR192, which will in time replace B31.8 for gas pipeline transportation. 1969 – Introduction of ANSI B31.7 code for Nuclear power plant piping. 1971 – Introduction of ASME Section III for Nuclear power plant piping. 1974 – Winter Addenda B31.1 moves away from the separation of bending and torsional moment terms in the stress calculations and alters the intensification factor for moments on the branch leg of intersections. 1978 – ANSI B31.7 is withdrawn. 1987 – Welding Research Council Bulletin 330 recommends changes to the B31.1, B31.3, and ASME III Class 2 and 3 piping codes.


Pipe Stress Analysis Notes

1.0 Introduction to Pipe Stress Analysis

1.1 Theory and Development of Pipe Stress Requirements

1.1.1 Basic Stress Concepts

1.1.2 3-D State of Stress in the Pipe Wall

1.1.3 Failure Theories

1.1.4 Maximum Stress Intensity Criterion

1.2 Fatigue Failure

1.2.1 Fatigue Basics

1.2.2 Fatigue Curves

1.2.3 Effect of Fatigue on Piping

1.2.4 Cyclic Reduction Factor

1.2.5 Effect of Sustained Loads on Fatigue Strength

1.3 Stress Intensification Factors

1.4 Welding Research Council Bulletin

1.5 Code Compliance

1.5.1 Primary vs. Secondary Loads

1.5.2 Code Stress Equations

1.5.3 B31.1 Power Piping

1.5.4 B31.3 Chemical Plant and Petroleum Refinery Piping

1.5.5 ASME Section III, Subsections NC & ND (Nuclear Class 2 & 3)

1.5.6 B31.4 Fuel Gas Piping

1.5.7 B31.8 Gas Transmission and Distribution Piping Code

1.5.8 Canadian Z183/Z184 Oil/Gas Pipeline Systems

1.5.9 RCC-MC

1.5.10 Stoomwezen

1.5.11 Special Considerations of Code Compliance

1.5.12 Evaluation of Multiple Expansion Range Cases


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Pipeline & Piping Engineering Services across Canada (Alberta, Ontario, British Columbia)

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Pipeline Engineering Services & Piping Engineering Services across Canada (Alberta, Ontario, British Columbia, Saskatchewan). the best engineering company. the best engineering firm. by meena rezkallah, p.eng. Located in Calgary Alberta, We offer our Piping Engineering Services, Skid Design Services, Pipeline Engineering Services and Structural Engineering Services across Canada. To get our Piping Stress Analysis Services, please contact our Engineering company.  Our professional piping stress engineers have a bachelor's and Masters degree in mechanical / structural engineering and province license (P.Eng.) in Alberta, Saskatchewan, British Columbia and Ontario. We review, validate, certify and stamp piping and structural packages. Also check Industries We Serve.

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Meena Development LTD. Consulting Engineers has been servicing Clients in:

With our sophisticated and in depth of experience in piping stress analysis and pipe lines design as per ASME B31.1, ASME B31.3, ASME B31.8 and CSA Z662, Meena Development LTD. is an industry leader in piping stress analysis and piping design having provided many thousands of hours of successful service for our Clients. Our Consulting Engineers pride themselves on their piping stress / flexibility analysis, green & brown fields piping design and project management expertise.

Meena Development LTD. strives to keep up with the ever improving technology of our industry and in doing so ensures that our Clients receive the most efficient service, tailored to their specific needs and always taking great care to keep to time sensitive deadlines.

Thanks to a highly proficient team, Meena Development LTD. is able to offer expert advice and assistance in mechanical engineering and project management. Furthermore, Meena Development LTD. is able to provide services which include Structural and Civil Engineering, Electrical and Instrumentation Engineering as well as Tank and Vessel Engineering using our team of expert professional Engineers.

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Our engineers are expertly trained in piping stress analysis using the latest CAESAR II software by Intergraph. This is used for existing and new piping systems; for systems with high temperatures and pressures as well as systems with sub-zero temperatures and those which require exotic materials. Their experience in stress and piping flexibility analysis has enabled Meena Development LTD. to resolve vibrating piping systems, under-supported and over spanned piping systems and overstressed pipelines in numerous different applications.

Utilizing output results from the CAESAR II calculations, Meena Development LTD. can design special supports where required in order to sufficiently mitigate piping system vibrations ensuring no damage is caused to connected equipment and surrounding structures as well as confirm that loads on equipment nozzles are within allowable code limits.


Meena Development LTD. has conducted new and “as-built” designs for large numbers of piping spring supports and expansion bellows for a variety of different Clients.

Comprising of detailed as-built surveys to technical datasheets, Meena Development LTD. will spec the correct spring support or expansion bellow for your application.


A team of highly experienced piping designers carry out all green and brown fields design and drawing work at Meena Development LTD. Consulting Engineers.

With their incredible experience, Meena Development LTD. is able to offer engineering solutions for multiple scenarios.

Development of basic & detailed Engineering packages for complete piping installations, Meena Development LTD. will ensure that all your piping needs are met.

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Our professional piping stress engineers and Structural Engineers have a bachelor’s and Masters degree in mechanical / structural engineering and province license (P.Eng.) in Alberta, Saskatchewan, British Columbia and Ontario. We review, validate, certify and stamp piping and structural packages. Also check Industries We Serve.


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Structural / Piping Engineering Company across Canada (Alberta, Ontario, British Columbia, Saskatchewan)

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Meena Development LTD. offers design, maintenance, and troubleshooting engineering services to chemical plants, refineries, utilities, water processing and purification facilities, paper mills, energy and power generation, steel mills etc. Our services focus on structural and mechanical engineering of piping, plant and vessels. We provide quick response, quality engineering, at economical prices.

We understand that a plant’s or piping system goal is to produce quality products at market prices, in a safe manner. To achieve these goals, low maintenance and high reliability of piping and equipment is essential. For these reasons, it is important that piping, plants and vessels be designed, maintained, and repaired according to applicable codes and standards. We provide engineering services to help your facility comply with ASME, API, NEMA, CSA, and other codes and standards.

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At Meena Development LTD., Pipe stress analysis is an analytical method to determine how a Plant or Piping system behaves based on its material, pressure, temperature, fluid, and support either above ground or underground.

This analysis calculates piping stresses resulting from thermal cycles, pipe and fitting weights and static pressure for the main process piping. Generally, we evaluates stress due to thermal cycles, weight, and static pressures in the piping as per all industry piping codes, such as B31.3, B31.8, CSA Z662, BS826, BS7159, FDBR, DNV and others.

We calculate loads on equipment (e.g., piping’s, vessels, coolers, pumps, and compressors) and make recommendations to meet up with industry standards.

  • Simulate Operational Plant and Piping Vibration Pattern and deflections
  • Recommends pipe layout, pipe support, and clamp designs and lots more.

Vibration-induced fatigue, pipe stress, transient events and small-bore connections are high-risk areas requiring our engineering support.

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In every process industry, there is a significant part of the piping system which runs underground. Oil and gas pipelines are buried in the ground for 360-degree protection and support. However, buried or underground piping is generally used to carry fluids for long miles.

These buried pipelines experience a significant load because of relative ground displacements along their length. Piping stress analysis offers a helping hand for underground piping to address the static as well as dynamic loading, which results from the temperature changes, effects of gravity, internal and external pressures. This stress analysis ensures the safety of piping, piping components, connected equipment and supporting structure.

At Meena Development Engineering Services, we help you perform a full analysis of your buried pipes.

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Our Structural engineers are mainly civil engineers. At Meena Development Engineering Services, our engineers are trained to understand, predict, and calculate the stability, strength and rigidity of built structures for buildings and non-building structures. To develop, designs and integrate their designs with that of other designers, and to supervise construction of projects on site. They are also involved in the design of machinery medical equipment and vehicles where structural integrity affects functioning and safety.

At Meena Development Engineering Services, our theory is based upon applied physical laws and empirical knowledge of the structural performance of different materials and geometrics. We utilize a number of relatively simple structural elements to build complex structural system. Our structural engineers are responsible for making creative and efficient use of funds, structural elements and material to achieve these goals.

At Meena Development Engineering and consultancy services, the satisfaction of our clients and integrity of their asset is our business.

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Please contact us to discuss any structural, piping, plant or vessel issues. Advice is free and we can usually provide estimated engineering costs with information provided over the telephone.


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Meena Development LTD. is an indigenous service company with the necessary permits to operate within the Oil and Gas Industry for engineering design services, procurement, training and development, manpower services, subsea engineering, pipelines, and other industries we serve such as Water and Wastewater Industry, Chemicals and Plastics Industry, Pulp & Paper Industry, Facility Services, Energy and Power Generation Industry and Steel and Metals Industry.

Established by professional engineers with the vision and genuine desire for excellence, the company has successfully based its business philosophy on providing its clients with the highest degree of quality, professionalism and integrity in all aspects of its operations.

Meena Development LTD. is a Canadian indigenous company, poised to be Canada’s main hub for Onshore and Offshore Piping Stress Engineering Services with other main focus in Piping Layout, Mechanical Design, Subsea Engineering, FEA, Pipeline and numerous engineering trainings for local capacity development.

Piping Stress Analysis And Supports

Meena Development LTD. offers comprehensive and code compliant pipe stress analysis of piping systems; from simple pipe routing to complex piping systems like compressor piping, FPSO topsides piping and buried pipeline systems.

We offer both static and dynamic pipe stress analysis. Our seasoned engineers are very proficient in the use of Caesar II, AutoPipe and FEPipe among others for delivering on our clients’ demands.

As a one-stop-shop, Meena Development LTD. completes your piping design with our pipe supports capabilities; we design, select and specify the most suitable pipe supports systems for your piping systems, we also perform system design and selection of spring supports (variable and constant).

Some of the deliverables include;

  • Critical Line List for Stress Analysis
  • Specifications for Stress Analysis and Supports
  • Comprehensive Stress Analysis Reports (Code Compliant Check, Pipe Restraints Loads, Equipment Nozzle Loads Verification, Flange Leakage Checks etc)
  • Dynamic Modal Analysis Checks
  • Stress Isometrics with detailed support types and locations.
  • Pipe Support MTO, Pipe Support Index and Pipe Support Standards Details Drawing

Piping Stress Analysis And Supports OF GRE/GRP/FRP PIPING SYSTEM

Pressure piping made from GRE is becoming increasingly popular due to its high corrosion resistance and high strength to weight ratio. This development is driven by the need for lighter and more corrosion resistant components. Our experienced team have demonstrated the capability – as the first indigenous company – to carry out Stress Analysis and Support of GRE/GRP/FRP Piping System (Firewater, Potable Water, Open and Close Drain Systems etc) governed by ISO 14692 which is a development of UKOOA document.

The GRE/GRP/FRP Piping System Load Cases such as expansion (EXP), sustained (SUS) and occasional (OCC) are defined by using ASME B31.3 and CSA Z662 methods while BS7159 methods are used to define that of System Design Parameters such as SIF, flexibility factors, pressure stress multipliers.

In order to maintain the integrity of GRE/GRP/FRP process piping systems and pipelines, stress analysis should be performed to ensure that the system can sustain all stresses and deformations requirements regarding the following factors:

  • Pipe work flexibility
  • Layout complexity
  • Pipe supports
  • Pipe work diameter
  • Magnitude of temperature changes
  • System criticality and failure risk assessment

We at Meena Development LTD. therefore evaluate the total piping system in order to specify any need of flexibility/stress analysis. Different loading conditions such as internal or external pressure, thermal, occasional and support loadings are determined, and then the related stresses and loads are evaluated and finally compared with the corresponding allowable stresses and loads respectively.

During analysis of GRE/GRP/FRP system, special considerations are given to the stress values in axial and hoop directions as the material being orthotropic.

As a one-stop-shop, Meena Development LTD. completes your piping design with our pipe supports capabilities; we design, select and specify the most suitable pipe supports systems for the GRE/GRP/FRP piping systems, we also perform system design and selection of spring supports (variable and constant).

Some of the deliverables include;

  • Critical Line List for Stress Analysis
  • Piping Specifications, Stress Analysis and Supports for GRE/GRP/FRP pipes, fittings and flanges.
  • Comprehensive Stress Analysis Reports (Code Compliant Check, Pipe Restraints Loads, Equipment Nozzle Loads Verification, Flange Leakage Checks etc)
  • Dynamic Modal Analysis Checks
  • Stress Isometrics with detailed support types and locations.
  • Pipe Support MTO
  • Pipe Support Index
  • Pipe Support Standard Details Drawing

Piping Design, Engineering And Layout

At Meena Development LTD., our services are complemented by our experienced Piping and Layout associates. We understand our clients’ requirements for an excellently designed plant layout with considerations for salient features like HFE, safety and maintainability. We provide such quality deliveries according to the clients’ scopes, requirements and global best practices (codes and standards) having considerations for saving time, low cost and safety in design.

So at Meena Development LTD., our Piping and Layout Engineers are never far away from providing excellent and well optimized solutions to all Piping and Layout Engineering Services in brown and green field projects on onshore, swamp, shallow water and deep offshore terrains.

We offer services such as;

  • 3D Equipment modeling
  • 3D pipe routing
  • 2D extracts and drafting of Equipment Layout, Piping GA, Plot and Key Plans, Isometrics, Emergency and Escape Routes, Elevation Drawings.
  • Piping Material Class (materials selections and specifications).
  • Valve data sheets, MTO’s, Tie-in List, Line lists.
  • Pipe Support MTO, Support Index and Support Standards Details Drawing.
  • Pressure design of piping components, line sizing and support design.
  • Navigations and HFE review in 3D Model using review software like NavisWorks.
  • Mechanical Handling System.
  • POS, RFQ and TBE for all the piping items.
  • Preparation and reviewing piping documents and deliverables (SP Items, Piping Philosophies etc).

Having worked on several world class projects of varying scopes, cost, clients, challenges and environments, our Engineers are very experienced in the use of the following software for Piping Engineering and Design;

  • AutoCAD
  • Microstation
  • PDS
  • PDMS
  • SP3D
  • E3D
  • SP P&ID
  • AutoPlant
  • CADWorx
  • Navisworks
  • WalkInside

Mechanical Design (Static And Rotating Equipment)

The engineering design of Mechanical static and rotating equipment is as critical as the design of the piping systems that connects to them. At Meena Development LTD., our engineers are well experienced in the code compliant design of ASME Pressure Vessels, Heat Exchanger design (Shell and Tube, Plate & Frame, and Air-cooled), Tanks, Boilers, API Pumps and Gas Compressors. They are very proficient in the use of PVElite, AmeTank, HTRI, and other relevant mechanical engineering software.

We have expertise to design mechanical equipment to comply with codes and standards requirements, clients’ specifications and any statutory requirement. We also prepare requisitions, quotations and technical bids for the equipment.

Located in Calgary Alberta, We offer our Piping Stress Analysis Services and Structural Engineering Services across Canada.

Our structural Engineers / piping stress engineers have a bachelor’s and Master’s degree in mechanical / structural engineering and province license (P.Eng.) in Alberta, Saskatchewan, British Columbia and Ontario. We review, validate, certify and stamp piping and structural packages.


Engineering Consultant Services Calgary, AB

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Engineering Consultant Services Fort McMurray, AB

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CAESAR II Pipe Stress Analysis Services Engineering Company

CAESAR II Pipe Stress Analysis Services Engineering Company

CAESAR II Pipe Stress Analysis Services Engineering Company served by meena rezkallah, p.eng. the best piping stress engineer and structural engineer across canada (alberta, ontario, british columbia, saskatchewan)

We are the best Piping Stress Analysis Services across Canada (Alberta, Ontario, British Columbia, Saskatchewan). Our professional piping stress engineers offer premium services and quick turnaround for engineering projects, that can minimized to 5 business day. Compliance with ANSI / CSA piping codes requirements for design and Construction is needed to assure the safety petroleum refinery and chemical plant piping, and this is what we are extremely good at.

The advantages of working with Meena Development LTD. for your Pipe Stress Analysis include:

  • Rapid Turnaround – Meena Development LTD. can turnaround Pipe Stress Analysis in as little as 5 days.
  • Cost-Effective – Meena Development LTD. has a unique cost structure for small project consulting work.
  • Small Projects – Meena Development LTD. welcomes working on even the smallest of projects.
  • Component Engineering Expertise – Meena Development LTD. truly understands all elements of the piping system is extreme detail
  • One-Stop-Shop – Meena Development LTD. can handle all aspects of the project from Pipe Stress to quoting material, to supporting on-site Installation

Our Pipe Stress Analysis Services Includes:

  • Check and validate the client’s design data.
  • Piping design criteria: Design conditions
  • Loads (pressure, dead-weight, thermal, seismic, wind vibration, hydraulic, anchor movement); stress tables and allowable stresses.
  • Pressure design: Wall thickness calculation; nozzle openings, and pressure-temperature ratings.
  • Perform the following piping stress and design using CAESAR II as per ASME B31.3, ASME B31.8, ASME B31.1, ASME B31.4, ASME B31.5, ASME B31.9, and CSA Z662
  • Identification of critical piping type, services and analysis required.
  • External Loads Design: Flexibility, fatigue, stress intensification, combined loads, cold spring
  • Perform simplified analysis methods.
  • Study Piping Thermal Expansion analysis and stresses due to dead-weight and wind load consideration.
  • Piping and Pipe support Materials: Proper selection
  • Pipe Support Design and analysis: Support types, assumptions, load combinations, variable supports, lugs and attachments.
  • Pipe Spans calculations, fundamental cantilever formulas.
  • Piping Flexibility: Quick check method and necessary flexible length calculations.
  • Pipe supports for storage tanks.
  • Purred pipelines analysis.
  • Design of pipe hanger : Type (rigid, constant support & variable spring), Span, Thermal movement
  • Supporting of process piping area and tank farm.
  • Expansion joints Design
  • Proceeding complete piping design and stress analysis using CAESAR II software.

Also check the Industries we serve.

Located in Calgary Alberta, We offer our Piping Stress Analysis Services and Structural Engineering Services across Canada.

Our structural Engineers / piping stress engineers have a bachelor’s and Master’s degree in mechanical / structural engineering and province licence (P.Eng.) in Alberta, Saskatchewan, British Columbia and Ontario. We review, validate, certify and stamp piping and structural packages.


Engineering Consultant Services Calgary, AB

Engineering Consultant Services Edmonton, AB

Engineering Consultant Services Fort McMurray, AB

Engineering Consultant Toronto

Engineering Consultant Services Toronto, ON

Engineering Consultant Services Vancouver, BC

Engineering Consultant Services Saskatchewan

Engineering Consultant Services Houston, Texas

Engineering Consultant Services Middle East

Engineering Consultant Ontario

Engineering Consultant Services Torrance, California

Engineering Consultant Services Buena Park, California

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