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Checklist for Piping Stress Analysis using Caesar II

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

In most organizations, there is a 3-tier checking process for every stress system for maintaining the quality of analyzed stress systems. Normally stress system is performed by one (junior or senior), checked by some other (must be experienced enough), and finally approved by the lead stress engineer. Even though the main points which need to be considered are well-known to every piping stress engineer, but still some important points could be missed at specific moments during stress analysis or checking. So a piping stress analysis checklist can be prepared and referred during the process for proper quality control.

The following article will provide insight into the main points that a stress engineer must check during analyzing a system. We request you to inform us of the additional points that We may have missed while writing this article by replying in the comments section.

Piping Stress Analysis Checklist

Important points to consider while checking any stress system (Piping Stress Analysis Checklist Points)

1. Whether the input for pipe material, pipe diameter, pipeline/pipe wall thickness, pipe temperatures (operating, design, and upset), pressures (design and hydro test), insulation thickness, corrosion allowance, fluid density, insulation density is correct?

2. Whether the input for the above design parameters for equipment and nozzles are correct?

3. Whether SIFs for Tee, bend/elbow, cross, and trunnions are taken correctly?

4. Whether the flanged elbow is considered where required?

5. Whether the actual weight of control valves/nonstandard rigid items/valve actuators are considered appropriate?

6. Whether equipment been modeled with the correct dimensions from the general arrangement drawing?

7. Whether trunnion modeling is done following in-house work instructions?

8. Whether settlements/displacements have been considered where required? Normally settlement is used for storage tanks and thermal displacements are used for compressors, turbines, and packaged items.

9. Whether proper parameters have been used for seismic and wind analysis?

10. Whether friction has been included when significant?

11. Whether the expansion stress range has been checked in between maximum and minimum temperatures to which the piping system will be subjected?

12. Whether the effect of friction on sliding support loads been considered?

13. Whether the use of low friction pads been properly marked if used?

14. Whether the analysis is performed for the system with and without friction to check the effect of friction (to determine the worst case) as friction is not something that can be relied on? The harmful effects of friction need to be considered but not the benefits.

15. Whether the Caesar plot and isometric plot are matching with the 3D plot?

16. Whether the loads on connected equipment are within the allowable limits?

17. Whether the thermal effects of pipe supports and equipment support been considered?

18. Whether the flange weight includes the weight of bolting? In large-size piping bolt weights become significant.

19. Whether all possible load cases (startup, shutdown, regeneration, any special process consideration) are considered in the analysis?

20. Whether the proper ambient temperature is used for the location?

21. Whether spring is modeled properly and selected considering all operating temperature cases?

22. Whether adequate documentation in case of gapped restraints (or any special consideration) are mentioned in isometric clearly to assure that supports will be installed in that manner on the construction site?

23. Whether there is a possibility of elastic follow-up or strain concentration condition?

24. Whether radial thermal expansion has been considered for line sizes greater than 24 inch NB?

25. Whether hot sustained check / Alt-sustained has been performed?

26. Whether the pressure thrust has been considered while using expansion joints?

27. Whether flanged elbows has been considered?

28. Whether sustained deflection and thermal displacements are within the limit specified by the project document?

29. Whether the SIF limitation been considered for large D/t piping?

30. Whether pressure stiffening of bends has been considered in the analysis?

31. Whether flange leakage has been performed as per specification?

32. Whether the change in pipe length due to internal pressure has been considered?

33. Whether all stresses are within code limits?

34. Whether variability of springs is within 10% near rotary/critical equipment and 25% for others?

35. Whether thermal displacements more than 50 mm are marked on isometric?

36. Whether support loads are checked and discussed with layout/design?

37. Whether feasibility of all supports been checked?

38. Whether pipe routing changes and special support requirements been clearly marked in stress isometric and informed to the layout/design group?

39. Whether spiders are modeled properly at appropriate intervals for jacketed pipes?

40. Whether the weight of hot tapping machines and related equipment are considered in specific situations?

41. Whether alignment checking (WNC file) has been performed for all rotary equipment as per API RP 686?

42. Whether PSV forces are considered for open-discharge PSV systems?

43. Whether Hot-Cold and Operating-Standby philosophy has been used when required?

44. Whether restrained and unrestrained piping is defined correctly for pipeline systems (ASME code B31.4/B31.8).

45. If three-way support is provided near the tie-in point, then civil load information for that support considered the impact of another side as well.

46. For Interfacing with other EPC contractors/Package equipment vendors/GRP Vendors data at tie-in points are transferred and back up kept for future reference.

47. For power plants Steam blowing activity is checked with the client and supports are designed for that activity.

48. Reference to FIV/AIV study is clearly mentioned in the Stress report.

49. Whether intermediate nodes are included for dynamic analysis.

50. Supports uplift force for Hold Down Supports are checked and highlighted.

51. Proper supporting for two-phase/slug/surge/vibrating forces is added.

Piping Design Guide of Reactors

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

Reactor piping is very critical due to the high temperature and pressure of the fluids it carries. Reactors are used in the process units to contain catalysts. It promotes the chemical transformation of feeds or to remove undesired materials from the feed.  They are generally cylindrical in shape, with hemispherical heads and axis vertical to the grade. Spherical reactors are used in methanol and catalytic reforming units. Catalysts are used to promote all chemical reactions taking place inside the reactor.  

Principle of Operation of Reactors

Feed enters the reactor at the top. Catalysts are packed along the length of the reactor. As the feed travels down the reactor it is converted into the desired product. The catalysts promote the chemical reaction. The desired product is removed from the bottom of the reactor.  

Catalysts in Reactor

Catalysts are generally ball or pellet-shaped and come in a variety of sizes depending on the process requirements. Catalysts tend to get saturated after a while and their efficiency decreases. They need to be regenerated. Catalysts need to be replaced after they get poisoned as they cannot be regenerated.  

Reactor Internals

The Internals of reactors is very limited. These include Catalyst bed supports, screens, inlet baffles, outlet collectors, and temperature probes.  

Piping Design considerations for Reactors

Locating the Reactor

The piping designer should economize the piping interconnections between the reactor and its adjacent equipment (pumps, feed exchangers, heaters, etc.) when locating the reactor. The following documents are needed to locate the reactor on the plot plan.    

  • P&ID
  • Process Vessel Sketch
  • Plot plan
  • Piping & Plant Layout Specification.

The reactor is located on the plot plan as per the process sequence dictated by the P&ID. Reactors are best located on either side of the pipe rack, as close as possible to the heater as dictated by safety and layout guidelines. This is to minimize the costs of the high-temperature piping. Adequate space must be available for operator movement, maintenance access, and catalyst loading and unloading. Reactor transportation, erection, and other constructability issues should also be investigated while finalizing the location on the plot plan. Locating close to an access road reduces maintenance efforts.  

After the reactor has been located on the plot plan, the following jobs are carried out.      

Reactor elevation calculation and support selection      

  • The Bottom Tan Line elevation is fixed by the following two requirements.
  • Catalyst unloading requirements – Catalyst unloading is accomplished by a nozzle at the bottom head, inclined to the tan line at a specified angle, and radial to the head. Sufficient clearance should be available for the movement of a catalyst removal truck under this nozzle.
  • Outlet nozzle – This nozzle is at the bottom of the hemispherical head, and the centerline elevation of the nozzle is lowered accordingly. This becomes a deciding factor in calculating the clear space required between the bottom of the outlet piping and HPP. Springs below the outlet piping should be considered before setting the final elevation.

  Reactor supporting arrangement 

  • Reactors are generally supported by the following methods
  • Skirt Supported with a foundation on grade – most preferred. Skirts are straight for short reactors and flared for tall ones.
  • Lug supported – Lugs on the reactor supported on concrete piers.
  • Ring girder supported – On tabletop (when the bottom nozzle needs to be accessed)
  • Skirt supported – On a tabletop
  • The choice of support may fix the reactor elevation for some layouts.

Reactor Nozzle orientation

The following documents are required for orienting the nozzles.      

  • Process vessel sketch
  • Level co-ordination diagram
  • P&ID
  • Plant layout specification
  • Nozzle summary
  • Insulation requirements
  • Plot plan

General considerations for locating nozzles

Generally, the following nozzles are present on all reactors.      

  • Inlet nozzle
  • Outlet nozzle
  • Catalyst removal nozzle
  • Instrument nozzle (Thermowell)
  • Sampling nozzle
  • Access Manhole

Orienting the nozzles

While orienting these nozzles the following points are to be considered.      

  • The feed inlet is on the top of the hemispherical head. Maintenance access on the top of the head can be separated or combined with the feed inlet, a gooseneck spool serving both purposes.
  • The outlet nozzle will be on the bottom head, and on the center of the hemispherical head. This is of gooseneck type for vessels with skirt-type support and the nozzle flange must be brought outside the skirt. Orientation is generally chosen to minimize piping to the downstream equipment keeping the line flexible enough from a stress point of view.
  • The catalyst removal nozzle is to be oriented toward the allocated catalyst drop-down area.
  • Thermowell nozzles require special consideration with regard to the pull-out area required for the thermowell element. Nozzles are either mounted radially hillside or on the top head of the reactor. A platform is a must at these nozzles.
  • The sampling nozzle is to be oriented towards an accessible area.
  • Skin thermocouples are equally placed all around the circumference of the reactor and along the length of the reactor. They should be oriented last, clearing all obstructions.

Nozzle standouts  

The feed nozzle on the top of the reactor should have its flange a minimum of 180mm and a maximum of 1000mm from the TOG of the access platform. Consideration for access to nuts under the flange is the be given while calculating the standout. Nozzles on the shell are to have minimum standout that clears the studs from reactor insulation. Reactors are thick shell  

Preparing the Nozzle Orientation Document

This document should show the plan, and if required, the elevation of the vessel with the location of nozzles on the same. Nozzle orientation is to be from the plant north and taken clockwise. Dimensioning should show the radial distance of the vessel flange from the vessel center. A nozzle summary table indicating the Nozzle number, service, size, rating, flange face, elevation from the bottom tan line, and stand out from the vessel center is to be included in the drawing. For nozzles on the vessel heads, the F/F stand out from the bottom or top tan line should be given in lieu of elevation from the bottom tan line.  

Miscellaneous Data to be included in Nozzle Orientation Document

Lifting Lugs

Generally, reactors can be lifted with two lugs welded below the top tan line. A tailing lug is to be provided near the bottom of the skirt for tailing operation. The preferred locations should be marked on the nozzle orientation drawing.  

Earthing Lugs

Two earthing lugs, ideally 180 degrees apart should be provided on the lower portion of the skirt. The same should be marked on the nozzle orientation drawing.  

Name Plate

The nameplate should be located at a prominent location and marked on the nozzle orientation drawing. Care should be taken that the nameplate projects outside the vessel insulation.  

Vessel Insulation Clips

Indicate that insulation clips/rods are required for holding the vessel insulating bands.  

Platforms and Access Ladders

Platforms are required for the following purposes      

  • Operational access to valves and instruments, etc.
  • Maintenance access to manholes for catalyst loading
  • Mid landings (when the elevation difference between two platforms exceeds 9 m)

Calculating the TOG elevation  

The platform on the top head of the reactor   TOG elevation from the top of the reactor head = Insulation thickness + 50 mm clearance + Platform member depth (assume 200 mm minimum) + 30 mm grating. Round off to the next higher multiple of 10.  

Platforms on the cylindrical portion of the reactor  

  • Platforms are to be made independent of the reactor in some cases. An Independent structure around the reactor is to be provided at the required elevations.
  • Nozzles – Platform to be 500mm (minimum) below the bottom of the flange of any nozzle.
  • Mid landing platforms-These are to be provided when the elevation difference between two platforms levels exceeds 9m. The mid landing to be ideally evenly placed between the two platforms.
  • Two platforms being serviced by a single ladder should ideally have an elevation difference of 600mm between them.
  • The platform elevations (TOG) should be rounded off to the nearest multiple of 10.

Sizing the Platform of the Reactor

The platform on the top head of the reactor

This platform should be rectangular. It should cover all the nozzles, flanged piping joints, valves, instruments, davits, etc. that need access for operations and maintenance. Ideally, a minimum space of 750mm should be provided around 3 sides of a nozzle. Side entry access to the platform should be the first preference.  

Platforms on the cylindrical portion of the reactor 

This platform should be rectangular. Its extent should cover all the nozzles, instruments, etc. that need access for operations and maintenance.  

Determining the platform width      

  • The inner radius of the platform should clear the reactor insulation by 50 mm.
  • Platform width is dictated by operator access requirements.

The following considerations are to be taken care of when deciding the width.      

  • The platform should extend along the thermowell element removal area.
  • A free landing space of 750 mm is to be provided for access ladders.
  • Platforms may be locally extended width-wise at regions where vertical pipes pierce the platform, maintaining a minimum of 750 mm clear space from the insulation of piping to the handrail of the platform.
  • When controls are located on the platform, the width of the platform is to be 900 mm plus the width of the controls.

 Access ladder      

  • Access ladders are to be vertical. They should have a clear climbing space of 680 mm. Toe clearance from the centerline of the ladder rung to any obstruction to be 230 mm.
  • A cage is to be provided for all ladders at an elevation of 2300 mm and above. Side entry ladders are the first preference.
  • The ladder is to be oriented so that it can also be utilized for access to instrument connections that are inaccessible from the working level.

Preparing the Platform Input Document  

Platform and Access ladder input is transmitted to Civil via a platform input drawing.  

The platform on the top head of the reactor:

This should clearly indicate the TOG elevation from bottom T/L, dimensions of the platform, and its location w.r.t. the vessel center lines. Grating cutout requirements (indicating size, shape, and location), required swing direction of the self-closing gate, and davit location needs to be marked on the same drawing. Any pipe supports/monorails intended to be taken from the platform should be marked.  

Platforms on the cylindrical portion of the reactor 

This should clearly indicate the TOG elevation from bottom T/L, the dimensions of the platform, and its inner radius from the vessel axis. Grating cutout requirements (indicating size, shape, and orientation), required the swing direction of the self-closing gate. Any pipe supports/monorails intended to be taken from the platform should be marked.   Orientations of access ladders should be marked on the respective platform elevation plans.  

Orienting piping on the face of the reactor

It is imperative that the orientations, arrangement, and standouts of various piping traveling down the face of the reactor are calculated keeping in mind the following points.      

  • Piping should drop towards the pipe rack side, clear from any platforms.
  • The piping can travel down the reactor radially, with independent supports.
  • The clear minimum space between the pipe and shell is to be 300 mm excluding any insulation.
  • The pipe with insulation should clear the stiffening ring and its insulation.
  • The minimum orientation angle between two adjacent pipes should be calculated to clear the support bracket of one pipe hitting the insulation cladding of the adjacent pipe.
  • Support points of adjacent piping should be offset to save space between them. as the support brackets will have to be oriented so that there is no clash between the cleats of the supports, or between the support members and bracings.

Supporting Piping from Reactors

Piping should be supported from the vessel or its platform when it is difficult to construct civil support from grade or adjacent structures at the required location. Vessel support should also be taken to take advantage of lower differential thermal growth between vessel and piping, as compared to piping and civil support. A judicious selection of support locations can eliminate the requirement for springs.  

Thumb rules for supporting piping from reactors      

  • Small loads can be transferred directly to the platform members. These include rest, one-way stops, two ways stop, or hold-down supports and the piping layout should be done accordingly.
  • Large loads should be transferred to the vessel shell and the piping layout should be done such that the platform members do not interfere with these independent supports.
  • The first piping support is rest support and it should be as close to the equipment nozzle as possible. The second and subsequent supports are guides and they are to be located as per the allowable piping spans available in the tables. For tall reactors, another rest support may be needed. This is done by providing spring support which will take care of the differential expansion of the vessel and piping.
  • Piping support should not cause any hindrance to the movement of personnel.
  • Vessel growth should be considered to check the clash of piping support with any adjacent piping or structure.

 Types of supports

Supports welded to piping

Horizontal trunnions welded to the pipe take the vertical load of the pipe. They are generally used in pairs, set apart at 180°. Their axis is perpendicular to the line drawn from the center of the reactor to the center of the pipe at the location of support. Trunnion lengths should be adequate so that their ends project 50mm from the outer edge of the support bracket member Shoes are provided for guidance purposes and to prevent insulation cladding from hitting the support bracket member. Adequate shoe length is to be taken for differential movement of pipe and vessel.  

Supports welded to the vessel  

Support brackets (non-braced and braced) and Guide brackets (non-braced and braced) are the most common support arrangements for vertical piping.  

Calculating the minimum dimensions of support members  

Load bearing supports

Trunnions or springs transfer load to these supports. Minimum clear inside dimensions are calculated so that the insulation cladding is 50 mm away from the inside of the structural member or support plate of the spring.  

Guide supports

A bare pipe is guided directly by the guide bracket. Shoes are provided in pairs, 180° apart, for lines with insulation. These can be single pairs or double pairs depending upon the type of guiding required at that location. The guide gap required by stress is to be added to the end-to-end dimensions of the bare pipe or pipe with shoes.  

Preparing the Civil Pipe Support (CPS) Input Document

CPS input is transmitted to Civil and Mechanical via a CPS input drawing. A sketch clearly indicating the TOS, dimensions, and CPS location with respect to the vessel centerline needs to be drawn. Any requirement for additional support plates for springs or trunnions is to be indicated. A summary table indicating the CPS number, TOS, stress file number, and corresponding node number from the Nozzle cleat load information chart needs to be created. The Nozzle cleat load information chart indicates the various loads acting at the support location under various conditions. It is to be attached along with the CPS input document.

What is a Sour Service? | NACE Sour Service Criteria

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

What is a Sour Environment?

NACE defines a Sour environment as one that contains enough H2S either in the gaseous or aqueous media.

Properties of Hydrogen Sulphide

  • Chemical Formula: H2S
  • Odour: Rotten Egg
  • Boiling point: 60OC
  • Specific Gravity: 1.19
  • Odour level: 0.13 mg/kg

The fatality of Hydrogen Sulphide (mg/kg)

  • Respiratory breakdown: 100
  • Nerve paralysis: 150
  • Nausea, Dizziness: 200
  • Unconsciousness: 500
  • Asphyxiant, Fatal: 700

What is Sour Service?

Sour Service is defined as a fluid service containing water as liquid & H2S exceeding the limits defined below:

Sour Gas-

Sour Gas Service is defined as the gas service

IF            the Total Pressure of the gas being handled is > = 65 PSIA

AND       Partial Pressure of H2S in the gas is > 0.05 PSIA

Then      The Environment is SOUR Gas

Sour Oil and Multi-phase

IF            the Fluid handled is Crude or Crude+Water+Gas

AND

  • Gas to Oil Ratio > 5000 (SCF/bbl)
  • H2S content in Gas-phase > 15%
  • Partial Pressure of H2S in Gas Phase > 10 PSIA
  • Surface operating Pressure > 265 PSIA

Then     The Environment is SOUR Oil

Sour Scenario in the oil industry as per NACE MR-01-75

Refer to the below image (Fig. 1) which shows a curve segregating the sour and non-sour regions as per NACE MR-01-75. The curve denotes the amount of H2S requirement for qualification of being Sour at a given absolute pressure.

Sour Scenario as per MR-01-75
Fig. 1: Sour Scenario as per MR-01-75

Limitations of NACE MR-01-75

  • Saltwater wells, injection wells
  • Downstream Industries, Petrochemical
  • Refineries and Chemical plants
  • Low-pressure multiphase systems

HIC Scenario – API Nelson Curves

Refer to Fig. 2 which shows the HIC and Non-HIC regions.

HIC SCENARIO – API NELSON CURVES
Fig. 2: HIC SCENARIO – API NELSON CURVES

Sour Scenario as per ISO 15156 / EFC 16

Fig. 3 shows the sour service criteria as per ISO 15156/EFC 16.

SOUR SCENARIO – ISO 15156 / EFC 16
Fig. 3: SOUR SCENARIO – ISO 15156 / EFC 16

Sour Service H2S ppm Criteria as per DEP

Shell DEP provides the following H2S criteria for fluid services

  • 0 to 49 PPM: Sweet Service
  • 0 to 499 PPM: Low-Risk Sour Service
  • 500 + PPM: High-Risk Sour Service

Hydrogen Sulphide – What it Can Do!

Dynamics of Sour Environments

Fig. 4 shows the dynamics of the sour service environment.

Dynamics of Sour Environment
Fig. 4: Dynamics of Sour Environment

For more understanding of NACE Services, I suggest the following course: NACE CIP 1 practice exam

Plastic Piping System: Types of Plastic Pipes

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

As the name implies, plastic pipes are made of plastic materials. Due to its many advantages, plastic pipes are the ideal choice in many piping and plumbing solutions. In fighting corrosion, plastic pipes are an important alternative.

Corrosion (deterioration of materials under the influence of an environment) is a big problem in all operating Process Plants. Many of the failures reported in Plants are because of Corrosion.  Hence given a choice one would be tempted to dispense away with Steel altogether as a material of construction for piping used. Unfortunately, it is not practical to undermine the usefulness of Steel in sustaining the Pressure and Temperature conditions normally foreseen in any Process Plant. That brings the concept of composite piping constructed from highly Chemical Resistant Polymer Compounds as the base material, reinforced with suitable fibrous materials such as Glass which provides it the requisite strength.

Advantages of Plastic Pipes

Plastic piping offers various advantages as listed below:

  • Economic.
  • Easy Installation.
  • an ideal choice for low-temperature services.
  • Lightweight, and easy to handle.
  • Low Support load.
  • Rust and corrosion-resistant.
  • Smooth surface so less frictional loss.
  • Chemical resistant.

Applications of Plastic Pipes

Due to its inherent benefits, Plastic pipes are widely used in the water and food industry for transferring drinking water, wastewater, irrigation, chilled water systems, chemicals, heating fluid, cooling fluids, foodstuffs, etc.

Types of Plastic Piping

Depending on plastic piping materials, basically, 3 types of Synthetic Polymer Components have found acceptance in industrial use.

  • Thermoplastic piping
  • Thermosets and
  • Composite Plastic piping

Thermoplastic Piping Materials

The Thermoplastics are Polymer Compounds, which are normally available in crystal form. On the application of heat and pressure, these crystals attain the requisite level of flowability to be able to attain the desired shape by a molding process. On re-heating, the plastic material can once again undergo the transformation from solid to a flowable state which allows their reprocessing into the desired shape.

Some of the commonly used Thermoplastic materials are as follows:

  • Polyethylene or PE
  • Polypropylene or PP
  • Polystyrene
  • Polyvinyl Chloride or PVC
  • Fluoro-Plastics

By and large, thermoplastics are structurally weak materials and have limited temperature endurance.

Typical HDPE Piping System
Fig. 1: Typical HDPE Piping System

Thermoset Piping Materials

Thermosetting Plastics are Polymer compounds (resins), which are normally available in liquid form at ambient temperature. With the addition of a Catalyst and an Accelerator, these Resins undergo a chemical transformation into a rigid product that sets into the required shape by the curing process.

Some of the commonly used Thermosetting Plastics are as follows:

  • Epoxies
  • Furans
  • Phenolic
  • Polyesters – Bisphenol, Isophthalic, Halogenated
  • Polyurethane
  • Vinyl esters

Even though Thermosetting Plastics are relatively superior to Thermoplastics in terms of structural strength and temperature endurance, still in their virgin form they find limited use in industrial applications.

Composite Plastic Piping Materials

It is evident from the foregoing discussion that both Thermoplastics and Thermosetting Plastics in their virgin form lack the ability to sustain the level of mechanical loading normally encountered in Industrial applications. An attempt to strike an appropriate balance between the two desired properties of the material (i.e. Mechanical Strength and Corrosion Resistance) therefore has always remained a desirable objective. This brought forward the concept of Composite Plastics wherein a reasonable degree of mechanical strength is imparted to the base Polymer which in itself is adequately resistant to Chemical Corrosion, by way of reinforcing it with a suitable reinforcing material.

Most of the commercially available composite materials in the Reinforced Plastic category use a combination of Thermosetting Plastic Resins (e.g. Polyester, Epoxy, Vinyl Ester, etc.) and Fiberglass or Synthetic Fibres as reinforcing material. In order to provide ultra-superior chemical resistance, it is also possible to manufacture a composite material using Thermoplastic Material (e.g. PVC, PVDF, PP, etc.) as a baseliner over which the layers of Thermosetting Resins and Fiberglass are applied to attain the required mechanical strength.

Typical PVC Pipes
Fig. 2: Typical PVC Pipes

Composite plastic Piping Manufacturing Process

Composite plastics pipes are commonly produced by one of the following methods:

Custom Contact molding

It is a manual/ semi-automated process in which the composite sections are manufactured by application of various layers of resin and Glass Fibers (in various forms such as surface mat, roving mat, chop-strand mat, etc.) either by Hand Lay-up or by Spray Lay-up method.

Filament Winding

It is a fully automatic process in which automatic control over winding angle ( 0 to 90 degrees) and winding pressure can be exercised to obtain the varying degree of Hoop – Axial ratio and Glass – Resin percentage composition. Normally a winding angle of 54 3/ 4 Degrees provides a 2:1 Hoop–Axial ratio which is a condition of optimum internal pressure requirement. By increasing the winding pressure the Glass – Resin proportion could be varied from 80 % – 20 % to 60% – 40 %. A composite section of high Glass content will result in high strength and low chemical resistance and vice versa.

Filament Winding Process
Fig. 3: Filament Winding Process

Pultrusion

As the name implies this is a sort of extrusion process by pulling the filaments through a resin bathtub and subsequently passing it through an extruding die and then through an atmosphere of controlled elevated temperature. The above process is commonly used for manufacturing rolled sections such as Angles, Channels, I Beams, etc.

Resin Transfer Molding

The above process is used for specialized applications for the manufacture of sandwich structures with certain core materials.

Plastic Piping System Design Considerations

The Plastic Piping System consists of Piping Profile fabricated from plain end pipe, plain and flanged end Fittings (i.e. Elbows and Reducers), and stub-in branch connections. The Flanged Joints are Stub Ends with loose Backing Flanges. In the case of Flanged Tapping Long Stub Flanges are recommended to be used in place of pipe stub-in and Short Stub Flanges. The pipe-to-pipe and pipe-to-fittings joints are laminated joints. Accessories for Piping System include Soft Rubber/ CAF Gaskets and Full Threaded Fasteners with Washers. The major considerations for the plastic piping system are listed below:

1. Owing to weak mechanical properties a minimum of NS 2” line size is recommended for Plastic Piping. However, tapping of small size (i.e. smaller than NS 2”) is permitted for drain/ vent, etc. provided the branch connection is adequately supported.

2. Owing to its large Coefficient of Thermal Expansion Plastic Pipelines exhibit a high tendency to grow under moderate temperatures. This may result in a sizable deflection of the branches and the corners of the Piping Profile. It shall, therefore, be ensured that the branch connections are not overstressed, either by providing adequate flexibility on the branch piping or by fixing the branch points by external means to disallow its deflection.

3. If free movement of the corners of the piping profile can be allowed (i.e. e.g. not being hindered by any other external item) then it is preferable to leave the profile to grow freely. However, if the growth of the profile has any adverse effect on the system stability (e.g. supports falling off from the external structure) it may be appropriate to restrict the growth of the sides of the profile by providing fixed supports at various locations as per Plastic Piping Support recommendations.

4. Unlike Steel, bellows are not used on Plastic Piping. The thermal stress behavior is addressed either by providing in-built flexibility in the system or by arresting the axial growth of the pipe runs within the pipe length itself. In case the later method is employed, the pipe may have to be guided at close intervals to avoid failure due to buckling.

5. Owing to its weak nature, the plastic piping shall not be supported by line contact between the pipe surface and the external structure taking the load. Hence as a general rule Clamp and Shoe type supports shall be employed on Plastic Piping System.

6. All concentrated loads (e.g. On-line Valves, Instruments, etc.) shall be directly supported to ensure that the load is transferred to the grade/ external structure without stressing the piping.

7. All the valves employed on Plastic Piping shall be provided a Fixed Type Support to ensure that the Piping is not overstressed in case of jamming of the Valve handwheel while operating.

8. Due to the excess thickness of the Plastic Pipe (as compared to Steel) it is likely to obstruct the opening of the flap of the Sandwich type Butterfly/ Wafer Check Valve into the pipe. In order to address the above issue, the Spacer Rings (made of the same or equivalent material as a pipe) will be employed across the valve. The above Spacer Ring is procured as a Special Part.

9. The Plastic Piping System shall be installed with permanent supports in place. The erection of Plastic Piping with temporary supports is not acceptable.

10. The pipes shall not be stretched in order to match the terminal ends

11. The Flange Joints shall be tightened to the specified Torque Value only by employing Torque Wrench.

12. As far as possible the Piping profile shall be prefabricated in the Vendors shop at the site, leaving only a few field joints for final fit-up.

13. In the case of FRP Piping with Thermoplastic Liner, the Field Weld will always be located at the convenient height/ location to allow down-hand welding/ jointing.

Few more related articles for you.

A short article on GRP Pipe for beginners
Basic Principles for an aboveground GRP piping system
Stress Analysis of Plastic Piping System
An Article on HYDROSTATIC FIELD TEST of GRP / GRE lines
Stress Analysis of GRP / GRE / FRP piping system using Caesar II
Stress Analysis of GRP / GRE / FRP Piping using START-PROF
Buried GRP/FRP pipe Laying and Installation Procedure

Damaging effects of Low-Velocity Flow In Piping And Pipelines

Written by Ankur Srivastava in Pipeline,Piping Design Basics,Piping Interface

Is Low-Velocity Flow Bad?

Many of you are aware that high velocities in piping and pipelines lead to many operational and maintenance issues like piping vibration, noise, pipe material erosion, and a combined corrosion-erosion issue. American Petroleum Institute’s defunct document API RP 14E, defines a formula for determining erosional velocities in two-phase flows which states that actual flowing fluid velocities must be well below the calculated erosional velocities. International Standards Organization’s ISO 13703 points to the same philosophy regarding erosional velocities since it is based on API RP 14E, with the only difference being that the erosional velocity formula of API RP 14E is available in SI units.

The current discussion, however, deals with low velocities. The adjective used here is damaging for low velocities. As it is known that high velocities come with an adverse impact of vibrations or noise in piping systems, the undesirable impact of low velocities in piping is more subtle and long-term. The adjective damaging signifies this subtle and long-term effect of low velocities.

In this article, we will discuss the undesirable damaging effects that low velocities create in piping and pipelines. In the following paragraphs, the fluid flow in pipes and pipelines is categorized based on fluid type and the fluid phase.

The flow of Slurries inside Pipes

When fluid velocity is very low, solid particles separate from the fluid. Solid particles with a heavier density tend to settle down at the bottom of the pipe in a horizontal pipe run. This settling will be even more at elbows or bends where the flow is changing direction or where the pipe diameter is reducing. The damaging effect here is that over a period of time, a layer of solid builds up inside the pipe and pipe fittings thereby reducing the pipe diameter which leads to

  • more pressure drop
  • partial or full flow disruption
  • the operating point of the pump moves towards shut-off leading to reduced pump efficiency and accelerated mechanical wear and tear of the pump and pump sealing system.

Flow of Liquids through pipelines

A typical example would be a hydrocarbon liquid with entrained water, where the hydrocarbon liquid is the continuous phase while the water is the discontinuous phase. At low flowing velocities, the entrained discontinuous phase water will drop out from the continuous phase hydrocarbon liquid to the bottom of the pipe. Water accumulation will occur in low points of the piping over the long term.

If the hydrocarbon liquid has even trace amounts of dissolved carbon dioxide or hydrogen sulfide, pipe/pipeline corrosion can occur. The mechanism of corrosion in simplistic terms is that carbon dioxide and/or hydrogen sulfide will react with the accumulated water in the pipeline leading to acid corrosion by the formation of Carbonic Acid (H2CO3) and/or Sulfuric Acid (H2SO4). Such corrosion can lead to the failure of carbon steel piping/pipeline over the long term.

Single Phase Gas Flow (with entrained liquids)

An example of such a system would be natural gas with entrained liquid water droplets and heavier hydrocarbons. When the flowing velocity is low, the flow may be stratified in the horizontal run of the pipe. The gas travels at the top part of the pipe and the liquid travels at the bottom part of the pipe, clearly parting the fluid into two parts. Liquid accumulation will occur at low points and direction changes in the pipe over a long period of time. The same problem of corrosion can occur as discussed for the flow of liquids. Additionally, the gas transport could see high-pressure drops and a reduction in flow, putting excessive loads on gas compressors.

Liquid accumulation over the long term in pipelines due to low velocities can also lead to intermittent slug flow in pipelines. The high momentum of liquid slugs can lead to structural damage to piping/pipelines and their supports.

Often natural gas pipelines have been found to have black powdery material (solids) in small amounts. The black powder could be because of corrosion products, trace amounts of solids carried over from gas treatment plants, mill scale, etc. Low flowing velocities in gas transmission pipelines can lead to accumulation and deposition on pipeline walls of the black powder over the long term and lead to excessive pressure drop and reduced flow.

Flow velocities need to be kept above a threshold velocity also known as minimum entrainment velocity to prevent black powder deposits.

Low Velocity Flow

3-phase flow (Gas-Liquid-Liquid with Oil as continuous phase)

A typical example of such flow will be crude oil from reservoirs with associated dissolved gas and free water. At Low flowing velocities, similar problems related to corrosion will arise. Additionally, if the crude oil is heavy containing asphaltenes, then reduced flow velocities for a given pipeline will drastically increase the asphaltene deposition rate on the pipe walls. So there could be partial or total flow stoppage in the long run. This will require costly cleaning operations for the full restoration of pipeline operations.

Quantification of Minimum Velocities

Quantification of minimum velocities in piping or pipeline systems is important. For unlined carbon steel pipelines that transport light crude oil or condensate or any other liquid hydrocarbons containing entrained water even in a very small quantity (e.g. 1% water cut), the velocities should not be allowed to fall below 1.5 m/s to prevent water drops out.

For gas pipelines, however, the normal range of fluid velocities should be 5 to 10 m/s. For bone-dry gas, velocities up to 20.0 m/s may be allowed. However, for higher velocities, design considerations for noise and flow-induced vibration prevention have to be incorporated during all operational scenarios.

As mentioned earlier, black powder in natural gas pipelines will not be entrained at low gas velocities. This may lead to accumulation at some portion of the gas pipeline over a long duration. The entrainment velocity for these very fine particles is a function of their micron size. Generally, for a particle size of 1 micron to remain entrained, the gas velocity should be in the range of 2.5 to 4.5 m/s, depending on the pipe size.

Measures to prevent low velocities

In intermittent or batch transfer operations, when demand is low at the receiving station, continue pumping at the same high rate as required for peak demand but for a shorter duration. There is no need to reduce the flow rate for low demand in batch transfer operations. Standard Operating Procedures (SOPs) should address such turndown or low-demand scenarios without reducing the flow and thus the velocity.

Measures to mitigate low velocities

In prolonged turndown scenarios and continuous operations, low flow velocities are inescapable. To get rid of such problems associated with less fluid velocities, the following measures could be implemented:

  • Addition of compatible anti-corrosion and anti-scale additives in the piping/pipeline system.
  • Injection of compatible emulsifying agents in liquid hydrocarbon-water systems to prevent phase separation occurring at low velocities.

To summarize, low flowing velocities in pipes and pipelines can create issues like scaling and deposit formation, corrosion, etc. However, appropriate operational measures can be used to prevent operations at low velocities.

Please click here if you are interested in more Process Design related Articles

Dry Gas Sealing Systems

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

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

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

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

Application of Dry Gas Sealing

Dry Gas Sealing is widely used on

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

Principle of Dry Gas Sealing operation

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

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

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

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

dry gas sealing operation

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

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

Single Seal, double seal and tandem seal

Seal Gas

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

Labyrinth Seals

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

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

Pressure Balancing

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

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

Primary Gas

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

Secondary Gas

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

Separation Gas

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

The typical control scheme for dry gas sealing

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

typical control scheme for dry gas sealing

Seal gas vent

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

Seal gas filters

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

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

Types of Dry Gas Seals

Dry Gas Seals have mainly configured in four types.

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

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

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

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

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

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

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

Barriers shaft sealing system

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

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

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

Dry Gas Sealing design considerations

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

(b) Process pressure in the compressor at normal operation

(c) Process settle out pressure in the compressor

(d) Pressure of seal gas

(e) Design minimum temperature (static/dynamic)

(f) Design maximum temperature (static/dynamic)

(g) Normal seal gas supply temperature in operation

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

DGS Operating Range

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

Advantages of DGS over Wet seals:

The following can be eliminated

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

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

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

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

Codes / Standards for Dry Gas Seals

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

Dry Gas Seal leakage rates

Seal leakage rates in operation (on-site)

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

(b) Seal medium: air

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

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

Acceptance criteria for seal leakage rates

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

Gas seal contamination

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

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

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

Inadequate gas seal monitoring

Outboard (OB) seals are often not monitored:

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

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

Improve gas conditioning by one or more of the following:

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