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Selection of Pipe Flanges in Piping Industry

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

This article will provide a guideline for the selection of metallic pipe flanges and provides information on pressure-temperature ratings, dimensions, tolerances, materials, marking, and testing of piping flanges and flanged fittings in sizes NPS 1/2 to 48, and classes 150 to 2500 which can be used in conjunction with ASME B16.5, B16.47, B31.3, B31.4, and B31.8.

Pressure Temperature Rating of Pipe Flanges

The Pressure-Temperature ratings for the applicable materials listed in ASME B16.5, Table 1A shall be the maximum allowable working gage pressures at temperatures shown in Table 2 of the same standard. The basis for establishing ratings shall be the minimum wall thickness, which shall be in accordance with ASME B16.5, Annexure D. The material groupings are based on closely matched allowable and yield strength values.

Within each pressure class, the dimensions are held constant, irrespective of the material. Physical properties, and thereby the allowable stress values, of different materials, vary, so the pressure-temperature ratings within each pressure class vary with the material. For example, a class 600 forged carbon steel (ASTM A105) pipe flange is rated at 1270 PSIG at 400 °F, whereas a class 600 forged stainless steel (A182-F304) flange is rated at 995 PSIG at 400 °F.

Piping Flange Dimensional Standards

The following dimensional standards shall apply to metallic pipe flanges and bolthole patterns of non-metallic companion flanges:

  • ASME B16.1, for integral cast iron piping flanges and blind flanges
  • ASME B16.5, Classes 150, 300, 600, 900, and 1500 up to NPS 24, and class 2500 up to NPS 12. Class 400 carbon steel flanges shall not be used.
  • Pipe Flanges larger than NPS 24 shall be specified in accordance with ASME B16.47. ASME B16.47 Series A for NPS 26 to NPS 60 in class 150 to 900 replaces these flange sizes in MSS SP-44. This is usually used in plants for mating certain valves.
  • Series B supersedes API 605 in sizes NPS 26 to 60. Series B is used for pipelines and is restricted to pipe flanges used for joints.
  • MSS SP-44 shall be used for steel pipeline flanges for sizes smaller than ASME B16.47 where the material grade is not listed in ASME B16.5
  • Piping Flanges of unlisted materials and flanges not covered by the above standards shall be designed in accordance with ASME Section VIII Div 1, Appendix 2, and for blind flanges, in accordance with ASME Section VIII Div 1, Section UG-34
  • Tolerances for pipe flanges shall be in accordance with ASME B16.5, section 7 for flanges up to NPS 24, and ASME B16.47 for flanges over NPS 24.

Pipe Flange Facings

Dimensions for flange facings shall be in accordance with ASME B16.5, Table 4 for flat face, raised face, and tongue and groove flanges, and Table 5 for ring joint flanges. These tables shall be used in conjunction with ASME B16.5, Figure 7.

Guidelines for Selection of Various Types of Flanges

Flat-face flanges, with full-face gaskets, shall be used when one or both of the mating pipe flanges in a joint are ASME B16.1. Class 125 gray cast iron, aluminum, or plastic, can be over-stressed by bearing against a raised face. Adapter rings may be necessary in some cases, to level off the surface, for mating equipment.

Raised face flanges shall be specified in ratings up to Class 600. These piping flanges are supplied with a 0.06-inch raised face, which is included in the minimum flange thickness. The finished height of the face shall be less than the nominal pipe wall thickness. Flanges in classes over 600 are supplied with a 0.25-inch raised face that is additional to the minimum flange thickness.

In ring-joint flanges, the thickness of the lap remaining after machining the ring groove shall not be less than the nominal wall thickness of the pipe used. Ring joint flanges for use with ASME B16.20 ring joint gaskets shall be used for:

  • Piping Flanges in Class 900 and higher ratings
  • Design temperatures in excess of 480 °C
  • API 6A Type 6B flanges (wellhead piping)
  • Hazardous fluid mediums

Tongue-and-groove facing, and male-and-female facing joints, shall not be used except in high-pressure service, or when it is necessary to match existing equipment.

Piping Flanges shall be finished in accordance with MSS SP-6, and ASME B46.1. Table I provides acceptable ranges of contact surface finishes for each type of gasket and service. The surface finishes shall be in Ra, Roughness average, expressed in micrometers, followed by micro-inches.

Pipe Flange roughness shall be judged by visual comparison to Ra standards using the GAR model S-22 Micro Finish Comparator.

Ring joint flanges shall have flat-bottom type grooves in accordance with ASME B16.20.

The bore of Welding Neck Flanges and Hub Design

Dimensions of welding end, bevel slopes, and bores shall be in accordance with ASME B16.5, Table 6, and Figures 8 to 14. Ratings of welding neck flanges shall be based upon their hubs at the welding end having thicknesses equal to that calculated for pipe having a 40 ksi specified minimum yield strength (SMYS). When the SMYS of the hub is less than that of the attached pipe, the minimum thickness of the hub at the welding end shall be at least equal to the product of the pipe wall thickness and the ratio, pipe to flange, of the specified minimum yield strengths. See MSS SP-44.

Mis-matches between pipe and flange shall be corrected during fabrication. Weldneck shall be tapered bored if specified in the purchase description. Pipe wall thickness shall be specified in the purchase description to ensure that the flange is bored within the specified tolerance.

Piping Flange Material Limitations

  • Flanges and flanged fittings shall be castings, forgings, or plates.
  • Bolting materials shall conform to ASME B16.5, Table 1B.
  • The material for flanges in pipeline service shall be suitable for welding. The carbon equivalents shall match the pipe material.

Iron Flanges

Cast Iron Flanges: Gray cast iron flanges shall not be used for process piping within the battery limits of any plant. The only exception shall be for use in approved fire systems. The material shall be ASTM A 126, Class B.

Ductile Iron Flanges: Ductile iron flanges may be used, in proprietary systems, for example, plastic-lined steel piping, as backup flanges for lapped joints.

ASME B16.1 Class 125 and Class 250 cast iron flanges may be mated with ASME B16.5 Class 150 and 300 steel flanges respectively. However, care shall be exercised to ensure that a flat-faced cast iron flange shall mate only with a flat-faced steel flange, and vice versa.

Carbon Steel Pipe Flanges

  • Carbon steel flanges shall not be used in services over 425 °C.
  • General Service- The standard carbon steel material shall be ASTM A105. Standard material shall be used between minus 29 °C and 425 °C.
  • Low-temperature Alloy Steel Flanges. Carbon steel flanges used for services below minus 29 °C, shall conform to the impact-testing requirements of ASME B31.3, ASTM A 350-LF2 shall be the standard material for this service.

Low and Intermediate Alloy Steel Piping Flanges

  • Material for Low alloy steel flanges (11/4 Cr – 1/2 Mo) shall be ASTM A 182-F11. Material for intermediate alloy steel flanges (11/2 Cr – 5 Mo) shall be ASTM A 182-F5.

Stainless Steel and Non-ferrous Pipe Flanges

Usually, weld neck flanges shall match the metallurgy of the pipe in any material class. Austenitic stainless steels, however, may in certain cases be interchangeable. For example, type 347 and 321 stainless steels are compatible. Flanges that are double stamped, or double graded, and are so marked. For example, low carbon grades such as 304L, and 316L may be substituted, for the ‘straight’ grade, provided that the ‘L’ grade meets the physical requirements of the application.

When pipe material is forged, weld neck flanges shall be forged. When pipe material is not forged, material for weld neck flanges shall be subject to client approval.

 Pipeline Service Flanges

  • Flanges for pipeline service shall match SMYS, and carbon equivalency specified in ASME B31.4 and B31.8.

NACE Service Flanges

When an in-plant service has water and H2S concentrations above the limits specified in NACE MR0175, that service shall be considered as the NACE service. Flanges for use in the NACE service shall be in accordance with NACE MR0175 special requirements. The purchase description shall specify the ‘NACE service’.

High-Strength Material Flanges for Pipeline Service

Flange Types

The selection of appropriate joining methods varies with the required mechanical strength in the joint, from a minimum, as in slip-on connections, to a maximum, as in integral-type flanges that are cast, integrally forged, or butt-welded to the pipe.

Weldneck Flanges

  • ASME B16.5 weld neck flanges with tapered hub and welding end shall be the primary selection for flanged joints in metallic piping systems of NPS 2 and larger. The individual material classes show the size range for any given service.
  • Welding ends of weld neck flanges shall be in accordance with ASME B16.5, Figures 8 to 14.

Threaded Flanges

  • When future material classes are generated, threaded flanges shall be added to material classes for threaded service, generally for mating equipment, and transitions between threaded and flanged piping.
  • Threaded flanges may also be used for water and air service in pipe sizes NPS 6 and less and at a design temperature of 250 °F and below. Seal welding shall not be required.
  • Threaded flanges shall be limited to size NPS 2 and smaller in hazardous service.
  • Threaded flanges shall have taper-type threads and shall conform to ASME B1.20.1.

Socket weld Flanges

Socket weld flanges and socket weld-reducing flanges are added to material classes for mating equipment, where a union will be subject to external stresses; and transitions between socket weld and flanged piping.

Slip-on Flanges

Slip-on flanges cost less than welding neck flanges and require less accurate pipe cutting, but their strength is approximately 2/3 of weld neck flanges under internal pressure, and they have approximately 1/3 the fatigue life of weld neck flanges.

Slip-on flanges shall be welded at the front and back of the hub, but not on the sealing face.

Slip-on flanges and reducing slip-on flanges shall not be used in the following services:

  • Severe cyclic conditions. See ASME B31.3, paragraph 300.2.
  • Design temperatures above 230 °C, or where the corrosion allowance exceeds 3 mm
  • ASME B16.5 Class 400 or higher rating
  • Piping Flange sizes larger than NPS 24 unless stress calculations in accordance with ASME Section VIII Div 1, Appendix 2, with thermal and other external piping loads considered, show that the slip-on flanged joint will not be over-stressed.
  • In hydrogen service with a hydrogen partial pressure above 690 kPa, flanges shall have a predrilled 3 mm diameter hole to vent the space between the pipe OD and the flange bore.

Lapped Joint Flanges

A lap joint is made up of a pair of stub ends, a pair of lap joint flanges used as a backup, and bolts and gaskets. These allow easy alignment of bolt holes and flanged joints.

The stub end shall match the material of the pipe. Stub ends for lapped joint flanges, if fabricated by welding, shall be made with full penetration welds.

Advantages are that lapped joints are an economical alternative to weld necks, and cost savings are large when the material is very expensive; dissimilar materials can be joined, provided galvanic corrosion does not occur; and spools can be rotated.

The disadvantage of this joint is that it is sensitive to external stress. Lapped joint flanges shall not be used in severe cyclic conditions.

 Blind Flanges

  • Blind flanges shall be used as end closures on flanged ends and valves unless end caps are specified in the design.
  • Blind flanges are forgings and shall be manufactured to the same materials standards as other matching flanges.
  • Blind flanges shall be of the same material as the weld necks, in all services. In corrosive atmospheres, stainless steel shall be used.
  • Blind flanges shall not be drilled for connections, for example, drains and flushing, unless stress calculations in accordance with ASME Section VIII Div 1, Appendix 2 show that the flanges will not be overstressed.

Orifice Flanges

  • Orifice flanges shall conform to this standard and ASME B16.36.
  • Orifice flanges shall be weld neck flanges.
  • Orifice flanges shall have jackscrews to facilitate the disassembly of the flanged joint during maintenance.

Other Standards

Other standards, for example, AWWA C207 for hub flanges, may be required for proper mating to equipment and shall be reviewed at the time of generation of a material class.

Information Required for Purchasing a Flange

The following shall be included in the purchase description for flanges:

  • Type of flange
  • Flange Rating
  • Flange Dimensional standard
  • Flange facing
  • Contact surface finish
  • Tolerances
  • Material grade
  • Additional material and testing requirements, if applicable
  • Nominal size of the flange
  • Wall thickness as defined by schedule, weight, or actual decimal wall

Marking of Flanges and Flanged Fittings

Flanges and flanged fittings shall be marked in accordance with MSS SP-25. The following shall be included in the marking:

  • Pressure rating class
  • ASME B16 designation
  • Nominal pipe size
  • The letter ‘R’ and the corresponding ring groove number for ring joint flanges
  • The letters ‘PL’ shall precede the grade symbol followed by the material grade of the pipe
  • Type of flange facing
  • Schedule or wall thickness for weld-neck flanges

Some more ready references for you:

Flange Selection Guidelines
Pressure Equivalent Method in Caesar II
Flange leakage calculation ASME Section VIII in Caesar II
Flange leakage calculation NC 3658.3 method in Caesar II
Procedure for Flange Bolt Tightening of Various Sizes of Flanges

Importance of Inter Discipline Check or IDC

Written by Ankur Srivastava in Piping Design Basics

What is IDC or Inter Discipline Check?

IDC or “Inter Discipline Check” is related to the quality of engineering deliverables. This term is frequently used in the engineering design and consulting field. The main objective is to provide error-free Engineering deliverables to the construction team that paves way for a smooth Construction, Operation, and Maintenance of the Plant or Processing Facility. This is a very good tool for improving the quality of engineering deliverables with minimum error.

This article specifically explains the Definition, Description, and Importance of IDC.

Engineering Disciplines involved in the Design firm

Normally, a multi-disciplinary team is engaged in providing consultancy and design services in the chemical process industry in an engineering design and consulting firm. The engineering teams that normally constitute the engineering design and consulting firm are

Importance of IDC Process

During the execution of any project, All the above-mentioned engineering teams prepare several engineering documents and deliverables. However, with very few exceptions, most of the projects are multi-disciplinary in nature. It means, to complete engineering activity drawings, documents, and calculations are required from all disciplines. To brief, the complete engineering package of any project comprises items from all disciplines.

In a multi-disciplinary project environment, drawings, documents, and deliverables for all disciplines become a joint or coordinated effort of all disciplines. Also, the process engineering group is the starting point of any project. As many interrelated disciplines are involved in creating engineering deliverables, the chances of missing an item or generating an error are high. The Interdisciplinary check process, therefore, is an activity to ensure the following:

  1. Complete project awareness creation among the assigned multi-disciplinary team
  2. Ensuring that all critical documents/drawings/calculations are reviewed, marked, and corrected as required by the multi-disciplinary team for correct inputs, removal of errors, and ensuring that the project quality plan is followed for producing first-class project deliverables
  3. Assure that information is flowing periodically during the project execution phase. For example, vendor data, design review(s), HAZOP data, etc. are captured in the engineering deliverables which ensures that these deliverables are useful up to the level for the construction of the plant.

Documents requiring IDC

The author, being a process engineer, The IDC is explained in the context to process engineering. The process engineering documents/drawings that need an IDC from other disciplines are typically listed below:

  • Process Flow Diagrams (need IDC only from Instrumentation and QA)
  • Project Design Basis (Require IDC from Piping, Instrumentation, Mechanical, HSE, Electrical, Civil, Projects, QA)
  • Process & Instrument Diagrams (IDC from Piping, Mechanical, Instrumentation, Electrical, HSE, Projects, QA, Civil)
  • Process Datasheets of Equipment (Piping, Mechanical, Instrumentation, Electrical, QA)
  • Instrument Process Datasheets (Instrumentation, Piping, Electrical, QA)
  • Hazardous Area Classification Drawings (Electrical, Instrumentation, HSE, Mechanical, Piping. QA)
  • Operating, Control, and Safeguarding Philosophy (Instrumentation, Mechanical, Piping, QA)
  • Plant Operating Manual (Piping, Instrumentation, Mechanical, HSE, Electrical, QA)
  • Commissioning and Pre-Commissioning Procedures (Mechanical, Instrumentation, HSE, Piping, QA)
  • Design Review and Closeout Report (Instrumentation, Mechanical, HSE, Piping, Electrical, Projects, QA)
  • HAZOP Review and Closeout Report (Piping, HSE, Instrumentation, Projects, Mechanical, Electrical, QA)

The aforementioned deliverables are just a few examples of the important process/HSE deliverables that require an IDC. Similarly, there are many more deliverables and some of them could also be project-specific.

Some of the engineering deliverables from other disciplines that need IDC from the process are:

  1. Piping Material Requisitions or specifications
  2. Mechanical Material Requisitions or specifications
  3. Instrument Material Requisitions or specifications
  4. Pipe / Valve / special in-line fittings Vendor Data
  5. Electrical Load List prepared by the Electrical
  6. Equipment (Static / Rotating / Package) Vendor Data
  7. Instrument Vendor Data

IDC Matrix

Not all disciplines are required to review all deliverables. For example, A process engineer does not need to do an IDC for a transformer or sub-station specification, or an IDC for civil foundation drawings and structural piles. In a similar way, the process engineer need not review an electrical single-line diagram or instrument loop drawings. It doesn’t make sense for a process engineer to review cable schedules. So IDC is required from relevant disciplines only.

So there must be some analysis of what deliverable requires an IDC and from whom. That’s why good engineering companies prepare an IDC matrix that specifies the discipline-wise individual deliverable which requires an IDC and from whom.

Design Guidelines for PE & ROTO Lined Carbon Steel Piping

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

Carbon steel piping with internal PE / ROTO lining is used for liquid service with high chloride as well as higher oxygen content. The maximum operating temperature of the PE & ROTO lined piping is 60 °C. Also, these types of coatings are suitable for gas-liquid ratio values up to 300.

A PE liner consists of a number of Polyethylene pipe lengths, which are fused together and inserted into sections of carbon steel pipelines and flowlines. The Carbon Steel pipe provides pressure containment; while the PE liner provides corrosion protection. At the ends of the sections, the liners are terminated by PE stub ends. Connections between PE-lined carbon steel pipes shall be flanged.

The PE & ROTO lining is carried out only after the pipe spools are fabricated & hydro-tested. No welding is allowed on the pipe spool once the PE or ROTO lining is done. The pipe trunnion member & line stop members, if applicable, shall be welded prior to the lining. Hydrotesting of the spool or pipelines is done before the lining & after the lining also. Therefore, gaskets are required to be considered for each flanged joint for hydro test purposes.

The requirements to be considered while designing PE-lined piping are mentioned below:

PE/ROTO lining dimensional limitations: 

The longest continuous length of liner, which can be installed in straight pipe, depends on diameter and wall thickness but is generally reduced in practice by local curvature of the line.

For off-plot piping scope, the PE lining can be done for a pipe spool of up to 250m lengths. For shop-lined piping, the maximum length of PE lined pipe spool is kept at 18m because of transportation limitations. The minimum pipe spool length requirement is 5m (can be as less as 2m if agreed with the PE lining vendor). PE lining can be done only for straight pipe spools. It can not be done for pipe spools with reducers or branches. In such cases (for pipe spools with reducers or branches) roto-lining is carried out.

Bends for PE lining shall not be less than 20D radius (recommended radius is 40D wherever possible). PE or ROTO lining cannot be carried out for pipe spools with orifice flanges because of the small size of orifice flange tapings. In this case, one option is to use a suitable material for the upstream & downstream pipe spools & the orifice flanges. And the other option is to use carrier rings with orifice tapings & orifice plates of the suitable material which will get sandwiched between two PE-lined flanges and avoids the use of expensive material for the upstream & downstream pipe spools. 

Annulus Vents

Every PE-lined pipe spool shall have vent points. The minimum number of vent points shall be one on each flanged end of a section of lined pipe. The vent points are to be provided with valves for oil & gas applications & without valves for water service applications. The valves shall be opened only for venting purposes. Continuous venting is not permitted. The purpose of venting is as follows.

  • To vent the (ambient) gas from the pipe/annulus during installation.
  • To vent the permeated fluids accumulated in the annulus to prevent collapse.
  • To allow monitoring of the integrity of the PE liner during the service life.

Vent holes shall be designed such that no extrusion of the PE liner will occur. For larger diameter lines, vent discs with multiple holes or wire screens may be used. Vent holes shall not be larger than 3 mm in diameter. All vents shall be valved (except for water service where vents can be plugged) and shall have a “snorkel” to prevent ingress of dirt, moisture, and/or air.

The design of the vent point assembly shall be agreed upon with the Company.

Design Guidelines for ROTO Lined Piping

Rotolining is a method of lining the inside of pipes or other parts with a seamless, one-piece inner layer of plastic. In this lining technique, the lined spool is produced by heating and rotating a carbon steel spool with a polymer, which is in a granular form, placed inside the pipe spool. The polymer melts and forms a liner on the internal surface of the carbon steel pipe. Also, the polymer forms a bond with the metal.

The choice of which polymer to use is based on the chemical resistance properties that are required for the final part. Polyethylene, Polypropylene, PVDF, or a number of other polymers is used for roto-lining applications. The lining thickness varies from 2 mm to 8 mm. The heavy lining thickness allows the post-machining of critical surfaces that would not be possible with a thinner lining applied by other methods. Virtually any type of metal weldment or casting can be rotolined. Typical items that can be rotolined are tanks, carbon steel pipes, fittings, and complex welded structures.

Rotolining Procedure

The rotolining process comprises placing a polymer having an average particle size of 70-1000 μm containing a melt processible fluoropolymer, in a cylindrical article to be lined (the powder being present in a sufficient amount to make a lining at least 500 μm thick).

The cylindrical article is rotated to bring the radial acceleration at the substrate surface to be coated to 100 m/sec2 or greater, pressing the powder against the article to be lined by means of the centrifugal force generated by that rotation, at the same time heating the melt-processible fluoropolymer to a temperature equal to or higher than the melting point of the melt-processible fluoropolymer, but not higher than 400° C., thereby adhering the melt-processible fluoropolymer to the surface of the article to be lined.

During the heating cycle, the polymer particles begin to stick to the hot metal substrate. Skin is formed. This skin gradually forms a homogenous layer of uniform thickness. Ultimate wall thickness is determined by the amount of material that is initially placed into the cavity.

Adding a small amount of a heat stabilizer such as PPS (polyphenylene sulfide) to prevent the decomposition of the fluoropolymer on heating can give an excellent coating with minimal bubble formation.

After a predetermined time at a specific temperature, the entire polymer is distributed over the surface of the spool. The spool is then cooled by a combination of forced air and water mist.

The part is then removed from the machine and surfaces such as the flange face and “O” ring sealing areas are machined into the plastic. Linings are spark and ultrasonically tested to ensure liner integrity.

The process itself introduces no force or shear to the material. The result is a relatively stress-free lining. Rotolined parts are completely seamless and weld-free.

Advantages of ROTOLINING

  • Seamless construction with a very smooth interior surface.
  • Polymer rotolining has excellent chemical resistance, relatively high-temperature performance, and an excellent metal-to-plastic bond.
  • Thicker lining & uniform wall thickness can be achieved than electrostatic or spray coating.
  • Drastically reduces permeation through the coating and possible corrosion of the metal substrate.
  • The thicker coating can be repaired by welding if mechanically damaged. Thin coatings must be stripped and recoated if repairs are not possible.

ROTO lining dimensional limitations

Guidelines for ROTO lining dimensional limitations are as per below table:

Rotolining Limitations
Rotolining Limitations
Rotolining Dimensional table for Size up to 28 inches
Rotolining Dimensional Table for Sizes up to 28 inches
Rotolining Dimensional Table for Size 32 inches to 40 inches
Rotolining Dimensional Table for Size 32 inches to 40 inches

All dimensions given in the above table shall be considered diagonal lengths. The above dimensions shall be verified with the ROTO lining contractor prior to issuing the isometrics for fabrication.

For ROTO lining minimum branch-off size shall be 1” NB.

The thickness of PE & ROTO lining on the flange raised face (collar thickness) is as per the below Table:

Flange Collar thickness
Flange Collar thickness

The above thicknesses shall be verified with the PE & ROTO lining contractors prior to issuing piping isometric drawings for construction.

Flange joint details for PE / ROTO lining piping: 

Typical PE / ROTO lined flange joint detail is as follows:

Typical Flanged joint
Typical Flanged joint

The 1/2” NB annulus vents shown in the above sketch are for PE-lined pipe spool only.

Galvanized carbon steel retainer rings are used between PE / ROTO lined flange joints to hold the stub ends in place (to avoid the plastic material from deformation). The width of the retainer ring is calculated as follows:

A = (2 x B + 2 x T) – 3 mm

Where,

  • A – Width of the retainer ring
  • B – Thickness of flange raised face
  • T – Collar thickness

Retainer rings are generally provided by the PE lining vendor, still, it has to be confirmed with the vendor at the start of the project.

The following sketches provide information regarding the use of a retainer ring & insulating gasket for PE & ROTO lining flange joints.

Flanged joints
Flanged joints

The use of insulating gasket for PE & ROTO lining piping is restricted for the insulating spools only wherever shown in P&ID/PEFS. For a flange joint between PE / ROTO lined CS piping & SS or DSS mating flange insulating gasket is not required to be provided.

For insulating joint insulating gasket, extra long sleeves, washers & extra long bolts are required. The spectacle blind, spade & spacers shall be considered suitable material for PE & ROTO lined piping and the blind flange shall be epoxy coated or ROTO lined. This shall be finalized with the client & construction contractor prior to the start of a project.

A typical isometric of PE/Rotolined pipe is shown below:

Typical PE/Roto-lined isometric drawing
Typical PE/Roto-lined isometric drawing

Storage Tank Settlement for Piping Stress Analysis

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

In my last article on stress analysis of tank piping, I described the effect of tank bulging. Click here to refresh yourself on the effect of storage tank bulging. In this article, I will describe the effect of storage tank settlement on stress analysis of piping systems connected to large tanks.

Why does settlement occurs for tanks but not for other equipment?

Other equipment’s diameter is usually small (up to 3m). Therefore it is possible to design its foundation with large rafts (say 10 m) to minimize or have an insignificant settlement.

Whereas storage tank diameters are generally large, of the order of 10 m to 60 m. Due to this, it is impractical to design its foundation with a raft, which would be much bigger than this. Many times it has a ring foundation with soil compacted within this concrete ring.

How much settlement is to be considered?

The amount of settlement depends on the location of the tank. The amount of settlement is normally mentioned in the soil investigation reports or geo-technological investigation reports.

IN THE CASE OF SAND:

The majority of the total settlement occurs during the hydrostatic test of the tank (before the piping is connected). This is generally permanent.

… Typically 60%

The balance of 40% of the settlement, occurs after the piping is connected to the storage tank nozzle. And the piping system needs to be designed properly with this settlement effect.

IN THE CASE OF CLAY:

Progressive settlement.

The settlement is more at the center of the storage tank, and typically 50% at the edge of the tank.

Since our nozzles and tank roof are connected/supported on the shell, which is on the outer edge of the atmospheric storage tank, we need to consider the settlement at the outer edge of the tank.

Following Data to be obtained from civil for each tank (for each project)

  • Total long-term settlement.
  • The settlement value that will occur during the construction and hydro test of the tank.
  • Recovery (if any) following construction and hydro test of the tank.
  • The further settlement, after the hydro test of the tank, (at the edge of the tank).

Sample Data from civil for each tank for a typical project is shown in Fig. 1 for understanding.

  • It contains each Tank number.
  • Settlement at the Centre of the Tank.
  • Settlement at Edge of Tank.

Then out of the total settlement at Edge, 40% of the total settlement is what we consider in piping stress analysis.

Sample tank settlement data for piping stress analysis
Fig. 1: Sample tank settlement data for piping stress analysis

Pipe routing guidelines (Fig. 2) to minimize the effect of tank settlement:

To reduce the effect of tank settlement on piping:

  • First support shall be kept sufficiently away from the tank nozzle.
  • Large-diameter piping combined with large tank settlement may call for use of spring support.

However, the use of spring support shall be avoided because accidental draining of the line will cause an excessive upward force on the piping and tank nozzle.

So, if spring support is used

  • WNC (Weight with No Content) load case shall be mandatory for liquid lines. In fact, for all liquid lines with spring support, (whether it is connected to the tank or any other line), a WNC run shall be mandatory. In the case of the tank, all lines connected to the tank will be carrying liquid only.
  • The spring hanger setting should be adjusted in such a way, that the nozzle load is within the limit in the normal operating case, as well as in the WNC case.
  • That is set spring support for loads lower than what is required. This will increase the nozzle load in the normal operating case but will reduce the load in the WNC case.
Figure showing pipe routing guidelines to reduce effect of tank settlement.
Fig. 2: Figure showing pipe routing guidelines to reduce the effect of tank settlement.

Click here to learn about storage tank piping layout considerations.

Pipe Stress Analysis Report Preparation for Issuing to the Client

Written by Anup Kumar Dey in Caesar II,Piping Stress Analysis,Start-Prof

Proper documentation of the stress calculation performed using Caesar II or any other stress analysis software is very important as the report or documents are the final deliverables to the client. So one should incorporate each and every detail of the analysis, assumptions if any, the basis of design, etc. in the final report. Every organization must have its standard format of reporting but the same changes slightly from project to project depending on client requirements. In this article, I will try to highlight major points which must be included in the final report before sending it to the client for approval.

Pipe Stress Analysis Report Front Page

Each final report starts with a very nice front page. The front page normally includes the project name; project no, client name with logo, PMC name with logo, and the performing organization or EPC consultant name with logo. It should also include the name of the stress system and the system number for which the report is prepared.

Contents of Pipe Stress Analysis Report

On the 2nd page normally it is better to include a table with revision details, name of performer, checker, and approver along with signature and report issue date. It informs the client about the responsible persons who are performing the analysis.

The next sheet or page should include brief content of all the major points with page numbers that are included in the report. From this page, the client will be able to know whether all relevant points are incorporated and considered in the analysis or not.

From the next page onwards, the actual analysis report of each stress system starts. Broadly the report should include the following major points:

Project Background: The project background can be included in 3-4 sentences highlighting the major points of the project. Many organizations use this as the starting point for the introduction part of the report. However, I personally do not prefer to include it.

Document Scope and Purpose: Every document must start stating the objective/ scope and purpose of the document. In this part, you can include the major system description. A typical objective is included here for your reference: “The main objective of this document is to furnish the findings of stress analysis performed on SYS-001 (Line 42”-P-YYYY-YYYY line routed from Tie-in YYYY to Tank (T-YYYY) inlet nozzle.” In a similar way, you can describe the system for which you are preparing the report.

Next, you can include a list of all abbreviations that you are going to use in the report. If you are not using abbreviated terms then this part is not required.

Now you have to include the lines which are included in that specific stress system. After including the major system lines, you can include the reference lines with the suffix REF (Ex. 18”-P-1235-REF).

Next, you have to include the names and numbers of all reference documents which are used in the analysis. Reference documents mean you should include the P&ID number with revision, line list number with revision, PMS number with revision, Equipment TAG and GA drawing number with revision, Any datasheet (PSV, Control Valve, etc.) number with revision, etc.

Assumptions and Consideration: The next part of the report is very important. Here you should mention all the considerations and assumptions if any. In a few points, you should mention all major highlights which can impact the stress system. A typical example of assumptions is shown below:

  • The ambient temperature considered is 21° C.
  • All systems have been analyzed for maximum and minimum design temperature cases. The operating temperature from the line list is not used in the analysis.
  • Caesar II configuration file “mm. fil” is used in the analysis.
  • Rigid body weights (flanges, valves, strainers, etc. as applicable) are considered from Caesar II database / Pipe Data Pro.
  • Control valve and PSV weights (wherever applicable) have been assumed suitably based on judgment where vendor data is not available.
  • Based on the YYYYYY project, YYYY has considered the Post Hydro test tank settlement value is assumed as 25 mm. All piping flanges have to be connected with tank nozzle flanges only after the tank hydro testing activity is finished.
  • Seismic Analysis has been ignored in this stress analysis.
  • Wind Analysis has not been performed as most of the lines are below 10 m elevation.
  • The existing part of lines has been modeled taking a reference from the existing PDMS 3D model. We have provided sufficient flexibility for a new line for arresting maximum thermal displacements where we could not find any guides/line stop in the existing line for proper boundary condition.

Conclusions: In this section, you should write in brief the conclusions which you have reached after the analysis. A typical example is shown in the below-mentioned bullet points:

  • Pipe Stresses are within the allowable limits (Refer to the attached Stress Summary Report)
  • Support loads are within the acceptable limits (Refer to attached Restraint Summary Extended Report)
  • Thermal Displacements and Sustained Sagging is within the acceptable limit (Refer to attached Restraint Summary Extended and Sustained displacement Reports)
  • Equipment nozzle loads are qualified with Vendor Allowable Loads in GA drawing/ relevant API standard (for pumps) as applicable (Refer to Nozzle Loading Details Sheet attached)
  • Supports at nodes YYY, ZZZ, and PPP are lifting in design temperature conditions. However, a separate hot sustained/lift-off file has not been made as the system is qualifying under Appendix P operating code stress check of ASME B 31.3. (Refer to attached Stress Summary Report).
  • Refer to marked-up stress isometrics for any stress recommendation.
  • Refer attached spring datasheets and SPS drawings for reference.

Load Cases used in Analysis: In the next section you can mention the load cases that you have considered for analysis. However, as all load cases will appear in the stress summary or restraint summary you can skip this part here.

Detailed Report Appendices: Now you are required to include the following reports from Caesar II. It is better to use an appendix for the same for proper demarcation. A typical method is shown here.

  • Appendix A: Pipe Stress Analysis input echo from Caesar II
  • Appendix B: Stress Summary Report from Caesar II
  • Appendix C: Restraint Summary Extended report from Caesar II
  • Appendix D: Sustained Displacement Report from Caesar II
  • Appendix E: Nozzle load qualification report (Normally in excel sheet, However, NEMA/WRC Caesar II reports can be attached)
  • Appendix F: Trunnion calculation Report
  • Appendix F: Spring datasheets if any
  • Appendix G: SPS drawings if any

Attachments for Reference data: In the final part you should include the final marked-up stress isometrics and reference drawings in attachment form as shown below:

  • Attachment A: Marked-up stress isometrics.
  • Attachment B: P&ID drawing highlighting the system marked up
  • Attachment C: LDT/ Line List drawing highlighting the specific lines.
  • Attachment D: Equipment GA Drawings highlighting the nozzles and relevant data.
  • Attachment E: PMS
  • Attachment F: Caesar II plots for the overall system look.

Briefly, the above-mentioned points are sufficient for a complete report. However, if the client insists on any additional details you have to include the same along with the above-mentioned points. Hope now you will be able to prepare a complete report of the stress systems that you are performing.

Difference Between Centrifugal and Reciprocating Compressor

Written by Ankur Srivastava in Mechanical,Piping Interface,Process

Compressors are mechanical devices that increase the pressure of gases by reducing their volume. They are essential in a wide range of applications, including oil and gas industries, chemical and petrochemical industries, HVAC systems, industrial processes, and transportation. The choice between centrifugal and reciprocating compressors can significantly impact efficiency, cost, and operational performance. This article aims to comprehensively compare these two compressor types, helping readers understand which might be more suitable for their specific needs.

What is a Centrifugal Compressor?

A centrifugal compressor is a dynamic compressor with a radial design. The gaseous fluid enters the center of a rotating impeller with radial blades and is pushed toward the center by centrifugal force, which results in a rise in pressure and increases in kinetic energy. This energy is then converted into pressure by passing through a diffuser and volute. A centrifugal compressor is popularly used in Process Industries, Oil and Gas, Refineries, Wastewater treatment plants, etc. Single- or Multistage compressors are used depending on specific applications and industries.

Centrifugal compressors consist of a rotating impeller and a diffuser. The impeller, which is usually made of materials like aluminum or steel, rotates at high speeds, drawing in gas through the inlet. As the gas moves through the impeller, it gains kinetic energy, which is then converted to pressure energy in the diffuser.

Key Components:

  • Impeller: The heart of the compressor, responsible for adding energy to the gas.
  • Diffuser: Converts kinetic energy into pressure by slowing down the gas flow.
  • Volute: Collects the compressed gas and directs it toward the discharge.

For more details about Centrifugal Compressors Click here

What is a Reciprocating Compressor?

A reciprocating compressor is a positive-displacement compressor that uses a cylinder and piston mechanism to compress the gas. The gas in the inlet section is compressed by the reciprocating motion of the pistons. Reciprocating compressors are used in refineries, gas pipelines, chemical and petrochemical plants, natural gas processing plants, and refrigeration plants.

Reciprocating compressors operate using a piston mechanism within a cylinder. The piston moves back and forth, creating a change in volume that compresses the gas. These compressors can be single-acting or double-acting, depending on whether the gas is compressed on one side or both sides of the piston.

Key Components:

  • Cylinder: Houses the piston and creates the compression chamber.
  • Piston: Moves to compress the gas.
  • Crankshaft: Converts rotational motion into the linear motion of the piston.
  • Valves: Control the intake and discharge of gas.

Click here to know more about Reciprocating Compressors

Centrifugal vs Reciprocating Compressor
Centrifugal vs Reciprocating Compressor

Difference between Centrifugal and Reciprocating Compressor

The major differences between centrifugal compressors and reciprocating compressors are provided below:

Differences in operating principles

Centrifugal Compressors

Centrifugal compressors operate based on the principles of fluid dynamics. The rotating impeller accelerates the gas, converting its velocity into pressure through the diffuser.

Steps in Operation:
  1. Gas Inlet: Gas enters the impeller.
  2. Acceleration: The impeller spins, imparting kinetic energy to the gas.
  3. Pressure Conversion: The diffuser slows down the gas, converting kinetic energy into pressure.
  4. Discharge: The high-pressure gas exits through the volute.

Reciprocating Compressors

Reciprocating compressors utilize the mechanical motion of a piston to compress gas.

Steps in Operation:
  1. Intake Stroke: The piston moves down, creating a vacuum that allows gas to enter the cylinder.
  2. Compression Stroke: The piston moves up, reducing the volume and increasing the pressure of the gas.
  3. Discharge Stroke: The discharge valve opens, allowing high-pressure gas to exit the cylinder.

Differences of Reciprocating Compressors and Centrifugal Compressors in Performance Characteristics

Efficiency

Efficiency in compressors is a critical factor that affects operational costs and energy consumption.

  • Centrifugal Compressors: Generally exhibit high efficiency at large flow rates and are better suited for continuous operation.
  • Reciprocating Compressors: More efficient at lower flow rates but can become less efficient at high flow rates due to the mechanical complexities involved.

Pressure Ratio

The pressure ratio refers to the ratio of the discharge pressure to the inlet pressure.

  • Centrifugal Compressors: Typically achieve high pressure ratios, making them suitable for applications requiring significant pressure increases.
  • Reciprocating Compressors: Can achieve higher pressure ratios but usually require multiple stages to do so effectively.

Capacity Control

Capacity control is essential for adapting to varying demand.

  • Centrifugal Compressors: Often employ variable speed drives or inlet guide vanes for capacity control.
  • Reciprocating Compressors: Use unloading mechanisms, such as suction throttling, to control capacity.

Differences in Applications

Centrifugal Compressors

Centrifugal compressors are widely used in applications that require a continuous supply of gas at high flow rates. Common applications include:

  • HVAC Systems: Used in large chillers for cooling.
  • Gas Processing: In the petrochemical industry for gas transport.
  • Power Plants: For air supply in combustion processes.

Reciprocating Compressors

Reciprocating compressors are versatile and can be found in various applications, including:

  • Refrigeration: For both domestic and industrial refrigeration systems.
  • Gas Transportation: Used in natural gas pipelines for pressure maintenance.
  • Automotive: Employed in air conditioning systems in vehicles.

Differences between Centrifugal and Reciprocating Compressors in Terms of Advantages and Disadvantages

Centrifugal Compressors

Advantages:
  • High Efficiency: Especially at large flow rates.
  • Simple Design: Fewer moving parts, leading to lower maintenance needs.
  • Continuous Operation: Suitable for applications requiring constant airflow.
Disadvantages:
  • Limited Pressure Range: Less effective at low flow rates.
  • Cost: Typically higher initial investment compared to reciprocating compressors.

Reciprocating Compressors

Advantages:
  • Versatility: Can handle a wide range of pressures and flow rates.
  • High Pressure Capability: Excellent for applications requiring significant pressure increases.
Disadvantages:
  • Maintenance: More moving parts can lead to higher maintenance costs.
  • Pulsating Flow: May require additional components to smooth out gas flow.

Differences between Maintenance Considerations

Proper maintenance is essential for both types of compressors to ensure longevity and efficiency.

Centrifugal Compressors

  • Routine Inspections: Check for wear on impellers and diffusers.
  • Lubrication: Ensure proper lubrication of bearings and seals.
  • Vibration Monitoring: Regularly monitor vibrations to detect imbalances.

Reciprocating Compressors

  • Piston Inspection: Regularly check piston rings and cylinders for wear.
  • Valve Maintenance: Inspect and replace valves as needed.
  • Oil Changes: Frequent oil changes to ensure optimal lubrication.

Some additional differences between centrifugal and reciprocating compressors based on various parameters like maximum and minimum flow, inlet and outlet pressure, efficiency, compression ratio, discharge temperature, flow range, materials of construction, cost, etc. are listed below.

The comparison refers to the article titled: “What’s Correct for My Application – A Centrifugal or Reciprocating Compressor” by compression equipment specialists of Ariel Corporation: Paul Gallick – Senior Applications Engineer, Elliott Company; Greg Phillipi and Benjamin F. Williams.

The contents of the above article are produced in a tabular manner with minor modifications based on various other sources and the author’s own understanding.

ParameterCentrifugal CompressorReciprocating Compressor
Maximum FlowThey can be sized for an inlet flow of 680,000 actual m3/h in a single body. Actual means at given suction pressure and temperature. The maximum flow through a centrifugal compressor is limited by the choke point, which is the point at which the flow through some part of the compressor nears a velocity of Mach 1.The capacity of a reciprocating compressor is limited by cylinder size, the number of throws available, and the available driver speeds. A “throw” is a location on the crankcase where a compressor cylinder can be attached.
Minimum FlowIt is recommended that for flow rates of actual 300 m3/h and above, centrifugal compressors be critically evaluated for suitability. Unlike a reciprocating compressor where flow is solely a function of compressor geometry and speed, the minimum flow for a centrifugal compressor is limited by an aerodynamic condition known as surge, which is a function of compressor geometry, speed, aerodynamic gas conditions, and system resistance.Similar to the maximum flow, the minimum flow in a reciprocating compressor is limited by the cylinder size, stroke, and speed. Reciprocating compressors of capacities of a few m3/h are available.
Minimum Suction (Inlet)PressureThis can be atmospheric or sub-atmospheric (vacuum). For sub-atmospheric suction conditions, special seal and buffering designs are employed to prevent atmospheric air from being drawn into the compressor.Can be atmospheric or vacuum. Where suction conditions involve sub-atmospheric pressures, adequate measures must be taken to prevent atmospheric air from leaking into the cylinder through the piston rod packing.
Maximum Discharge (Outlet) PressureFor horizontally split compressors, discharge pressures up to 100 barg are common. For radially split (barrel) compressors, discharge pressures could go as high as 1000 barg.Typical reciprocating compressors in the process industry are used to generate discharge pressures as high as 800 barg. Special compressors known as hyper compressors used in low-density polyethylene manufacture will generate pressures as high as 3500 barg.
Minimum Suction (Inlet) TemperatureStandard Centrifugal compressor materials are typically suitable for -20 to -50 deg C. Refrigeration compressors in ethylene service typically have temperatures as low as -100 deg C which require special low-temperature alloys. The lowest temperature requirement for centrifugal compressors is typically found in LNG boil-off gas applications. Minimum temperatures up to -170 deg C are required to be accommodated for this service and low-temperature alloy steels are employed as materials. Low-temperature seals and O-Rings are also required.The common compressor cylinder materials, cast gray iron, and cast ductile iron are acceptable for use at temperatures as low as -40 deg C which typically occur in refrigeration applications. The lowest suction temperatures required typically are in LNG boil-off applications with requirements as low as -170 deg C and there are very limited manufacturers for this application.
Maximum Discharge (Outlet) TemperatureMaximum discharge temperatures are typically 200 to 230 deg C. Centrifugal compressors with higher temperatures can be manufactured but would require special designs such as center-supported diaphragms, less efficient seal materials, and high-temperature O-rings and sealants.Discharge temperature limits will depend on the application (gas compressed) and the seal element materials selected. In hydrogen-rich gas applications, API 618 (2007) limits discharge temperatures to 135 deg C. For natural gas service, the maximum discharge temperature limit is 175 deg C. However, a more practical limit followed is 149 deg C. Air compressor discharge temperature limits may be as high as 200 deg C.
Flow Range (turndown)The flow range of a centrifugal compressor is determined by the surge and choke points. Typical turndown for a fixed-speed, multi-stage centrifugal pump is approximately 20-30%. With variable speed drive or adjustable inlet guide vanes, the turndown can be increased to 40-50%.Reciprocating Compressors have the ability to change flow through speed control, the addition of fixed clearance to a cylinder (fixed or variable volume clearance pockets), cylinder end deactivation, and gas recycling. The typical flow range might be from 100%, down to 20%, or even lower. The application will determine what type of capacity control method is required and used. On low compression ratio applications (compression ratio less than 1.6, such as pipeline transmission of natural gas) adding fixed clearance will hardly change the flow. Such an application may require speed control or cylinder end deactivation. In other applications with higher compression ratios, clearance pockets and cylinder end deactivation are commonly used to regulate flow.
Compression RatioFor centrifugal compressors, the compression ratio is a function of gas molecular weight, compressibility factor, stage geometry, speed, and the number of compressor stages. For a specific gas, the limits to compression ratio are the mechanical and rotodynamic limitations on speed and the number of stages that can be accommodated in a single body. High discharge temperatures due to high compression ratios can usually be controlled by the intercooling between a compression stage.The maximum compression ratio that a reciprocating compressor can handle in one stage is limited mostly by gas discharge temperature. The piston rod load generated by the compression ratio may also be a limit. Typical compression ratios for one stage are 1.2 to 4.0.
Compressed Gas Molecular WeightThe compression ratio is highly dependent on gas molecular weight. The head is developed by increasing gas velocity to create kinetic energy and then converting the kinetic energy to pressure in the diffuser. The amount of kinetic energy is a function of the gas velocity and gas molecular weight. Centrifugal compressors are used for a broad range of molecular weights including low molecular weight applications such as hydrogen recycling and high molecular weight applications using refrigerant gases with molecular weights over 100.Reciprocating compressors are not limited by gas molecular weight. Both light and heavy gases are compressed very well. Over the range of molecular weight, different application configurations may be required. For example, very low molecular weight gases may present seal challenges and very high molecular weight gases may present challenges related to compressor efficiency.
EfficiencyPolytropic efficiencies are used for centrifugal compressors rather than adiabatic efficiencies. In applications involving air compression adiabatic efficiencies are used. Typical polytropic efficiencies range from 70% to 85%. Efficiencies approaching 90% are possible. Efficiencies are primarily affected by internal leakage and mechanical losses.Reciprocating compressors have a very characteristic adiabatic efficiency curve. Refer to the figure. As the compression ratio drops, adiabatic efficiency drops. Efficiency changes with molecular weight too. Other factors also impact efficiency, most significantly the compressor cylinder’s ratio of valve flow area to main bore diameter and piston speed.
Table 1: Centrifugal Compressor vs Reciprocating Compressors
Adiabatic Efficiency vs Compression Ratio
Adiabatic Efficiency vs Compression Ratio
ParameterCentrifugal CompressorReciprocating Compressor
Multiservice CapabilityTypically, centrifugal compressors are not designed to handle a multitude of gases. Customized designs would be required that could handle different gases simultaneously.Reciprocating compressors are very adaptable to a multitude of gases and can handle different gases at either the same stage or at different stages in the same machine. The number of different services on a given compressor crankcase (frame) is only limited by the throws available and the number of stages required for each service. 8, 10, and even 12 frames are not uncommon
Materials of ConstructionMaterials for major components such as casings, nozzles, shafts, impellers, etc. are primarily carbon steel, stainless steel, and/or alloy steel. Components may be cast, forged, or machined. Cast iron may be used for some stationary components. Material selection is primarily dependent on temperature, stress (pressure/torque), and gas composition (corrosive/erosive).Reciprocating compressors are made of very common materials such as gray iron, ductile iron, carbon steel, stainless steel, and alloy steel. This could be in the cast, forging, or bar stock form. Some compressor pistons and covers may be made of aluminum. For corrosive applications, it is common to use stainless steel such as 17-4PH or 400 series for piston rods and compressor valve seats and guards.
Cost – Capital and OperatingThe capital cost of a centrifugal compressor is typically higher than a reciprocating compressor operating under the same conditions. This is primarily due to the fact that centrifugal compressors require parts with more complex geometry, such as impellers and diaphragms. However, a centrifugal compressor has fewer wearing parts, resulting in lower operating costs in terms of replacement parts, repairs, and downtime. 

For gas pipeline compression services where large centrifugal compressors (>7500 kW) are employed, using gas turbine drivers becomes economical compared to electrical motors when doing a cost evaluation in terms of capital and operating expenditure.		Generally, a reciprocating compressor will have a lower capital cost but a higher operating cost (excluding power consumption). For the same operating conditions, a reciprocating compressor will consume less power per unit volume flow. The reason for the higher operating costs is due to more wearable parts requiring frequent maintenance and leading to higher machine downtime. Compressor valves happen to be one of the most wearable parts in a reciprocating compressor.
ReliabilityThe reliability and availability of centrifugal compressors are typically 98 to 99%.The reliability and availability of reciprocating compressors is typically 95  to 98%. Since reciprocating compressors have many more parts and more rubbing seals (pressure packing, piston rings, and rider rings) that wear and require more frequent replacement, they are considered somewhat less reliable than centrifugal compressors. Another reciprocating compressor component is compressor valves (simple spring-loaded check valves) which require frequent maintenance and replacement
Typical Maintenance IntervalsIn clean gas service and without much variation in operating conditions, a centrifugal compressor can operate continuously for 10 years or longer. Maintenance requirements are typically limited to replacing bearing pads and seal-wearing parts.Maintenance requirements for reciprocating compressors vary significantly with the application and follow maintenance patterns very much based on what has been described in the reliability section. Compressor valve and seal elements may require to be maintained in durations as short as a few months and as long as 3-5 years. Major machine overhaul including bearing replacement may be required after 10 years of operation or longer.
Installation Time and ComplexityThe installation time varies widely depending on the size of the compressor. The number of main casing nozzles and the type of driver (electric motor/gas or steam turbine) also affect installation time. Location can also be a factor. Remote or offshore locations can add to installation time. The compressor and driver are typically packaged on a base plate complete with oil piping and wiring to junction boxes.   Process equipment such as scrubbers, and coolers and process control valves are typically installed at the site. Auxiliary systems such as lube oil consoles, control panels, and seal buffer systems may also be installed separately. Piping and wiring from these auxiliary systems and process equipment to the compressor train are typically done at the site. Installation time for a typical motor / gear-driven compressor package is 2-3 weeks. For a very large compressor or a gas turbine-driven compressor, the installation time could be as high as 6-8 weeks.Installation time for a reciprocating compressor varies significantly with site and location, and whether or not the compressor is packaged. Packaged compressors up to 3.4 MW and of a high-speed short-stroke design are common today. Installation time for these might vary from a few days to a couple of weeks. Larger slow speed long stroke compressors assembled at the site might require 3 to 4 weeks to install
Lead TimeLead time for a centrifugal compressor train range from 35 to 75 weeks. Often the lead time is governed by the driver (electric motor/turbine) since these are generally made to order. Special metallurgy and/or special design requirements of compressor components significantly add to the lead time.Lead time for a bare compressor will vary from 14 to 40 weeks depending on size and manufacturer. Electrical motor-driven reciprocating compressors may require longer lead times specifically if large high-horsepower motors are required.  For reciprocating gas engine-driven large compressors the lead times may be shorter
Table 2: Reciprocating Compressor vs Centrifugal Compressors