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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

What is Category M Fluid Service for Process Piping Design?

Written by Anup Kumar Dey in Piping Design Basics,Process

While referring ASME B31.3 code we come across various types of fluid services. In day-to-day engineering design activities, we normally design and construct systems following the rules of Normal Fluid service. Category M fluid service is different from normal fluid service. As defined in clause 300.2 of ASME B31.3 Category M Fluid Service is a fluid service in which both of the following two conditions apply:

  • the fluid is so highly toxic (poisonous or lethal) that a single exposure to a very small quantity of the fluid, caused by leakage, can produce serious irreversible harm to persons on breathing or bodily contact, even when prompt restorative measures are taken.
  • after consideration of piping design, experience, service conditions, and location, the owner determines that the requirements for Normal Fluid Service do not sufficiently provide the leak tightness required to protect personnel from exposure.

Chapter VIII of ASME B31.3 code provides rules for piping designated by the owner as being in Category-M Fluid Service which means It is the owner’s responsibility to select the fluid service category. Selections of Category D or Category M cannot be made without the owner’s permission.

Also note that it is Category M Fluid Service and not Category M fluids, as it is not simply the fluid, but also the conditions of installation that are considered in making the designation. The owner is guided in the classification of the piping system by the definition of Category M Fluid Service in Chapter I of ASME B31.3. Additionally, a guide to the application of these rules is provided in ASME B31.3, Appendix M, which contains a flow chart to assist the owner in classifying fluid services. This Appendix is considered by the Code to provide guidance, not Code requirements.

It is not possible to create a list of Category M fluids, because the conditions of the installation must be considered in making the classification. For a fluid service to be Category M, the potential for personnel exposure must be judged to be significant. If piping is double-contained, for example, it could be judged that even highly toxic fluids (such as methyl isocyanate, phosgene, or nerve gas) do not make the system Category M, because the potential for personnel exposure is not significant. For Category M fluid service, the rules for Normal Fluid Service are not applicable. Instead, additional rules that lead to more costly construction, with provisions designed to enhance piping system tightness, are provided in Chapter VIII.

If higher integrity piping is desired by the owner, even though the fluid service does not meet the definition of Category M, the owner can still specify the additional design, construction, examination, and testing requirements that are provided in Chapter VIII. Hydrofluoric acid is one example of a fluid for which many owners specify more stringent requirements than are provided in the Code for Normal Fluid Service, although it actually would be considered Normal Fluid Service.

Normally the following should be applicable for Category M fluid services.

  • Use of any temperature other than the fluid temperature as the design temperature shall be substantiated by heat transfer calculations confirmed by tests or by experimental measurements.
  • Design, layout, and operation of piping shall be conducted so as to minimize impact and shock loads.
  • Suitable dynamic analysis, such as computer simulation, shall be made where necessary to avoid or minimize conditions that lead to detrimental vibration, pulsation, or resonance effects in the piping.
  • Allowance for Pressure and Temperature Variations, Metallic Piping is not permitted.
  • Valves having threaded bonnet joints (other than union joints) shall not be used.
  • Special consideration shall be given to valve design to prevent stem leakage into the environment.
  • Bonnet or cover plate closures and body joints shall be flanged and secured by at least four bolts with gasketing.
  • Single-welded slip-on flanges, expanded-joint flanges, slip-on flanges used as lapped flanges, and threaded metallic flanges, except those employing lens rings or similar gaskets and those used in the lined pipe where the liner extends over the gasket face, shall not be used.
  • Split backing rings shall not be used.
  • Socket welded joints greater than DN 50 (NPS 2) are not permitted.
  • Caulked joints shall not be used.
  • Soldered, brazed, and braze welded joints shall not be used. adhesive joints and bell-type joints shall not be used.
  • Relief set pressure shall be in accordance with ASME BPVC, Section VIII, Division 1.
  • The maximum relieving pressure shall be in accordance with Section VIII, Division 1.
  • Materials of unknown specification shall not be used.
  • A piping system designed for Category M service fluid preferably shall not go under severe cyclic conditions
  • No variations in design pressure and/or design temperatures shall be considered even in occasional cases
  • Creased or Corrugate type of bends shall not be used
  • Miter bends shall not make a change in direction at a single joint greater than 22.5 deg
  • Special consideration shall be given to valve design to prevent stem leakage into the environment

Click here for a basis for determining ASME B31.3 Category M fluid services

Process Safety Management (PSM) and Process Safety

Written by Anup Kumar Dey in Health & Safety,Process

What is Process Safety Management (PSM)?

Process Safety Management (PSM) is the management of hazards that can give rise to major accidents involving the release of potentially dangerous materials, the release of energy (such as fire or explosion), or both. It focuses on the prevention of leaks, spills, overpressure, equipment malfunction, excessive temperatures, metal fatigue, corrosion, and other similar conditions by the application of good engineering and design principles. In short, Process Safety Management focuses on controlling the release of highly hazardous substances. All plants handling highly hazardous materials must undergo a sound Process Safety Management program.

Functions of Process Safety Management

The foundation of a process safety management system is to manage risks and reduces them to a tolerable level, either by reducing the likelihood of the hazard release, reducing the consequences if does get released, or both. So, basically, process safety management is a blending of management and engineering skills to prevent catastrophic accidents. The main functions of process safety management are:

  • the proactive and systematic identification of unsafe releases
  • evaluation and mitigation or prevention of chemical releases

A sound Process Safety Management will ensure minimal risk from:

  • Fire
  • Explosion
  • Poisoning, and
  • Suffocation

Written procedures for managing those hazardous releases must be developed and implemented from the design stage itself to ensure proper process safety management.

The US Occupational Safety and Health Administration (OSHA) has issued a Process Safety Management standard “29 CFR 1910.119” for helping chemical companies to identify highly hazardous chemicals and take precautionary action for ensuring a safe and healthy workplace.

What is Process Safety?

Process Safety is defined as “a discipline that focuses on the prevention of fires, explosions, and accidental chemical releases at chemical process facilities”. So it is a disciplined framework for managing the integrity of operating systems and processes that handle hazardous substances. It relies on good design principles, engineering, and operating and maintenance practices. It deals with the prevention and control of events that have the potential to release hazardous materials and energy. Such events don’t only happen at chemical facilities, they occur in refineries, offshore drilling facilities, petrochemical plants, solids handling facilities, water treatment plants, ammonia refrigeration plants, off-shore operations, etc.

Why is Process Safety important?

Process safety hazards can give rise to major accidents involving the release of potentially dangerous materials, the release of energy (such as fires and explosions), or both. Process safety incidents can have catastrophic effects and can result in multiple injuries and fatalities, as well as substantial economic, property, and environmental damage.

Process safety refinery incidents can affect workers inside the refinery and members of the public who reside nearby. Process safety in a refinery involves the prevention of leaks, spills, equipment malfunctions, over-pressures, excessive temperatures, corrosion, metal fatigue, and other similar conditions. Process safety programs focus on the design and engineering of facilities, hazard assessments, management of change, inspection, testing, and maintenance of equipment, effective alarms, effective process control, procedures, training of personnel, and human factors.

Several Major incidents in both the upstream and downstream industries have highlighted the importance of having robust processes and systems in place. A major incident is typically initiated by a hazardous release; it may also result from a structural failure or loss of stability that escalates to become a major incident. For the oil and gas industry, the emphasis of process safety and asset integrity is to prevent unplanned releases which could result in a major incident.

We cannot afford to rely solely on lessons from major process incidents, which happen relatively infrequently. To strengthen safety barriers and prevent these incidents from occurring at all, it is necessary to collect, collate and analyze data from less severe incidents and shortfalls in management system performance. Process safety is required as Failures of process safety management systems are deadly and costly. It impacts people, communities, assets, and the environment.

What is Process Safety Engineering?

Process safety in Design Engineering means

  • Prevention and mitigation of incidents
  • Identifying Safety-critical equipment and linking them to performance standards
  • Compliance with applicable standards
  • Properly design, procure, build, install and test
  • Hand over safe facilities

Engineering process safety emphasizes existing good practices to reduce unsafe acts and conditions. It guides daily actions one can take to prevent these incidents from happening again.

The following image briefly explains the bare minimum steps to follow for process safety in engineering.

Elements of Process Safety Management

To manage chemical operations involving hazardous materials; Process Safety Management must be implemented. The main elements of Process Safety Management are

  • Technology,
  • Design and Engineering Facilities
  • Hazard Assessment
  • Management of Change
  • Regular Inspection and Testing
  • Equipment Maintenance
  • Effective Alarm Management
  • Implementation of process control,
  • Proper operating procedures
  • Maintaining all regulatory requirements
  • and Human factors.

Reasons for Process safety management

There are numerous reasons to implement process safety management in plants. The main reasons are:

  • Prevention of major accidents and potential impact of the same.
  • Managing the risks inside the plant.
  • increasing sustained value and boosting productivity.
  • produce a high-quality product at less cost.
  • Increasing profit.
  • Keeping the environment safe.
  • increase shareholder value.

So the main role of process safety management is to keep the hazard under control inside the equipment or pipes that are designed and maintained to handle them safely. It requires a commitment from design, engineering, operation, and maintenance personnel to follow all the roles without deviation.

Fundamental Questions for Safety Management Process

To reduce or manage the process safety risk inside a plant one must ask the following four fundamental questions:

  • What can go wrong?
  • Are proper controls in place if a major incident occurs?
  • What does each control deliver in terms of a “safety outcome”?
  • Is it confirmed that the controls will work as intended?

Process Safety Management Process

A sound process safety management can be achieved by ensuring the following:

  • Design Integrity
  • Technical Integrity, and
  • Operating Integrity

Design Integrity:

Design integrity ensures the integrity of all activities prior to commissioning. This leads to

  • compliance with the design and engineering standards
  • robust assurance process during the EPC phase.
  • design HSE cases
  • to identify the maintenance routine for Safety-Critical Equipment.
  • written Design and Operating philosophy
  • with clear agreement on maintenance and inspection strategies.

Technical Integrity:

It means the safeguarding of assets through effective maintenance, inspection, repair, and assurance that can be achieved through

  • Identification of safety-critical elements
  • Maintaining readily accessible, up-to-date information.
  • Verification of appropriate inspection and rectification of deficiencies.

Basically, technical integrity is established during the design, construction, and commissioning phases.

Operating Integrity:

It means operating facilities within safe operating limits all the time, maintaining and following the procedures. This is achieved through

  • Verification of operating parameters against design parameters.
  • Clear, consistent, and effective communication and shift handovers
  • Accessible and up-to-date procedures, critical drawings, and documents
  • Establishing a permit system only for authorized personnel

Piping Nipples for Piping and Plumbing Industry

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

In the piping and plumbing industry, a piping nipple is a pipe fitting, consisting of a short straight piece of pipe, usually provided with male pipe thread at both ends, for connecting two other female threaded fittings or pipes. It is one of the most popular categories of pipe fittings. Pipe Nipples are commonly used as adapters from one connection type to another.

Pipe nipples are mainly used in low-pressure piping systems. They are used to fit straight-end hoses or pipes. The working pressure of pipe nipples will vary with the size and construction of the pipe, temperature, and product being conveyed. Pipe nipples are available in the widest variety of wall thicknesses and materials in the industry.

Pipe nipples are fabricated by cutting a specified length of pipe and applying the desired end connections. The pipe nipple dimensions and material follow pipe specifications based on ASME code B16.11. Pipe nipples come in seamless, threaded, grooved, barbed, bent, or welded construction.

Applications of pipe nipples

Pipe nipples as pipe fittings in a wide variety of industrial applications like:

  • Oil & Gas
  • Chemical processing industries
  • Petrochemical
  • Pharmaceutical
  • Food & beverage
  • Pulp & paper
  • Shipbuilding/marine
  • Waste incineration
  • Machine building
  • Architectural
  • Semiconductor etc.

Pipe Nipple Ordering Information

When ordering pipe nipples, the following properties must be specified:

  • Diameter
  • Length
  • Schedule or thickness
  • Material  (Brass/ Aluminium/ Stainless steel/ Iron/ Copper/ PVC/ Carbon steel/ Cast Iron)
  • End Connections (Threads/ Bevelled Ends/ Square Cut Ends/ Grooved/ Bended/ Barbed/ Seamless)
  • Technical Specifications like Pressures, Temperatures, Safety coefficients, Conformity to the standards, Certifications, Standard, Double duty, Extra duty, Extra double duty, etc.

The length of the pipe nipple is usually specified by the overall length including threads. Pipe Nipples can come in any specified length, but most commonly range between close to 12”.  A close pipe nipple is the shortest piece of pipe necessary to allow for fully threaded end connections, where there is no smooth surface between threads. Threads used on nipples are BSP, BSPT, NPT, NPSM, and Metric.

Types of Pipe Nipples

There are several different types of pipe nipples in common use. A short list includes:

  • Barrel Nipple
  • Close Nipple / Running Nipple
  • Hexagonal Nipple
  • Reducing Nipple / Unequal Nipple
  • Hose Nipple
  • Welding Nipple
  • Swage Nipple
Various types of Piping Nipples
Fig. 1: Various types of Piping Nipples

Swage nipple

The basic purpose of a swage nipple is to bring the flow of fluids from one pipe size to another. These are available with plain, beveled, or threaded ends.

Close Nipple / Running Nipple

In its most basic form, a pipe nipple is a short length of pipe with male pipe threads at both ends for connecting other fittings. Generally, there is a short distance of unthreaded pipe between the two threaded ends, depending on how far apart you need the attached fittings to be. When there is no unthreaded pipe between the two connecting ends, the pipe nipple is called a “close nipple” or a “running nipple”. In that case, connected fittings come close to touching one another and very little of the nipple can be seen.

Close nipples are difficult to work with. A close nipple can only be unscrewed by gripping one threaded end with a pipe wrench which will damage the threads and necessitate replacing the nipple, or by using a specialty tool known as a nipple wrench which grips the inside of the pipe, leaving the threads undamaged.

Hexagonal Nipple

In pipe nipples where there is a little space between both the threaded ends, there may have a hexagonal section in the center for a wrench to grasp the nipple. These nipples are called “hexagonal nipples”. This hexagonal section in the middle functions like a nut that can be gripped by a normal wrench, providing a greater mechanical advantage than a normally rounded pipe nipple. A hexagonal nipple with more distance between the threaded ends is called a “long hex nipple”.

Reducing Nipple / Unequal Nipple

For ping systems that require a change in pipe dimension, “reducing nipple” or “unequal nipple” is used. Reducing nipple takes a female fitting with a larger connection and attaches it to a smaller one. Care should be taken when using these parts since a reduction in pipe diameter can mean more pressure and a greater flow rate in the smaller pipe/fitting.

Hose Nipple

For piping systems that require pipe connection to tubing, a “hose nipple” is used. A hose nipple features a male threaded connection on one end and a hose barb on the other end. The hose barb may be the same size as the pipe connection or it may be of reduced size.

Welding Nipple

For piping systems that require to be connected to welded pipes or fittings, a “welding nipple” is used. The welding nipple has a threaded connection on one end and a normal cut pipe at the other end. The unthreaded end of the pipe provides more surface area for the use of welding materials to make a stronger connection. One main benefit of welding nipples is that once the unthreaded end is connected, connecting pipes or other fittings to the threaded end becomes much easier.

Pipe Nipple End Connections

The end connections need to be specified by the customer as well;

  • Plain Both Ends (PBE), Threaded Both Ends (TBE), Bevelled Both Ends (BBE), Threaded One End (TOE), Bevelled One End (BOE), Plain One End (POE), or a combination thereof, depending on the ends of the piping system into which the pipe nipple will be fitted.
  • A Plain Both Ends (PBE) pipe nipple, has both ends as plain ends, with no thread, typically used to fit a socket weld connection.
  • A Threaded Both Ends (TBE) pipe nipple has both ends as threaded ends and is used to fit female threaded connections.
  • A Bevelled Both Ends (BBE) pipe nipple has both ends as bevel ends and is used for welding purposes like a buttweld fitting.
End Connection of Pipe Nipples
Fig. 2: End Connections of Pipe Nipples

Finishes on piping nipples

Piping Nipples comes with the following finishes

  • Black coating
  • Electro-galvanized
  • Hot-dipped galvanized finishes
  • Copper plating etc.

Few more related resources for you.

Types of Reducers in the Piping Industry
Piping Elbows vs Bends: A useful literature for piping engineers
“Pipe Coupling”-A short Introduction for the piping professionals
Different Types of Hose Couplings
A Literature on Piping Nipples for piping and plumbing industry
Guidelines for Selection of Various Types of Flanges

Basics of Shell and Tube Heat Exchangers

Written by Anup Kumar Dey in Mechanical

A Heat exchanger is a device to transfer heat from one fluid (Liquid/Gas) to another. There are various types of heat exchangers used in process piping. Shell and Tube heat exchanger is the most common type of heat exchanger. This article will provide you with a guide to everything you need to know about shell and tube heat exchangers. The major topics covered in this article are:

  • Definition of Shell and Tube Heat Exchanger
  • Working Principle of Shell and Tube Heat Exchanger
  • Basic Components and Parts
  • Types of Shell and Tube Heat Exchanger
  • Codes and Standards for Shell and Tube Heat Exchangers
  • Design of Shell and Tube Heat Exchangers
  • And much more.

What is a Shell and Tube Heat Exchanger?

Shell and tube heat exchanger (STHE) is the most widely used heat exchanger and is among the most effective means of heat exchange. A shell and tube heat exchanger is a device where two working fluids exchange heat by thermal contact using tubes housed within a cylindrical shell. The fluid temperature inside the shell and tube are different and this temperature difference is the driving force for temperature exchange. Used for wide temperature and pressure ranges, Shell and tube heat exchangers are compact in design, easy to construct and maintain, and provide excellent heat exchange.

As the name specified, it consists of a shell and a number of tubes. The shell is the housing of the exchanger and tubes are mounted inside the cylindrical shell.

Working Principle of Shell and Tube Heat Exchanger

The working of a shell and tube heat exchanger is fairly simple. One fluid flows inside the tubes and the other through the shell. While flowing they exchange heat which means the cold fluid gains the heat from the hot fluid. So one cold fluid enters the shell (or tube side or channel side) inlet nozzle and comes out of the outlet nozzle as hot fluid. Obviously, the other fluid will become colder in the outlet than in the inlet. The heat transfer in a shell and tube heat exchanger is determined by the exposed surface area and is decided by the number of thermally conductive metal tubes. The fluid flow inside the shell and tube heat exchanger can be parallel flow or crossflow.

Fig 1 shows the typical working principle of a shell and tube heat exchanger.

Working principle of Typical Shell and Tube Heat Exchanger
Fig. 1: Working principle of a Typical Shell and Tube Heat Exchanger

The above figure shows both the inlet and outlet nozzle in the front header of the channel side. That means this exchanger consists of an even number of tube passes. However, there can be an odd number of tube passes. In that situation, the channel side outlet nozzle will be on the read header. Increasing the number of tube passes increases the heat transfer coefficient.

To increase the fluid turbulence in the tube and shell side flow, turbulators and baffles are installed inside tubes and shells respectively. This increases the heat transfer between the fluids.

Basic Components of Shell and Tube Heat Exchanger

Typically a Shell and Tube Heat Exchanger consists of two-compartment / sections; one is shell side and the other is channel/tube side

  • The shell side section consists of the following components: Shell, Cover, Body Flange, Nozzles, and Saddle support.
  • Channel / Tube side section consists of the following components: Channel, Cover, Body Flange, Nozzles, Tube Sheet, and Tubes  (Tube Bundle)
Components of a Shell and Tube Heat Exchanger
Fig. 2: Components of a Shell and Tube Heat Exchanger

The heat exchanger is supported by saddles in the shell part.

Tube Bundle of Shell and Tube Heat Exchanger

Tube Bundle (Fig. 3) consists of the following components

  • Tube sheet
  • Tubes
  • Baffles
  • Tie rods and Spacers
  • Sliding strips

Tube bundles are removed during maintenance. Standard practice is to flow the corrosive fluid inside the tubes so that if corroded they can be easily replaced or repaired. Fig. 3 below shows a typical tube bundle.

Typical tube bundle of a shell and tube heat exchanger
Fig. 3: Typical tube bundle of a shell and tube heat exchanger

Tube Pattern inside Shell & Tube Heat exchanger

Normally tubes inside the exchanger are 0.5″ to 2″ in size and arranged in triangular or square patterns as shown in Fig. 4

Typical tube patterns
Fig. 4: Typical tube patterns

Tube Pitch

The tube shall be placed with a minimum center-to-center distance of 1.25 times the tube outside diameter of the tube. When mechanical cleaning of the tube is specified then a minimum cleaning lane of 6.4 mm shall be provided.

Baffles

Baffles are installed in the shell of the shell and tube heat exchanger to create more turbulence and increase the flow time so that better heat exchange is possible. Baffles support the tubes so that damage and vibration of tubes are minimized.

Types of Shell and Tube Heat Exchangers

TEMA shell and tube heat exchanger types based on application

As per TEMA (Tubular Exchanger Manufacturers Association) Shell and Tube Heat Exchanger can be classified as

  • Class R Exchangers – Refinery and Petrochemical Application
  • Class C Exchangers – General Process Application
  • Class B Exchangers- Chemical Process Application

TEMA Shell and Tube Heat Exchanger Applicable Criteria

  • Inside diameter less than 2540 mm (100 inches)
  • Product of nominal diameter (mm) and design pressure (kPa) of   17.5 x 106
  • Design pressure of 3000 psig (20684 KPa)

The reason behind such limitation is to keep the maximum shell wall thickness below 3 in. (76 mm), and the maximum stud diameter below 4 in. (102 mm).

Shell and Tube heat exchanger types based on construction

Depending on various construction and configuration parameters following types of shell and tube heat exchangers are widely used in industries.

Fixed Tube Sheet Heat Exchanger

The tube sheet is fixed in the shell by welding and hence the term fixed tube sheet exchanger applies. This simple and economical construction allows the cleaning of the tube bores by mechanical or chemical means. An expansion bellow is installed in the shell when there is a large temperature difference between the shell and tube materials. Refer to Fig. 5 for an example of the fixed tube heat exchanger.

Example of a typical fixed tube heat exchanger
Fig. 5: Example of a typical fixed tube heat exchanger

Floating Head Heat Exchanger

In floating head construction, the rear header can float or move as it is not welded to the shell. The tube bundle can easily be removed during maintenance. Fig. 6 shows an example of a floating head heat exchanger.

Example of a typical Floating Head Removable bundle heat exchanger
Fig. 6: Example of a typical Floating Head Removable bundle heat exchanger

Stationary Tube sheet with removable tube bundle

Fig. 7 shows an example of a stationary tube sheet with a removable tube bundle.

Example of a typical stationary tube sheet type heat exchanger
Fig. 7: Example of a typical stationary tube-sheet type heat exchanger

U-tube Heat exchanger

U-tube exchangers are a type of shell and tube heat exchanger whose tube bundle is made of continuous tubes bent into a “U” shape. The bend side is free-floating and this helps in thermal expansion without requiring expansion joints. However, such bends are difficult to clean.

Typical representation of U-tube Heat exchanger
Fig. 8: Typical representation of U-tube Heat exchanger

Based on the number of times the tube-side/shell-side flows pass through the exchanger, the shell and tube heat exchanger is categorized as:

  • Single-Pass exchangers and
  • Multi-Pass exchangers

The full TEMA classification of shell and tube heat exchanger types is provided in Fig. 9 below:

TEMA Shell and Tube Heat Exchanger types
Fig. 9: TEMA Shell and Tube Heat Exchanger types

Depending on the application of shell and tube heat exchangers, they are known as various types as listed below:

Stack Types of Configuration

In this, two or three heat exchangers are placed one above the other. This is termed as 1 shell in parallel and 2 or 3 Shells in series. Refer to Fig. 10.

Figure showing stack arrangement of heat exchangers
Fig. 10: Figure showing stack arrangement of heat exchangers

Codes and Standards for Shell and Tube Heat Exchangers

The following codes and standards govern the design of shell and tube heat exchangers.

  • API 660 ( Shell and Tube heat exchangers for general refinery service)
  • ISO 16812
  • ASME SECT.VIII Div.1 (UHX) or Div.2
  • PD 5500
  • EN 13445
  • AD 2000 Merkblatt.
  • TEMA -Tubular Exchanger Manufacturers Association
  • Shell DEP 31.22.20.31 and DEP 31.21.01.30

Design of Shell and Tube Heat Exchangers

Process Design of Shell and tube Heat exchanger

The design of the Shell and tube heat exchanger is a trial-and-error iterative process. In recent times, thermal design has been carried out by the process team using engineering software. However, the logic behind the calculations should be clearly understood. The shell and tube heat exchanger design calculations are based on the initial selection of a preliminary exchanger configuration and certain initial decisions like

  • the front and rear header type,
  • shell type,
  • the sides the fluids are allocated,
  • baffle type and baffle pitch
  • tube diameter, length, and tube layout
  • shell diameter, and
  • number of tube passes

Further steps for the shell and tube heat exchanger design consist of

  • Calculation of shell side flow distribution and heat transfer coefficient
  • Estimation of tube side heat transfer coefficient and pressure drop
  • Determination of wall resistance and overall heat transfer coefficient
  • Calculation of Mean temperature difference (log mean temperature difference) from the inlet and outlet temperatures of the two fluids.
  • Estimation of the required heat transfer area
  • Comparison of the calculated area with the assumed geometry
  • Comparison of shell and tube-side pressure drop with allowable pressure drop
  • If the pressure drop is within the allowable pressure drop design is acceptable. Otherwise, adjust the assumed geometry and repeat the above steps.

Once the requirements are met, a process datasheet is developed indicating all process design parameters of shell and tube heat exchanger design.

General design Considerations for shell and tube heat exchanger

Fluid Allocation: Shell Side vs. Tube Side

The following table (Table 1) provides general guidelines for shell and tube side fluid allocation in a shell and tube heat exchanger:

Fluid ParametersFluid Allocation-Shell SideFluid Allocation-Tube Side
High-Pressure Fluid Stream X
Corrosive Fluid X
High-fouling fluid stream X
More Viscous fluidX 
Lower Flow Rate FluidX 
Fluid with a low heat transfer coefficientX 
Toxic Fluid X
Table 1: Shell and Tube-side Fluid Allocation

Fluid Velocity inside Shell and Tube

High fluid velocities increase heat transfer coefficients and reduce fouling but cause erosion and increase pressure drop. So velocity selected should be just enough to prevent the settling of suspended solids. Typical fluid velocities considered for the design of shell and tube heat exchangers are given in the following table (Table 2):

Fluid TypesFluid Velocity-Shell SideFluid Velocity-Tube Side
Liquid0.3 to 1 m/s1 to 2 m/s
Gas /Vapor (Vacuum Pressure)50 to 70 m/s50 to 70 m/s
Gas /Vapor (Atmospheric Pressure)10 to 30 m/s10 to 30 m/s
Gas /Vapor (High Pressure)5 to 10 m/s5 to 10 m/s
Table 2: Typical fluid Velocities in Shell and Tube Heat Exchanger Design

Pressure Drop Consideration

Typical pressure drop values considered for shell and tube heat exchanger design are:

  • For Liquids with Viscosity<1 mN-s/m2, ΔP=35 kPa
  • For liquids with Viscosity=1 to 10 mN- s/m2, ΔP= 50-70 kPa
  • Liquids without phase change= 70 kPa
  • Condensing streams= 14 kPa
  • For Vapor and gas services:
    • High vacuum Pressure: 0.4-0.8 kPa
    • Medium vacuum Pressure: 0.1 x absolute pressure
    • Pressure 1 to 2 bar: 0.5 x system gauge pressure
    • Pressure above 10 bar: 0.1 x system gauge pressure
    • Vapors without phase change= 14 kPa
    • Boiling Streams = 7 kPa

Software used for Thermal Design

The most popular software used for the thermal design of shell and tube heat exchanger are listed below

  • HTRI – Heat Transfer Research Institute
  • HTFS – Heat Transfer Research and fluid flow service

Mechanical design of Shell and Tube Heat exchanger

Mechanical design of shell and tube heat exchangers consists of calculation of shell thickness, flange thickness, etc. Various codes like ASME Sec VIII, PD 5500, TEMA, etc. provide guidelines for mechanical design. The following design guidelines can be followed:

  • Minimum Shell Thickness (Fig. 11) as per TEMA for Class – R
Minimum Shell thickness of shell and tube heat exchanger
Fig. 11: Minimum Shell thickness of shell and tube heat exchanger
  • Baffle clearance, Baffle spacing, and thickness as per TEMA table RCB -4.3
  • Tie rod size and nos. as per TEMA table R- 4.71  for class – R
  • Peripheral Gasket: The minimum width of the peripheral ring gasket for external joints shall be 10 mm for shell sizes up to 584 mm and 12 mm for all larger shell sizes.
  • Pass Partition Gasket: The min. width of the gasket web for the pass partition of the channel shall not be less than 6.4 mm for shell sizes up to 584 mm and 9.5 mm for all larger shell sizes. The gasket joint shall be confined type
  • Shell and Head design is done as per selected Pressure Vessels Design Code  such as ASME, EN, or AD
  • The most widely used design code across the world is ASME Sect. VIII Div.1 & 2
  • Body / Girth Flange Design as per Appendix -2 of ASME Sect. VIII Div.1
  • The tube sheet design is Mandatory as per UHX of ASME Sect. VIII Div.1
  • The tube sheet is designed for the following three cases.
    • Tube side pressure (Pt) acting and Shell side pressure (Ps) is Zero
    • Shell side pressure (Ps) acting and Tube side pressure (Pt) is Zero
    • Shell side pressure (Ps) acting and Tube side pressure (Pt) acting
  • Please consider the effect of Vacuum in the above load cases
  • Tube sheet Design formula based on the theory of Flat Plates

Shell and Tube Heat Exchanger Material of Construction (MOC)

The following materials are the most common as Shell and Tube Heat Exchanger MOC.

  • Carbon steel and Cladding Plates
  • Stainless Steel
  • Duplex Stainless steel
  • Tubes –  Carbon steel, Stainless steel, Duplex stainless steel, Exotic material such as copper, Inconel, Titanium

Maintenance of Shell and Tube Heat exchangers

Depending on user experience and manufacturer guidelines, shell and tube heat exchangers should be inspected at regular intervals. A shell and tube heat exchanger can fail by one or more of the following factors:

  • Improper design.
  • Excessive fouling.
  • Air or gas binding resulting from improper piping installation or lack of suitable vents.
  • Excessive clearances between the baffles and shell and/or tubes, due to corrosion.
  • Operating conditions differ from design conditions.
  • Maldistribution of flow in the unit, etc

Following preventive maintenance steps at regular intervals can reduce the risk of equipment failure. Following maintenance steps can be followed to enhance shell and tube heat exchanger performance:

  • Cleaning periodically to avoid fouling
  • Inspection of tubes
  • Gasket replacement
  • Repairing leaks if detected during inspection.

Application of Shell and Tube Heat Exchangers

Shell & Tube Heat Exchangers find their application in the following Industries-

  • Refinery and Petrochemical
  • Fertilizer
  • Oil and Gas
  • Chemical
  • Power Plants

Advantages of Shell and Tube Heat Exchanger

Shell and tube heat exchangers are widely used in various industrial processes due to their numerous advantages. These advantages make them a preferred choice for many applications where efficient heat transfer is essential. Here are some of the key advantages of shell and tube heat exchangers:

High Heat Transfer Efficiency: Shell and tube heat exchangers are known for their excellent heat transfer capabilities. The design, which features a large surface area for heat exchange, allows for the efficient transfer of thermal energy between the fluids. This results in rapid heating or cooling, making them highly efficient in heat transfer applications.

Versatility: Shell and tube heat exchangers are versatile and can handle a wide range of fluids, including gases and liquids. They can be used for both heating and cooling processes and are compatible with various industries, including chemical processing, power generation, food and beverage, and HVAC systems. They are available in a range of configurations to suit various operations.

Robust and Durable Construction: These heat exchangers are typically built with materials like stainless steel, copper, or titanium, which offer excellent resistance to corrosion and wear. This durability ensures a long operational lifespan, reducing maintenance and replacement costs.

Ease of Maintenance: Shell and tube heat exchangers are relatively easy to maintain. The tube bundle can be accessed and cleaned or replaced without the need to disassemble the entire unit. This feature minimizes downtime and reduces maintenance costs.

Compact Design: Despite their high efficiency, shell and tube heat exchangers have a compact design, which is particularly beneficial in applications with limited space. Their compactness allows for efficient heat transfer within a relatively small footprint.

High Pressure and Temperature Capabilities: Shell and tube heat exchangers are capable of handling high-pressure and high-temperature applications. This makes them suitable for use in industries such as oil refining and chemical processing, where extreme conditions are common.

Customizable Configurations: These heat exchangers can be customized to meet specific requirements. Engineers can adjust the number of tubes, tube diameter, tube arrangement, and other design parameters to optimize performance for a particular application.

Resistance to Fouling: The design of shell and tube heat exchangers often includes baffles and turbulence-inducing features, which help reduce fouling by preventing the buildup of deposits on the tube surfaces. This resistance to fouling ensures consistent heat transfer efficiency over time.

Long Service Life: When properly maintained, shell and tube heat exchangers can have a significantly long service life, making them a cost-effective investment for industries that rely on continuous heat exchange operations.

Energy Efficiency: Their high heat transfer efficiency translates into energy savings. Shell and tube heat exchangers can help reduce energy consumption in processes that require heating or cooling, contributing to overall operational cost reductions.

Disadvantages of Shell and Tube Heat Exchanger

While shell and tube heat exchangers offer numerous advantages, they also have some disadvantages and limitations. It’s essential to consider these drawbacks when selecting a heat exchanger for a specific application. Here are some of the disadvantages of shell and tube heat exchangers:

  • High Initial Cost
  • Large Footprint
  • Limited Heat Transfer for Low Temperature Differences
  • Limited Turbulence
  • High Pressure Drop
  • Fouling and Scaling
  • Weight Considerations

Few more resources for You..

Shell & Tube Heat Exchanger Piping: A brief Presentation
An article on Plate Heat Exchanger with Steam
A typical Check List for Reviewing of Shell & Tube Heat Exchanger Drawings
A brief presentation on Air Cooled Heat Exchangers
Basic Considerations for Equipment and Piping Layout of Air Cooled Heat Exchanger Piping
Reboiler Exchanger and System Type Selection

What are Control Valves? | Selection and Types of Control Valves

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

Control valves are control devices that are used to manage and control fluid flow, pressure, temperature, or liquid level by varying the flow passage size. In process systems of production wells, oil and gas plants, Chemical and Petrochemical industries, refineries, and power plants, Control valves are frequently used to control or manage any of the process parameters.

The piping systems of industrial, commercial, residential, and other civic facilities carry the lifeblood of modern civilization, like arteries and veins. And the valves in those piping systems serve the functions of allowing, stopping, regulating, and controlling the flow, to fulfill the intended objectives of the system.

Valves are an essential part of any piping system that conveys liquids, gases, vapors, slurries, and mixtures of liquid and gaseous phases of various flow media.

Some valves are self-actuated while others are manually operated or have actuators that are powered with electric motors, pneumatic or hydraulic, or a combination to operate the valve. Valves are manufactured with metals and non-metals.

What is a Control Valve?

The control valve is an automated valve that can make precise adjustments to regulate and monitor any commodity flowing through a piping system. The function of a control valve is to provide throttling control in response to signals from a control system, using an actuator and a positioner. They are considered the ‘‘final control element’’ in an automated and usually very sophisticated ‘‘control loop.’’

A control valve receives the information from various sensors and transmitters in a control loop and processes that data to manage the control of the fluid parameter. The following figure shows a typical control loop for a control valve

Typical Control Loop of a Control Valve
Typical Control Loop of a Control Valve

Components of Control Valve

Control valves have basically three interactive components:

  1. a valve body subassembly (either with a reciprocating or rotating stem),
  2. an actuating device (usually a spring diaphragm type),
  3. a valve positioner (an instrument that converts an electronic control signal from a controller, or computer, into an air signal to control the position of the control valve stem), and
  4. an air set or regulator to supply air pressure to the positioner.
Parts of a Control Valve
Parts of a Typical Control Valve

Control Valve Features

The most common valve body style used as a control valve is the globe valve. Although many other body styles such as angle valves, Three-way valves, Eccentric rotary plug valves, semispherical ball valves, Ball Valves, Butterfly valves, etc are used, the globe valve provides the most effective means to regulate and control flow.

Control valves use signals received from instruments positioned throughout the piping system to automatically make adjustments that regulate the commodity within the pipe. Though control valves can perform many functions, they are typically used to control the flow of a commodity within a pipe or to limit its pressure.

Control valves must be arranged within a run of the pipe so that they can be easily operated. To achieve this, control valve manifolds are configured. Control valve manifolds make control valves readily accessible to plant workers.

Control Valve Actuators

The actuator of a control valve is the assembly that provides power for moving the control valve mechanisms. In a control valve loop, actuators move the plug, ball, or vane upon receipt of a signal from the control system to allow or disallow full or partial flow. There are three types of actuators in a Control Valve. They are

  • Pneumatic Actuators
  • Electric Actuators and
  • Hydraulic Actuators

Pneumatic Actuators:

Pneumatic Actuators are the most basic and widely used control valve actuators that use an air or gas signal from an external source to produce a modulating control action. The top port sends the pneumatic signal to the actuator that exerts pressure on the diaphragm plate to move the valve stem. On loss of driver power, pneumatic actuators provide a fail-safe response.

Electric Actuators:

Electric Actuators of a control valve are motor-driven devices. A motor rotates when an electrical signal is received. A gear reduction drive converts this rotating motion into a linear motion to drive the control valve stem for flow modulation. They are used for On-OFF applications in isolation services and for continuous positioning control.

Hydraulic Actuators:

Control Valve Hydraulic actuators use hydraulic oil as the signal fluid. When the force required to move the valve stem is high, hydraulic actuators are used. Due to the non-compressibility of the liquid they exhibit stable positioning.

Specifying Control Valve

The first step in specifying a control valve is to define its function in the given application. In some, it will operate as an on-off valve that opens or closes following the commands of a programmable controller on, say, a batch process. In others, it will be used to remotely set a flow rate in a process—that is, it will be used as a manually controlled variable orifice in a pipe (an open-loop application).

Finally, in more sophisticated applications, the control valve will serve as the final control element in a process control loop and respond to the sometimes infinitely small variations of a signal coming from a controller (typically a computer). The signal will be generated in response to a deviation in the desired temperature, pressure, or level of a process fluid as measured by a transmitter.

More than 90 percent of all control valves use pneumatic actuating devices—either spring-opposed diaphragm types or piston-actuated.

Materials for Control Valves

For noncorrosive use, the material of choice is carbon steel (ASTM A216 Grade WCB, if cast; and A105 when forged). For mild, corrosive applications, valve housings are made from type CF8M (316 stainless steel). However, Teflon-lined housings and exotic alloys, such as Hastelloy, Monel, or Titanium are available for highly corrosive fluids.

Characteristics of different valves to serve as Control Valve

Control Valves play a major role in the everyday effort to increase process plant profitability and conserve energy. Proper selection of these valves can have a significant financial impact on the overall cost of a project and how well the process can be controlled. To narrow down the choices, the engineer must understand how the general characteristics of each type of valve match up with the design requirements. Refer to table 1 for the general characteristics of a few valve types.

General Features of Each type of Valves
General Features of Each type of Valve

Control Valve Characteristics

Each control valve has a flow characteristic, which describes the relationship between the flow rate and the control valve travel. As a valve opens, the flow characteristic, which is inherent to the design of the selected valve, allows a certain amount of flow through the valve at a particular percentage of the stroke. This enables flow regulation through the control valve in a predictable manner. The three most common types of control valve flow characteristics are:

  • Linear
  • Equal percentage
  • Quick opening

Control Valve Selection

There are two major parameters on which the control valve selection is dependent-

  • Service condition and
  • Load characteristics

Other parameters that determine the control valve selection are

  1. Ability to control the flow rate;
  2. Lack of turbulence or resistance to flow when fully open – turbulence reduces head pressure;
  3. Quick opening and closing mechanism – rapid response is many times needed in an emergency or for safety;
  4. Tight shut-off – prevents leaks against high pressure;
  5. Ability to allow flow in one direction only – prevents return;
  6. Opening at a pre-set pressure – procedure control to prevent equipment damage; and
  7. Ability to handle abrasive fluids – hardened material prevents rapid wear.

Control Valve Types

Depending on various parameters control valves are classified as follows:

Types of control Valve
Types of control Valve

Pressure Control Valve

Pressure Control valves help in controlling system pressure within a limit. They are installed in all systems where pressure fluctuations can occur and can cause a hazard if not controlled. Pressure control valves are basically closed valves with a restriction for pressure control. There are two mechanisms on which pressure control valves operate:

  • Direct-Acting Valve and
  • Pilot Operated valve.

Relief valves, reducing valves, etc are examples of pressure control valves.

Control Valve Symbols

The symbols used for different types of control valves in P&ID are as given below:

Control Valve Symbols in P&ID
Control Valve Symbols in P&ID

How to install a Control Valve?

Control valves are normally installed in a horizontal orientation in a straight pipe run preferably away from elbows. The actuator is kept in a vertical position. A bypass valve is installed for continuous operation during control valve inspection and maintenance. Upstream and downstream isolation valves and drains are added to the piping system to isolate the control valve for maintenance. The following figure shows a typical control valve installed in a piping system.

Control Valve in a Piping System
Control Valve in a Piping System

Click here to know about Control Valve Sizing Procedure: Valve Flow Terminologies, Control Valve Characteristics, Cavitation, and Flashing

Control valve sealing classification

The sealing quality of a metal seated control valve is very important. Normally, The higher the pressure class of the valve, the lower the allowable leakage rate in a closed position.

Control Valve Assembly

The control valve assembly is used for controlling process parameters in piping systems. The following figures show typical different arrangements of control valve assemblies

Control Valve Assembly Arrangement
Control Valve Assembly Arrangement
Various types of control Valve Assembly Arrangements
Various types of control Valve Assembly Arrangements
Example of Control Valve Assembly
Example of Control Valve Assembly

The following videos will explain more details about control valves and their working methodology:

Control Valve Basics

The following video briefly describes the basics of Industrial Control Valves.

Flow control valves

Flow control valves are devices that manage the rate of fluid flow in part of a hydraulic circuit. The following video tutorial explains the basics of flow control valves

Few more Resources for you…

Details about control valves
Ball Valve Design Features: A Literature
A brief article on Valve Inspection & Testing
An article on ROTARY SELECTOR VALVE (RSV) and MULTIPHASE FLOW METER (MPFM)
Selection of Valves: A Few Guidelines