Electroplating and Anodising

--Electroplating is an electrolytic process, in which metals are mostly separated from metal salt solutions with the use of a power source and chemical aids.
--Anodising is the electrolytic formation of an oxide layer on light alloys such as Aluminium and Magnesium. Both are electro-chemical processes for the refinement of base materials (e.g. nickel-plating, chrome-plating, gold-plating, anodising, etc.).
Surface properties such as corrosion protection, appearance, electrical properties, resistance to wear, smoothness, ability to be soldered etc. can be significantly altered by applying thin metal layers.
The thickness of these layers can vary from less than 1μm up to several 100 μm. Single layers or a combination of several different layers can be applied. The quality of the coating is always proven and tested using appropriate process controls and monitoring techniques. These involve a number of chemical and physical testing and examination methods....

Blowers

Single Stage Fabricated Centrifugal Blowers

Spencer single stage scroll blowers, aeration/ventilation blowers and heavy-duty RB pressure blowers are widely used in Original Equipment Manufacturing applications and in processes that require uniform airflow over an entire volume range. Typical uses are aeration, combustion air delivery, ventilation, materials handling, air curtains and drying. Maximum airflow volume is 50,000 ICFM, maximum pressure 3.5 PSIG. 

 

 

Multistage Fabricated Centrifugal Blowers

There are three designs of Spencer multistage fabricated machines: standard overhung (SOH), four-bearing overhung (4BOH) and four-bearing outboard (4BOB). Sheet steel construction is standard for blower housings, but other metals can be selected for specialized resistance in cases involving extremely high temperatures, chemicals or corrosive conditions. With housing diameters from 14" to 88", these blowers can handle volume to 25,000 ICFM, pressure to 20 PSIG and vacuum to 15" Hg.

 

 

Custom Blowers & Gas Boosters

For very difficult gas handling jobs, Spencer offers high-performance blowers and gas boosters with special designs and constructions using a variety of high-performance metals such as Hastelloy®, stainless steel and titanium. Typical gases handled include corrosive and toxic sulfides, halogens, acids, flue and stack gases, cyanides and ammonia. Maximum parameters include temperatures to 1100°F, housing design pressures to 1000 PSIG, operating pressures to 300 PSIG.

 

 

Special Features

Spencer has a variety of choices to deal with unusual applications. They include special materials, coatings and corrosion allowances for corrosive gases; effective sealing techniques or hermetic, leaktight configuration for hazardous gases; alternative drivers such as gas turbines instead of electric motors; belt drives for blower operation at a specific speed; various drive arrangements and couplings; and accessories from acoustical wraps to vibration isolating pads.

 

 Cast Centrifugal Blowers

In addition to major components of cast iron, Power Mizer blowers have cast aluminum impellers with three-dimensional blades that transfer energy to the airstream with very high efficiency. In continuous-duty industrial processes and wastewater aeration applications, they offer energy savings of thousands of dollars per blower per year. Performance specifications include pressure to 28 psig (193 kPa), volume to 35,000 icfm (991 m3/min); power to 2000 hp (1491 kW). 

 Regenerative Blowers

Vortex single stage regenerative (side channel) blowers are compact units that are well-suited for in-plant use and for air handling in OEM equipment. They deliver clean, oil-free air without pulsations. Many options are available: TEFC or explosion-proof motors; one-phase or three-phase power; 50 or 60 Hz operation. Maximum performance characteristics: 645 icfm (1096 m3/hr volume, 3.9 psi (27 kPa) pressure and 7.6" Hg vacuum.

Centrifugal Pumps: Basic Concepts of Operation, Maintenance, and Troubleshooting

Introduction

The operating manual of any centrifugal pump often starts with a general statement, “Your centrifugal pump will give you completely trouble free and satisfactory service only on the condition that it is installed and operated with due care and is properly maintained.”

Despite all the care in operation and maintenance, engineers often face the statement “the pump has failed i.e. it can no longer be kept in service”. Inability to deliver the desired flow and head is just one of the most common conditions for taking a pump out of service.

There are other many conditions in which a pump, despite suffering no loss in flow or head, is considered to have failed and has to be pulled out of service as soon as possible. These include seal related problems (leakages, loss of flushing, cooling, quenching systems, etc), pump and motor bearings related problems (loss of lubrication, cooling, contamination of oil, abnormal noise, etc), leakages from pump casing, very high noise and vibration levels, or driver (motor or turbine) related problems.

The list of pump failure conditions mentioned above is neither exhaustive nor are the conditions mutually exclusive. Often the root causes of failure are the same but the symptoms are different. A little care when first symptoms of a problem appear can save the pumps from permanent failures. Thus the most important task in such situations is to find out whether the pump has failed mechanically or if there is some process deficiency, or both. Many times when the pumps are sent to the workshop, the maintenance people do not find anything wrong on disassembling it. Thus the decision to pull a pump out of service for maintenance / repair should be made after a detailed analysis of the symptoms and root causes of the pump failure. Also, in case of any mechanical failure or physical damage of pump internals, the operating engineer should be able to relate the failure to the process unit’s operating problems.

Any operating engineer, who typically has a chemical engineering background and who desires to protect his pumps from frequent failures must develop not only a good understanding of the process but also thorough knowledge of the mechanics of the pump.

Effective troubleshooting requires an ability to observe changes in performance over time, and in the event of a failure, the capacity to thoroughly investigate the cause of the failure and take measures to prevent the problem from re-occurring.

The fact of the matter is that there are three types of problems mostly encountered with centrifugal pumps:

• design errors
• poor operation
• poor maintenance practices

The present article is being presented in three parts, covering all aspects of operation, maintenance, and troubleshooting of centrifugal pumps. The article has been written keeping in mind the level and interests of students and the beginners in operation. Any comments or queries are most welcome.

Working Mechanism of a Centrifugal Pump

A centrifugal pump is one of the simplest pieces of equipment in any process plant. Its purpose is to convert energy of a prime mover (a electric motor or turbine) first into velocity or kinetic energy and then into pressure energy of a fluid that is being pumped. The energy changes occur by virtue of two main parts of the pump, the impeller and the volute or diffuser. The impeller is the rotating part that converts driver energy into the kinetic energy. The volute or diffuser is the stationary part that converts the kinetic energy into pressure energy.

Note: All of the forms of energy involved in a liquid flow system are expressed in terms of feet of liquid i.e. head.

Generation of Centrifugal Force

The process liquid enters the suction nozzle and then into eye (center) of a revolving device known as an impeller. When the impeller rotates, it spins the liquid sitting in the cavities between the vanes outward and provides centrifugal acceleration.

As liquid leaves the eye of the impeller a low-pressure area is created causing more liquid to flow toward the inlet. Because the impeller blades are curved, the fluid is pushed in a tangential and radial direction by the centrifugal force. This force acting inside the pump is the same one that keeps water inside a bucket that is rotating at the end of a string. Figure A.01 below depicts a side cross-section of a centrifugal pump indicating the movement of the liquid.

Figure A.01: Liquid flow path inside a centrifugal pump

Conversion of Kinetic Energy to Pressure Energy

The key idea is that the energy created by the centrifugal force is kinetic energy. The amount of energy given to the liquid is proportional to the velocity at the edge or vane tip of the impeller. The faster the impeller revolves or the bigger the impeller is, then the higher will be the velocity of the liquid at the vane tip and the greater the energy imparted to the liquid.

This kinetic energy of a liquid coming out of an impeller is harnessed by creating a resistance to the flow. The first resistance is created by the pump volute (casing) that catches the liquid and slows it down. In the discharge nozzle, the liquid further decelerates and its velocity is converted to pressure according to Bernoulli’s principle.

Therefore, the head (pressure in terms of height of liquid) developed is approximately equal to the velocity energy at the periphery of the impeller expressed by the following well-known formula:

A handy formula for peripheral velocity is:

This head can also be calculated from the readings on the pressure gauges attached to the suction and discharge lines.

Pump curves relate flow rate and pressure (head) developed by the pump at different impeller sizes and rotational speeds. The centrifugal pump operation should conform to the pump curves supplied by the manufacturer. In order to read and understand the pump curves, it is very important to develop a clear understanding of the terms used in the curves. This topic will be covered later.

General Components of Centrifugal Pumps

A centrifugal pump has two main components:

I. A rotating component comprised of an impeller and a shaft

II. A stationary component comprised of a casing, casing cover, and bearings.

The general components, both stationary and rotary, are depicted in Figure B.01.

The main components are discussed in brief below. Figure B.02 shows these parts on a photograph of a pump in the field.

Figure B.01: General components of Centrifugal Pump

Figure B.02: Gene ral components of a Centrifugal Pump

Stationary Components

Casing

Casings are generally of two types: volute and circular. The impellers are fitted inside the casings.

1. Volute casings build a higher head; circular casings are used for low head and high capacity.

• A volute is a curved funnel increasing in area to the discharge port as shown in Figure B.03. As the area of the cross-section increases, the volute reduces the speed of the liquid and increases the pressure of the liquid.

Figure B.03: Cut-away of a pump showing volute casing

• One of the main purposes of a volute casing is to help balance the hydraulic pressure on the shaft of the pump. However, this occurs best at the manufacturer’s recommended capacity. Running volute-style pumps at a lower capacity than the manufacturer recommends can put lateral stress on the shaft of the pump, increasing wear-and-tear on the seals and bearings, and on the shaft itself. Double- volute casings are used when the radial thrusts become significant at reduced capacities.

2. Circular casing have stationary diffusion vanes surrounding the impeller periphery that convert velocity energy to pressure energy. Conventionally, the diffusers are applied to multi-stage pumps.

• The casings can be designed either as solid casings or split casings. Solid casing implies a design in which the entire casing including the discharge nozzle is all contained in one casting or fabricated piece. A split casing implies two or more parts are fastened together.

When the casing parts are divided by horizontal plane, the casing is described as horizontally split or axially split casing. When the split is in a vertical plane perpendicular to the rotation axis, the casing is described as vertically split or radially split casing. Casing Wear rings act as the seal between the casing and the impeller.

Figure B.04: Solid Casing

Suction and Discharge Nozzle

The suction and discharge nozzles are part of the casings itself. They commonly have the following configurations.

1. End suction/Top discharge (Figure B.05) - The suction nozzle is located at the end of, and concentric to, the shaft while the discharge nozzle is located at the top of the case perpendicular to the shaft. This pump is always of an overhung type and typically has lower NPSHr because the liquid feeds directly into the impeller eye.
2. Top suction Top discharge nozzle (Figure B.05) -The suction and discharge nozzles are located at the top of the case perpendicular to the shaft. This pump can either be an overhung type or between-bearing type but is always a radially split case pump.

Figure B.05: Suction and Discharge Nozzle Locations

3. Side suction / Side discharge nozzles – The suction and discharge nozzles are located at the sides of the case perpendicular to the shaft. This pump can have either an axially or radially split case type.

Seal Chamber and Stuffing Box

Seal chamber and Stuffing box both refer to a chamber, either integral with or separate from the pump case housing that forms the region between the shaft and casing where sealing media are installed. When the sealing is achieved by means of a mechanical seal, the chamber is commonly referred to as a Seal Chamber.

When the sealing is achieved by means of packing, the chamber is referred to as a Stuffing Box. Both the seal chamber and the stuffing box have the primary function of protecting the pump against leakage at the point where the shaft passes out through the pump pressure casing. When the pressure at the bottom of the chamber is below atmospheric, it prevents air leakage into the pump. When the pressure is above atmospheric, the chambers prevent liquid leakage out of the pump. The seal chambers and stuffing boxes are also provided with cooling or heating arrangement for proper temperature control. Figure B.06 below depicts an externally mounted seal chamber and its parts.

Figure B.06: Parts of a simple Seal Chamber

• Gland: The gland is a very important part of the seal chamber or the stuffing box. It gives the packings or the mechanical seal the desired fit on the shaft sleeve. It can be easily adjusted in axial direction. The gland comprises of the seal flush, quench, cooling, drain, and vent connection ports as per the standard codes like API 682.
• Throat Bushing: The bottom or inside end of the chamber is provided with a stationary device called throat bushing that forms a restrictive close clearance around the sleeve (or shaft) between the seal and the impeller.
• Throttle bushing refers to a device that forms a restrictive close clearance around the sleeve (or shaft) at the outboard end of a mechanical seal gland.
• Internal circulating device refers to device located in the seal chamber to circulate seal chamber fluid through a cooler or barrier/buffer fluid reservoir. Usually it is referred to as a pumping ring.
• Mechanical Seal: The features of a mechanical seal will be discussed in Part-II of the article.

Bearing housing

The bearing housing encloses the bearings mounted on the shaft. The bearings keep the shaft or rotor in correct alignment with the stationary parts under the action of radial and transverse loads. The bearing house also includes an oil reservoir for lubrication, constant level oiler, jacket for cooling by circulating cooling water.

Rotating Components

1. Impeller

The impeller is the main rotating part that provides the centrifugal acceleration to the fluid. They are often classified in many ways.

o Based on major direction of flow in reference to the axis of rotation

• Radial flow
• Axial flow
• Mixed flow

o Based on suction type

• Single-suction: Liquid inlet on one side.
• Double-suction: Liquid inlet to the impeller symmetrically from both sides.

o Based on mechanical construction (Figure B.07)

• Closed: Shrouds or sidewall enclosing the vanes.
• Open: No shrouds or wall to enclose the vanes.
• Semi-open or vortex type.

Figure B.07: Impeller types

Closed impellers require wear rings and these wear rings present another maintenance problem. Open and semi-open impellers are less likely to clog, but need manual adjustment to the volute or back-plate to get the proper impeller setting and prevent internal re-circulation. Vortex pump impellers are great for solids and “stringy” materials but they are up to 50% less efficient than conventional designs. The number of impellers determines the number of stages of the pump. A single stage pump has one impeller only and is best for low head service. A two-stage pump has two impellers in series for medium head service. A multi-stage pump has three or more impellers in series for high head service.

o Wear rings: Wear ring provides an easily and economically renewable leakage joint between the impeller and the casing. clearance becomes too large the pump efficiency will be lowered causing heat and vibration problems. Most manufacturers require that you disassemble the pump to check the wear ring clearance and replace the rings when this clearance doubles.

2. Shaft

The basic purpose of a centrifugal pump shaft is to transmit the torques encountered when starting and during operation while supporting the impeller and other rotating parts. It must do this job with a deflection less than the minimum clearance between the rotating and stationary parts.

o Shaft Sleeve (Figure B.08): Pump shafts are usually protected from erosion, corrosion, and wear at the seal chambers, leakage joints, internal bearings, and in the waterways by renewable sleeves. Unless otherwise specified, a shaft sleeve of wear, corrosion, and erosionresistant material shall be provided to protect the shaft. The sleeve shall be sealed at one end. The shaft sleeve assembly shall extend beyond the outer face of the seal gland plate. (Leakage between the shaft and the sleeve should not be confused with leakage through the mechanical seal).

Figure B.08: A view of a shaft sleeve

o Coupling: Couplings can compensate for axial growth of the shaft and transmit torque to the impeller. Shaft couplings can be broadly classified into two groups: rigid and flexible. Rigid couplings are used in applications where there is absolutely no possibility or room for any misalignment. Flexible shaft couplings are more prone to selection, installation and maintenance errors. Flexible shaft couplings can be divided into two basic groups: elastomeric and non-elastomeric

• Elastomeric couplings use either rubber or polymer elements to achieve flexibility. These elements can either be in shear or in compression. Tire and rubber sleeve designs are elastomer in shear couplings; jaw and pin and bushing designs are elastomer in compression couplings.
• Non-elastomeric couplings use metallic elements to obtain flexibility. These can be one of two types: lubricated or nonlubricated. Lubricated designs accommodate misalignment by the sliding action of their components, hence the need for lubrication. The non-lubricated designs accommodate misalignment through flexing. Gear, grid and chain couplings are examples of non-elastomeric, lubricated couplings. Disc and diaphragm couplings are non-elastomeric and nonlubricated.

Industrial Pumps

INDUSTRIAL PUMPS

To keep pumps operating successfully for long periods of time, several elements are required. These elements include careful pump design selection; proper installation; careful operation; the ability to observe changes in performance over time; and, in the event of a failure, the capacity to thoroughly investigate the cause of the failure and take measures to prevent the problem from recurring. Pumps that are properly sized and dynamically balanced; that sit on stable foundations with good shaft alignment and with proper lubrication; that operators start, run, and stop carefully; and that maintenance personnel observe for the appearance of unhealthy trends, usually never experience a catastrophic failure.

The family of pumps comprises a large number of types based on application and capabilities. The two major groups of pumps are dynamic and positive displacement.

Dynamic Pumps (Centrifugal Pump)
Centrifugal pumps are classified into three general categories:

Radial flow – a centrifugal pump in which the pressure is developed wholly by centrifugal force.

Mixed flow – a centrifugal pump in which the pressure is developed partly by centrifugal force and partly by the lift of the vanes of the impeller on the liquid.

Axial flow – a centrifugal pump in which the pressure is developed by the propelling or lifting action of the vanes of the impeller on the liquid.

Positive Displacement PumpA positive displacement pump has an expanding cavity on the suction side of the pump and a decreasing cavity on the discharge side. Liquid is allowed to flow into the pump as the cavity on the suction side expands and the liquid is forced out of the discharge as the cavity collapses. This principle applies to all types of positive displacement pumps whether the pump is a rotary lobe, gear within a gear, piston, diaphragm, screw, progressing cavity, etc.

A positive displacement pump, unlike a centrifugal pump, will produce the same flow at a given rpm no matter what the discharge pressure is. A positive displacement pump cannot be operated against a closed valve on the discharge side of the pump, i.e., it does not have a shut-off head like a centrifugal pump does. If a positive displacement pump is allowed to operate against a closed discharge valve, it will continue to produce flow which will increase the pressure in the discharge line until either the line bursts or the pump is severely damaged or both.
Types of Positive Displacement Pumps

Single Rotor - Vane, Piston, Flexible Member, Single Screw

Multiple Rotor -Gea,r Lobe, Circumferential Piston, Multiple Screw

Component Description

Centrifugal Pumps

Impeller and volute The two main components of a centrifugal pump are the impeller and the volute.

The impeller produces liquid velocity and the volute forces the liquid to discharge from the pump converting velocity to pressure. This is accomplished by offsetting the impeller in the volute and by maintaining a close clearance between the impeller and the volute at the cut-water. A centrifugal pump impeller slings the liquid out of the volute.

Positive Displacement Pumps

Single Rotor:

Vane The vane(s) may be blades, buckets, rollers, or slippers that cooperate with a dam to draw fluid into and out of the pump chamber.

Piston Fluid is drawn in and out of the pump chamber by a piston(s) reciprocating within a cylinder(s) and operating port valves.

Flexible member Pumping and sealing depends on the elasticity of a flexible member(s) that may be a tube, vane, or a liner.

Single screw Fluid is carried between rotor screw threads as they mesh with internal threads on the stator.

Multiple Rotor:

Gear Fluid is carried between gear teeth and is expelled by the meshing of the gears that cooperate to provide continuous sealing between the pump inlet and outlet.

Lobe Fluid is carried between rotor lobes that cooperate to provide continuous sealing between the pump inlet and outlet.

Circumferential piston Fluid is carried in spaces between piston surfaces not requiring contacts between rotor surfaces.

Multiple screw Fluid is carried between rotor screw threads as they mesh.

Relief Valves:

NOTE: It is essential to have a relief valve on the discharge side of a positive displacement pump.

Internal relief valve Pump manufacturers normally have an option to supply an internal relief valve. These relief valves will temporarily relieve the pressure on the discharge side of a pump operating against a closed valve. They are normally not full ported, i.e., cannot bypass all the flow produced by the pump. These internal relief valves should be used for pump protection against a temporary closing of a valve.

External relief valve An external relief valve installed in the discharge line with a return line back to the supply tank is highly recommended to provide complete protection against an unexpected over pressure situation.

Basic Measures to Improve Pump Efficiency
-Shut down unnecessary pumps.
-Restore internal clearances if performance has changed.
-Trim or change impellers if head is larger than necessary.
-Control by throttle instead of running wide-open or bypassing flow.
-Replace oversized pumps.
-Use multiple pumps instead of one large one.
-Use a small booster pump.
-Change the speed of a pump for the most efficient match of horsepower requirements with output.

Pump Efficiency Actions Large Horsepower Pumps (25 HP or greater)

-Here are some actions to take to improve pump efficiency. (Listed in order of decreasing potential for efficiency.)
-Excessive pump maintenance – this is often associated with one of the following:
Oversized pumps that are heavily throttled.Pumps in cavitation. Badly worn pumps.Pumps that are misapplied for the present operation.
-Any pump system with large flow or pressure variations. When normal flows or pressures are less than 75% of their maximum, energy is probably being wasted from excessive throttling, large bypass flows, or operation of unneeded pumps.
-Bypassed flow, either from a control system or deadhead protection orifices, is wasted energy.
-Throttled control valves. The pressure drop across a control valve represents wasted energy that is proportional to the pressure drop and flow.
-Fixed throttle operation. Pumps throttled at a constant head and flow indicate excessive capacity.
-Noisy pumps or valves. A noisy pump generally indicates cavitation from heavy throttling or excessive flow. Noisy control valves or bypass valves usually mean a higher pressure drop with a corresponding high energy loss.
-A multiple pump system. Energy is commonly lost from bypassing excess capacity, running unneeded pumps, maintaining excess pressure, or having a large flow increment between pumps.
-Changes from design conditions. Changes in plant operating conditions (expansions, shutdowns, etc.) can cause pumps that were previously well applied to operate at reduced efficiency.
-A flow-flow, high-pressure user. Such users may require operation of the entire system at high pressure.
-Pumps with known overcapacity. Overcapacity wastes energy because more flow is pumped at a higher pressure than required.

Pumps

Classifications of Pumps

Selecting between Centrifugal Pumps and Positive Displacement Pumps

Pumps are in general classified as Centrifugal Pumps (or Roto-dynamic pumps) and Positive Displacement Pumps.
Centrifugal Pumps (Roto-dynamic pumps)

The centrifugal or roto-dynamic pump produce a head and a flow by increasing the velocity of the liquid through the machine with the help of a rotating vane impeller. Centrifugal pumps include radial, axial and mixed flow units.

Centrifugal pumps can further be classified as 

• end suction pumps
• in-line pumps
• double suction pumps
• vertical multistage pumps
• horizontal multistage pumps
• submersible pumps
• self-priming pumps
• axial-flow pumps
• regenerative pumps 

Positive Displacement Pumps

The positive displacement pump operates by alternating of filling a cavity and then displacing a given volume of liquid. The positive displacement pump delivers a constant volume of liquid for each cycle against varying discharge pressure or head.

The positive displacement pump can be classified as: 

• Reciprocating pumps - piston, plunger and diaphragm
• Power pumps
• Steam pumps
• Rotary pumps - gear, lobe, screw, vane, regenerative (peripheral) and progressive cavity

Selecting between Centrifugal or Positive Displacement Pumps 

Selecting between a Centrifugal Pump or a Positive Displacement Pump is not always straight forward. 

Flow Rate and Pressure Head 

The two types of pumps behave very differently regarding pressure head and flow rate: 

• The Centrifugal Pump has varying flow depending on the system pressure or head
• The Positive Displacement Pump has more or less a constant flow regardless of the system pressure or head. Positive Displacement pumps generally gives more pressure than Centrifugal Pump's.

Capacity and Viscosity

Another major difference between the pump types is the effect of viscosity on the capacity:

• In the Centrifugal Pump the flow is reduced when the viscosity is increased
• In the Positive Displacement Pump the flow is increased when viscosity is increased

Liquids with high viscosity fills the clearances of a Positive Displacement Pump causing a higher volumetric efficiency and a Positive Displacement Pump is better suited for high viscosity applications. A Centrifugal Pump becomes very inefficient at even modest viscosity.

Mechanical Efficiency

The pumps behaves different considering mechanical efficiency as well.

• Changing the system pressure or head has little or no effect on the flow rate in the Positive Displacement Pump
• Changing the system pressure or head has a dramatic effect on the flow rate in the Centrifugal Pump

Net Positive Suction Head - NPSH

Another consideration is the Net Positive Suction Head NPSH.

• In a Centrifugal Pump, NPSH varies as a function of flow determined by pressure
• In a Positive Displacement Pump, NPSH varies as a function of flow determined by speed. Reducing the speed of the Positive Displacement Pump pump, reduces the NPSH

Related Topics

• Pumps Piping systems and pumps - centrifugal pumps, displacement pumps - cavitation, viscosity, head and pressure, power consumption and more

Related Documents

• NPSH - Net Positive Suction Head A definition and an introduction to Net Positive Suction Head - NPSH
• Volume Flow and Temperature Rise in Pumps Calculate temperature rise in pumps
• Positive Displacement Pumps An introduction tutorial to the basic operating principles of positive displacement pumps
• Stable and Unstable Centrifugal Pumps Characteristics of stable and unstable centrifugal pumps
• Centrifugal Pump Speed-Torque Curve Centrifugal pumps characteristics - speed torque curve
• Centrifugal Pumps An introduction to Centrifugal Pumps
• Centrifugal Pumps and Standards Centrifugal pumps design and dimensions standards
• Pumps, Compressors, Blowers and Fans Comparing pumps, compressors, blowers and fans
• Alternating Pumps Secure the system and achieve equal wear by alternate pumps in parallel

SHELL AND TUBE TYPE. FLOATING HEAD TYPE. EXPANDED & DOUBLE TUBE SHEET TYPE.

General Description

Shell and Tube Heat Exchangers are one of the most popular types of exchanger due to the flexibility the designer has to allow for a wide range of pressures and temperatures. There are two main categories of Shell and Tube exchanger:

1. those that are used in the petrochemical industry which tend to be covered by standards from TEMA, Tubular Exchanger Manufacturers Association (see TEMA Standards);
2. those that are used in the power industry such as feedwater heaters and power plant condensers.

Regardless of the type of industry the exchanger is to be used in there are a number of common features (see Condensers).

A shell and tube exchanger consists of a number of tubes mounted inside a cylindrical shell. Figure 1 illustrates a typical unit that may be found in a petrochemical plant. Two fluids can exchange heat, one fluid flows over the outside of the tubes while the second fluid flows through the tubes. The fluids can be single or two phase and can flow in a parallel or a cross/counter flow arrangement.

Figure 1. Shell and tube exchanger.

The shell and tube exchanger consists of four major parts:

• Front Header—this is where the fluid enters the tubeside of the exchanger. It is sometimes referred to as the Stationary Header.
• Rear Header—this is where the tubeside fluid leaves the exchanger or where it is returned to the front header in exchangers with multiple tubeside passes.
• Tube bundle—this comprises of the tubes, tube sheets, baffles and tie rods etc. to hold the bundle together.
• Shell—this contains the tube bundle.

The remainder of this section concentrates on exchangers that are covered by the TEMA Standard.

Shell and Tube Exchanger: Geometric Terminology

The main components of a shell and tube exchanger are shown in Figure 2 a, b and c and described in Table 1.

Figure 2. Type BEM, CFU and AES exchangers. © 1988 by Tubular Exchanger Manufacturers Association.

Table 1. Shell and tube geometric terminology

1	Stationary (Front) Head—Channel	20	Slip-on Backing Flange
2	Stationary (Front) Head—Bonnet	21	Floating Tubesheet Skirt
3	Stationary (Front) Head Flange	22	Floating Tubesheet Skirt
4	Channel Cover	23	Packing Box Flange
5	Stationary Head Nozzle	24	Packing
6	Stationary Tubesheet	25	Packing Follower Ring
7	Tubes	26	Lantern Ring
8	Shell	27	Tie Rods and Spacers
9	Shell Cover	28	Transverse Baffles or Support Plates
10	Shell Flange—Stationary Head End	29	Impingement Baffle or Plate
11	Shell Flange—Rear Head End	30	Longitudinal Baffle
12	Shell Nozzle	31	Pass Partition
13	Shell Cover Flange	32	Vent Connection
14	Expansion Joint	33	Drain Connection
15	Floating Tubesheet	34	Instrument Connection
16	Floating Head Cover	35	Support Saddle
17	Floating Head Flange	36	Lifting Lug
18	Floating Head Backing Device	37	Support Bracket
19	Split Shear Ring

Tema Designations

The popularity of shell and tube exchangers has resulted in a standard nomenclature being developed for their designation and use by the Tubular Exchanger Manufactures Association (TEMA). This nomenclature is defined in terms letters and diagrams. The first letter describes the front header type, the second letter the shell type and the third letter the rear header type. Figure 2 shows examples of a BEM, CFU, and AES exchangers while Figure 3 illustrates the full TEMA nomenclature.

Figure 3. TEMA nomenclature. © 1988 by Tubulare Exchanger Manufacturers Association.

Many combinations of front header, shell and rear header can be made. The most common combinations for an E-Type Shell are given in Table 2 but other combinations are also used.

Table 2. Shell and tube geometric terminology

Fixed tubesheet exchangers	U-tube exchangers	Floating head exchangers
AEL	AEU	AES
AEM	CEU	BES
AEN	DEU
BEL
BEM
BEN

Essentially there are three main combinations

• Fixed tubesheet exchangers
• U-tube exchangers
• Floating header exchangers

Fixed Tubesheet Exchanger (L, M, and N Type Rear Headers)

In a fixed tubesheet exchanger, the tubesheet is welded to the shell. This results in a simple and economical construction and the tube bores can be cleaned mechanically or chemically. However, the outside surfaces of the tubes are inaccessible except to chemical cleaning.

If large temperature differences exist between the shell and tube materials, it may be necessary to incorporate an expansion bellows in the shell, to eliminate excessive stresses caused by expansion. Such bellows are often a source of weakness and failure in operation. In circumstances where the consequences of failure are particularly grave U-Tube or Floating Header units are normally used.

This is the cheapest of all removable bundle designs, but is generally slightly more expensive than a fixed tubesheet design at low pressures.

U-Tube Exchangers

In a U-Tube exchanger any of the front header types may be used and the rear header is normally a M-Type. The U-tubes permit unlimited thermal expansion, the tube bundle can be removed for cleaning and small bundle to shell clearances can be achieved. However, since internal cleaning of the tubes by mechanical means is difficult, it is normal only to use this type where the tube side fluids are clean.

Floating Head Exchanger (P, S, T and W Type Rear Headers)

In this type of exchanger the tubesheet at the Rear Header end is not welded to the shell but allowed to move or float. The tubesheet at the Front Header (tube side fluid inlet end) is of a larger diameter than the shell and is sealed in a similar manner to that used in the fixed tubesheet design. The tubesheet at the rear header end of the shell is of slightly smaller diameter than the shell, allowing the bundle to be pulled through the shell. The use of a floating head means that thermal expansion can be allowed for and the tube bundle can be removed for cleaning. There are several rear header types that can be used but the S-Type Rear Head is the most popular. A floating head exchanger is suitable for the rigorous duties associated with high temperatures and pressures but is more expensive (typically of order of 25% for carbon steel construction) than the equivalent fixed tubesheet exchanger.

Considering each header and shell type in turn:

A-Type front header

This type of header is easy to repair and replace. It also gives access to the tubes for cleaning or repair without having to disturb the pipe work. It does however have two seals (one between the tube sheet and header and the other between the header and the end plate). This increases the risk of leakage and the cost of the header over a B-Type Front Header.

B-Type front header

This is the cheapest type of front header. It also is more suitable than the A-Type Front Header for high pressure duties because the header has only one seal. A disadvantage is that to gain access to the tubes requires disturbance to the pipe work in order to remove the header.

C-Type front header

This type of header is for high pressure applications (>100 bar). It does allow access to the tube without disturbing the pipe work but is difficult to repair and replace because the tube bundle is an integral part of the header.

D-Type front header

This is the most expensive type of front header. It is for very high pressures (> 150 bar). It does allow access to the tubes without disturbing the pipe work but is difficult to repair and replace because the tube bundle is an integral part of the header.

N-Type front header

The advantage of this type of header is that the tubes can be accessed without disturbing the pipe work and it is cheaper than an A-Type Front Header. However, they are difficult to maintain and replace as the header and tube sheet are an integral part of the shell.

Y-Type front header

Strictly speaking this is not a TEMA designated type but is generally recognized. It can be used as a front or rear header and is used when the exchanger is to be used in a pipe line. It is cheaper than other types of headers as it reduces piping costs. It is mainly used with single tube pass units although with suitable partitioning any odd number of passes can be allowed.

E-Type shell

This is most commonly used shell type, suitable for most duties and applications. Other shell types only tend to be used for special duties or applications.

F-Type shell

This is generally used when pure countercurrent flow is required in a two tube side pass unit. This is achieved by having two shells side passes—the two passes being separated by a longitudinal baffle. The main problem with this type of unit is thermal and hydraulic leakage across this longitudinal baffle unless special precautions are taken.

G-Type shell

This is used for horizontal thermosyphon reboilers and applications where the shellside pressure drop needs to be kept small. This is achieved by splitting the shellside flow.

H-Type shell

This is used for similar applications to G-Type Shell but tends to be used when larger units are required.

J-Type shell

This tends to be used when the maximum allowable pressure drop is exceeded in an E-Type Shell even when double segmental baffles are used. It is also used when tube vibration is a problem. The divided flow on the shellside reduces the flow velocities over the tubes and hence reduces the pressure drop and the likelihood of tube vibration. When there are two inlet nozzles and one outlet nozzle this is sometimes referred to as an I-Type Shell.

K-Type shell

This is used only for reboilers to provide a large disengagement space in order to minimize shellside liquid carry over. Alternatively a K-Type Shell may be used as a chiller. In this case the main process is to cool the tube side fluid by boiling a fluid on the shellside.

X-Type shell

This is used if the maximum shellside pressure drop is exceeded by all other shell and baffle type combinations. The main applications are shellside condensers and gas coolers.

L-Type rear header

This type of header is for use with fixed tubesheets only, since the tubesheet is welded to the shell and access to the outside of the tubes is not possible. The main advantages of this type of header are that access can be gained to the inside of the tubes without having to remove any pipework and the bundle to shell clearances are small. The main disadvantage is that a bellows or an expansion roll are required to allow for large thermal expansions and this limits the permitted operating temperature and pressure.

M-Type rear header

This type of header is similar to the L-Type Rear Header but it is slightly cheaper. However, the header has to be removed to gain access to the inside of the tubes. Again, special measures have to be taken to cope with large thermal expansions and this limits the permitted operating temperature and pressure.

N-Type rear header

The advantage of this type of header is that the tubes can be accessed without disturbing the pipe work. However, they are difficult to maintain and replace since the header and tube sheet are an integral part of the shell.

P-Type rear header

This is an outside packed floating rear header. It is, in theory, a low cost floating head design which allows access to the inside of the tubes for cleaning and also allows the bundle to be removed for cleaning. The main problems with this type of header are:

• large bundle to shell clearances required in order to pull the bundle;
• it is limited to low pressure nonhazardous fluids, because it is possible for the shellside fluid to leak via the packing rings;
• only small thermal expansions are permitted.

In practice it is not a low cost design, because the shell has to be rolled to small tolerances for the packing to be effective.

S-Type rear header

This is a floating rear header with backing device. It is the most expensive of the floating head types but does allow the bundle to be removed and unlimited thermal expansion is possible. It also has smaller shell to bundle clearances than the other floating head types. However, it is difficult to dismantle for bundle pulling and the shell diameter and bundle to shell clearances are larger than for fixed head type exchangers.

T-Type rear header

This is a pull through floating head. It is cheaper and easier to remove the bundle than with the S-Type Rear Header, but still allows for unlimited thermal expansion. It does, however, have the largest bundle to shell clearance of all the floating head types and is more expensive than fixed header and U-tube types.

U-tube

This is the cheapest of all removable bundle designs, but is generally slightly more expensive than a fixed tubesheet design at low pressures. However, it permits unlimited thermal expansion, allows the bundle to be removed to clean the outside of the tubes, has the tightest bundle to shell clearances and is the simplest design. A disadvantage of the U-tube design is that it cannot normally have pure counterflow unless an F-Type Shell is used. Also, U-tube designs are limited to even numbers of tube passes.

W-Type rear header

This is a packed floating tubesheet with lantern ring. It is the cheapest of the floating head designs, allows for unlimited thermal expansion and allows the tube bundle to be removed for cleaning. The main problems with this type of head are:

• the large bundle to shell clearances required to pull the bundle and;
• the limitation to low pressure nonhazardous fluids (because it is possible for both the fluids to leak via the packing rings).

It is also possible for the shell and tube side fluids to become mixed if leakage occurs.

Geometric Options

Tube diameter layout and pitch

Tubes may range in diameter from 12.7 mm (0.5 in) to 50.8 mm (2 in), but 19.05 mm (0.75 in) and 25.4 mm (1 in) are the most common sizes. The tubes are laid out in triangular or square patterns in the tube sheets. See Figure 4.

Figure 4. Tube layouts.

The square layouts are required where it is necessary to get at the tube surface for mechanical cleaning. The triangular arrangement allows more tubes in a given space. The tube pitch is the shortest center-to-center distance between tubes. The tube spacing is given by the tube pitch/tube diameter ratio, which is normally 1.25 or 1.33. Since a square layout is used for cleaning purposes, a minimum gap of 6.35 mm (0.25 in) is allowed between tubes.

Baffle types

Baffles are installed on the shell side to give a higher heat-transfer rate due to increased turbulence and to support the tubes thus reducing the chance of damage due to vibration. There are a number of different baffle types, which support the tubes and promote flow across the tubes. Figure 5 shows the following baffle arrangements:

• Single Segmental (this is the most common),
• Double Segmental (this is used to obtain a lower shellside velocity and pressure drop),
• Disc and Doughnut.

Figure 5. Baffle arrangements.

The center-to-center distance between baffles is called the baffle-pitch and this can be adjusted to vary the crossflow velocity. In practice the baffle pitch is not normally greater than a distance equal to the inside diameter of the shell or closer than a distance equal to one-fifth the diameter or 50.8 mm (2 in) whichever is greater. In order to allow the fluid to flow backwards and forwards across the tubes part of the baffle is cut away. The height of this part is referred to as the baffle-cut and is measured as a percentage of the shell diameter, e.g., 25 per cent baffle-cut. The size of the baffle-cut (or baffle window) needs to be considered along with the baffle pitch. It is normal to size the baffle-cut and baffle pitch to approximately equalize the velocities through the window and in crossflow, respectively.

There are two main types of baffle which give longitudinal flow:

• Orifice Baffle,
• Rod Baffle.

In these types of baffle the turbulence is generated as the flow crosses the baffle.

Heat Transfer Enhancements Devices

There are three main types.

Special surfaces

These tend to be used to promote nucleate boiling when the temperature driving force is small.

Tube inserts

These are normally wire wound inserts or twisted tapes. They are normally used with medium to high viscosity fluids to improve heat transfer by increasing turbulence. There is also some evidence that they reduce fouling. In order to use these most effectively the exchanger should be designed for their use. This usually entails increasing the shell diameter, reducing the tube length and the number of tubeside passes in order to allow for the increased pressure loss characteristics of the devices.

Extended surfaces

These are used to increase the heat transfer area when a stream has a low heat transfer coefficient. The most common type is "low fin tubing" where typically the fins are 1.5 mm high at 19 fins per inch. (See also Augmentation of Heat Transfer.)

Selection Criteria

In many cases the only way of ensuring optimum selection is to do a full design based on several alternative geometries. In the first instance, however, several important decisions have to be made concerning:

• allocation of fluids to the shellside and tubeside;
• selection of shell type;
• selection of front end header type;
• selection of rear end header type;
• selection of exchanger geometry.

To a large extent these often depend on each other. For instance, the allocation of a dirty fluid to the shellside directly affects the selection of exchanger tube layout.

Fluid allocation

When deciding which side to allocate the hot and cold fluids the following need to be taken into account, in order of priority.

1. Consider any and every safety and reliability aspect and allocate fluids accordingly. Never allocate hazardous fluids such they are contained by anything other than conventional bolted and gasketted—or welded—joints.
2. Ensure that the allocation of fluids complies with established engineering practices, particularly those laid down in customer specifications.
3. Having complied with the above, allocate the fluid likely to cause the most severe mechanical cleaning problems (if any) to the tubeside.
4. If neither of the above are applicable, the allocation of the fluids should be decided only after running two alternative designs and selecting the cheapest (this is time consuming if hand calculations are used but programs such as TASC from the Heat Transfer and Fluid Flow Service (HTFS) make this a trivial task).

Shell selection

E-type shells are the most common. If a single tube pass is used and provided there are more than three baffles, then near counter-current flow is achieved. If two or more tube passes are used, then it is not possible to obtain pure countercurrent flow and the log mean temperature difference must be corrected to allow for combined cocurrent and countercurrent flow using an F-factor.

G-type shells and H shells are normally specified only for horizontal thermosyphon reboilers. J shells and X-type shells should be selected if the allowable DP cannot be accommodated in a reasonable E-type design. For services requiring multiple shells with removable bundles, F-type shells can offer significant savings and should always be considered provided they are not prohibited by customer specifications

Front header selection

The A-type front header is the standard for dirty tubeside fluids and the B-type is the standard for clean tubeside fluids. The A-type is also preferred by many operators regardless of the cleanliness of the tubeside fluid in case access to the tubes is required. Do not use other types unless the following considerations apply.

A C-type head with removable shell should be considered for hazardous tubeside fluids, heavy bundles or services requiring frequent shellside cleaning. The N-type head is used when hazardous fluids are on the tubeside. A D-type head or a B-type head welded to the tubesheet is used for high pressure applications. Y-type heads are only normally used for single tube-pass exchangers when they are installed in line with a pipeline.

Rear header selection

For normal service a Fixed Header (L, M, N-types) can be used provided that there is no overstressing due to differential expansion and the shellside will not require mechanical cleaning. If thermal expansion is likely a fixed header with a bellows can be used provided that the shellside fluid is not hazardous, the shellside pressure does not exceed 35 bar (500 psia) and the shellside will not require mechanical cleaning.

A U-tube unit can be used to overcome thermal expansion problems and allow the bundle to be removed for cleaning. However, countercurrent flow can only be achieved by using an F-type shell and mechanical cleaning of the tubeside can be difficult.

An S-type floating head should be used when thermal expansion needs to be allowed for and access to both sides of the exchanger is required from cleaning. Other rear head types would not normally be considered except for the special cases.

Selection of Exchanger Geometry

Tube outside diameter

For the process industry, 19.05 mm (3/4") tends to be the most common.

Tube wall thickness

Reference must be made to a recognized pressure vessel code to decide this.

Tube length

For a given surface area, the longer the tube length the cheaper the exchanger, although a long thin exchanger may not be feasible.

Tube layout

45 or 90 degree layouts are chosen if mechanical cleaning is required, otherwise a 30 degree layout is often selected, because it provides a higher heat transfer and hence smaller exchanger.

Tube pitch

The smallest allowable pitch of 1.25 times the tube outside diameter is normally used unless there is a requirement to use a larger pitch due to mechanical cleaning or tube end welding.

Number of tube passes

This is usually one or an even number (not normally greater than 16). Increasing the number of passes increases the heat transfer coefficient but care must be taken to ensure that the tube side ρv² is not greater than about 10,000 kg/m·s².

Shell diameter

Standard pipe is normally used for shell diameters up to 610 mm (24"). Above this the shell is made from rolled plate. Typically shell diameters range from 152 mm to 3000 mm (6" to 120").

Baffle type

Single segmental baffles are used by default but other types are considered if pressure drop constraints or vibration is a problem.

Baffle spacing

This is decided after trying to balance the desire for increased crossflow velocity and tube support (smaller baffle pitch) and pressure drop constraints (larger baffle pitch). TEMA provides guidance on the maximum and minimum baffle pitch.

Baffle cut

This depends on the baffle type but is typically 45% for single segmental baffles and 25% for double segmental baffles.

Nozzles and impingement

For shellside nozzles the ρv² should not be greater than about 9000 in kg/m·s². For tubeside nozzles the maximum ρv²should not exceed 2230 kg/m·s² for noncorrosive, nonabrasive single phase fluids and 740 kg/m·s² for other fluids. Impingement protection is always required for gases which are corrosive or abrasive, saturated vapors and two phases mixtures. Shell or bundle entrance or exit areas should be designed such that a ρv² of 5950 kg/m·s² is not exceeded.

Materials of Construction

In general, shell and tube exchangers are made of metal, but for specialist applications (e.g., involving strong acids or pharmaceuticals), other materials such as graphite, plastic and glass may be used.

Thermal Design

The thermal design of a shell and tube exchanger is an iterative process which is normally carried out using computer programs from organizations such as the Heat transfer and Fluid Flow Service (HTFS) or Heat Transfer Research Incorporated (HTRI). However, it is important that the engineer understands the logic behind the calculation. In order to calculate the heat transfer coefficients and pressure drops, initial decisions must be made on the sides the fluids are allocated, the front and rear header type, shell type, baffle type, tube diameter and tube layout. The tube length, shell diameter, baffle pitch and number of tube passes are also selected and these are normally the main items that are altered during each iteration in order to maximize the overall heat transfer within specified allowable pressure drops.

The main steps in the calculation are given below together with calculation methods in the open literature:

1. Calculate the shellside flow distribution [Use Bell-Delaware Method, see Hewitt, Shires, and Bott (1994)].
2. Calculate the shellside heat transfer coefficient (Use Bell- Delaware Method)
3. Calculate tubeside heat transfer coefficient (see, for example, Tubes: Single Phase Heat Transfer In).
4. Calculate tubeside pressure drop (see, for example, Pressure Drop, Single Phase).
5. Calculate wall resistance and overall heat transfer coefficient (see Overall Heat Transfer Coefficient and Fouling).
6. Calculate mean temperature difference (see Mean Temperature Difference).
7. Calculate area required.
8. Compare area required with area of assumed geometry and allowed tubeside and shellside pressure drop with calculated values.
9. Adjust assumed geometry and repeat calculations until Area required is achieved within the allowable pressure drops.

Books by E. A. D. Saunders [Saunders (1988)] and G. F. Hewitt, G. L. Shires, and T. R. Bott [Hewitt et al. (1994)] provides a good overview of tubular thermal design methods and example calculations.

Mechanical Design

The mechanical design of a shell and tube heat exchanger provides information on items such as shell thickness, flange thickness, etc. These are calculated using a pressure vessel design code such as the Boiler and Pressure Vessel code from ASME (American Society of Mechanical Engineers) and the British Master Pressure Vessel Standard, BS 5500. ASME is the most commonly used code for heat exchangers and is in 11 sections. Section VIII (Confined Pressure Vessels) of the code is the most applicable to heat exchangers but Sections II—Materials and Section V—Non Destructive Testing are also relevant.

Both ASME and BS5500 are widely used and accepted throughout the world but some countries insist that their own national codes are used. In order to try and simplify this the International Standards Organization is now attempting to develop a new internationally recognized code but it is likely to be a some time before this is accepted.