Mihir's handbook of chemical process engineering (Excerpts)

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they may not be reproduced for publication.
ISBN # 978-93-5279-698-4

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PREFACE - ABOUT THE AUTHOR
Mihir M. Patel
Chemical Engineer &
Project Management Professional
https://chemicalprocessengineering.com
The author Mihir M. Patel is a Chemical Engineer with a Master’s degree from USA in 1987. He
is a practicing chemical engineer since 1987 in process and process safety engineering.
Additionally, he is a Project Management Professional (PMP®) from PMI, USA, which gives him
a unique overall project perspective in addition to process perspective. He is also a TUV SUD
certified Functional Safety Professional.
He has worked all around the globe, in small as well as mega greenfield and brownfield
projects. The projects have been oil & gas, petrochemicals, polymerization as well as chemical
plants. The processes have been continuous as well as batch.
He has worked in premium companies in design as well as in operations field.
Dedicated to:
My Heavenly Father, Almighty God,
Who gave me the idea, wisdom and perseverance to take-up and complete this book.

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FOREWORD by Manoj Shah
Mumbai, 22 Sep 2017
Setting up of a Greenfield Chemical Plant is essentially a complex process and a chemical engineer (quite often
called a process engineer) has to wear different hats while visualizing and implementing any chemical plant
from “Concept to Commissioning”, in a time bound manner. Whereas theoretical understanding of concepts is
very important, it is equally critical to have an easy access to the vast pool of Chemical Engineering knowledge
in the form of handy design tools, documents and formats which help the process engineer to overcome the
challenges of time and cost constraints of a project. “The Handbook of Chemical Process Engineering”
endeavors to do just that. The author with his vast experience as a “Process” as well as a “Project” Engineer in
the chemical industry, has brilliantly compiled the various practical aspects of process design and project
management in this Handbook.
The Handbook does excellent justice to the most common Unit Operations encountered in the Chemical and
Petroleum Industry. Besides covering the important theoretical aspects from a more practical viewpoint in
various chapters in Volumes I & II, one must note that the Volume III, Chapters 40 to 44 place a very important
tool in the hands of the Process / Project engineer by vividly covering the important Process Engineering
Calculation Templates, Checklists, Datasheets, Technical Bid Evaluation Formats and Typical P&IDs.
Overall, this is an excellent reference book for Process / Project Engineers of all ages involved in Chemical
Process Engineering. I wish Mihir all the success for the launch of this handbook and complement him for his
tireless efforts in compiling and publishing such a useful reference book for chemical process engineers.
Manoj Shah
Presently: Consultant Chemical Plants and Technologies.
Previously: Retired as Executive Director (Technical) at IBI Chematur Engineering & Consultancy Ltd., Mumbai,
India
Background of Manoj Shah: He is a Chemical Engineer with a Master’s degree in Chemical Engineering from
USA. He has 40+ years experience in the Chemical industry, having carried out engineering on many projects,
greenfield as well as brownfield in the international market.

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SAMPLE FROM THE BOOK
Sno. Volume / Chapter Title
1 Volume I / Chapter 3 Pumps
2 Volume I / Chapter 6 Heat Exchangers
3 Volume I / Chapter 7 Tanks
4 Volume I / Chapter 16 Utilities System Design
5 Volume I / Chapter 24 Special Process Items
6 Volume II / Chapter 26 Types of Projects
7 Volume II / Chapter 29 Process Design Documentation
8 Volume II / Chapter 30 Technical Bid Evaluations

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Chapter 3:
PUMPS
3.5 OVERALL PUMP OPTIONS:
The following chart gives an introduction of pump selection options as a function of flow and
required head.
Fig 3.1: Pump Selection Guide Chart

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Pump Capacity, gpm
Fig 3.2 Centrifugal pump selection chart
The specification of process pumps involves a step-by-step approach. The process engineer
must select a pump with the best efficiency for the full range of process operating conditions.
The major types of pumps available are listed in the following table.
Kinetic Positive Displacement
Centrifugal: Reciprocating:
1. Radial Flow 1. Piston
2. Axial Flow 2. Plunger

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3. Mixed Flow 3. Diaphragm
4. Turbine
Special: Rotary:
1. Jet 1. Gear
2. Gas Lift 2. Screw
3. Hydraulic Ram 3. Lobe
4. Inertia 4. Vane
5. Progressive Cavity 5. Flexible Chamber
6. Concrete pumps 6. Flexible Tube (peristaltic)
Table 3.1 Types of Pumps
Comparison between centrifugal and positive displacement type is provided below in table
3.2.
Parameter POSITIVE DISPLACEMENT DYNAMIC
Definition Increases pressure by operating on a fixed
volume in a confined space
Increases pressure by using rotary
blades to increase fluid velocity
Types Screw, gear, reciprocating, progressive cavity Centrifugal, axial
Characteristics i) Constant volume
ii) Variable differential head
iii) Relatively insensitive to liquid properties
iv) Relatively insensitive to system changes
v) Not self-limiting
i) Variable volume
ii) Constant differential head
iii) Sensitive to liquid properties
iv) Sensitive to system changes
v) Self-limiting
Characteristic flow versus
differential head curve

8
Table 3.2: Comparison between positive displacement and dynamic pumps
Many applications can be handled by a horizontal or vertical centrifugal pump. The following
should be considered.
Feature Horizontal Vertical
Space Requirements Less headroom Less floor area, more head
room
NPSH Requires more Requires less
Flexibility for future change Less More
Maintenance More accessible Major work project
Table 3.3 Horizontal & Vertical Centrifugal Pump Selection Guide
A selection table showing the physical range of head and capacity suitable for the various
types of pump is provided below.
Pump Type Capacity m3
/h (usgpm) Head m (ft)
Minimum Maximum
Low Capacity
Peripheral 0.23 (1) 4.5 (20) 213 (700)
Vane TBD 17 (75) 122 (400)
Reciprocating Plunger 0.23 (1) 34 (150) Over 1,525
(5,000)
General Use
Reciprocating Power 4.5 (20) 227 (1,000) Over 305
(1,000)
Direct 1.4 (5) 114 (500) Over 305
(1,000)
Centrifugal 1 – Stage 2.7 (10) 1820 (8,000) Over 150
(500)

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2 – Stage 2.7 (10) 1820 (8,000) Over 210
(700)
Multistage 2.7 (10) 680 (3,000) Over 305
(1,000)
Screw 2.7 (10) 180 (800) Over 305
(1,000)
High Capacity
Centrifugal 1 – Stage 1.4 (5) 11,350 (50,000) 15 – 122 (50
– 400)
(Low Head) 57 (250) 22,700 (100,000) 3 – 61 (10 –
200)
Mixed Flow 227 (1,000) 45,400 (200,000) 0 – 7.5 (0 –
25)
Table 3.4 Pump Selection Table
Page 32
3.6.8 Stream Specific Gravity (Multiple Fluids)
Occasionally, pumping services will be designed to operate on fluids with widely differing
gravities. When calculating the hydraulics for the different cases, the fluid with lighter gravity
will often control the pump sizing. However, it should be stressed that when the pump is
operating at a lower volume throughput, often at a noticeably higher differential head and
incidentally lower pump efficiency, the effect of the heavier gravity fluid will give a pump
discharge pressure considerably in excess of the design requirement of the lighter material.
The process engineer must be aware of two potential problems during operation of the
heavier gravity fluid:
1. Downstream equipment (piping, heat exchangers, vessels, etc.) may be over
pressurized. In this event, either equipment ratings will need to be increased or
safeguarding measures must be implemented to prevent over pressurizing.
2. The motor may be overloaded. In this event a larger motor may be required or means
of restricting flow will need to be implemented to prevent overload.
3. On the data sheet, the process engineer should also note the specific gravity of the
heaviest liquid that the pump is expected to handle.

10
Relations in Discharge of Identical Centrifugal pump handling liquids of different specific
gravity is shown in below fig 3.17.
Fig 3.17: Typical performance of same centrifugal pump handling different fluids..
What this diagram implies is that e.g. if same centrifugal pump of say 20 mlc head is used to
pump water (sp. gr of 1.0) and also mercury (sp. gr of 13.6), then ignoring effect of viscosity
for this example and considering atmospheric suction, the discharge pressure of water will be
2 barg while of mercury will be 27.2 barg. Thus, in case of pumping mercury, if pump has
been procured originally only for water, then either motor will trip due to overload or pump
casing may bust if it is of lower design pressure.
Pages 48 to 52
3.6.18 Parallel vs. Series Centrifugal Pump Operation
3.6.18.1 Parallel Pump Operation

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The combined characteristics of pumps operating in parallel are obtained by adding their
individual flow rates for a given value of head.
Pumps with different pump curves should generally not operate in parallel. When this cannot
be avoided, the pump with the lower shut-off head must be protected against operating at
flows below the allowable minimum flow.
The shut-off head of the combined pump discharge system is determined by the pump with
the highest shut-off head.
Fig 3.29: Dissimilar two centrifugal pumps in parallel operation

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Fig 3.30: Two identical centrifugal pumps in parallel operation
Centrifugal pumps may be combined into parallel operation for numerous reasons. Some are:
1. Capacity increase is required for an existing pumping service and a new pump is added
in parallel to one or more existing pumps. The engineer should be aware that the
system flow will not necessarily increase in proportion to the number of pumps added
2. Very high reliability is required of the pumping service without total reliance on the
functioning of an auto-start control mechanism. Also, the loss of one pump will not
cause sudden total shutdown of the system.

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In order to meet a requirement for flow capacity higher than normal on an infrequent basis, it
may be preferable to have the primary pump and its spare operate in parallel, instead of
designing each pump for the full above-normal flow rate.
1. The required service capacity may exceed the utility energy supply available for a single
driver or driver type e.g. many companies have low voltage (LV) to high voltage (HV)
power supply cutoff at 160 KW motor size. Thus multiple parallel pumps may be
installed to make each motor LV.
2. Desire for operating flexibility in power supply or type could result in multiple pumps
with different driver types e.g. one motor driven with other steam turbine driven.
3. The use of multiple pumps may allow investment savings. For example, three 50%-
pumps may require lower a total investment than two pumps sized for 100% for the
service capacity. (This would be possible but unusual.)
For parallel operation, the head-capacity curve is obtained by adding the individual pump
capacities at any one given head. Pumps with different head-capacity curves will have
different flow rates. The process engineer must be certain that one pump is not “backed out”
or forced to operate below its minimum flow.
When pumps are operated in parallel it is imperative that their performance curve rise
steadily to shut-off. A drooping type of performance curve gives two possible points of
operation and pumps may oscillate between each other and cause surging. In parallel
operation additional pumps can be started up only when their shut-off heads exceed the
head developed by the pumps already running. Pumps operating in parallel should have a
shut-off head 10-20% higher than the rated head (API 610).
Another difficulty may occur as a result of inadequately engineered suction lines such that
one pump suction steals from the other. The remedy is to design for equal suction heads and
to assure that available NPSH is sufficient to satisfy each pump.
Adequate check valves must be used on pump systems operating in parallel to minimize
possible back flow through pumps and to minimize the effects of surge which is possible on
some parallel pumping systems.
It is advisable to provide a piping bypass system so that either pump can be operated without
the other. Aside from flexibility, a bypass system permits operation at reduced conditions
during maintenance, inspection or repair of either pump.

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Caution: Pumps in Parallel
A problem that can occur with pumps in parallel is shown in fig 3.31. Two pumps are never
exactly alike. If two pumps are installed in parallel, one pump may take more than half of the
total flow and the other pump less than half. The pump with the lower flow rate may be
operating below its minimum acceptable flow rate. As the fig shows, the head produced by
the two pumps will be identical because they are connected to the same process. If the head
produced by pump B is lower than head produced by pump A, the situation shown in the fig
will occur. Pump B will decrease its flow rate until it can produce the same head as pump A.
This situation is most dangerous when one pump is driven by a motor and the other pump by
a turbine. It is impossible to set the two speeds exactly equal, and the difference in speed will
cause a difference in head produced.
If two pumps are nominally identical and both driven by motors, the two head curves can be
assumed to be within 3% of each other. If so, one can make the worst assumption, that is, the
head of pump B is 3% lower than the head of pump A. Then, using the system operating
conditions, plot the flow through both pumps. Make sure that the lowest flow rate is not
below the pump minimum allowable flow rate.
Fig 3.31: Pumps in parallel

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3.6.18.2 Series Pump Operation
The combined characteristics of pumps operating in series is obtained by adding their
individual heads for a given flow rate.
The shut-off head of the combined pump discharge system is determined by adding the shut-
off heads of individual pumps.
Note that NPSH is generally a key design consideration for the first pump only since the first
pump acts as a booster for the 2nd pump in series.

16
Fig 3.32: Performance curve for two dissimilar centrifugal pumps in series
Pumps may be designed to operate in series arrangement for any of the following reasons:
1. The head requirement exceeds the capability of a single pump.
2. The differential pressure requirement is low enough at times that one of several pumps
in series can be turned off, as in transportation pipe lines.
3. The primary pump has a high NPSHR Therefore, a low-head booster pump is installed to
pressure the suction of the higher-head pump.

17
4. Plant feed must be transferred from a remote storage area to the suction of an on-site
high-head pump.
5. Two or more pumps are preferred over a multistage pump in erosive slurry operation.
For series operation, the head-capacity curve is obtained by adding the two heads at any
given capacity.
Fig 3.33: Two identical centrifugal pumps in series

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It is important that adequate suction pressure be available to all pumps, especially to the first
pump in series operation. If the first pump in a series system is deprived of adequate NPSH,
its capacity will be reduced until NPSHR equals NPSHA. Then the capacity through all the
pumps in series will be reduced, resulting in a significant overall flow loss.
The design pressure for piping and equipment, including the pumps themselves, should be
carefully examined in a series-flow operation especially if the pumping system can be
deadheaded.
The engineer should be aware that reliability is reduced for the series-flow service since
operation is now dependent on not just one pump but each pump in the series.
Caution: Pumps in Series
Two pumps in series will generate much more discharge pressure than one pump alone. In
some cases, this pressure might be greater than the design pressure of the downstream
piping or other equipment. This condition must be checked before proceeding with an
installation of two or more pumps in series. It is important to check the design pressure at the
condition called “pump shutoff pressure.” Shutoff pressure is obtained when the
downstream control valve is closed and the pumps operate at zero capacity and maximum
head. The shutoff pressure is equal to the pressure in the suction vessel plus the shutoff
delta P of both pumps combined. See Fig 3.34 and the example table beneath it. For this
example, the normal operating discharge pressure is satisfactory because it is less than the
design pressure. However, at shutoff, the discharge pressure downstream of the second
pump would be greater than the equipment design pressure. This situation is not allowed.
One remedy is to install a safety valve at the discharge of the second pump as shown.

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Chapter 6:
HEAT EXCHANGERS
6.4.1 TEMA Types
TEMA standards cover the heavy-duty heat exchangers (TEMA R) as well as the lighter duty
heat exchangers (TEMA C and TEMA B). Refineries typically use only the TEMA “R” heat
exchangers due to the generally severe requirements of petroleum applications; however,
more moderate process services may warrant consideration of TEMA B construction.
Each TEMA heat exchanger consists of following main parts: the front end stationary head
(commonly referred to as “channel”); the tube bundle; the rear head and the shell. Each part
can be designed in several modifications, commonly referred to as “types”.
Shown in Fig 6.17 are the TEMA standard designates which are five types of channels (A, B, C
or N, and D), seven types of shells (E, F, G, H, J, K and X), and eight rear end head types (L, M,
N, P, S, T, U and W). The rear end head type determines whether or not the tube bundle is
removable from the shell.

21
i) Straight Tube, Fixed tubesheet, Type BEM, AEM, NEN, Etc. – This TEMA type is the simplest
design and is constructed without packed or gasketed joints on the shell side. The tubesheet
is welded to the shell and the heads are bolted to the tubesheet. On the NEN heat exchanger,
the shell and the head is welded to the tubesheet. Typically, a cover plate design is provided
to facilitate tube cleaning. This TEMA category, especially the NEN, is the lowest cost TEMA
design per square foot of heat transfer surface.
Advantages
• Less costly than removable bundle designs
• Provides maximum amount of surface for a given shell and tube diameter
• Provides for single and multiple tube passes to assure proper velocity
• Maybe interchangeable with other manufacturers of the same TEMA type limitations
• Shell side can be cleaned only by chemical methods
• No provision to allow for differential thermal expansion must use an expansion joint
on the shell side
Applications
• Oil Coolers, Liquid to Liquid, Vapor condensers, rebuilders, gas coolers
• Generally, more viscous and warmer fluids flow through the shell
• Corrosive or high fouling fluids should flow inside the tubes
ii) Removable Bundle, Externally Sealed Floating tubesheet, Type AEW, BEW. – This design
allows for the removal, inspection and cleaning of the shell circuit and shell interior. Special
floating tubesheet prevents intermixing of fluids. In most cases, straight tube design is more
economical than U-tube designs.
Advantages
• Floating tubesheet allows for differential thermal expansion between the Shell and
the tube bundle.
• Shell circuit can be inspected and steam or mechanically cleaned
• The tube bundle can be repaired or replaced without disturbing shell pipe

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• Less costly than TEMA type BEP or BES which has internal floating head
• Maximum surface for a given shell diameter for removable bundle design
• Tubes can be cleaned in AEW models without removing piping.
Limitations
• Fluids in both the shell and tube circuits must be nonvolatile, non-toxic
• Tube side passes limited to single or two pass design
• All tubes are attached to two tube sheets. Tubes cannot expand independently so
that large thermal shock applications should be avoided
• Packing materials produce limits on design pressure and temperature
Applications
• Intercoolers and aftercoolers, the air inside the tubes
• Coolers with water inside the tubes
• Jacket water coolers or other high differential temperature duty
• Place hot side fluid through the shell with entry nearest the front end
iii) Removable Bundle, Outside Packed Head, Type BEP, AEP, etc – This design allows for the
easy removal, inspection and cleaning of the shell circuit and shell interior without removing
the floating head cover. Special floating tubesheet prevents intermixing of fluids. In most
cases, straight tube removable design is more costly than U-tube designs.
Advantages
• Floating tubesheet allows for differential thermal expansion between the shell and
the tube bundle.
• Shell circuit can be inspected and steam cleaned. If the tube bundle has a square tube
pitch, tubes can be mechanically cleaned by passing a brush between rows of tubes.
• The tube bundle can be repaired or replaced without disturbing shell piping
• On AEP design, tubes can be serviced without disturbing tubeside piping
• Less costly than TEMA type BES or BET designs
• Only shell fluids are exposed to packing. Toxic or volatile fluids can be cooled in the

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tubeside circuit
• Provides large bundle entrance area, reducing the need for entrance domes for
proper fluid distribution
Limitations
• Shell fluids limited to non volatile, non toxic materials
• Packing limits shell side design temperature and pressure
• All tubes are attached to two tubesheets. Tubes cannot expand independently so that
large thermal shock applications should be avoided
• Less surface per given shell and tube diameter than AEW or BEW
Applications
• Flammable or toxic liquids in the tube circuit
• Good for high fouling liquids in the tube circuit
iv) Removable Bundle, Internal Split Ring Floating Head, Type AES, BES, etc. – Ideal for
applications requiring frequent tube bundle removal for inspection and cleaning. Uses
straight-tube design suitable for large differential temperatures between the shell and tube
fluids.More forgiving to thermal shock than AEW or BEW designs.Suitable for cooling volatile
or toxic fluids.
Advantages
• Floating head design allows for differential thermal expansion between the shell and
the tube bundle.
• Shell circuit can be inspected and steam cleaned. If it has a square tube layout, tubes
can be mechanically cleaned
• Higher surface per given shell and tube diameter than “pull-through” designs such as
AET, BET, etc.
• Provides multi-pass tube circuit arrangement.
Limitations
• Shell cover, split ring and floating head cover must be removed to remove the tube

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bundle, results in higher maintenance cost than pull-through
• More costly per square foot of surface than fixed tube sheet or U-tube designs
Applications
• Chemical processing applications for toxic fluids
• Special intercoolers and aftercoolers
• General industrial applications
v) Removable Bundle, Pull-Through Floating Head, Type AET, BET, etc. – Ideal for
applications requiring frequent tube bundle removal for inspection and cleaning as the
floating head is bolted directly to the floating tubesheet. This prevents having to remove the
floating head in order to pull the tube bundle.
Advantages
• Floating head design allows for differential thermal expansion between the shell and
the tube bundle.
• Provides large bundle entrance area for proper fluid distribution
• Suitable for toxic or volatile fluid cooling
Limitations
• For a given set of conditions, this TEMA style is the most expensive design
• Less surface per given shell and tube diameter than other removable designs
Applications
• Chemical processing applications for toxic fluids
• Hydrocarbon fluid condensers
• General industrial applications requiring frequent cleaning

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vi) Removable Bundle, U-Tube, Type BEU, AEU, etc. – Especially suitable for severe
performance requirements with maximum thermal expansion capability. Because each tube
can expand and contract independently, this design is suitable for larger thermal shock
applications. While the AEM and AEW are the least expensive, U-tube bundles are still an
economical TEMA design.
Advantages
• U-tube design allows for differential thermal expansion between the shell and the
tube bundle as well as for individual tubes.
• Less costly than floating head or packed floating head designs
• Capable of withstanding thermal shock applications.
• The bundle can be removed from one end for cleaning or replacement
Limitations
• Because of U-bend, tubes can be cleaned only by chemical means (although
nowadays, new techniques of the fluid pressurized scraper, similar to a pipeline pig, are
available)
• Because of U-tube nesting, individual tubes are difficult to replace
• No single tube pass or true countercurrent flow is possible
• Tube wall thickness at the U-bend is thinner than at the straight portion of tubes
• Draining of tube circuit is difficult when mounted with the vertical position with the
head side up.
Applications
• Oil, chemical and water heating applications
• Excellent in steam to liquid applications

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Chapter 7:
TANKS
Case Scenario:
A fixed roof tank storing flammable material is having inert gas blanketing. The outlet of
nitrogen blanket is taken to a LP flare system. Below is the sequence of pressure set point
engineering (refer figure 7.37 below also):
1. First, calculate the inbreathing and outbreathing flow rates based on API 2000.
2. Next based on the flowrate of out-breathing to LP flare and the back pressure of flare,
calculate the pressure drop in the flare header, to arrive at the pressure required at outlet of
out-breathing control valve. Let us say the friction drop in LP header is 150 mm WC (mm
water column), & pressure at valve outlet is 400 mm WCg.
3. Next step is to provide certain pressure drop across the out breathing control valve. This
pressure drop should be at least 1/3rd of friction drop in outlet line to flare, for good
controllability. In this example, we provide 50 mm WC across valve.
4. Once the inlet pressure to out breathing control valve is established, this is the top setpoint
of pressure in the tank pressure controlling range. In example thus, top operating pressure is
450 mm WCg. At this point, the control valve is fully open.
5. The high pressure alarm on tank needs to be set above this pressure of point (4). Thus, high
pressure alarm will be 500 mm WCg.
6. The breather valve positive pressure will be above the high pressure alarm setpoint. Thus,
this will be 550 mm WCg. Note that breather valve will have 10% accumulation, thus, it will be
fully open at 605 mm WCg.
7. The emergency vent valve setpoint will accordingly be above the breather valve positive set
pressure. The setpoint of emergency valve is also the design pressure of tank on positive side.
In our example, emergency valve will be set at 650 mm WCg. This is also the design pressure
of tank. One can however keep design pressure little above emergency valve set point also.
Both are acceptable.

27
8. Now, one needs to provide an operating range for tank operation. Thus, the outbreathing
control valve will be fully closed at 350 mm WCg inlet pressure.
9. There is a dead band normally provided between the closing of inlet control valve and
opening of outlet control valve. In our example, this will be between 200 mm WCg and 350
mm WCg.
10. Thus, inlet control valve will start to open at 200 mm WCg. It will be fully open at 100 mm
WCg.
11. Still if pressure in tank drops, the low pressure alarm will come in at 50 mm WCg.
12. The inbreathing set point of PVRV will be set at (-22 mm WCg) and with 10% accumulation
it will be full open at (-25 mm WCg).
13. Thus tank design pressure can be set at (-25 mm WCg).
In summary, tank design pressure is (-25) / 650 mm WCg.

28
Fig 7.37: the typical setting of tank pressures
The above diagram shows establishing of key pressures for an atmospheric storage tank. The
Pressure/Vacuum (PV) Valve is really two valves in one. One is for pressure, and the other is
for vacuum. The principle of operation is the same. As the pressure on the pressure side of a
PV valve rises, the force due to pressure reduces the seating force of the pallet and it starts to
leak. Leakage, however, is relatively insignificant until the set point is reached, at which point
the flow increases dramatically and follows the flow curves given by the manufacturer.

29
Beyond the set point, PV valves do not “pop” open, but slowly lift as the overpressure (the
actual upstream pressure above the value of the setpoint) increases.
A narrow operating pressure range becomes particularly more important for systems that
have inert gas blanketing or large tanks with shallow roof angles that have a very low failure
pressure. The problems with sufficient margins to allow vents to operate within the design
pressure of the tank become more acute for large diameter tanks. Smaller tanks can
frequently take the higher pressures without the need for special design consideration,
whereas large tanks will be damaged if the internal pressure exceeds the design pressure.
Emergency vent valves are simply large PV valves capable of venting greater than normal
venting loads caused by emergency conditions.
Fig 7.38: Typical Inert Gas Blanketed Tank with a vent to flare

30
7.4.13 Process Datasheet Preparation:
i) Choosing Tank / Storage Vessel Type
Operation at above 18 kPag (2.5 psig) should preferably consider a bullet (a horizontal
pressure vessel with L:D ratio that may exceed 5:1).
In some applications, provision of a spheroid or sphere will prove more economic than use of
multiple bullets.
Note: Tanks handling liquids with solids contamination require special attention.
ii) Optimizing Vessel Size
The following guidelines should be followed in optimizing dimensions:
a) Tanks:
As a general rule, storage tanks should be limited to a maximum height of 25 m (80 ft) and 60
m (200 ft) diameter.
As a general rule, the cheapest tank will have a height: diameter ratio of 1, although standard
tank dimensions should be used wherever shop built tanks are used as this will help reduce
cost.
b) Drums / Bullets:
Normal Length / Diameter (L/D) ratio is 2:1 to 5:1 for horizontal bullets with > 3:1 often being
the most economic in low-pressure applications. As pressure increases, the economic L/D
tends to increase. The higher range of L/D’s is advantageous for horizontal separators and
settlers. Also, refer to chapter 9 on “Separators” for more information on L/D.
Minimum drum size should be 610 mm (24”) inside diameter (ID). Small drums can
sometimes be fabricated more economically using 24 or 30” outside diameter pipe.
Start by specifying inside diameters and T/T lengths in 152 mm (6”) increments. The
Mechanical Engineer responsible for the design of the vessels may come back to Process if a
more economical design is possible. This could occur where using standard plate sizes in 610
mm (2 ft) increments are a better fit, or in very high pressure and/or alloy services they may

31
suggest tighter dimensions down to 75 mm (3”) or even 25 mm (1”) increments in order to
reduce cost. The Process Engineer should adjust the elevations on the vessel sketch he has
provided, once overall dimensions are finalized, with all levels referenced to the bottom of
the shell.
Table 7.9 provides nominal standard capacities of vertical Steel cylindrical Storage tanks in m3
iii) Nozzle Sizing and Location
It is not possible for Process Engineering to definitively locate all major nozzles. This is due to
the uncertainty of vessel reinforcement pad sizes and other mechanical details. However,
Process Engineering must indicate the number, size, and general location.

32
Chapter 6:
UTILITIES SYSTEM DESIGN
16.2.2 Liquid Fuel
16.2.2.1 Introduction
Fuel oil is a fraction obtained from petroleum distillation, either as a distillate or a residue.
Broadly speaking, fuel oil is any liquid petroleum product that is burned in a furnace or boiler
for the generation of heat or used in an engine for the generation of power. In this sense,
heavy fuel oil (HFO) or diesel are types of fuel oil. Fuel oil is made of long hydrocarbon
chains, particularly alkanes, cycloalkanes and aromatics. The term fuel oil is also used in a
stricter sense to refer only to the heaviest commercial fuel that can be obtained from crude
oil, heavier than gasoline and naphtha.
Fuel oil systems are provided to ensure a constant regulated supply of oil to burners of steam
boilers and process furnaces. The system includes a fuel oil pump and heater set which
discharges oil at a constant pressure and at the required condition of temperature and
viscosity so that atomisation and efficient combustion are possible.
Dependent on the grade of Fuel oil and process demand, the source may be from process
make within the complex, subsidized by import to meet the total complex demand or
imported via road, rail or marine off-loading facilities.
Where gas is available for fuel and there is a preference for it, Fuel oil make may be exported
via road, rail or marine off-loading facilities.
A typical analysis of a fuel oil or waste liquid contains the following information:
1. Ultimate analysis: The results indicate the quantities of sulfur, hydrogen, carbon,
nitrogen, oxygen and ash.
2. API gravity

33
3. Heating value
4. Viscosity
5. Pour point: The pour point is the lowest temperature at which a liquid fuel flows under
standardized conditions.
6. Flash point: The flash point is the temperature to which a liquid must be heated to
produce vapours that flash but do not burn continuously when ignited.
7. Water and sediment: The water and sediment level, also called bottom sediment and
water (BSW), is a measure of the contaminants in a liquid fuel. The sediment normally
consists of calcium, sodium, magnesium and iron compounds. For heavy fuels, the
sediment may also contain carbon.
Additional information, which is often required when designing a boiler, includes:
1. Carbon residue,
2. Asphaltenes,
3. Elemental ash analysis,
4. Burning profile, and
5. Distillation curve.

34
Refer table 16.2.3 below for fuel oil analysis for commercial
grades.
Table 16.2.3: Analysis of commercial fuel oil grades

35
Table 16.2.4: Typical characteristics of various liquid fuel types

36
Table 16.2.5: Comparison of properties of fuel oil amongst various countries

37
Pages 24 to 25
16.3 Compressed Air system
16.3.1 Introduction
Compressed air is supplied on industrial sites for two main purposes, as Instrument Air for
control systems and Plant Air for general use.
Instrument Air systems provide a constant flow of dry compressed air at the pertinent
conditions to maintain the following services:
Instrumentation (control valves, positioners, shut down valves)
Process Air
Plant Air is supplied for the following services:
Service Air (utility stations)
Motive Air (to run air motor driven equipment e.g. air operated double diaphragm pumps
(AODD))
Maintenance facilities (purging equipment containing chemical vapour/inert gas to allow man
entry)
Cleaning air (soot blowers, workshops)
16.3.1.1 Determination of System Capacity
(i) Capacity of Instrument Air System
The capacity of the system is to be based upon the total requirements of all connected loads,
assuming all instruments operate simultaneously at maximum air consumption. The capacity
of the Instrument Air system cannot be accurately assessed until the process control diagrams
are complete and a provisional count of the instrumentation is possible.

38
When accurate manufacturer’s data is not available, the following assumptions are
acceptable in calculating the Instrument Air requirements, based on all instrument operating
simultaneously:
Users Instrument Air Rate per
single (1) Device
[Nm3
/h] [scfm]
Old type control valve with fully pneumatic system (includes leakage rate of app. 0.3
Nm3
/h)
2.98 1.75
Modern type control valve, electronically controlled with only the actuator using
Instrument Air (includes leakage rate of app. 0.3 Nm3
/h)
1.50 0.88
On-Off Isolation Valve (includes leakage rate of app. 0.3 Nm3
/h) – only fraction of on-off
valves needs to be considered operating simultaneously for normal consumption, say 10%
5.53 3.25
Analyzer (oxygen, chromatograph) 8.50 5
Analyzer (moisture, pH, conductivity, water, emission) 3.40 2
Louvers / Dampers 8.50 5
Miscellaneous (compressor pulse jet, on-line / off-line washing, dry gas seal panel, anti
surge valve etc.)
As required As
require
d
Margin to be added %
Margin for air dryer regeneration losses during operation (this depends on vendor design
for air dryers)
+ 10% to 25%
Margin to avoid overloading the compressor + 15% to 20%
Margin for leakage in the system (optional- see note 1) + 10%
Note 1: In case GI pipes are used for instrument air as is usual practice, then connectors are
union joints since GI pipes cannot be welded. Here, this margin is appropriate. However, if
instrument air piping is SS 304 with flanges, then this margin can be ignored)
Table 16.3.1: Recommended Typical Instrument Air Requirements
(ii) Capacity of Plant Air System
Plant Air demand is difficult to predict as invariably plant modification and new constructions
services are to be considered in addition to normal plant operations: Service Air, Furnace

39
Decoking and maintenance workshop demands. The largest demand for Plant Air in a
production plant is for furnace steam / air decoking (normally 2,500 NM3
/hr), which may vary
considerably with the type of plant size and number of furnaces.
User Plant Air Rate [Nm3
/h]
Production Plant As required in
consultationwith licensor /
vendors
Plant Service Air (one utility stations at 85 Nm3
/h each) 85
Maintenance workshop 100 maximum
Table 16.3.2 Typical Plant Air Requirements
Note that, sometimes, decoke air has its own compressor and in such cases the consumption
would not be considered part of Plant Air.
Table 16.3.3 shows demands and operating conditions for pneumatic tools and construction
equipment. Note that these are peak values and that average loads are often 10-35% of the
peak values quoted.
Tool Weight [kg] Air Rate [lts/min] Work. Pres.
[barg]
Clay diggers 11 800 4.9
Clay diggers 14 600 to 680 4.9
Clay diggers 15.5 680 4.9
Clay diggers 18 1600 4.9
Concrete tampers 18 1100 4.9
Riveting Hammer Light 1.6 to 1.8 200 to 250 4.9
Riveting Hammer Heavy 7.2 to 11.4 88 to 900 4.9
Drilling Machines (1/8”-3/4”) 0.75 to 3.9 400 to 800 4.9 to 5.9

40
Drilling Machines (7/8”-1 1/4”) 6.3 to 14 1000 to 1600 4.9 to 5.9
Drilling Machines (2”) 22 2500 4.9 to 5.9
Hand Grinder (5/16” dia.) 0.5 to 1.0 400 to 650 4.9
Hand Grinder (4”x2”-6”x1 1/4″) 4.8 to 5.1 1000 4.9
Hand Grinder (8”x1 1/2″) 7.5 1500 4.9
Grinders with Flexible Pad (8”-10” dia.) 5.5 1900 4.9
Table 16.3.3: Approximate peak Demands for Pneumatic Tools
Pages 27 to 30
Dryers
The most common measurement of compressed air water content is dew point. Dew point is
the temperature where air is saturated with water and moisture will begin to condense. In
other words, it’s the point where dew begins to form. Dew point is always stated as a
temperature. Simply put, dew point is the temperature where condensation begins.
In compressed air applications, pressure is critical when discussing dew point. Compression
and expansion of air affects its dew point. Generally speaking, compression increases dew
point, and expansion (i.e. de-compression) lowers dew point.
For this reason, the phrase “pressure dew point (PDP)” is commonly used. This term usually
refers to the dew point of the compressed air at full line pressure. Conversely the phrase
“atmospheric dew point” refers to what the dew point would be if fully depressurized to
atmospheric conditions.
Fig 16.3.1 provides conversion chart of pressure to atmospheric dew point for compressed air
at various pressures. To obtain the dew point temperature expected if the gas were expanded
to a lower pressure proceed as follows:
1. Using “dew point at pressure” locate this temperature on scale at right hand side of
chart.

41
2. Read horizontally to intersection of curve corresponding to the operating pressure at
which the gas was dried.
• From that point read vertically downward to curve corresponding to the expanded
lower pressure.
1. From that point read horizontally to scale on right hand side of chart to obtain dew
point temperature at the expanded lower pressure.
2. If dew point temperatures of atmospheric pressure are desired, after step (ii) above,
read vertically downward to scale at bottom of chart, which will provide “Dew Point at
Atmospheric Pressure”.
Fig 16.3.1: Pressure dewpoint versus atmospheric dewpoint conversion
Two 100% air dryer packages are normally installed (duty and stand by).

42
Dryer types and details of each are provided below:
Compressed Air Dryers are mainly used in industries for various applications in pneumatic
tools, pneumatic instruments and pneumatic machines and in a variety of production
processes. The consequences of using wet air are rust and scale deposits in steel pipes,
increased resistance in flow, malfunctioning of process control instruments, corrosion and
damage to electromagnetic valves and pneumatic system, peeling and blistering effect on
spray painted surface, etc. Thus it will affect the quality of product and lead to excessive
maintenance cost.
The sketch below shows a typical Compressed air system to remove these damaging
impurities and get Clean and Dry air. When compressed to 7 Kg/cm2
g, the temperature of
discharge air reaches around 140o
C. The after cooler and Separator installed after the
compressor will cool the air, and remove @90% of moisture and oil. For instance, when the
compressor takes in 100 NM3
/h of ambient air at 40o
C and 50% relative humidity, at 7
Kg/cm2
g, the after cooler will condense an average of 30 liters of water in 24 hours. If the
outlet air temperature from the after cooler is 40o
C, it still contains 8000 ppm moisture. At
45o
C, compressed air contains 10,500 ppm, at 50o
C, 13,500 ppm moisture which is removed
by Air Dryer. Therefore, lower the temperature of air at dryer inlet, smaller would be the size
of Air Drying Unit.
Dryer types are as below:
1. Internally Heat Reactivated Type Air Dryers
2. Blower Reactivated Type Air Dryer
3. Heatless Type Air Dryers
4. Heat of Compression Type Air Dryers
5. Refrigerated Type Air Dryers
6. No Purge Loss Type Air Dryers
Pages 216 to 217

43
16.5.9 Specification of Boilers
(i) Preferred Arrangement
Required total capacity should be provided by use of at least 3 boilers, but all boilers should
be considered to be operating at partial load to supply normal steam requirements. The
above is recommended for redundancy purposes only.
All boilers should preferably be considered to be water tube type except small package units
of low pressure which may be of fire tube construction.
Boilers should be of the outdoor installation type except that semi outdoor type should be
used in cold climates.
Package boilers should be preferred in standard sizes and pressure ranges where commonly
available.
Boilers should usually be equipped with automatic fuel burners, forced or induced draft fans,
flue gas ducts, soot blowers, platforms and ladders, and other related auxiliaries and
accessories, as neccessary. Controls and instruments are usually supplied to a certain degree
with the boiler.
(ii) Boilers
The boiler specification should cover all aspects of the expected operating cycle of the boiler.
It is important that any special operating aspects such as daily start-up or rapid load swings
are covered in the specification of the boiler, which should include the following:
• Analysis of the fuels to be used
• Duty required (maximum and minimum flows, pressure and temperatures and
allowable variation)
• Water analysis and expected ranges and feed water temperature
• Layout constraints and access problems
• Any unusual site features such as earthquake or wind problems
• Applicable emissions regulations
• Codes and standards required for the country, plus site safety rules
• Delivery and commissioning requirements
• Auxiliary equipment required and types of drive

44
• Control system and data management needs
• Guarantees and warranties
• Any essential bid comparison basis such as utility values, capital charges, etc.
(a) Boiler Specifications and a few important terminologies:
Boilers are always typically specified by the following Industrial Boiler Specification Factors.
(Note: At the end of this section are provided guidelines for process engineer to prepare
specifications and evaluate vendor bids. Vol II Chapter 30 also provides technical bid
evaluation for boilers).
1. Steam pressure
2. Steam temperature and control range
3. Steam flow: Peak, Minimum, Load patterns
4. Feed water temperature and quality
5. Standby capacity and number of units
6. Fuels and their properties
7. Ash properties
8. Firing method preferences
9. Environmental emission limitations: sulfur dioxide (SO2), nitrogen oxides (NOx),
particulate, other compounds
10.Site space and access limitations
11.Auxiliaries
12.Operator requirements
13.Evaluation basis
Out of these, the usual four most important attributes are:
1. Steam flow or evaporation
2. Steam outlet pressure (SOP)
3. Steam outlet temperature (SOT)
4. Feed water (FW) inlet temperature
(b) Steam Flow or Evaporation or Boiler Output
This is the amount of steam generated from the FW supplied at a certain temperature. It is
the capacity or the rating of the boiler expressed in pounds per hour (lb/h), kilograms per
hour (kg/h), or kilograms per second (kg/s). In a re-heater (RH) boiler, heat is added to steam

45
to raise its temperature from inlet to outlet condition. This also forms a part of evaporation.
As the feed temperature varies a good deal and reheating is invariably present in utility
boilers, boiler ratings are better designated by the heat duty than evaporation. This is
expressed in million British thermal units per hour (MMBtu/h), million kilocalories per hour
(MMkcal/h), or megawatt thermals (MWth).
(c) Maximum Continuous Rating
Maximum continuous rating (MCR) is the ability of the boiler to generate and supply the
declared amount of steam continuously and effortlessly without any kind of shortfall or side
effects (such as overheating or slagging or overloading) on the main boiler or auxiliaries.
(d) Peak Rating
Peak rating is the evaporation that can be sustained by the boiler for a specified period of, for
example, 2 or 4 h in a day, to meet an increased need in either the process or the power
plant. The concept of peak rating does not apply to HRSGs.
Peak duty is always met at a fractionally reduced efficiency, as the final exit temperature of
the gas from the unit would be more than that at an MCR condition (as the fuel flow is
higher), leading to higher stack losses.
Usually, the peak duty does not exceed 110% MCR and 4 h in a day, and it is mostly met by
making use of the design and test block margins of the boiler and the auxiliaries without
having to oversize the equipment.

46
Chapter 24:
SPECIAL PROCESS ITEMS
24.1 Flame Arresters:
Flame arresters are used:
• to stop the spread of an open fire
• to limit the spread of an explosive event that has occurred
• to protect potentially explosive mixtures from igniting
• to confine fire within an enclosed, controlled, or regulated location
• to stop the propagation of a flame traveling at sub-sonic velocities
Few of their common usages are:
• fuel storage tank vents
• fuel gas pipelines
• safety storage cabinets for paint, aerosol cans, and other flammable mixtures
• the exhaust system of internal combustion engines
• the air intake of marine inboard engines
• overproof rum and other flammable liquors
Explosive mixtures can burn in various ways. The following, among other things, can influence
the combustion process: the chemical composition of the mixture, possible pressure waves,
pre-compression, the geometric shape of the combustion chamber, and the flame
propagation speed.
The relevant combustion processes for flame arresters are defined by international
standards:
Explosion is the generic term for abrupt oxidation or decomposition reaction producing an
increase in temperature, pressure or both simultaneously.

47
Deflagration is an explosion that propagates at subsonic velocity. Depending on the
geometric shape of the combustion area, a distinction is drawn between atmospheric
deflagration, pre-volume deflagration and in-line deflagration.
Atmospheric deflagration (Fig. 24.1.1) is an explosion that occurs in open air without a
noticeable increase in pressure.
Fig 24.1.1: Atmospheric deflagration
Pre-volume deflagration (Fig. 24.1.2) is an explosion in a confined volume (such as within a
vessel) initiated by an internal ignition source.

48
Fig 24.1.2: Pre-volume deflagration
In-line deflagration (Fig 24.1.3) is an accelerated explosion within a pipe that moves along the
axis of the pipe at the flame propagation speed.
Fig 24.1.3: In-line deflagration in pipe
Stabilized burning is the even, steady burning of a flame, stabilized at or close to the flame
arrester element. A distinction is drawn between short time burning (stabilized burning for a
specific period) and endurance burning (stabilized burning for an unlimited period) (Fig
24.1.4).

49
Fig 24.1.4: Stabilised burning
Detonation is an explosion propagating at supersonic velocity and is characterized by a shock
wave.
A distinction is drawn between stable detonations and unstable detonations (Fig 24.1.3). A
detonation is stable when it progresses through a confined system without a significant
variation of velocity and pressure characteristic (for atmospheric conditions, test mixtures
and test procedures, typical velocities are between 1,600 and 2,200 meter/second). A
detonation is unstable during the transition of the combustion process from a deflagration
into a stable detonation. The transition occurs in a spatially limited area in which the velocity
of the combustion wave is not constant and where the explosion pressure is significantly
higher than in a stable detonation.
Pages 26 to 27
24.2 Spray nozzles:
A spray nozzle is a precision device that facilitates dispersion of liquid into a spray. Nozzles
are used for three purposes: to distribute a liquid over an area, to increase liquid surface
area, and create impact force on a solid surface. A wide variety of spray
nozzle applications use a number of spray characteristics to describe the spray.

50
Spray nozzles can be categorized based on the energy input used to cause atomization, the
breakup of the fluid into drops. Spray nozzles can have one or more outlets; a multiple outlet
nozzle is known as a compound nozzle.
Understanding sprays, drop size, and the strengths and characteristics of nozzle types and
correctly positioning them are fundamental to the desired process result.
By creating a large droplet surface area, sprays are used to generate the high rates of heat
and mass transfer that is necessary in spray drying, liquid waste incineration, and spray
quenching applications. Spray nozzles are applied in a wide variety of process applications
with a wide range of criticality. An example is the quenching of hot gases where high
performance, high reliability, and robustness are required. Another usage of nozzles is
manual pressure washing of equipment. Similarly, Desuperheating of superheated steam by
spraying water into the superheated steam as well as chemical injections into main streams
are other usages of spray nozzles.
Types of spray nozzles are:
1. Single fluid spray nozzles
2. two-fluid atomizing nozzles
3. rotary disk
4. ultrasonic.
24.2.1 Single-fluid nozzle
Single-fluid or hydraulic spray nozzles utilize the kinetic energy of the liquid to break it up into
droplets. This most widely used type of spray nozzle is more energy efficient at producing
surface area than most other types. As the fluid pressure increases, the flow through the
nozzle increases, and the drop size decreases. Many configurations of single fluid nozzles are
used depending on the spray characteristics desired.
(i) Plain-orifice nozzle
The simplest single fluid nozzle is a plain orifice nozzle as shown in the fig 24.2.1. This nozzle
often produces little if any atomization, but directs the stream of liquid. If the pressure drop is
high, at least 25 bars (2,500 kPa), the material is often finely atomized, as in a diesel injector.
At lower pressures, this type of nozzle is often used for tank cleaning, either as a fixed
position compound spray nozzle or as a rotary nozzle.

51
Fig 24.2.1: Plain orifice spray nozzle
(ii) Shaped-orifice nozzle
The shaped orifice (fig 24.2.2) uses a hemispherical shaped inlet and a ‘V’ notched outlet to
cause the flow to spread out on the axis of the ‘V’ notch. A flat fan spray results which is
useful for many spray applications, such as spray painting.
Fig 24.2.2: Flat fan spray pattern spray nozzle
(iii) Surface-impingement single-fluid nozzle
A surface impingement nozzle (fig 24.2.3) causes a stream of liquid to impinge on a surface
resulting in a sheet of liquid that breaks up into drops. This flat fan spray pattern nozzle is
used in many applications ranging from applying agricultural herbicides to row crop to
painting.
The impingement surface can be formed in a spiral (fig 24.2.4) to yield a spiral shaped sheet
approximating a full cone spray pattern or a hollow-cone spray pattern.

52
The spiral design generally produces a smaller drop size than pressure swirl type nozzle
design, for a given pressure and flow rate. This design is clog resistant due to the large free
passage.
Common applications include gas scrubbing applications (e.g., flue-gas desulfurization where
the smaller droplets often offer superior performance) and fire fighting (where the mix of
droplet densities allow spray penetration through strong thermal currents).
Pages 118 to 119
24.7 Liquid Filtration:
Liquid filtration plays a very important part in any process. Filtration is a process whereby
solid particles present in a suspension are separated from the liquid or gas employing a
porous medium, which retains the solids but allows the fluid to pass through. When the
proportion of solids in a liquid is less, the term clarification is used. It is a common operation
which is widely employed in production of sterile products, bulk drugs, and in liquid oral
formulation.
The suspension to be filtered is known as slurry. The porous medium used to retain the solids
is known as filter medium. The accumulated solids on the filter are referred as filter cake &
the clear liquid passing through the filter is called the filtrate.
24.7.1 Types of filtration
Based on the mechanism, three types of the filtration are known.
1. i) Surface filtration: It is a screening action by which pores or holes of the medium
prevent the passage of solids. The mechanisms, straining and impingement are
responsible for surface filtration. For this purpose, plates with holes or woven sieves
are used. Example is cellulose membrane filter.
2. ii) Depth filtration: This filtration mechanism retains particulate matter not only on the
surface but also at the inside of the filter. This is aided by the mechanism
entanglement. It is extensively used for clarification.
Examples are ceramic filters and sintered filters.
iii) Ultra filtration: Ultra filtration is a pressure-driven membrane transport process that has
been applied, on both the laboratory and industrial scale. Ultra filtration is a separation

53
technique of choice because labile streams of biopolymers (proteins, nucleic acids &
carbohydrates) can be processed economically, even on a large scale, without the use of high
temperatures, solvents, etc.
24.7.2 Filter Selection:
In choosing the filter, selection depends on several considerations which are covered by the
following queries:
– what is the duty of the filter?
– what is the sizing requirement to carry the process flow rate and contain the solids
removed?
– what filter area (ft2
) and cake capacity (ft3
) is needed?
– Is there a requirement to prefilter?
– Is the filter for a fine-filtration requirement?
– Is manual or automatic operation preferred?
– Is the process batch or continuous operation?
Manually operated filters include basket filters, plate-and-frame filter presses, plate filters
and some pressure leaf filters.
Pressure-leaf type filters have features to achieve self-cleaning or automatic cake discharge.
These features allow discharge of the filter cake by washing the cake off the filter medium
with internal spray headers or by vibrating the cake off with a pneumatic vibrator. Sometimes
pressure leaf filters are operated manually with respect to valve operation, but their self-
cleaning features remove them from the manual classification. Both horizontal and vertical
tank designs are available with hydraulically operated quick-opening closures to speed the
opening of the tank for dry cake discharge. Filter media types used are cloth covers, felt
covers and wire mesh.
(i) Basket filters

54
For coarse filtration, the basket or strainer filter type is selected, and consists of a pressure
vessel type housing with a perforated internal member that separates the coarse solids from
the process liquid. The internal element is made of perforated metal or is a coarse wire-
woven basket. Refer point 24.9 for details on basket filters.
(ii) Plate-and-frame filter press
The oldest filter type is the plate-and frame filter press. These filters rely on the type of media
used, which is generally the filter sheet or pad for depth filtration not requiring a precoat. The
chamber between the filter plates becomes filled by the removed solids until full.
Fig 24.7.1: Plate and Frame filter
Pages 136 to 137
24.9.2 Basket type strainers:
These are used for services where heavy solids or filtration is necessary e.g. fuel oil service,
strainers before specialized exchangers like core exchangers.

55
Fig 24.9.3: Simplex basket strainer
A procedure to specify area required of basket strainer is provided below:
24.9.3 Strainer Specification
• Liquid Services
For liquid services to core exchangers use permanent basket line strainers (slant top style).
The perforated basket shall be lined with mesh stainless steel wire liner if there is any
potential for the presence of particulates in a fluid system, otherwise 40 mesh is adequate.
Body materials and flange ratings will depend on the exchanger design conditions. The
volume or dimensions of the basket shall be specified as follows:
Volume = (1) Volume of mill scale formed on the inside wall of the upstream pipe back to
the source vessel or drum.
+
(2) Volume allowance of mill scale, dirt, and debris expected in the source vessel.
Use scale thickness of 1/32”.

56
Table 24.9.1: Volume of mill scale (ft3
)
This calculated volume shall be specified to be below the path of fluid flow.
Also, note that to obtain proper volume of the basket, the length may become prohibitive.
For these cases, increase the body size leaving the inlet and outlet flange line sizes to obtain a
more desirable basket geometry.
• Vapor Services:
Use the identical procedure as for liquids, but, source vessel allowance may be neglected.
(These services are typically from tower or vessel overheads where debris/scale settles out at
the bottom of the vessel.)
24.9.4 Pressure Drop Calculation
– As a general thumb rule, an engineer should allow for two extra hard tees for a ‘clean’
strainer when performing preliminary pressure drop calculations. A more accurate pressure
drop estimate should then be obtained through the specific strainer vendor. This back check
needs to be performed to insure that the ‘hard tee’ assumption for pressure loss is
conservative enough. Attached (Figs 24.9.7 to 24.9.11) are some specific pressure drop curves
for reference use for detailed calculations in case vendor data is unavailable at time of
detailed hydraulic calculation, as well as a pressure drop for screen clogging curve, Fig
24.9.12.

57
Chapter 26:
TYPES OF PROJECTS
26.1 PROJECT STAGES:
A process engineer should be aware of the various stages (table 26.1) that a project can
undergo. It is not necessary for all projects to pass through each and every of below
mentioned stages, however, it is important to understand significance of each. It is to be
specifically noted that there is a purpose behind each stage of any project. Few examples
would illustrate this better.
Example (25-1): Example of a new mega greenfield project:
Suppose a major international corporation intends to put up a new mega greenfield
petrochemicals complex catering to various chemicals production. Such a company will find it
very beneficial to go through the various stages as listed in table 26.1 below, to obtain
concrete evidence that the project envisaged is a winner.
• First, it will proceed with ACCESS stage where it may undergo the study with its own
staff or employ a specialist third party to carry out the project feasibility and
confirmation of alignment with its business strategy. It will also obtain the full picture
of various licensors providing technologies for each chemical, their pro-cons in
technology, as well as the potential buyer’s database.
• Secondly, once it is satisfied with viability of project, it will go one step further into
SELECT phase (also called Pre-FEED stage), where having selected the suitable
technologies for each chemical, it will most likely, engage a specialist third party, to
refine the engineering to include not only licensed units but also the offsites and
utilities (O&U) definition which should lead to a rough order of magnitude (ROM)
costing of project (+/- 30% costing approximately) as well as the profitability of project
and return on investment. During the ROM costing, budgetary quotes are obtained for
many major equipment and suitable judgmental factors are taken for many items like
cabling, piping, instrumentation, insulation, overheads based on equipment costs. This

58
stage will facilitate it to plan the budget / resources it would require to put up such a
project, having in hand most probably the report approved by the board of directors as
a gated exercise.
• Having been satisfied with SELECT phase project report, the company will proceed to
next stage i.e. DEFINE stage (also called FEED).
In DEFINE stage, each unit licensor are engaged to provide their basic engineering design
packages (BEDP) and an engineering company is hired, to carry out FEED engineering (Front
End Engineering Design) of complete project incorporating information from BEDP of each
licensed unit and its own engineering effort in offsites and utilities (O&U).
List of FEED deliverables is listed in Volume II, chapter 28 for all disciplines involved in
engineering. In FEED, actual quotations are obtained for most equipment including electrical /
instrumentation equipment (like panels), material take-offs (MTOs) generated for piping,
insulation, instrumentation, cables, civil materials, safety equipment/systems, etc. and
quotations obtained for these. Similarly, quotations are obtained from erection contractors
for all disciplines. Costs are also obtained for site related infrastructure like temporary DG set,
temporary porta cabins at site, labor camps, etc.
All of these provide the company with detailed engineering documentation which leads to
cost estimate of +/- 10% accuracy, definition of total project scope as well as schedule of
project. Note that although our example is for greenfield project, in the case of a brownfield
project, it also gets clear idea of demolition scope as well as risk involved in construction of
new facilities next to a running plant (SIMOPS study).
The FEED report is extremely useful to company to line up resources for project funding. It is
also useful for it to create a scope of work (SOW) for next stage of project which is the
implementation stage (EXECUTE stage).
Many a times, in FEED, the company insists on the engineering firm to identify the LLI’s (long
lead items- e.g. incinerator which can have delivery of 12 months), obtain detailed quotes
from vendors and have TBE (technical bid evaluation) ready for such LLI’s so that at start of
EXECUTE phase, order can be placed on such LLIs to ensure actual project implementation can
be completed fast.
Table 25-1: Overview of Stages of a Project

59
Sr No. STAGES OF PROJECT DEFINITION of STAGE
I ASSESS Determine project feasibility and alignment with business strategy
II SELECT Select preferred project option (s) incorporating pre-DEFINE Engineering
III DEFINE Finalize project scope, cost, and schedule and get project funding
IV EXECUTE Produce an operating asset consistent with scope, cost, and schedule
incorporating EPC and commissioning
V OPERATE Evaluate asset to ensure performance to specification and maximum return to
stakeholders.
In EXECUTE phase (also called detail engineering, procurement, construction and
commissioning phase), the actual implementation of the project takes place. Here, the
company has much flexibility on the project contract to be placed on contractors who will
carry out the further project implementation work. These are defined in point 2. Once it firms
up the contract type, it floats an ITB in the market (invitation to bid), obtains bids from
selected bidders on one of which order is placed for EXECUTE phase. Refer Volume II, Chapter
28 for engineering deliverables as normally prepared by contractors in EXECUTE phase.
In addition to contractor, the company has also many responsibilities in this phase namely,
providing cash flow for procurement, supervising / reviewing of contractors work, ensuring
schedule is on correct path, tying up with external utility suppliers (e.g. fuel gas from Saudi
Aramco gas line supply if project is in KSA) as well as tying up with parties who will take away
company generated wastes, interviewing / hiring of operations staff, training to be provided
for technical staff from licensors, etc.

60
Chapter 29:
PROCESS DESIGN
DOCUMENTATION
29.5 TITLE OF DOCUMENT: Equipment List
PURPOSE OF DOCUMENT: Equipment list communicates to rest of engineering team, all of
the equipment and package units involved in the engineering.
Equipment list is used by other departments for following purpose:
• Based on the equipment list, Planning Department prepares the detailed schedule /
planning using Primavera and it is further used to monitor the progress.
• Procurement Department generates procurement status and monitors the progress of
procurement on the basis of equipment list.
• Piping, mechanical, civil and electrical engineers also refer to the equipment list to
understand discipline-wise responsibility of each item and monitor progress of same.
INPUTS REQUIRED (as applicable):
1. Simulation report
2. Block flow diagram
3. Process Flow Diagrams
4. Basis of Design (BOD)
CONTENTS OF DOCUMENT: It includes all major mechanical items in the plant. It is prepared
unit-wise for each plant which means all equipment in a particular unit are listed together.
However, it excludes electrical, instrumentation and construction equipment and all special
parts (SPI).

61
A unique number is given to each and every mechanical item in a process plant to enable its
identification.
Equipment list is one of the most effective tools extensively used and referred to during basic
as well as detailed engineering phase of the project. It is used for generating field erection
data sheets for process equipment.
Equipment list is made and controlled by process engineer and used by other engineering
disciplines also.
Block flow diagrams & Process flow diagrams form an input for generating equipment list.
In case of package units, all equipment included within the package unit are numbered and
included in equipment list with an indication of requirement of E-Motor for each item to
enable a fairly correct estimation of size of MCC with respect to number of feeders.
Following are the specific contents of an Equipment List.
Please refer to Vol III Chapter 42 for template of an equipment list.
• Equipment Code : Equipment number is indicated here
• Description: Equipment title or name is indicated here
• P&ID reference number where equipment is shown
• Quantity: Numbers of equipment are indicated. (Column “a” is for number of operating
equipment and Column “b” is for number of standby equipment.)
• Medium: Fluid handled by equipment is indicated
• Technical Details: Technical data for each equipment is given under this column
For example; Pumps:
Type: Centrifugal
F: Flow in m³/h
H: Differential Pressure in mlc
Heat Exchangers:
Type: Shell & Tube

62
Q: Heat Duty in kcal/h
A: Area in m², Length, and OD
For package units, duty parameters are given. For example; for boilers, capacity in TPH and
pressure in kg/cm²g is given. Technical details of equipment within package unit are furnished
only after order placement.
• Design Pressure
• Design Temperature
• Drive: Requirement of E-Motor, steam turbine, gas turbine or Electrical Heater
• Material of Construction: Broad material of construction for major parts of equipment
is specified, for example;
• Pumps & Blowers – MOC for Casing & Impeller
• Heat Exchangers – MOC for shell side, MOC for tube side
• Test Pressure and Medium: For hydro test or pneumatic test
• Source of Supply: Whether the equipment is indigenous (I), foreign (F) or part of
package unit (P) is indicated here.
• Group Responsibility: Different equipment is handled by different disciplines and are
responsible for procurement/inquiry. In order to identify the responsible department,
following codes are entered:
e.g. Process, Mechanical, Piping, Civil, Electrical, Client
Any additional information which needs to be known is specified under “Remarks” e.g. if an
existing equipment is to be used, the same is highlighted. Similarly, if an equipment requires
emergency power backup, this is indicated in the remarks column.
29.6 TITLE OF DOCUMENT: BLOCK FLOW DIAGRAM (BFD)
PURPOSE OF DOCUMENT: BFD is prepared in initial stage of process engineering. The
purpose of block diagram in basic engineering package is to show at one place the material
balance in kg/h or m³/h of all process streams entering and leaving each unit in the overall
process. This communicates the overall scope of project to the rest of team.
INPUTS REQUIRED:
For the preparation of block flow diagram, the following documents are required:

63
• Understanding of process
• Preliminary overall General Arrangement (GA) drawing
Each unit is shown as one rectangular block and all incoming and outgoing process streams as
lines with arrows. The units are also shown as per the location as per overall GA drawing.
By the above representation of unit as a block, the total process plant can be covered under
one block diagram. In one block diagram, all plants in a complex can also be represented.
Similarly, an overall utility block diagram can also be generated, if required, as per contract;
by showing individual utility consumption for each unit.
While selecting a capacity for utility package, block diagrams are generally prepared along
with concept notes.
Refer to sample BFD attached below for an incinerator project.
29.7 TITLE OF DOCUMENT: PROCESS FLOW DIAGRAMS (PFD) and UTILITY FLOW
DIAGRAM (UFD)
PURPOSE OF DOCUMENT: In a chemical process plant, raw materials go through a series of
unit operations before getting converted into the finished product. Unit operations could be
feed preparation, reaction, separation, distillation, filtration, crystallization, centrifugation,
drying, etc.
To understand these operations easily a Process Flow Diagram (PFD) is prepared which shows
the flow of chemicals/reactants through various equipment. Thus a Process Flow Diagram
(PFD) shows all the important pieces of equipment with flow lines and control systems in a
schematic way, along with its process description, which helps to understand the process very
well.
CONTENTS OF DOCUMENTS:
A) Process flow diagram is a fundamental process drawing which depicts major process
related equipment, machines, and process lines in a simple manner.
Inputs for generating process flow diagram are as follows:
– Design basis

64
– Simulation Report
– Thermo-physical property data
i) The contents of process flow sheets are mainly as follows:
– All equipment and machines as per simulation report
– Package units as blocks
– Equipment number (matching later with equipment list)
– Main connecting process lines between the equipment are shown. However, less important
lines like minimum flow lines are not shown.
– Main control loops with control valves and impulse lines of the instruments are shown.
– Number for major open loops are shown.
– Operating pressure of the line is shown
– Operating temperature of the line is shown
– Operating pressure of the equipment is shown inside the equipment.
– Process stream numbers are marked
– Incoming lines enter from the left and leave on the right side.
– If a process stream is appearing on another sheet also then on the subsequent sheet the
stream number as on the previous stream is given to identify the stream easily
ii) The minimum information of the process streams is as given below:
– Stream No.
– Composition
– Operating pressure & temperature

65
– Density
– Volumetric / mass flow rates
– Viscosity
– Utilities like steam, cooling water, pressurized air, etc. are shown by a line with the short
code for medium
– The heat balance is given in units as per Design Basis units of measurement.
– The utility consumption is given on each consumer as volume or mass stream.
– Additional temperature and pressure data is given as required.
– Pressures is given in gauge pressure
– Flow sheets are organized to show correct relative elevations of equipment and also in
relation to other flow sheets.
iii) The PFD and the material balance is the basis for the following engineering activities:
– Preparation of P&I Diagrams and to size lines.
– Preparation of list of consumption figures
– Preparation of list of emissions required by statutory bodies
– Preparation of utility summary and concept notes for utility package units
– Sizing of static and rotating equipment
– Unit equipment plot plans
– Hazid / Envid safety study
iv) Separate process flow diagrams are generated to take care of:
– Start of run conditions (SOR)

66
– End of run condition (EOR)
– Runaway condition
v) Also from the same process, different grades of products can be manufactured, for
example, for HDPE plant:
– Extrusion grade HDPE
– Blow moulding grade HDPE
Separate PFD thus is generated for each such grade.
vi) Material balance shown in PFD is corresponding to the contractual design capacity of the
plant.
vii) It is also a practice to give the heat & material balance portion in a separate A4 size
sheet for large unit PFDs.
B) UTILITY FLOW DIAGRAMS:
Utility flow diagrams are prepared for each utility showing each consumer as a rectangular
block. These are generated mainly for all process plant consumers.
Pages 28 to 29
29.12 TITLE OF DOCUMENT: PROCESS SAFEGUARDING FLOW DIAGRAMS (PSFD)
PURPOSE OF DOCUMENT: Process Safeguarding Flow Diagrams (PSFD) provide an overview
of the process safeguards applied to a process plant. They show the location of pressure
relieving devices based on design pressures of the system. They, therefore, serve as a starting
point for the development of P&IDs.
INPUTS REQUIRED:
(i) BFD
(ii) PFD

67
CONTENTS OF DOCUMENT:
The following should be shown on the PSFDs:
i) Safeguarding elements:
– Ultimate safeguards (these are trip interlocks e.g. High-high, low-low):
– Relief valves will be shown along with relief destination e.g. HP or LP flare.
– Safety Instrumented Systems (SIS), if used as an ultimate safeguard.
– Capacity determining components:
• Control valves and by-passes will be shown along with action on air failure (i.e. spring
action fail open/close or stay put).
• Notes should be shown as necessary to state which if any of downstream relief systems
are affected by the capacity (i.e. CV) of the control valve and restriction orifices where
applicable.
ii) Mitigating systems:
– All mitigating systems such as ESD valves, ROVs installed for an emergency (e.g. in pump
suction lines), check valves etc.
– Emergency depressuring valves along with relief destination.
– Relevant interfaces with upstream and downstream units
Details of penultimate safeguards (i.e. alarms of high and low) do not need to be shown on
PSFDs.
Process Safeguarding Flow Diagrams (PSFD) should be prepared only for new process units
and repeat modified units where the changes affect the safety integrity of the system.
PSFDs are based on the initial issue of the relevant PFD. The PSFDs are intended to assist and
guide the development of the P&IDs with regard to identifying safety protective devices
including emergency shutdown valves, relief valves and depressuring facilities.

68
PSFDs should be issued before the issue of P&IDs to ensure that the required information is
transposed on to the P&IDs.
Refer sample PSFD shown below.
Fig 29.4: PSFD of a LPG bullet storage facility

69
Chapter 6:
TECHNICAL BID EVALUATIONS
30.7 – Technical Evaluation Guidelines for Screw Compressors:
Standard:
Generally, screw compressors are specified and manufactured as per manufacturer standard
for compressed air service.
Gas screw compressors are manufactured as per API 619 for compressor and API 614 for oil
system.
Following are the evaluation criteria:
1. Vendor should be asked to submit the following:
• Basis for selection of offered model.
• Selection chart
• In case of critical service, references of supply for selected model for the process
medium and process operating conditions.
In case of oil lubricated screw compressors, the oil content in ppm at discharge of
compressor. Generally, all refrigerated screw compressors are oil flooded type. Air screw
compressors can also be oil lubricated type provided oil in outlet air is acceptable.
Dry type are also available for process services and for compressed air service.
2. Control method of achieving minimum turndown should be provided by vendor.
3. If vendor is offering compressor with economizer, check the following:

70
• Duty and area provided for economizer are consistent with respect to in/out conditions
• Operating conditions with respect to pressures and temperature of the economizer for
shell and tube side
• Ensure that oil removal boot is provided in economizer shell side
4. Consumption figures:
• Refer compressor chart and cross check the power requirement for model selected.
• Minimum turndown and power consumption at part load conditions to be checked.
5. Oil Circuit:
Oil circuit for compressor should be checked carefully and following points must be checked:
• To minimize possibility of cavitation of oil pump, pump should be located at the lowest
elevation of oil circuit. Suction pipe for pump should be properly sized. Length of
suction pipe should be as minimum as possible. Vertical loop on pump suction line
must be avoided, otherwise, oil pump may cavitate because of separation of dissolved
gases from oil at pump suction.
• Volume of oil separator should be checked and ensure that 70% of the capacity of oil
separator is adequate to receive all oils from crank case and other parts of oil circuit.
• Duplex type filter with change-over facility equipped with all necessary instrumentation
like differential pressure indicator, is generally recommended. Downstream of filter
upto compressor should be in stainless steel material.
• Requirement of pre and post lube operation for compressor should be clarified by
vendor. In case when vendor recommends post lube, immediate restart may become
difficult because the compressor gets flooded with oil and oil separator gets empty.
• Tube bundle of oil cooler must be of stainless steel. This is required to avoid formation
of water oil emulsion when tube fails due to corrosion and pressure in cooling water is
higher than oil pressure.
• Vendor must be asked to provide two oil pumps (1 W + 1 S).
6. Motor Selection:
Vendor shall be asked to indicate power requirement when suction gas density is maximum.
Selected motor should have minimum 15% margin over gauranteed power requirement and
over power requirement for maximum suction gas density condition whichever is higher.

71
7. Review the reference list for quoted model and ensure that said model has already been
installed elsewhere and it is working satisfactorily for more than two years.
8. From consideration of maintenance and inventory control, single stage machine is always
preferred and more common. If vendor has quoted for two stage machine with
intermediate bearing, then thorough investigation of the model is necessary including
downtime for maintenance. It has been noticed that time required to dismantle the
machine to replace any parts or to align the rotor for single stage machine is much less than
that for two stage machine.
9. For oil lubricated compressors, oil used for machine should not be reactive towards gas
handled by machine.
10. Instrumentation and Interlocks:
11. Ensure that following minimum interlocks have been considered by vendor. Compressor
should trip under following interlocks:
• Low low suction pressure
• High high discharge pressure
• High high discharge temperature
• Low cooling water flow (for water cooled machines)
• High level of economiser and low & high level of oil separator
• Low lube oil pressure
• High lube oil temperature
• Low lube oil differential pressure
ii) All instrumentation and controls other than shut down sensing devices shall be installed
with suitable isolations and controls while system is in operation.
iii) Necessary instruments to provide alarms before trip should be included
iv) Instrumentation for compressor control (if included in enquiry should be in vendor scope).
******************************************************* *******************************************
--- END OF SAMPLE ---
******************************************************* *******************************************

72
Index (Full Version)
Vol Chapter No. Title No. of Pages
I – Preface, Foreword and Overall Table of Contents 6
I 1 Introduction 5
I 2 General 138
I 3 Pumps 181
I 4 Compressors 149
I 5 Fans and Blowers 59
I 6 Heat Exchangers 93
I 7 Pressure vessels, Tanks and Bullets 58
I 8 Fractionators and Absorbers 396
I 9 Separators 92
I 10 Fired Heaters 142
I 11 Incinerators 68
I 12 Agitated Vessels 86
I 13 Safety Relief Systems 255
I 14 Line Sizing, Hydraulics 76
I 15 Vacuum systems 90
I 16 Utilities 469
I 17 Dryers 48
I 18 Motors 16
I 19 Evaporators 62
I 20 Pneumatic Conveying 78
I 21 Crystallisers 32
I 22 Steam and Gas Turbines 84
I 23 Leaching and Extraction 77
I 24 Special Process Items 191
I 25 Additional Process Calculations 50

73
II 26 Project Types 13
II 27 Engineering Disciplines and Sequence of Engineering 60
II 28 Overall Engineering Documentation for all Disciplines in a
Project
13
II 29 Process Design Documentation 256
II 30 TBE Guidelines 44
II 31 Safety Studies 15
II 32 Automation and Control 138
II 33 Material of Construction 90
II 34 Cost, Time & Resource Estimation 10
II 35 Inspection and Testing 11
II 36 Precommissioning, Commissioning and Guarantee Run 58
II 37 Specialised Studies 55
II 38 Heat Exchanger Optimization 156
II 39 Philosophies 28
III 40 Calculation Templates (40 numbers)
III 41 Checklists (25 numbers)
III 42 Datasheets (93 numbers)
III 43 Technical Bid Evaluation Formats (11 numbers)
III 44 Go-By Reference P&IDs (41 numbers)
Handbook Details
1 No. of Chapters 44
2 No. of Pages 4000
3 Figures 2265
4 Tables 440
5 Calculation Templates 40
6 Datasheets 93
7 TBE Blank Formats 11
8 Checklists 25

74
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