Final Year Thesis.PDF

Introduction to the
Sweetening of Natural Gas
with Emphasis on Sulfur
Recovery
(Sulfur Recovery: 80 tons per day)
Project Advisor:
Prof. Dr. Shahid Naveed
Project Co advisor:
Madam Masooma Sundus
Project Team
Name Registration No.
Imran Shabbir 2005-Chem-79
Omer Farooqi 2005-Chem-97
Jahanzaib Ali Bugti 2005-Chem-95
Ali Shan Malik 2005-Chem-41
Osman Shahid 2005-Chem-65
UNIVERSITY OF ENGINEERING AND
TECHNOLOGY LAHORE PAKISTAN
DEPARTMENTOFCHEMICALENGINEERING
[Typeyouraddress][Typeyourphonenumber][Typeyoure-mailaddress]
DEPARTMENTOFCHEMICALENGINEERING
August2009

Approval Certificate
INTRODUCTION TO THE SWEETENING OF NATURAL GAS
WITH EMPHASIS ON SULFUR RECOVERY
This major project report has been completed and submitted to the Department of Chemical
Engineering, University of Engineering and Technology Lahore in partial fulfillment of the
requirement for the B.Sc Chemical Engineering degree
Project Team:
Imran Shabbir
Muhammad Omer Farooqi
Jahanzaib Ali Bugti
Ali Shan Malik
Osman Shahid
Approved by:
Prof. Dr. Shahid Naveed Prof. Dr. A. R. Saleemi
(Project Advisor) (Chairman)
____________________ ___________________
External Examiner
____________________ ___________________

In the name of
Allah
The most Merciful and
Compassionate, The most Gracious
and Beneficent Whose help and
guidance we always solicit at every step,
in each moment of our lives

DEDICATION
Our parents, whose
blessing brought us at
this stage and who
trample their
inclination & longings
for uploading our
studies

Acknowledgments
Thanks to The Almighty ALLAH, “Who taught us with pen and
told what we did not know” and guided us by the Holy Prophet Hazrat
Mohammad (Peace be upon Him) after whom no further guidance is
needed.
We are indebted to our chairman, Prof. Dr. A. R. Saleemi who
provided us his knowledge and facilities to complete this project.
We acknowledge our indebtedness to our beloved project adviser
Prof. Dr. Shahid Naveed and our project co adviser Madam Masuma
Sundus for their timely guidance, encouragement, sympathetic attitude
and professional assistance, without which this project would not have
been completed.
A special thank you goes to Engr. Sir Mohsin Kazmi, Engr. Sir
Faheem and Engr. Sir Qazi Zaka ur Rehman for being so kind and
helping to us. Indeed without their guidance it was not an easy job to
complete this project.
A general debt of gratitude is due to all the teachers of the
Chemical Engineering Department, UET Lahore for their kind help.
There is a deep contribution from our teachers to whatever we have
achieved and whatever we intend to achieve in our lives.
We are also thankful to the non-teaching staff of the department
for their intellectual and moral support.
We extend special thanks to our sweet parents for their unlimited
love, kindness and support throughout our studies, and who pray for our
success and bright future deeply.
AUTHORS

TABLE OF CONTENTS
Abstract І
Preface І І
Problem Statement (1)
Chapter 1 (2-20)
INTRODUCTION TO NATURAL GAS PROCESSING
1.1 Exploration of Natural Gas
1.2 Processing Natural Gas
1.3 Sweetening
1.3.1 Reasons of Removing H2S and CO2
1.3.2 Amine Solutions used in Sweetening
1.3.3 The Girdler Process
1.4 About Sulfur
1.4.1 Properties of Sulfur
1.4.2 Processing of Sulfur
1.4.3 Uses of Sulfur
1.4.4 Products of Sulfur
1.5 Sulfur Recovery Methods
1.5.1 Medium (0.20 to 25.0 LTPD)
1.5.2 Large (greater than 25.0 LTPD)
1.5.3 Explanation of Various Processes
1.5.3.1 Sulfa Treat Direct Oxidation Process
1.5.3.2 The Claus Process

1.5.3.3 Recycle Selectox Process
1.5.3.4 Selective Oxidation Process
1.5.3.5 Cold Bed Adsorption Process
1.5.3.6 Thermal Cracking of H2S
1.6 The Claus Process
1.6.1 History
1.6.2 Description
1.6.3 Simplified Process Description
1.6.4 Process Improvements
1.6.5 Claus Process Auxiliaries
1.6.5.1 Blow Down System
1.6.5.2 Fuel System
Chapter 2 (21-30)
MAJOR EQUIPMENTS USED IN CLAUS PROCESS & THEIR
IMPROVEMENT CONSIDERATIONS
2.1 Introduction
2.2 Reaction Furnace (F-100)
2.3 Waste Heat Boiler (B-100)
2.4 Sulfur Condensers (E-100, E-102, E-104, E-106)
2.5 Heaters (E-101, E-103, E-105)
2.5.1 Direct Reheat Methods
2.5.2 Hot Gas Bypass
2.5.3 Acid Gas Fired Line Burner
2.6 Catalytic Reactors (R-100, R-101, R-102)
2.7 Sulfur Pits

Chapter 3 (31-45)
MATERIAL BALANCE OF THE SULFUR RECOVERY UNIT (SRU)
3.1 Introduction
3.2 Overall Material Balance
3.3 Material Balance across Furnace F-100
3.4 Material Balance across Condenser E-100
3.5 Material Balance across Reactor R-100
3.11 Final Calculations
Chapter 4 (46-57)
ENERGY BALANCE OF THE SULFUR RECOVERY UNIT (SRU)
4.1 Introduction
4.2 Overall Energy Balance
4.3 Energy Balance across Furnace F-100
4.4 Energy Balance across Boiler B-100
4.5 Energy Balance across Condenser E-100
4.6 Energy Balance across Heater E-101
4.7 Energy Balance across Reactor R-100

Chapter 5 (58-93)
EQUIPMENTS DESIGN
5.1 Design of Reaction Furnace (F-100)
5.2 Design of Waste Heat Boiler (B-100)
5.3 Design of Reactors (R-100, R-101, R-102)
5.4 Design of Condenser (E-106)
5.5 Design of Process Stream Heater (E-105)
Chapter 6 (94-97)
PROCESS INSTRUMENTATION & CONTROL
6.1 Introduction
6.2 General Discussion on the Instrumentation of the Sulfur Recovery Unit (SRU)
6.2.1 Feed Flow Measurement and Control
6.2.2 Combustion Air Control
6.2.3 Main Burner and Reaction Furnace
6.2.4 Waste Heat Boiler
6.2.5 Sulfur Condensers
6.2.6 Heaters
6.2.7 Catalytic Reactors
6.2.8 Shutdown System

6.3 Instrumentation for Condensers
Chapter 7 (98-101)
MECHANICAL DESIGN OF THE PROCESS STREAM HEATERS
7.1 Introduction
7.2 Waste Heat Boiler
7.3 The Claus Reactors
7.4 Sulfur Condensers
7.5 Sulfur Pits
Chapter 8 (102-104)
HAZOP STUDY OF THE SULFUR RECOVERY UNIT (SRU)
8.1 Introduction
8.2 General Safety Rules
8.3 Building and Process Equipment Safety
8.3.1 Lights
8.3.2 Electrical and Mechanical Hazards
8.3.3 Chemical Hazards
8.3.4 Fire Prevention and Control
8.3.5 Personnel Safety
8.4 Claus Process
8.4.1 Special Hazards and Precautions
Chapter 9 (105-112)
COST ESTIMATION OF THE SULFUR RECOVERY UNIT (SRU)
9.1 Introduction
9.2 Fixed and Working Capital

9.3 Total Production Cost
9.3.1 Manufacturing Cost
9.3.2 General Expenses
9.4 Equipment Cost
References

I
ABSTRACT
This project has to design Sulfur Recovery Unit (SRU). There are many
processes for the recovery of sulfur from natural gas but we selected the Claus
process, because the design of the process is economically most favorable. The
economics of the plant also make balance with the efficiency and is most suited
to Pakistan’s wells of oil and gas.
The process selected for this purpose is the Claus process and the unit is
designed to produce 80 tons of elemental sulfur per day.
This report includes introduction to natural gas exploration, Dakhni gas
processing plant review, production and processing, various processes
employed for the sulfur recovery from the natural gas, the details of the Claus
process, material and energy balances across the sulfur recovery unit (SRU),
individual equipments design, instrumentation and control, piping, cost
estimation, selection process of the construction material and lining of
refractory, and the safety of the sulfur recovery unit (SRU).
In summary, the focus on the future improvements in the Claus process
makes this project distinctive and particularly relevant for educating present or
perspective engineers. We have worked hard to complete this project that is
stimulating for engineers to read. We also strived to develop the design of the
sulfur recovery unit (SRU) that will capture engineer’s attention, is
pedagogically sound and well integrated with project material, and is easy for
the engineers to use and adapt.
We welcome any comments or suggestions. Please feel free to contact via
e-mail at: chem_protagonists@hotmail.com and
chem_protagonists@yahoo.com, furthermore a soft copy can be obtained on
request at the said e-mail addresses.

II
PREFACE
The aim behind this project is to design the sulfur recovery unit (from
natural gas). The capacity of the proposed plant is 80 tons per day.
Generally, the natural gas obtained from the reservoirs, contains many
impurities including hydrogen disulfide (H2S), the presence of which makes the
gas toxic. To make the use of this gas environmentally acceptable, the gas is
passed through a number of purifying stages. One of these stages is that of
sulfur recovery unit (SRU).
There are many different processes used for the recovery of sulfur from
natural gas. We selected the Claus process, as it is the most economical process
especially for the large amounts to process like we had to. This process mainly
comprises two reactions; first, one by third of the hydrogen disulfide present in
the feed is converted into sulfur dioxide by burning in the furnace and second,
the remaining hydrogen disulfide reacts with the produced sulfur dioxide to
give elemental sulfur. First reaction occurs in a furnace while the second
reaction takes place in a series of reactors. Sulfur produced in the reactors is
then condensed in the condenser. The pipelines throughout are insulated so that
sulfur may not freeze inside the pipes.
Sulfur obtained by this process is used commercially as a hardening
agent in the manufacture of rubber products, such as tires. The most important
use of sulfur is in the manufacture of sulfur compounds, such as sulfuric acid,
sulfites, sulfates, and sulfur dioxide. Medicinally, it has assumed importance
because of its widespread use in sulfa drugs and in many skin ointments. Sulfur
is also employed in the production of matches, wood pulp, carbon disulfide,
insecticides, bleaching agents, vulcanized rubber etc.

1
Problem Statement
This project report had been assigned to us as the partial fulfillment for the
requirement of the B.Sc Chemical Engineering degree. The problem statement is:
“INTRODUCTION TO THE SWEETENING OF NATURAL GAS WITH EMPHASIS ON SULFUR
RECOVERY”. The proposed plant capacity is selected to be 80 tons per day which matches
with the prevailing extended market needs and to meet the industrial demands. The
inspiring facility for this project is the Oil and Gas Development Corporation Limited
(OGDCL), Dakhni. This facility has a current production of 65 tons per day of elemental
rhombic sulfur but is interested in extension of the production plants to produce 80 tons per
day which is the very problem assigned to us in this project.
The natural gas obtained from wells contains toxic hydrogen sulfide gas which must
be removed in order to make the use of natural gas safe and friendly. Sweetening is done to
remove hydrogen sulfide gas and then the famous Claus process is employed to recover
elemental rhombic sulfur from the hydrogen sulfide gas stream which is a valuable market
product having its use, in the production of many daily life useful products, as a raw
material.
Fig: Flow diagram for the Claus process.
The project team is guided and motivated by respected Dr. Shahid Naveed as the
project advisor. All of the material and data being presented in this report is taken from
authentic literature and timely references have been provided to guide the reader and at
the same time prevent ourselves of getting divert from the main essence of report writing.

Chapter 1
INTRODUCTION AND LITERATURE REVIEW
1.1 Exploration of Natural Gas
he practice of locating natural gas and petroleum deposits has been transformed
dramatically in the last 15 years with the advent of extremely advanced,
ingenious technology. In the early days of the industry, the only way of locating
underground petroleum and natural gas deposits was to search for surface
evidence of these underground formations. Those searching for natural gas
deposits were forced to scour the earth, looking for seepages of oil or gas emitted from
underground before they had any clue that there were deposits underneath. However,
because such a low proportion of petroleum and natural gas deposits actually seep to the
surface, this made for a very inefficient and difficult exploration process. As the demand for
fossil fuel energy has increased dramatically over the past years, so has the necessity for
more accurate methods of locating these deposits.
1.2 Processing Natural Gas
A Natural Gas Processing Plant Natural gas, as it is used by consumers, is much different
from the natural gas that is brought from underground up to the wellhead. Although the
processing of natural gas is in many respects less complicated than the processing and
refining of crude oil, it is equally as necessary before its use by end users. The natural gas
used by consumers is composed almost entirely of methane. However, natural gas found at
the wellhead, although still composed primarily of methane, is by no means as pure. Raw
natural gas comes from three types of wells: oil wells, gas wells, and condensate wells.
Natural gas that comes from oil wells is typically termed as “associated gas”. This gas can
exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved
gas). Natural gas from gas and condensate wells, in which there is little or no crude oil, is
termed ‘non-associated gas’. Gas wells typically produce raw natural gas by itself, while
condensate wells produce free natural gas along with a semi-liquid hydrocarbon
condensate. Whatever the source of the natural gas, once separated from crude oil (if
present) it commonly exists in mixtures with other hydrocarbons; principally ethane,
propane, butane, and pentanes. In addition, raw natural gas contains water vapor,
hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.
Natural gas processing consists of separating all of the various hydrocarbons and
thuds from the pure natural gas, to produce what is known as ‘pipeline quality’ dry natural
gas. Major transportation pipelines usually impose restrictions on the make-up of the
T

Chapter 1Introduction to Natural Gas Processing
3
natural gas that is allowed into the pipeline. That means that before the natural gas can be
transported it must be purified. While the ethane, propane, butane, and pentanes must be
removed from natural gas, this does not mean that they are all ‘waste products’.
In addition to processing done at the wellhead and at centralized processing plants,
some final processing is also sometimes accomplished at ‘straddle extraction plants’. These
plants are located on major pipeline systems. Although the natural gas that arrives at these
straddle extraction plants is already of pipeline quality, in certain instances there still exist
small quantities of NGLs, which are extracted at the straddle plants.
The actual practice of processing natural gas to pipeline dry gas quality levels can be
quite complex but usually involves four main processes to remove the various impurities:
 Oil and Condensate Removal
 Water Removal
 Separation of Natural Gas Liquids
 Sulfur and Carbon Dioxide Removal
Fig 1.1: Diagram of a typical gas processing plant.

4
1.3 Sweetening
Amine gas treating, also known as gas sweetening and acid gas removal, refers to a
group of processes that use aqueous solutions of various alkanolamines (commonly
referred to simply as amines) to remove hydrogen sulfide (H2S) and carbon dioxide (CO2)
from gases. It is a common unit process used in refineries, petrochemical plants, natural gas
processing plants and other industries. Processes within oil refineries or natural gas
processing plants that remove hydrogen sulfide and/or mercaptans are commonly referred
to as sweetening processes because they result in products which no longer have the sour,
foul odors of mercaptans and hydrogen sulfide.
1.3.1 Reasons of Removing H2S and CO2
Carbon dioxide, hydrogen sulfide, and other contaminants are often found in natural
gas streams. CO2 when combined with water creates carbonic acid which is corrosive. CO2
also reduces the BTU value of gas and in concentrations of more that 2% or 3% the gas is
unmarketable. H2S is an extremely toxic gas that is also tremendously corrosive to
equipment. Amine sweetening processes remove these contaminants so that the gas is
marketable and suitable for transportation. The recovered hydrogen sulfide gas stream may
be:
 Vented to atmosphere.
 Flared in waste gas flares or modern smokeless flares.
 Incinerated for sulfur removal.
 Utilized for the production of elemental sulfur or sulfuric acid.
If the recovered H2S gas stream is not to be utilized as a feedstock for commercial
applications, the gas is usually passed to a tail gas incinerator in which the H2S is oxidized to
SO2 and is then passed to the atmosphere out a stack.
1.3.2 Amine Solutions Used in Sweetening
Amine has a natural affinity for both CO2 and H2S allowing this to be a very efficient
and effective removal process. There are many different amines used in gas treating:
 Monoethanolamine (MEA) -Used in low pressure natural gas treatment applications
requiring stringent outlet gas specifications.
 Diethanolamine (DEA) -Used in medium to high pressure treating and does not
require reclaiming as do MEA and DGA systems.
 Methyldiethanolamine (MDEA) -Has a higher affinity for H2S than CO2 which allows
some CO2 "slip" while retaining H2S removal capabilities.
 Diisopropylamine (DIPA)
 Aminoethoxyethanol / diglycolamine (DGA)
 Formulated special solvents.

5
However, the most commonly used amines in industrial plants are the
alkanolamines MEA, DEA, and MDEA. Amines are also used in many oil refineries to remove
sour gases from liquid hydrocarbons such as liquefied petroleum gas (LPG).
1.3.3 The Girdler Process
Natural gas is considered "sour" if hydrogen sulfide (H2S) is present in amounts
greater than 5.7 milligrams per normal cubic meters (mg/Nm3
) or 0.25 grains per 100
standard cubic feet [gr/100 scf]). The H2S must be removed (called "sweetening" the gas)
before the gas can be utilized. If H2S is present, the gas is usually sweetened by absorption
of the H2S in an amine solution, also known as the Girdler process.
Other methods, such as carbonate process, solid bed absorbent and physical
absorption, are employed in the other sweetening plants.
The main reaction of the Girdler process is as follows:
2RNH2 + H2S (RNH3)2S
Where:
R = mono, di, or tri-ethanol
N = nitrogen
H = hydrogen
S = sulfur
Fig 1.2: A typical amine gas sweetening plant.

6
1.4 About Sulfur
Sulfur is a non-metallic element that occurs in both combined and free states and is
distributed widely over the earth’s surface. It is tasteless, odorless, insoluble in water, and
often occurs in yellow crystals or masses. It is one of the most abundant elements found in
a pure crystalline form. The word sulfur is Latin for “burning stone”, and was used almost
interchangeably with the term for fire. Because of its combustibility, sulfur was used for a
variety of purposes at least 4,000 years ago.
Although it is plentiful on a world scale, native sulfur is usually found in relatively
minute quantities. The greatest quantity of naturally occurring sulfur by far is combined
with other elements, most notably the sulfides of copper, iron, lead, and zinc, and the
sulfates of barium, calcium (commonly known as gypsum), magnesium, and sodium.
In the late 1 800s the Frasch process - a mining technique that recovers from 75% to
92% of a salt dome’s recoverable sulfur - became operational. Stockpiles today account for
more than 50% of the. US, Canada, Japan, France, Poland, and Mexico are major sulfur
suppliers.
Secondary sources of sulfur today are the sulfur dioxide (SO2) obtained from
industrial mineral, wastes, and flue gasses, and the hydrogen sulfide (H2S) found in “sour”
natural gas, petroleum refinery products, and coke-oven gasses. Once considered
unwelcome byproducts of industrial processes, these sources of sulfur have the advantage
of being nearly inexhaustible.
It was stated that 80% to 85% sulfur production in the year 2000 was recovered
sulfur produced from hydrogen sulfide (H2S).
1.4.1 Properties of Sulfur
Chemical Name: Sulfur
Family Name: Element - Sulfur
Chemical Formula: S8
Physical State: Solid
Appearance: Yellow colored lumps, crystals, powder, or formed shape
Odor: Odorless, or faint odor of rotten eggs if not 100% pure
Purity: 90% - 100%
Molecular Weight: 256.50

7
Vapor Density: (Air = 1): 1.1
Vapor Pressure: 0 mmHg at 280 o
F
Solubility in Water: Insoluble
Specific Gravity: 2.07 at 70 o
F
Boiling Point: 832 o
F (444 o
C)
Freezing/Melting Point: 230-246 o
F (110-119 o
C)
Bulk Density: Lumps 75-1 15 lbs./ft3 Powder 3 3-80 lbs./ft3
Flashpoint: 405 o
F (207.2 o
C)
Flammable Limits: LEL: 3.3 UEL: 46.0
Auto-ignition Temperature: 478-511 o
F (248-266 o
C)
Sulfur is an odorless, tasteless, light yellow solid. It is a reactive element that given
favorable circumstances combines with all other elements except gases, gold, and platinum.
Sulfur appears in a number of different allotropic modifications: rhombic, monoclinic,
polymeric, and others. The rhombic structure is the most commonly found sulfur form. Each
allotropic form differs in solubility, specific gravity, crystalline, crystalline arrangement, and
other physical constants. These various allotropes also can exist together in equilibrium in
definite proportions, depending on temperature and pressure.
1.4.2 Processing of Sulfur
Sulfur processing is accomplished in plants using four manufacturing methods,
producing sulfurs described as: Milled sulfurs, Formed sulfurs, Emulsified sulfur, and
Precipitated sulfur.
Milled Sulfurs
These products are produced using Raymond roller mills to grind to specific particle
ranges. Additives such as dispersants, flow aids, and dust suppressants may be added to
enhance product performance.
Formed Sulfurs
These products are produced by molding, drum flaking, or rotoforining, and then
sized to meet specific needs. Additives may be used for degradability.

8
Emulsified Sulfur
These products are manufactured using homogenizing technology to create a water
based suspension.
Precipitated Sulfur
Flowers of sulfur are distilled sulfurs of exceptional purity obtained by sublimation of
sulfur vapor into particulate form in an inert atmosphere.
1.4.3 Uses of Sulfur
Sulfur is an element used for everything from adhesives to matches. Its most
common use is as a hardening agent in the manufacture of rubber products, such as tires.
The most important use of sulfur is in the manufacture of sulfur compounds, such as sulfuric
acid, sulfites, sulfates, and sulfur dioxide. Medicinally, it has assumed importance because
of its widespread use in sulfa drugs and in many skin ointments. Sulfur is also employed in
the production of matches, vulcanized rubber, dyes, and gunpowder. In a finely divided
state and, frequently, mixed with lime, sulfur is used as a fungicide on plants. The salt,
sodium thiosulfate, Na2S2O3.5H2O, commonly called hypo, is used in photography for
“fixing” negatives and prints. When combined with various inert mineral fillers, sulfur forms
a special cement used to anchor metal objects, such as railings and chains, in stone. Sulfuric
acid is one of the most important of all industrial chemicals because it is employed not only
in the manufacture of sulfur-containing molecules but also in the manufacture of numerous
other materials that do not themselves contain sulfur, such as phosphoric acid.
1.4.4 Products of Sulfur
Three major product groups exist according to use: Rubber maker’s, Industrial, and
Agricultural.
Rubber maker’s Sulfur
Sulfur has been used as a rubber chemical since Charles Goodyear discovered its
vulcanizing properties in the mid 1800’s. Pencil erasers, rubber bumpers on automobiles,
and latex gloves all use the same type of product, but in different quantities and heat
variations.
Rubber maker’s sulfur products vary widely in formulation and use. Conditioning
agents are added to improve flow ability, handling, and dispersion characteristics of finely
ground sulfur. Oil is often added as a dust suppressant, reducing the risk of a sulfur dust
explosion.
The following sulfur options are called grades, and offer a wide choice of purity,
fineness, and conditioning agents for rubber processing

9
 Grinding and Screening
 Conditioning Agents
 Oil Treatment
Industrial Sulfur
Industrial sulfurs are 99.5% minimum purity, processed into various physical shapes
to provide a full range of particle sizes. This market includes pulp and paper, metals
reclaiming, mining, steel, oil refining, and a multitude of other uses. Sulfur is also used in
the public utilities sector as a scale inhibitor. Industrial sulfur is available as crude lumps,
flakes, ground sulfur, formed pastilles, or formed briquettes. Flake sulfur can be screened to
a variety of specifications.
Commercial Grades
 Ground sulfurs milled to various specifications.
 Arrow Roll® Refined Sulfur
 Prill
 Animal Feed Sulfur
 Granular / Pastille
 Emulsified
 Flake
Agricultural Sulfur
These products are formulated for use as nutrients, soil amendments, and
pesticides. Their main uses are as fungicides, insecticides, and miticides. Another common
use is as a soil additive to correct alkalinity or sulfur deficiency.
Wettable Sulfurs
Wettable powders are formulated by blending dispersants and surfactants together
and then milling to a very fine particle size. They can be applied as a spray or dust These
products are used primarily as a fungicide or miticide. Wettable sulfur can be applied as a
ground spray or aerial application. Poultry houses can be rid of depluming mites by applying
spray to all interior surfaces. These products are registered by the EPA.
Flowable Sulfur

10
Dispersion or flowable type products are generally used on vine crops such as
grapes, tomatoes, and peanuts. Formulated as water based dispersion weighing six pounds
per gallon and is primarily used as a fungicide. This product can also be used as a soil
amendment if immediate pH correction is required. These products are registered by the
EPA.
Dusting Sulfur
Formulated at 98%, this product is primarily used as a fungicide. This product is
registered by the EPA.
Degradable Sulfur
Formulated at 90%, this product is primarily used as a plant nutrient. Formed as a
pastille or granule, degradable sulfur is also available in various sizes to conform to specific
blend requirements.
1.5 Sulfur Recovery Methods
On a worldwide basis natural gas and crude oil are becoming sourer. As the
sweeter, more desirable natural gas and crude oil supplies are exhausted; more and more
emphasis is placed on these sour, less desirable feed stocks. The sulfur species in natural
gas after its removal is generally in the form of hydrogen sulfide (H2S). The most common
means of recovering the sulfur contained in hydrogen sulfide is the Clause process. This
process can recover 93-99% of the sulfur contained in its feed. Recovery depends upon feed
composition, age of catalyst, and number of reactor stages. The gas leaving the Clause plant
is referred to as tail gas and is burnt to convert the remaining hydrogen sulfide, which is
lethal at low levels, to sulfur dioxide, which has a much higher toxic limit. The off-gas stream
is vented to atmosphere or sent to Tail Gas Recovery Plant.
Fig 1.3: Average production of crude oil and natural gas for sulfur extraction.
0
2000
4000
6000
8000
10000
12000
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
Production(MTPD)
Sulfur Production
Production
(MTPD)
Crude
Production
(MTPD)
Natural Gas

11
Processes are differentiated on the bases of capacity as follows.
1.5.1 Medium (0.20 to 25.0 LTPD)
 Sulfa Treat DO (Direct Oxidation) is a medium scale process.
1.5.2 Large (greater than 25.0 LTPD)
 Clause process least expensive, well proven but only economical at large scales.
 Recycle Selectox Process.
 Selective Oxidation Process.
- Parson’s High Activity Process.
- Super Clause Process.
 Wet Oxidation Based on Aqueous Solution.
-Stratford and Sulfoline Process.
-SulFerox Process.
-Bio-SR Process.
 Cold Bed Absorption Process.
- CBA 4 Reactor Scheme.
- CBA 3 Reactor Scheme.
 Thermal Cracking of H2S.
1.5.3 Explanation of Various Processes
A brief description is given below for each of the above mentioned processes. This
discussion will prove helpful in final process selection.
1.5.3.1 Sulfa Treat Direct Oxidation Process
It is a medium scale process which selectively oxidizes H2S to Sulfur and Water.
H2S +
1
2
O2 S + H2O
No equilibrium limitations are there because of good catalyst selectivity. This
process recovers 90% of H2S as sulfur in a single step. It uses a patented catalyst and has a
very low capital and operating costs. It can be directly operated on Natural Gas, Syngas and
Hydrogen. It has got a smaller footprint than Liquid Redox or Claus Process.

12
Inlet Gas
(syngas
or natural
gas)
Liquid
knockout
Feed
Preheater
Fuel / air
Flue Gas
Air
Direct
Oxidation
Reactor
Sulfur
Condenser
Sulfur
To
downstream
processing
1.5.3.2 The Claus Process
This is the least expensive, well proven but only economical at large scales. It was
developed by Carl Friedrich Claus in 1883. The process was later significantly modified by a
German company; I. G. Farbenindustrie A. G. The Claus technology can be divided into two
process steps, thermal and catalytic.
Thermal Step. In the thermal step, hydrogen sulfide-laden gas reacts in a substoichiometric
combustion at temperatures above 850 °C such that elemental sulfur precipitates in the
downstream process gas cooler. The H2S content and the concentration of other
combustible components (hydrocarbons or ammonia) determine the location where the
feed gas is burned. Claus gases (acid gas) with no further combustible contents apart from
H2S are burned in lances surrounding a central muffle by the following chemical reaction:
H2S +
3
2
O2 SO2 + H2O (∆H = -4147.20 kJ/kgmol)
Gases containing ammonia, such as the gas from the refinery's sour water stripper
(SWS), or hydrocarbons are converted in the burner muffle. Sufficient air is injected into the
muffle for the complete combustion of all hydrocarbons and ammonia. The air to the acid
gas ratio is controlled such that in total 1/3 of all hydrogen sulfide (H2S) is converted to SO2.
This ensures a stoichiometric reaction for the Claus reaction (see next section below).
The separation of the combustion processes ensures an accurate dosage of the
required air volume needed as a function of the feed gas composition. To reduce the
process gas volume or obtain higher combustion temperatures, the air requirement can
also be covered by injecting pure oxygen. Several technologies utilizing high-level and low-
level oxygen enrichment are available in industry, which requires the use of a special burner
in the reaction furnace for this process option.
Usually, 60 to 70% of the total amount of elemental sulfur produced in the process is
obtained in the thermal process step. The main portion of the hot gas from the combustion
Fig 1.4: A typical flow
diagram of direct
oxidation (DO)
process.

13
chamber flows through the tube of the process gas cooler and is cooled down such that the
sulfur formed in the reaction step condenses. The heat given off by the process gas and the
condensation heat evolved are utilized to produce medium or low-pressure steam. The
condensed sulfur is removed at the gas outlet section of the process gas cooler.
A small portion of the process gas can be routed through a bypass inside of the
process gas cooler, as depicted in the here above mentioned figure. This hot bypass stream
is added to the cold process gas through a three-way valve to adjust the inlet temperature
required for the first reactor.
Catalytic Step. The Claus reaction continues in the catalytic step with activated aluminum
(III) or titanium (IV) oxide, and serves to boost the sulfur yield. The hydrogen sulfide (H2S)
reacts with the SO2 formed during combustion in the reaction furnace, and results in
gaseous, elemental sulfur. This is called the Claus reaction:
2H2S + SO2
3
8
S8 + 2H2O (∆H = -1165.60 kJ/kgmol)
The catalytic recovery of sulfur consists of three sub steps: heating, catalytic
reaction and cooling plus condensation. These three steps are normally repeated a
maximum of three times. Where an incineration or tail-gas treatment unit (TGTU) is added
downstream of the Claus plant, only two catalytic stages are usually installed.
The first process step in the catalytic stage is the gas heating process. It is necessary
to prevent sulfur condensation in the catalyst bed, which can lead to catalyst fouling. The
required bed operating temperature in the individual catalytic stages is achieved by heating
the process gas in a reheater until the desired operating bed temperature is reached.
Several methods of reheating are used in industry:
 Hot-gas bypass: this involves mixing the two process gas streams from the process
gas cooler (cold gas) and the bypass (hot gas) from the first pass of the waste-heat
boiler.
 Indirect steam reheaters: the gas can also be heated with high-pressure steam in a
heat exchanger.
 Gas/gas exchangers: whereby the cooled gas from the process gas cooler is
indirectly heated from the hot gas coming out of an upstream catalytic reactor in a
gas-to-gas exchanger.
 Direct-fired heaters: fired reheaters utilizing acid gas or fuel gas, which is burned
substoichiometrically to avoid oxygen breakthrough which can damage Claus
catalyst.
The typically recommended operating temperature of the first catalyst stage is
315 °C to 330 °C (bottom bed temperature). The high temperature in the first stage also

14
helps to hydrolyze COS and CS2, which is formed in the furnace and would not otherwise be
converted in the modified Claus process.
The catalytic conversion is maximized at lower temperatures, but care must be
taken to ensure that each bed is operated above the dew point of sulfur. The operating
temperatures of the subsequent catalytic stages are typically 240 °C for the second stage
and 200 °C for the third stage (bottom bed temperatures).
In the sulfur condenser, the process gas coming from the catalytic reactor is cooled
to between 150 and 130 °C. The condensation heat is used to generate steam at the shell
side of the condenser.
Before storage, liquid sulfur streams from the process gas cooler, the sulfur
condensers and from the final sulfur separator are routed to the degassing unit, where the
gases (primarily H2S) dissolved in the sulfur is removed.
The tail gas from the Claus process still containing combustible components and
sulfur compounds (H2S, H2 and CO) is either burned in an incineration unit or further
desulfurized in a downstream tail gas treatment unit.
Fig 1.5: Flow diagram for the Claus process.
1.5.3.3 Recycle Selectox Process
The Recycle Selectox Process developed by Parsons and Unocal, treats lean acid gas
containing 5 to 30 mole percent H2S. The selector catalyst directly catalyzes the oxidation of
H2S to SO2, eliminating the reaction furnace of Claus Process. It also catalyzes the Claus
reaction of production of elemental sulfur. The exothermic Claus reaction results in a
temperature increase of 30o
C in first reactor stage and about 15 o
C across the second
stage.
The Recycle Selectox stage usually consists of one Selectox stage, followed by two
Claus stages. A recycler blower dilutes the incoming acid gas with Selectox condenser.
Typical H2S conversion to sulfur is more than 80%. Total sulfur recovery with two
subsequent Claus stages ranges from 94 to 96 percent. If the lean gas contains less than 5

15
percent H2S, the once-through Selectox process can be used. Except for the recycle loop,
equipment arrangement is same.
Fig 1.6: Flow diagram for the Recycle Selectox Process.
1.5.3.4 Selective Oxidation Process
There are two types need to be illustrated in this account.
Parson's Hi-Activity Process
In a Claus unit, complete conversion of H2S and SO2 to elemental sulfur is not
possible due to limitations of thermodynamic chemical equilibrium of the Claus process.
Selective oxidation of H2S to sulfur can be thermodynamically complete as indicated by the
following reaction:
H2S+
1
2
O2
1
n
Sn + H2O
Parson's hi-activity process utilizes a series of proprietary catalysts for direct
oxidation of H2S to elemental sulfur. The Hi-activity catalysts, which are prepared with
different mixtures of Iron-based metal oxides without the use of a carrier, posses low
specific surfaces and wild pores , the process scheme is very similar to a conventional
modified Claus unit, except that the last catalytic stage is replaced with h-activity catalyst.
Super Claus Process
The Super Claus process consists of a thermal stage followed by three of four
catalytic reaction stages. The first two or three reactors are filled with standard Claus
catalyst while the last reactor is filled with the selective oxidation catalyst. In the thermal
stage the acid gas is burnt with a sub-stoichiometric amount of controlled combustion air
such that the tail gas leaving the second reactor contains 0.80 to1.50% by volume of H2S.

16
The catalyst in the last reactor (selective oxidation reactor) oxidizes the H2S to sulfur
(H2S +
1
2
O2 S + H2O) at a very high efficiency. Because the catalyst neither oxidizes
H2S to SO2 and H2O, nor reverses the reaction of sulfur and water to H2S and SO2, a total
sulfur recovery rate in the range of 99% can be obtained, depending on Claus Feed Gas
composition.
1.5.3.5 Cold Bed Adsorption Process
The conventional Claus sulfur recovery process is limited by reaction equilibrium
considerations to sulfur recoveries in the range of 94-97%. Very high (more than 99.8%)
sulfur recoveries can be achieved by adding an amine-based tail gas cleanup process on the
Claus effluent. A good example of this technology is the SCOT process licensed by Shell,
which is often employed in refineries to reduce sulfur dioxide emissions to very low levels.
However, amine-based tail gas cleanup units are not only expensive to build (often 80% or
more of the cost of the upstream Claus plant), but expensive to operate as well. A better
choice of technology for the intermediate sulfur recovery range of 98-99.5% is the so-called
“sub-dew point” Claus process. This process extends the capability of the Claus process by
operating the Claus reaction at a lower temperature, so that the sulfur produced by the
reaction condenses. Since the Claus reaction occurs in the gas phase, this liquid sulfur does
not inhibit the reaction like sulfur vapor does, resulting in a favorable shift in the reaction
equilibrium and higher sulfur conversion. Amoco Corporation developed and licenses the
most widely used sub-dew point Claus process.
A CBA sulfur plant consists of a conventional Claus section and a CBA section. The
thermal and catalytic conversion in the conventional Claus portion of the sulfur plant
usually recovers 90-95% of the inlet sulfur. Adding more conventional Claus catalytic stages
beyond this point would not add much sulfur recovery because the Claus reaction is an
equilibrium reaction and becomes limited by the concentrations of water and sulfur vapor
in the gases flowing through the plant. The CBA portion of the sulfur plant overcomes this
limitation through the use of “sub-dew point” conversion stages. Although catalytic
conversion of H2S and SO2 is higher at lower reactor temperatures, conventional Claus
reactors must be operated at temperatures sufficiently high to keep the sulfur produced
from condensing. Sulfur catalyst will adsorb liquid sulfur in its pores, which blocks the active
sites where the Claus reaction occurs. If the Claus reactor temperature is too low, the sulfur
concentration in the vapor will exceed its dew point concentration, causing liquid sulfur to
form and adsorb on the catalyst. Over time, this liquid sulfur will block all of the active sites
in the catalyst and render the catalyst bed almost completely inactive.
A CBA reactor is operated in a cyclic fashion to avoid complete catalyst deactivation
from liquid sulfur blocking the active sites. The CBA reactor is operated at low temperature
(250-300°F/120-150°C) initially so that it is below the sulfur dew point of the reaction
products (i.e., “sub-dew point”) and the sulfur formed is condensed and adsorbed on the
catalyst. After operating in this manner for a period of time, the CBA reactor is
“regenerated” by flowing hot gas through the reactor to vaporize the adsorbed liquid sulfur,

17
which is then condensed and removed in a down-stream sulfur condenser. This process is
analogous to the processing steps used when dehydrating gas streams with molecular
sieves. There are normally two or more CBA reactors in series so that at least one can be
operating sub-dew point while the other is being regenerated. Not only does a CBA reactor
benefit from a more favorable Claus reaction constant at its lower operating temperature, it
also has the advantage of shifting the Claus reaction equilibrium. The Claus reaction is a
vapor-phase reaction, so condensing the sulfur product removes it from the vapor, forcing
the equilibrium in the Claus reaction further to the right, toward higher conversion. These
two factors allow much higher sulfur conversion than in a conventional Claus reactor,
resulting in overall sulfur recovery efficiencies in excess of 98-99.5% for CBA plants.
The cyclic nature of the CBA process requires process gas switching valves that must
perform in very demanding sulfur vapor services. This has caused significant operation and
maintenance problems in CBA plants designed by other engineering companies and
contractors.
1.5.3.6 Thermal Cracking of H2S
In this process operation at significantly high temperatures is made possible and
economical by oxidation of part of the H2S to provide the energy required for the
decomposition reaction to proceed to a significant extent. Partial oxidation of H2S in the
H2S-containing fuel gas is carried out in the presence of an inert, porous, high-capacity
medium and the intense heat exchange results in flame temperatures that significantly
exceed the adiabatic flame temperature of the gas mixture. By coupling the partial
oxidation of H2S in the porous medium with the H2S decomposition, temperatures as high
as 1400°C (1673K) can be achieved economically within a reaction zone without the input of
external energy, and therefore, no additional CO2 emissions. In this reaction zone, the self-
sustaining conditions are very favorable for the decomposition reaction to proceed to an
industrially significant extent, within a slowly propagating thermal wave.
Fig 1.7: Thermal cracking of H2S.

18
1.6 The Claus Process
The Claus process is the most significant gas desulfurizing process, recovering
elemental sulfur from gaseous hydrogen sulfide. First invented over 100 years ago, the
Claus process has become the industry standard.
1.6.1 History
The process was invented by Carl Friedrich Claus, a chemist working in England. A
British patent was issued to him in 1883. The process was later significantly modified by a
German company called I. G. Farbenindustrie A. G.
1.6.2 Description
The multi-step Claus process recovers sulfur from the gaseous hydrogen sulfide found
in raw natural gas and from the by-product gases containing hydrogen sulfide derived from
refining crude oil and other industrial processes. The by-product gases mainly originate
from physical and chemical gas treatment units (Selexol, Rectisol, Purisol and amine
scrubbers) in refineries, natural gas processing plants and gasification or synthesis gas
plants. These by-product gases may also contain hydrogen cyanide, hydrocarbons, sulfur
dioxide or ammonia.
Gases with an H2S content of over 25% are suitable for the recovery of sulfur in
straight-through Claus plants while alternate configurations such as a split-flow set up or
feed and air preheating can be used to process leaner feeds.
Hydrogen sulfide produced, for example, in the hydro desulfurization of refinery
naphthas and other petroleum oils, is converted to sulfur in Claus plants The overall main
reaction equation is:
2H2S + O2 S2 + 2H2O
In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide
in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants.
Sulfur is used for manufacturing sulfuric acid, medicine, cosmetics, fertilizers and rubber
products.
Inevitably a small amount of H2S remains in the tail gas. This residual quantity,
together with other trace sulfur compounds, is usually dealt with in a tail gas unit. The latter
can give overall sulfur recoveries of about 99.8%, which is very impressive indeed.
Gases containing ammonia, such as the gas from the refinery's sour water stripper
(SWS), or hydrocarbons are converted in the burner muffle. Sufficient air is injected into
the muffle for the complete combustion of all hydrocarbons and ammonia. Air to the acid

19
gas is controlled such that in total 1/3 of all hydrogen sulfide (H2S) is converted to SO2. This
ensures a stoichiometric reaction for the Claus reaction.
Fig 1.8: The Claus process for sulfur recovery.
1.6.3 Simplified Process Description
 The hot combustion products from the furnace at 1000- 1300 °C enter the waste heat
boiler and are partially cooled by generating steam. Any steam level from 3 to 45 bar
g can be generated.
 The combustion products are further cooled in the first sulfur condenser, usually by
generating LP steam at 3 – 5 bar g. This cools the gas enough to condense the sulfur
formed in the furnace, which is then separated from the gas and drained to a
collection pit.
 In order to avoid sulfur condensing in the downstream catalyst bed, the gas leaving
the sulfur condenser must be heated before entering the reactor.
 The heated stream enters the first reactor, containing a bed of sulfur conversion
catalyst. About 70% of the remaining H2S and SO2 in the gas will react to form sulfur,
which leaves the reactor with the gas as sulfur vapor.
 The hot gas leaving the first reactor is cooled in the second sulfur condenser, where
LP steam is again produced and the sulfur formed in the reactor is condensed.
 A further one or two more heating, reaction, and condensing stages follow to react
most of the remaining H2S and SO2.
 The sulfur plant tail gas is routed either to a Tail Gas treatment Unit for further
processing, or to a Thermal Oxidizer to incinerate all of the sulfur compounds in the
tail gas to SO2 before dispersing the effluent to the atmosphere.
1.6.4 Process Improvements

20
Over the years many improvements have been made to the Claus process. Recent
developments include:
 SUPERCLAUS(TM)
. A special catalyst in the last reactor oxidizes the H2S selectively to sulfur,
avoiding formation of SO2. Significantly higher conversions are obtained at modest cost.
 Oxygen Claus. The combustion air is mixed with pure oxygen. This reduces the amount of
nitrogen passing through the unit, making it possible to increase throughput.
 Better Catalysts. Higher activities have been achieved with catalysts that provide higher
surface areas and macro porosity.
More improvements can be expected. Here are some possibilities.
 CS2 destruction. Carbon disulfide (CS2) is a side product made in the furnace. Laboratory
work has shown that special catalysts operating in the furnace can destroy the CS2 before it
gets into the catalytic section. A commercially available catalyst like this might be developed
for use in a Claus plant.
 Catalyst Temperature Policy. The conversion of H2S goes faster at higher temperatures, but a
more favorable equilibrium is obtained at lower temperatures. It isn't obvious whether
higher or lower temperatures are needed in the third converter. Kinetic modeling may supply
the answer, thereby improving conversion or reducing catalyst replacement cost.
1.6.5 Claus Process Auxiliaries
Following are some of the auxiliaries being used in the Claus process.
1.6.5.1 Blow Down System
Boiler blow down flows is collected and drained into SBD-1. Steam Blow Down Drum. The
steam is vented from the top of SBD-1 and liquid flows from the bottom to SBC-1,Steam Blow Down
Cooler. The blow down flows from E-2 to the drain system.
1.6.5.2 Fuel System
Fuel gas is supplied from OSBL services. The three users are F-1 (Muffle furnace), TG-1 ( Tail
Gas Incinerator), and a PA-1(Package Auxiliary Box). In normal operation, fuel flows only to TG-1.
The fuel to F-1 is used only in start up when heating the unit. The fuel to PA-1 is used only when the
clause process is shut down, then PA-1 is used to supply steam for heating services, primarily on the
liquid sulfur containing lines and equipment.
There are two different fuel gases. One is natural gas types and is supplied to all three-fuel
users. The other fuel gas is vaporized LPG which is supplied only to PA-1 to provide an alternate fuel
for this equipment.

Chapter 2
MAJOR EQUIPMENTS USED IN CLAUS PROCESS
2.1 Introduction
he major equipment items used in the project are discussed in this chapter,
generally in the order of process flow through the SRU. The concept presented
is intended to improve the SRU reliability and are not intended to be complete
design guidelines. A general comment that applies to all equipment items is to
provide pressure point/sample point connections between all major equipment
items. These will prove invaluable in troubleshooting the SRU.
2.2 Reaction Furnace (F-100)
The main burner and reaction furnace combine to form the SRU thermal reactor.
The burner and reaction furnace are normally mounted horizontally with the burner
coaxially mounted on the end of the reaction furnace.
The thermal reactor is the heart of the SRU even though it is frequently selected or
designed without considering its level of importance. We consider the main burner to be
the most important piece of equipment in the SRU. The burner must perform the function
of burning one third of the feed hydrogen disulfide (H2S) to sulfur dioxide (SO2) to satisfy
the stoichiometric requirements of the modified Claus process, while also destroying
impurities in the acid gas feed and consuming all of the oxygen in the combustion air. The
burner must be capable of performing efficiently at normal operating feed rates and low
turn down rates. The burner must also be capable of substoichiometric burning of natural
gas during start up and shut down operations.
The use of a very efficient mixing, high intensity burner is preferred. Inefficient
burners are frequently employed in SRU’s around in many industries. Frequently, these
burners are not able to achieve adequate destruction of impurities, complete oxygen
consumption and tend to produce some amounts of sulfur trioxide (SO3). These
shortcomings can result in equipment corrosion, catalyst deactivation, and plugging of
piping, equipment and catalyst beds. All of these adverse results reduce the SRU reliability
since under these conditions the requirement for shutting down of unit increases for
maintenance repairs, catalyst change and/or unblocking an obstruction. The burner must
accomplish the combustion reactions. The combustion reactions are relatively fast. The
reaction furnace provides the residence time at high temperature required
T

Chapter 2Major Equipments Used in the Claus Process
22
for the Claus reactions and side reactions to occur. Many feed impurities and intermediate
components must be destroyed in the reaction furnace or they will cause downstream
problems.
These components must have adequate time for the reactions to reach
completion/equilibrium. The reaction furnace should have 5 to 7 seconds residence time.
The specific features and residence time required for an individual reaction furnace are
dependent on several factors including the operating temperature and expected feed
impurities.
2.3 Waste Heat Boiler (B-100)
A WHR boiler is a closed vessel in which water or other fluid is heated. The heated or
vaporized fluid exits the WHR boiler for use in various processes or heating applications.
The various types of waste heat boilers include:
• Fire-Tube Boiler.
• Water-Tube Boiler.
• Vertical boiler.
• Hydronic Boiler.
Fire-Tube Boiler:
A fire-tube boiler is a type of boiler in which hot gases from a fire pass through one
or more tubes running through a sealed container of water. The heat energy from the gases
passes through the sides of the tubes by thermal conduction, heating the water and
ultimately creating steam.
Water-Tube Boiler:
It is a type of boiler in which water circulates in tubes heated externally by the fire.
Water tube boilers are used for high-pressure boilers. Fuel is burned inside the furnace,
creating hot gas which heats water in the steam-generating tubes. In smaller boilers,
additional generating tubes are separate in the furnace, while larger utility boilers rely on
the water-filled tubes that make up the walls of the furnace to generate steam.
VerticalBoiler:

23
The Cyclone Hot Water Boilers provide for exceptionally high efficiencies, lower fuel
costs, and extremely rugged construction. Compact space saving vertical design four-pass
design shock proof, no tubes to loosen or burn out. Convenient access to "eye high" burner
solid state controls for trouble free operation factory assembled, fully automatic UL and
ASME CSD-1. Simple and inexpensive to install.
Hydronic Boiler:
Hydronic boilers are used in generating heat for residential and industrial purposes.
They are the typical power plant for central heating systems fitted to houses in northern
Europe (where they are commonly combined with domestic water heating), as opposed to
the forced-air furnaces or wood burning stoves more common in North America. The
Hydronic boiler operates by way of heating water/fluid to a preset temperature (or
sometimes in the case of single pipe systems, until it boils and turns to steam) and
circulating that fluid throughout the home typically by way of radiators, baseboard heaters
or through the floors. The fluid can be heated by any means...gas, wood, fuel oil, etc, but in
built-up areas where piped gas is available, natural gas is currently the most economical and
therefore the usual choice. The fluid is in an enclosed system and circulated throughout by
means of a motorized pump.
2.4 Sulfur Condensers (E-100, E-102, E-104, E-106)
The Claus sulfur recovery process consists of four repeating steps for sulfur
condensation. Sulfur condensers serve the primary function of cooling and condensing
sulfur formed in the upstream reaction step. Sulfur condensers are normally horizontal,
kettle type shell and tube boilers. However, sulfur condensers are unique heat exchangers.
In addition to condensing product sulfur from the process gases, the liquid sulfur must also
be separated from the process gases before they flow to the next processing step. This is
normally done in an oversized outlet channel. Sulfur condensers are also unique because
the process gas flow rate through the condensers must be maintained within a specific
operating range/velocity or there will be adverse effects on the process. The term to
describe this flow property is the “Mass Velocity”, which is normally expressed as “pounds
of process gas flow per second per square foot of cross sectional flow area”. The
recommended mass velocity operating range is 1.50 to 5.50 lb/sec-ft2
.
Ideally sulfur is condensed from the process gas at the cool condenser tube walls,
flows from the tube into the outlet channel, is separated from the process gas, and is
drained from the condenser. If the mass velocity is too high, liquid sulfur can be entrained in
the process gas and be carried to the next stage or from the SRU instead of draining from
the tube. If the mass velocity is too low, sulfur can condense in the vapor as a very small
droplet or fog. The sulfur fog droplets are so small that the gas stream carries them much

24
like atmospheric fog or smoke to the next stage or from the SRU. In either of these cases,
sulfur recovery is lost. Lower recovery does not directly affect SRU reliability, but lower SRU
recovery will cause additional load on the downstream tail gas cleanup unit or increase the
plant emissions. Either of these conditions may ultimately cause the SRU to be shut down
permanently for maintenance.
Some designs utilize one or more of condensers as BFW preheaters upstream of the
WHB. The lower level heat from the condenser is used to increase the generation of higher
pressure stream by preheating the WHB feed water. The condenser shell must operate at
the BFW header pressure with this design. But this will exert excessive stress on the tube to
tube sheet attachment and reduces unit reliability. If sulfur condensers are used as BFW
preheaters, the tubes should be strength welded to the tube sheet. Some designs allow the
first condenser to act like the BFW preheater but some steam is generated on the shell side
of the sulfur condenser. Because the shell is not designed for vaporizing conditions, vapor
blanketing of some tubes can occur. This can result in overheating the tubes and sulfide
corrosion.
Some designs also use cold BFW on the shell of the final sulfur condenser to
minimize the process outlet temperature and maximize sulfur recovery.
As mentioned above, generation of low pressure steam to minimize the process
outlet temperature is preferred because if the BFW is too cold, there is a potential to freeze
the sulfur in the tubes.
It is essential for each sulfur condenser to have an independent sulfur seal and look
box. The ability to observe the sulfur production from each condenser is a very valuable
process evaluation and troubleshooting tool. The sulfur rate, consistency of rate, color,
temperature, and presence of bubbles are all important information items that can only be
obtained from individual seals and look boxes.
Each sulfur condenser drain line, sulfur seal, look box and rundown line to the sulfur
pit should be fully steam jacketed. The drain line between the condenser and seal should
have a steam jacketed plug valve located as close as practical to the condenser to allow on-
line rodding of the drain line and sulfur seal. Clear access must be provided for rodding the
drain line and overhead access must be provided to rod the seal.
Some plants have implemented a method to flush sulfur seals to keep the seals open
and free flowing. Steam jacketed piping with block valves are employed from the sulfur
pump discharge to the inlet of each sulfur seal. This allows flushing the individual seals by
closing the block valve in the drain line from the condenser and flowing product sulfur from
the pump discharge through the seal and back to the sulfur pit. This is an excellent and safe

25
method to keep the seals free flowing. Some plants use steam to periodically blow the
sulfur seals when there is an indication of partial plugging. While this method normally
works, we feel it should not be done as a routine practice because of the safety risks from
the hot liquid sulfur.
2.5 Heaters (E-101, E-103, E-105)
Reheaters definitely offer more options to the process designer than any other item
in the SRU. There are two general types of reheaters, direct and indirect. There are also
multiple options within each type.
Indirect method is preferred over direct method; however, each method has specific
applications where it should be considered. Each reheating method is briefly discussed
below.
2.5.1 Direct Reheat Methods
Direct reheat methods use a hot gas stream that is mixed with the process gas to increase
the temperature of the mixed stream to the desired inlet temperature of the downstream catalytic
reactor. The hot gas stream may originate within the process or from combustion. The direct reheat
methods are hot gas bypass, acid gas fired line burner, and natural gas fired line burner, and natural
gas fired line burner, if any of the direct methods are used, it is very important to insure there is
adequate mixing of the streams upstream of the temperature control point.
2.5.2 Hot Gas Bypass
This method has been used in many SRU's. It uses a hot stream from the first pass outlet of
the WHB (1000-1200F) to mix with process gas streams from the sulfur condensers.
It is inexpensive to install, but it has the disadvantages of lowering sulfur recovery by
bypassing conversion steps with a portion of the process gas, poor turndown performance, and high
temperature sulfide corrosion of carbon steel piping and control valves. The corrosion problems can
be minimized with proper metallurgy, but this is often not done because the cost is higher, and low
cost is a primary reason to use hot gas bypass reheat.
The only reason to use hot gas bypass reheat in current design is for very small, isolated
location plants that do not have access to high pressure steam or adequate, reliable electric power
supplies.
2.5.3 Acid Gas Fired Line Burner

26
Acid gas fired burners have been used in many SRU’s. There primary advantage the ability to
achieve any desired catalytic reactor inlet temperature. However, line burners have disadvantages.
The overall sulfur recovery is normally reduced because acid gas bypasses some conversion steps.
The burner air/fuel ratio must be closely controlled or oxygen breakthrough, soot formation, and/or
SO3 formation is likely.
We prefer to use a steam reheater design in which the high pressure steam is on the tube
side of a U-tube type heat exchanger. This type design avoids having to design the shell for the high
pressure steam and avoids tube to tube sheet stresses which can cause failures with steam leakage
into the process and SRU shutdown to make repairs. The U-tube bundle, free to expand within the
shell, avoids these mechanical stresses.
2.6 Catalytic Reactors (R-100, R-101, R-102)
Reactor is a vessel in which different species react to forma product under specified
operating conditions.
TYPES OF RECTOR:
Chemical reactors come in the form of vessels or tanks for batch reactors or back-
mix flow reactors ,as cylinders for fluidized bed reactors or as single or multiple tubes inside
a cylindrical container for plug flow reactor.
CATALYTIC REACTOR:
Use of catalysts requires modification to basic reactor design in order to account for
mass and energy transport issues arising from catalysts.
FIXED BED REACTOR (FBR):
These reactors are solid-catalyst containing vessels. Their design can lead to high
pressure drops. These units are generally used in heterogeneous catalysis where the
catalysts and reacting species are of different phases. The major advantage of such units is
their simplicity and ease of catalyst access for maintenance and regeneration. Use of
multiple fixed beds can improve both heat transport and control resulting in improved
performance while maintaining the relative simplicity of this reactor arrangement.
MULTIPLE TUBULAR REACTORS:
These types of reactors are modified multiple fixed bed units , where the multiple
beds are catalyst-filled tubes arranged in parallel with a heat conducting fluid flowing
outside the tubes. These reactors offer good thermal control and uniform residence time
distribution , but experience increased complexity as well as catalyst in accessibility.
Catalyst access is somewhat simplified by packed tube arrangement although packing and
removing the catalyst from the tubes can still be difficult.
SLURRY REACTOR:

27
Reaction of slurries containing solid particles that can be physically separated from
the suspension fluid are often best performed in agitated tank-type fluid reactors. The
reactor offer simplicity good transport properties and control while sacrificing nothing in
catalyst access since catalyst particles can be added and removed continuously. There is
however, an increased element of equipment degradation due to particle impingement on
the fluid handling equipment, such as impellers, nozzles and pipes.
MOVING BED REACTOR:
These units are also fluid reactors used where the fluid contains solid particles that
can be physically separated from from the suspension fluid. In this case however, the slurry
travels through the reactor in essentially plug flow. Again simplicity , access and control are
good with a uniform residence time distribution.
FLUIDIZED BED REACTORS:
These are reactors with a gas phase-working fluid that requires gas flow around and
past fine particles at a rate sufficient to fluidize the particles suspended within the reactor.
There are considerable operating difficulties associated with initiating and running fluidized
bed reactors due to flow and suspension issues. Further these types of reactors have large
residence time distribution of the ease of back flow in the gas and approach CSTR
behaviour. The advantages of these reactors are their ability to process fine particles and
suitability to high reaction rate processes.
THIN OR SHALLOW BED REACTORS:
These designations are reserved for reactors where the reactant fluid flow through
catalyst meshes or thin beds. These are simple reactors particularly suitable for fast
reaction that require good control where catalyst access is important for purposes of
catalyst reactivation or maintenance or where large heats of reaction are involved.
DISPERSION REACTORS:
These types of reactors are fluid-containing vessels that allow dispersion of liquid
and gas phase reactants by bubbling the latter through the liquid or dripping the liquid into
the gas stream or into a less dense liquid, to achieve increased contact area and reaction
performance. Even though these reactors are simple and inexpensive reactors, they require
careful planning due to their sensitivity to flow behaviour.
FILM REACTORS:
A reactor design that maximizes contact area for gas/liquid reactions is film the
reactor that brings together a gas and liquid as a thin film over a solid support. This type of
reactor offers an added benefit of increased thermal control via the solid support. Such as
arrangement also allows for complex phase dependent reactions in which solid, liquid and
gas phase are involved.

28
SELECTION OF REACTORS:
The selection of best reactor type for a given process is subjected to # of major
consideration. Such design aspects, for example,
1) Temperature and pressure of the reaction.
2) Need for removal or addition of reactants and products.
3) Required pattern of product delivery (continuous or batch wise)
4) Catalyst use consideration, such as the requirements for solid catalyst particle
replacement and contact with fluid reactants and products;
5) Relative cost of reactors.
REACTOR USED FOR CATALYTIC STEP OF CLAUSE PROCESS:
The reactor used for catalytic step of clause process of sulphur recovery is the fixed
bed catalytic reactor. The most important characteristic of FBR is that material flows
through the reactor as plug, all of the stream flows at the same velocity, parallel to reactor
axis with no back mixing. All material present at any given reactor cross-section has had an
identical residence time.
 They can be classified according to the manner in which the temperature is
controlled into reactors with adiabatic reaction control.
 Fixed bed reactors contain a bed of catalyst pellets.
 The catalyst lifetime in these reactors is greater than three months.
 These are rectors widely used in petro-chemical industries.
 They can generally be carried out continuously at low to medium pressure.
Fixed bed reactors are often referred to as packed bed reactors. They may be
regarded as the workhorse of the chemical industry w.r.t. number of reactors employed and
the economic value of materials produced. In a FBR, for a fluid- solid reaction, the solid
catalyst is present as a bed of relatively small particles randomly oriented and fixed in
position. The fluid moves by convective flow through the spaces between the particles.
There may also be diffusive flow or transport within the particles.We also focus on steady-
state operation thus ignoring any implications of catalyst deactivation with time.
INDUSTRIAL IMPLICATIONS OF FBR:
 Synthesis of Ammonia
 Production of styrene monomer by dehydrogenation of ethyl benzene.
 Alkylation of benzene to ethyl benzene.
 Production of sulphuric acid.
 Synthesis of butynediol from acetylene and formaldehyde.
FLOW ARRANGEMENT:
Traditionally most FBR are operated with axial flow of liquid down the bed of solid.

29
ADIABATIC MODE OF OPERATION:
In adiabatic operation, no attempt is made to adjust temp within the bed by means
of beat transfer. For a reactor consisting of one bed of catalyst, this defines the situation
thermally. If catalyst is divided into two or more beds arranged in series (a multistage
reactor). There is an opportunity to adjust temp b/w stages, even if each step is operated
adiabatically this may be done in two ways:
(1) Ist involves the inter-stage beat transfer by means of heat exchangers used for
either exothermic or endothermic reaction.
(2) Second called the COLD-SHOT COOLING, can be used for exothermic reactions
PURPOSE OF ADJUSTMENT OF TEMP:
(1) To shift an equilibrium limit so as to increase fractional conversion or yield.
(2) To maintain relatively light rate of reaction to decrease amount of catalyst and
size of vessel required.
DESIGN CONSIDERATION:
The most important factor to be considered in the design of such reactors is:
 Residence time distribution: influence on conversion and selectivity.
 Temp control: maintenance of temp limits, axially and radialy , min temp diff,
b/w reactor medium and catalyst surface , as well as within the catalyst particle.
 Catalyst lifetime and catalyst regeneration
 Pressure drop as a function of catalyst shape and gas velocity.
In addition to flow, thermal and bed arrangement an important design consideration
is the amount of catalyst required and its possible distribution over two or more stages. This
is the measure of size of reactor. The depth (L) and diameter (D) of each stage must also be
determined.
CATALYST USED:
Catalyst used in catalyst step of clause process is activated alumina (Al203) in the
form of spherical pellets.
CONSIDERATION OF PARTICLE AND BED CHARACTERISTICS:-
Characteristics of a catalyst particle include its chemical composition, which
primarily determines its catalyst activity and its physical properties such as size, shape,
density and porosity or voidage which determines the diffusion characteristics.

30
2.7 Sulfur Pits
Product sulfur is normally collected in a below grade, concrete pit equipped with steam coils
to keep the sulfur molten. The pit doesn't directly effect the SRU process operation until the SRU
must be shut down because of problems with the pit. Some common sulfur pit problems are steam
coil leakage, sulfur pump failure, internal sulfur fires, and even internal explosions. There are a few
design features that will significantly improve the reliable operation of the sulfur pit.
1. Construct the pit using sulfate resistant concrete with limestone- free aggregate.
2. Use alloy piping for the steam coil steam supply down comers and condensate risers,
and any internal components such as ladder rungs that will be alternately covered with
liquid sulfur and then exposed to air as the pit level changes.
3. Install dual steam jacketed sulfur transfer pumps.
4. Use a fully steam jacketed steam eductor to continuously draw atmospheric air into the
pit, sweeping vapor space to prevent the accumulation of H2S.
5. Steam snuffing connection(s) for extinguishing internal sulfur fires.
6. The number of inlets depends on the size and configuration of the pit.

Chapter 3
MATERIAL BALANCE OF THE SULFUR RECOVERY UNIT
(SRU)
3.1 Introduction
he material balance across the proposed sulfur recovery unit (SRU) is done by
the conservation equation of mass, as is done conventionally. A system must
be defined to account for the streams entering and leaving. In our case the
obvious selection is the sulfur recovery unit (SRU) itself, while all the other
premises are considered surroundings. Some preliminary bases are to be
specified for the sake of convenience in the calculations. Following
specifications are taken to meet the above mentioned situation:
 Sulfur production: 80 tons per day
 Time of operation: 1 hr
Now the material balance calculations are made first along the whole unit and then
across individual equipments. It is to be noted that whether the calculations are made
across the whole unit or the individual equipments, the basic law of conservation of mass
equation remains the same and is given as:
Amount of substance Amount of substance Amount of substance
entering the system - leaving the system + generated within the -
through the boundaries through the boundaries system boundaries
Amount of substance Amount of substance
consumed within the = accumulated within the (3.1)
system boundaries system boundaries
3.2 Overall Material Balance
The chemical reactions taking place are:
T

Chapter 3Material Balance of the SRU
32
Main Reactions:
1- H2S +
3
2
O2 SO2 + H2O (3.2)
2- SO2 + 2H2S
3
8
S8 + 2H2O (3.3)
Side Reactions:
3- CH4 + 2O2 CO2 + 2H2O (3.4)
4- C2H6 +
𝟕
2
O2 2CO2 + 2H2O (3.5)
5- C3H8 + 5O2 3CO2 + 4H2O (3.6)
Fig 3.1: Overall material balance across SRU.
NOTE: In all the diagrams the compositions are mentioned in mole fraction basis
Sulfur production target (S8) = 80 ton/day
=
= 13.0 kgmol/hr
H2S required by S8 =
16
3
× 13.0 kgmol (from equ. 3.3)
80
tons
1
day
1000
kg
1
kgmol
day
24
hr
1
ton
256.5
kg
Flow Rate = ?
H2S = 0.523
CO2 = 0.376
CH4 = 0.004
H2O = 0.010
C2H6 = 0.0008
C3H8 = 0.0001
Flow Rate = ?
O2 = 0.210
N2 = 0.790
Flow Rate = 13 kgmol/hr
S8 = 0.999
H2O = 0.001

33
= 69.30 kgmol
H2S supply for S8 (on account for 99.9% conversion from the Claus process)
= 0.999 × 69.30 kgmol = 69.37 kgmol
SO2 required by S8 =
8
3
= 34.65 kgmol
H2S consumed for SO2 = 34.65 kgmol (from equ. 3.2)
Total H2S supplied = 69.37 kgmol + 34.65 kgmol = 104.03 kgmol
Total acid gas feed supply = 104.03 kgmol /0.523 = 198.80 kgmol
Now the Stream-01 composition is as follows:
Stream-01 composition
Component Mole fraction Flow rate-F01 (kgmol/hr)
H2S 0.523 104.03
CO2 0.376 74.83
CH4 0.004 0.95
H2O 0.010 18.80
C2H6 0.0008 0.16
C3H8 0.0001 0.02
TOTAL 1.0 198.80
3.3 Material Balance across Furnace F-100
It is to be noted that according to the specifications of the Claus process only
30% of total sulfur dioxide produces in the furnace is converted into elemental sulfur.1
Fig 3.2: Material balance across furnace F-100.
1
“Sulfur Recovery”, GPSA Engineering data book Vol. 2, 11
th
edition, 1998. Chapter 22
Flow Rate = 198.80 kgmol/hr
H2S = 0.523
CO2 = 0.376
CH4 = 0.004
H2O = 0.010
C2H6 = 0.0008
C3H8 = 0.0001
O2 = 0.210
N2 = 0.790
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
S8 = ?

34
In the furnace the following chemical reactions are taking place:
Main Reactions:
1- H2S +
3
2
O2 SO2 + H2O (3.2)
2- SO2 + 2H2S
3
8
S8 + 2H2O (3.3)
Side Reactions:
3- CH4 + 2O2 CO2 + 2H2O (3.4)
4- C2H6 +
7
2
O2 2CO2 + 2H2O (3.5)
5- C3H8 + 5O2 3CO2 + 4H2O (3.6)
SO2 produced = 34.65 kgmol (from equ. 3.3)
H2S still available for S8 production = 104.03 kgmol - 34.65 kgmol= 69.37 kgmol
H2S consumed for S8 production = 10.4 kgmol × 2 = 20.80 kgmol
H2S remaining = 69.37 kgmol - 20.80 kgmol = 48.58 kgmol
SO2 consumed = 34.65 kgmol × 0.30 = 10.40 kgmol
SO2 remaining = 34.65 kgmol - 10.40 kgmol = 24.25 kgmol
S8 produced =
3
8
×10.40 kgmol = 3.90 kgmol
O2 required in SO2 formation = 52.0 kgmol (from equ. 3.2)
O2 required in CH4 combustion = 1.90 kgmol (from equ. 3.4)
O2 required in C2H6 combustion = 0.55 kgmol (from equ. 3.5)
O2 required in C3H8 combustion = 0.10 kgmol (from equ. 3.6)
Total O2 required = 52.0 kgmol + 1.90 kgmol + 0.55 kgmol +
0.10 kgmol
= 54.54 kgmol
Air fed to furnace = 54.54 kgmol / 0.210
= 259.70 kgmol
N2 going in = N2 going out = 259.70 kgmol × 0.790

35
= 205.20 kgmol
CO2 generated in CH4 combustion = 0.95 kgmol (from equ. 3.4)
CO2 generated in C2H6 combustion = 0.31 kgmol (from equ. 3.5)
CO2 generated in C3H8 combustion = 0.05 kgmol (from equ. 3.6)
CO2 going out = 0.95 kgmol + 0.31 kgmol + 0.05 kgmol +
74.83 kgmol
= 76.16 kgmol
H2O formed in SO2 production = 34.65 kgmol (from equ. 3.2)
H2O formed in CH4 combustion = 1.90 kgmol (from equ. 3.4)
H2O formed in C2H6 combustion = 0.47 kgmol (from equ. 3.5)
H2O formed in C3H8 combustion = 0.08 kgmol (from equ. 3.6)
H2O formed in S8 production = 20.80 kgmol (from equ. 3.3)
Total H2O produced = 34.65 kgmol + 1.90 kgmol + 0.47 kgmol +
0.08 kgmol + 20.80 kgmol
= 58.0 kgmol
H2O going out = 58.0 kgmol + 18.80 kgmol = 76.72 kgmol
Now the Stream-02, Stream-03 and Stream-04 compositions are as follows:
O2 0.210 54.54
N2 0.790 205.20
TOTAL 1.0 259.70
H2S 0.116 48.58
CO2 0.183 76.16
N2 0.50 205.20
SO2 0.058 24.25

36
H2O 0.140 58.0
S8 0.010 3.90
TOTAL 1.0 416.0
There is no need for the calculation of material balance across the waste heat
boiler B-100 since no material change takes place in there. So the composition of Stream-03
and Stream-04 are identical.
H2S 0.116 48.58
CO2 0.183 76.16
N2 0.50 205.20
SO2 0.058 24.25
H2O 0.140 58.0
S8 0.010 3.90
TOTAL 1.0 416.0
Only energy changes occur and in the subsequent chapter related to the energy
balance, calculations are made across it.
All of the sulfur produced in the furnace F-100 is condensed in the first
condenser E-100, along with some water. The purity of sulfur extracted is 99.9%.
Fig 3.3: Material balance across condenser E-100.
S8 going in Stream-S21 = 3.90 kgmol
H2S = 0.116
CO2 = 0.183
N2 = 0.50
SO2 = 0.058
H2O = 0.140
S8 = 0.010
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
Flow Rate = ?
S8 = 0.999
H2O = 0.111

37
Total amount of Stream-S21 =
3.90 kgmol
0.999
= 3.91 kgmol
H2O going in Stream-S21 = 3.91 kgmol × 0.111 = 0.004 kgmol
H2O going in Stream-05 = 58.0 kgmol – 0.004 kgmol = 57.90 kgmol
Now the Stream-S21 and Stream-05 compositions are as follows:
Stream-S21 composition
Component Mole fraction Flow rate-FS21 (kgmol/hr)
S8 0.999 3.90
H2O 0.001 0.004
TOTAL 1.0 3.904
H2S 0.117 48.58
CO2 0.184 76.16
N2 0.50 205.20
SO2 0.058 24.25
H2O 0.140 57.90
TOTAL 1.0 412.0
Again there is no need for the application of material balance calculations
around the heat exchanger E-101. So the Stream-06 has the same composition as that of
Stream-05.
H2S 0.117 48.58
CO2 0.184 76.16
N2 0.50 205.20
SO2 0.058 24.25
H2O 0.140 57.90
TOTAL 1.0 412.0

38
Fig 3.4: Material balance across reactor R-100.
Now, according to the specifications of the Claus process, the reactor R-100
converts only 70% of the incoming sulfur dioxide into elemental sulfur.1
Thus:
SO2 consumed in S8 production = 24.25 kgmol × 0.70 = 16.90 kgmol
SO2 remaining = 24.25 kgmol – 16.90 kgmol = 7.27 kgmol
H2S consumed in S8 production = 16.90 kgmol × 2 (from equ. 3.3)
= 33.90 kgmol
H2S remaining = 48.58 kgmol – 33.90 kgmol = 14.62 kgmol
H2O formed along with S8 = 16.90 kgmol × 2 (from equ. 3.3)
= 33.90 kgmol
H2O going out of reactor = 57.90 kgmol + 33.90 kgmol = 91.86 kgmol
S8 produced =
3
8
= 6.36 kgmol
H2S 0.036 14.62
CO2 0.190 76.16
N2 0.511 205.20
SO2 0.018 7.27
1
th
H2S = 0.117
CO2 = 0.184
N2 = 0.50
SO2 = 0.058
H2O = 0.140
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
S8 = ?

39
H2O 0.228 91.86
S8 0.015 6.36
TOTAL 1.0 401.50
As in the previous case all of the produced sulfur is condensed through the condenser
and then withdrawn from the collecting pits.
Fig 3.5: Material balance across condenser E-102
6.36 kgmol
0.999
= 6.37 kgmol
H2O going in Stream-08 = 91.86 kgmol – 0.006 kgmol = 91.85 kgmol
S8 0.999 6.37
H2O 0.001 0.0067
TOTAL 1.0 6.38
H2S = 0.036
CO2 = 0.190
N2 = 0.511
SO2 = 0.018
H2O = 0.228
S8 = 0.015
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
Flow Rate = ?
S8 = 0.999
H2O = 0.111

40
H2S 0.037 14.62
CO2 0.192 76.16
N2 0.520 205.20
SO2 0.018 7.27
H2O 0.232 91.86
TOTAL 1.0 395.12
Again there is no need for the application of material balance calculations around the
heat exchanger E-103. So the Stream-09 has the same composition as that of Stream-08.
H2S 0.037 14.62
CO2 0.192 76.16
N2 0.520 205.20
SO2 0.018 7.27
H2O 0.232 91.86
TOTAL 1.0 395.12
Fig 3.6: Material balance across reactor R-101
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
S8 = ?

41
Now, according to the specifications of the Claus process, the reactor R-101 converts
only 80% of the incoming sulfur dioxide into elemental sulfur.1
Thus:
= 11.64 kgmol
= 11.64 kgmol
S8 produced =
3
8
= 2.18 kgmol
H2S 0.007 2.98
CO2 0.194 76.16
N2 0.524 205.20
SO2 0.003 1.45
H2O 0.264 103.50
S8 0.005 2.18
TOTAL 1.0 391.48
As in the previous case all of the produced sulfur is condensed through the condenser
and then withdrawn from the collecting pits.
1
th

42
2.18 kgmol
0.999
= 2.185 kgmol
H2O going in Stream-11 = 103.50 kgmol – 0.002 kgmol
= 103.48 kgmol
S8 0.999 2.18
H2O 0.001 0.002
TOTAL 1.0 2.20
H2S 0.037 2.98
CO2 0.192 76.16
N2 0.520 205.20
SO2 0.018 1.45
H2O 0.232 103.48
TOTAL 1.0 389.30
H2S = 0.007
CO2 = 0.194
N2 = 0.524
SO2 = 0.003
H2O = 0.264
S8 = 0.005
Flow Rate = ?
S8 = 0.999
H2O = 0.111
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?

43
Again there is no need for the application of material balance calculations around the
heat exchanger E-105. So the Stream-12 has the same composition as that of Stream-11.
H2S 0.037 2.98
CO2 0.192 76.16
N2 0.520 205.20
SO2 0.018 1.45
H2O 0.232 103.48
TOTAL 1.0 389.30
Fig 3.8: Material balance across reactor R-102
Now, according to the specifications of the Claus process, the reactor R-102 converts
only 95% of the incoming sulfur dioxide into elemental sulfur.1
Thus:
= 2.76 kgmol
1
th
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?
S8 = ?

44
= 2.76 kgmol
S8 produced =
3
8
= 0.51 kgmol
H2S 0.0005 0.21
CO2 0.120 76.16
N2 0.528 205.20
SO2 0.0001 0.072
H2O 0.273 106.27
S8 0.001 0.51
TOTAL 1.0 388.43
As in the previous cases all of the produced sulfur is condensed through the
condenser and then withdrawn from the collecting pits.
H2S = 0.005
CO2 = 0.120
N2 = 0.528
SO2 = 0.0001
H2O = 0.273
S8 = 0.001 Flow Rate = ?
S8 = 0.999
H2O = 0.111
Flow Rate = ?
H2S = ?
CO2 = ?
N2 = ?
SO2 = ?
H2O = ?

45
0.51 kgmol
0.999
= 0.52 kgmol
H2O going in Stream-14 = 106.27 kgmol – 0.0005 kgmol
= 106.27 kgmol
Now the Stream-S24and Stream-14 compositions are as follows:
Component Mole fraction Flow rat-FS24 (kgmol/hr)
S8 0.999 0.51
H2O 0.001 0.0005
TOTAL 1.0 0.52
H2S 0.0005 0.21
CO2 0.196 76.16
N2 0.530 205.20
SO2 0.0001 0.072
H2O 0.274 106.27
TOTAL 1.0 387.91
3.11 Final Calculations
Total S8 produced from SRU= S8 withdrawn from condenser E-100 + S8
withdrawn from condenser E-102 + S8
withdrawn from condenser E-104 + S8
withdrawn from condenser E-106
= 3.90 kgmol + 6.37 kgmol + 2.18 kgmol +
0.51 kgmol
= 12.99 kgmol = 80 tons/day

Chapter 4
ENERGY BALANCE OF THE SULFUR RECOVERY UNIT
(SRU)
4.1 Introduction
he energy balance across the proposed sulfur recovery unit (SRU) is done by the
conservation equation of energy, as is done conventionally. A system must be
defined to account for the streams entering and leaving. In our case the obvious
selection is the sulfur recovery unit (SRU) itself while all the other premises are
considered surroundings. Some preliminary bases are to be specified for the
sake of convenience in the calculations. Following specifications are taken to meet the
above mentioned situation:
 Time of operation: 1 hr
 Ambient temperature: 25o
C
 Ambient pressure: 1 atm
Now the energy balance calculations are made by using the following equation for the
law of conservation of energy:
Amount of energy Amount of energy Amount of energy
entering the system - leaving the system + generated within the -
through the boundaries through the boundaries system boundaries
Amount of energy Amount of energy
consumed within the = accumulated within the (4.1)
system boundaries system boundaries
Furthermore, all the enthalpies of the streams are calculated by the following relation:
Q = Σ (mCp) ∆T (4.2)
T

Chapter 4Energy Balance of the SRU
47
Whereas:
Q = amount of heat contained by the stream (kJ/hr)
m = molar flow rate of the stream (kgmol/hr)
Cp = Heat capacity of the stream (kJ/kgmol-o
C)
∆T= Temperature of the stream (o
C)
The chemical reactions taking place in the process are:
Main Reactions1
:
1- H2S + 3/2O2 SO2 + H2O (4.3)
(∆H = -4147.20 kJ/kgmol)
2- SO2 + 2H2S 3/8S8 + 2H2O (4.4)
(∆H = -1165.60 kJ/kgmol)
Side Reactions:
3- CH4 + 2O2 CO2 + 2H2O (4.5)
(∆H = -891.0 kJ/kgmol)
4- C2H6 + 7/2O2 2CO2 + 2H2O (4.6)
(∆H = -1560.0 kJ/kgmol)
5- C3H8 + 5O2 3CO2 + 4H2O (4.7)
(∆H = -2220.0 kJ/kgmol)
NOTE: In all the diagrams the compositions are mentioned in mole fraction basis
4.2 Overall Energy Balance
1
All heat of reaction data is taken from: http://en.wikipedia.org/wiki/Claus_process

48
Fig 4.1: Overall energy balance across SRU
Stream-01 H2S CO2 CH4 H2O C2H6 C3H8 Total
m (kgmol/hr) 104.03 74.83 0.95 18.80 0.16 0.02 198.80
Cp (kJ/kgmol-o
C) 35.65 41.29 40.35 34.50 64.44 92.91 -
∆T(o
C) 190.6 190.6 190.6 190.6 190.6 190.6 -
Q01 (kJ/hr) 706872 588902 7306 123623 1965 354 1429098
Stream-02 O2 N2 Total
m (kgmol/hr) 54.54 205.20 259.70
Cp (kJ/kgmol-o
C) 29.49 29.30 -
∆T (o
C) 45.0 45.0 -
Q02 (kJ/hr) 72377 270556 342940
4.3 Energy Balance across Furnace F-100
Temp. = 215.6
o
C
H2S = 0.523
CO2 = 0.376
CH4 = 0.004
H2O = 0.010
C2H6 = 0.0008
C3H8 = 0.0001
Temp. = 70
o
C
O2 = 0.210
N2 = 0.790
Temp. = ?
H2S = 0.116
CO2 = 0.183
N2 = 0.50
SO2 = 0.058
H2O = 0.140
S8 = 0.010
Temp. = 215.6
o
C
H2S = 0.523
CO2 = 0.376
CH4 = 0.004
H2O = 0.010
C2H6 = 0.0008
C3H8 = 0.0001
Temp. = 70
o
C
O2 = 0.210
N2 = 0.790
Flow Rate = 13 kgmol/hr
Temp. = 124.4
o
C
S8 = 0.999
H2O = 0.001
Fig 4.2: Energy
balance across
furnace F-100

49
Enthalpy of Stream-01 = 1429098.75 kJ/hr
Enthalpy of Stream-02 = 342939.52 kJ/hr
Heat of reactions of all
reactions taking place = (-4147.20 - 1165.60 - 891.0 - 1560.0 - 2220.0) kJ/hr = -9983.80 kJ/hr
in the furnace
Total amount of enthalpy = (1429098.75 + 342939.52 - 9983.80) kJ/hr = 1762054.47 kJ/hr
within the furnace
Now we calculate the output temperature of the Stream-03 using equ. 4.1:
Q = Σ (mCp) ∆T
1762054.47 kJ/hr = 416.0 kgmol/hr × Cp × (Tout-25 o
C)
By iteration, the outlet temperature comes out to be 1177 o
C (2150 o
F)
Stream-03 H2S CO2 N2 SO2 H2O S8 Total
m (kgmol/hr) 48.58 76.16 205.20 24.25 58.0 3.90 416.0
Cp (kJ/kgmol-
o
C)
51.19 58.36 34.26 57.01 45.69 655.20 -
∆T(o
C) 1152.0 1152.0 1152.0 1152.0 1152.0 1152.0 -
Q03 (kJ/hr) 2864805 5120291 8098735 1592631 3052823 2943682 23672970
4.4 Energy Balance across Boiler B-100
Fig 4.3: Energy balance across boiler B-100
Temp. = 1177
o
C
H2S = 0.116
CO2 = 0.183
N2 = 0.50
SO2 = 0.058
H2O = 0.140
S8 = 0.010
Temp. = 649
o
C
H2S = 0.116
CO2 = 0.183
N2 = 0.50
SO2 = 0.058
H2O = 0.140
S8 = 0.010

50
The waste heat recovery boiler extracts such an amount of energy from the stream-03 that
the outlet temperature of the stream leaving the boiler; stream-04, becomes equal to 649
o
C (1200 o
F).
m (kgmol/hr) 48.58 76.16 205.20 24.25 58.0 3.90 416.0
Cp (kJ/kgmol-
o
C)
44.77 52.72 32.24 53.89 40.43 165.50 -
∆T(o
C) 624.0 624.0 624.0 624.0 624.0 624.0 -
Q04 (kJ/hr) 1357154 2505456 4128164 815463 1463242 402760 10672242
Fig 4.4: Energy balance across condenser E-100
The condenser E-100 reduces the temperature of the stream-04 from 649 o
C (1200 o
F) to
124.4 C (256 o
F) which is the dew point temperature of rhombic sulfur.
Stream-05 H2S CO2 N2 SO2 H2O Total
m (kgmol/hr) 48.58 76.16 205.20 24.25 57.90 412.0
Cp (kJ/kgmol-o
C) 35.37 40.69 29.56 42.89 79.20 -
∆T(o
C) 99.4 99.4 99.4 99.4 99.4 -
Q05 (kJ/hr) 170796 308035 602931 103384 455816 1640964
Stream-S21 S8 H2O Total
m (kgmol/hr) 3.90 0.004 3.904
Cp (kJ/kgmol-o
C) 33.75 79.20 -
∆T(o
C) 99.4 99.4 -
QS21 (kJ/hr) 13083 31.4 13115
Temp. = 649
o
C
H2S = 0.116
CO2 = 0.183
N2 = 0.50
SO2 = 0.058
H2O = 0.140
S8 = 0.010
Temp. = 124.4
o
C
H2S = 0.117
CO2 = 0.184
N2 = 0.50
SO2 = 0.058
H2O = 0.140
Temp. = 124.4
o
C
S8 = 0.999
H2O = 0.111

51
4.6 Energy Balance across Heat Exchanger E-101
Fig 4.5: Energy balance across heat exchanger E-100
The heater heats the incoming stream-05 from 124.4 o
C (256 o
F) to 248.8 o
C (480 o
F) which
is the required temperature of the first reactor R-100.
m (kgmol/hr) 48.58 76.16 205.20 24.25 57.90 412.0
Cp (kJ/kgmol-o
C) 37.27 44.07 30.20 46.67 35.43 -
∆T(o
C) 223.8 223.8 223.8 223.8 223.8 -
Q06 (kJ/hr) 405207 751156 1386897 253285 459102 3255648
Fig 4.6: Energy balance across reactor R-100
Enthalpy of Stream-06 = 3255648 kJ/hr
Temp. = 248.8
o
C
H2S = 0.117
CO2 = 0.184
N2 = 0.50
SO2 = 0.058
H2O = 0.140
Temp. = 124.4
o
C
H2S = 0.117
CO2 = 0.184
N2 = 0.50
SO2 = 0.058
H2O = 0.140
Temp. = 248.8
o
C
H2S = 0.117
CO2 = 0.184
N2 = 0.50
SO2 = 0.058
H2O = 0.140
Temp. = ?
H2S = 0.036
CO2 = 0.190
N2 = 0.511
SO2 = 0.018
H2O = 0.228
S8 = 0.015

52
Heat of reaction taking = -1165.60 kJ/hr
place in the reactor
Total amount of enthalpy = 3255648 kJ/hr – 1165.60 kJ/hr = 3254482 kJ/hr
within the furnace
Q = Σ (mCp) ∆T
3254482 kJ/hr = 401.50 kgmol/hr × Cp × (Tout-25 o
C)
By iteration, the outlet temperature comes out to be 354.4 o
C (670 o
F)
m (kgmol/hr) 14.62 76.16 205.20 7.27 91.86 6.36 401.50
Cp (kJ/kgmol-
o
C)
39.14 46.63 30.72 49.20 36.61 60.32 -
∆T(o
C) 329.4 329.4 329.4 329.4 329.4 329.4 -
Q07 (kJ/hr) 188491 1169811 2076453 117821 1107770 126370 4786717
Temp. = 354.4
o
C
H2S = 0.036
CO2 = 0.190
N2 = 0.511
SO2 = 0.018
H2O = 0.228
S8 = 0.015
Temp. = 124.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Temp. = 124.4
o
C
S8 = 0.999
H2O = 0.111

53
m (kgmol/hr) 14.62 76.16 205.20 7.27 91.86 395.12
Cp (kJ/kgmol-o
C) 35.37 40.69 29.56 42.89 79.20 -
∆T(o
C) 99.4 99.4 99.4 99.4 99.4 -
Q08 (kJ/hr) 51400 308035 602931 30994 723166 1716528
The heater heats the incoming stream-08 from 124.4 o
C (256 o
F) to 204.4 o
C (400 o
F) which
is the required temperature of the second reactor R-101.
m (kgmol/hr) 14.62 76.16 205.20 7.27 91.86 395.12
Cp (kJ/kgmol-o
C) 36.45 42.91 29.97 45.52 35.0 -
∆T(o
C) 179.4 179.4 179.4 179.4 179.4 -
Q09 (kJ/hr) 95602 586284 1103282 59369 576789 2421325
m (kgmol/hr) 6.37 0.0067 6.38
Cp (kJ/kgmol-o
C) 33.75 79.20 -
∆T(o
C) 99.4 99.4 -
QS22 (kJ/hr) 21370 52.7 21422
Temp. = 124.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Temp. = 204.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232

54
Fig 8.9: Energy balance across reactor R-101
Enthalpy of Stream-09 = 2421325 kJ/hr
Heat of reaction taking = -1165.60 kJ/hr
place in the reactor
Total amount of enthalpy = 2421325 kJ/hr – 1165.60 kJ/hr = 2420159 kJ/hr
within the furnace
Q = Σ (mCp) ∆T
2420159 kJ/hr = 391.48 kgmol/hr × Cp × (Tout-25 o
C)
By iteration, the outlet temperature comes out to be 243.3 o
C (470 o
F)
m (kgmol/hr) 2.98 76.16 205.20 1.45 103.50 2.18 391.48
Cp (kJ/kgmol-o
C) 37.18 43.93 30.17 46.52 35.38 44.48 -
∆T(o
C) 218.3 218.3 218.3 218.3 218.3 218.3 -
Q10 (kJ/hr) 24187 730368 1351470 14725 799377 21167 2941295
Temp. = 204.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Temp. = ?
H2S = 0.007
CO2 = 0.194
N2 = 0.524
SO2 = 0.003
H2O = 0.264
S8 = 0.005

55
m (kgmol/hr) 2.98 76.16 205.20 1.45 103.48 389.30
Cp (kJ/kgmol-o
C) 35.37 40.69 29.56 42.89 79.20 -
∆T(o
C) 99.4 99.4 99.4 99.4 99.4 -
Q11 (kJ/hr) 10477 308035 602931 6181 814644 1742270
m (kgmol/hr) 2.18 0.002 2.20
Cp (kJ/kgmol-o
C) 33.75 79.20 -
∆T(o
C) 99.4 99.4 -
QS23 (kJ/hr) 7313 15.7 7329
Temp. = 243.3
o
C
H2S = 0.007
CO2 = 0.194
N2 = 0.524
SO2 = 0.003
H2O = 0.264
S8 = 0.005
Temp. = 124.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Temp. = 124.4
o
C
S8 = 0.999
H2O = 0.111
Temp. = 124.4
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232
Temp. = 196.6
o
C
H2S = 0.037
CO2 = 0.192
N2 = 0.520
SO2 = 0.018
H2O = 0.232

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