Project
Transcript of Project
Chapter 1 Introduction
CHAPTER 01
Background
And
Introduction
1
Chapter 1 Introduction
BACKGROUND
Today’s refiner is faced with the need to convert the heavier components of the
crude barrel into lighter more valuable products. This situation is a result of
increasingly heavier crudes, lower demand for fuel oil, a steady to lower demand for
motor gasoline and an increasing demand for mid-distillates particularly diesel.
Ultimately new conversion facilities have to be built to upgrade barrel to light
products. However neither the available cash flow nor the project economics will
support such investment today in most refineries. Redeploying existing facilities to
provide the partial solution to residual fuel conversion is an immediately viable
move. Mild hydro-cracking is a widely applicable example of such reuse of existing
facilities.
Other options include fluid catalytic cracking and coking but both of these processes
require heavy investments. However, if these units already exist on-site, some of the
end products are of such poor quality that further upgrading will be required.
Fundamentally the trend towards lower feed grading is related to an increase in
the carbon/hydrogen ratio of crudes. This can be overcome by upgrading
methods which lower this ratio, by adding hydrogen.
Though the technology to upgrade heavy oils exists, selection of the optimum
process units is very much dependent on each refiner’s need and goals.
Today, hydro-cracking technology plays the major role in meeting the need for cleaner-
burning fuels, effective feedstocks for petrochemical operations, and more effective
lubricating oils. Only through hydro-cracking can heavy fuel oil components be
2
Chapter 1 Introduction
converted to transportation fuels and lubricating oils whose quality will meet tightening
environmental and market demands. Hydro-processing feedstocks—naphthas,
atmospheric gas oils, vacuum gas oils (VGO’s), and residuum—have widely different
boiling character. Within each of these different
boiling ranges exist a variety of molecular types. This depends on both the crude
oil source and whether the material was produced in a cracking reaction or as a
straight-run component of the original crude oil. The impurity levels in a variety of
crude oils and in their vacuum residua are shown.
Inspection of crude oil and vacuum residua
Source Arabian
Light
Arabian
Heavy
Kuwait Iranian
Heavy
Venezuelan California
Crude oil
Density, API 33.3 28.1 31.3 30.8 33.3 20.9
Sulphur, wt% 1.8 2.9 2.5 1.6 1.2 0.94
Nitrogen, wt% 0.16 0.19 0.09 0.18 0.12 0.56
Residuum 10000F+ (5380C+ );
Density, API 8.0 4.6 7.4 6.3 10.9 5.4
Sulphur, wt% 3.7 5.6 5.1 3.2 2.8 1.6
Nitrogen,wt% 0.49 0.67 0.38 0.83 0.56 1.33
Asphaltenes,wt% 11.3 20.6 12.0 14.7 16.0 12.0
Nickel+Vanadium,
ppm
96 220 116 462 666 296
Iron, ppm _ 10 0.9 9.0 5.0 90
3
Chapter 1 Introduction
The vacuum residuum is the lowest-value in the crude oil. Historically it has
blended into heavy fuel. The demand for this product, however, has not kept
pace with the tremendous increase demand for transportation fuels. Environment
pressures have widened this gap restricting the use of high-sulfur fuel oil while
mandating cleaner light products. The products into which the refiner must
convert the bottom of the barrel are summarized in the table given
Hydro-processing Objectives
4
Chapter 1 Introduction
5
Chapter 1 Introduction
HISTORY
Hydrotreating and hydro-cracking are among the oldest catalytic processes used
in petroleum refining. They were originally employed in Germany in 1927 for
converting lignite to gasoline and later used to convert petroleum residues to
distillable fractions. The first commercial hydro-refining installation in the United
States was at Standard Oil
Company of Louisiana in Baton Rouge in the 1930s. Following World War II,
growth in the use of hydro-cracking was slow. The availability of Middle Eastern
crude oils reduced the incentive to convert coal to liquid fuels, and new catalytic
cracking processes proved more economical for converting heavy crude fractions
to gasoline. In the 1950s, hydrodesulfurization and mild hydrogenation processes
experienced a tremendous growth, mostly because large quantities of by-product
hydrogen were made available from the catalytic reforming of low-octane
naphthas to produce high-octane gasoline.
The first modern hydro-cracking operation was placed on-stream in 1959 by
Standard Oil Company of California. The unit was small, producing only 1000
barrels per stream day (BPSD). As hydro-cracking units were installed to
complement existing fluid catalytic cracking (FCC) units, refiners quickly
recognized that the hydro-cracking process had the flexibility to produce varying
ratios of gasoline and middle distillate. Thus, the stage was set for rapid growth
in U.S. hydro-cracking capacity from about 3000 BPSD in 1961 to about 120,000
BPSD in just 5 years. Between 1966 and 1983, U.S. capacity grew eightfold, to
about 980,000 BPSD.
Outside the United States, early applications involved production of liquefied
petroleum gas (LPG) by hydro-cracking naphtha feedstocks. The excellent quality of
distillate fuels produced when hydro-cracking gas oils and other heavy feedstocks
6
Chapter 1 Introduction
led to the choice of the hydro-cracking process as a major conversion step in
locations where diesel and jet fuels were in demand. Interest in high-quality distillate
fuels produced by hydro-cracking has increased dramatically worldwide. As of 2002,
more than 4 million BPSD of hydro-cracking capacity is either operating or is in
design and construction worldwide.
Process Applications
Hydro-cracking is one of the most versatile of all petroleum refining processes.
Any fraction from naphtha to non-distillable can be processed to produce almost
any desired product with a molecular weight lower than that of the chargestock.
At the same time that hydro-cracking takes place, sulfur, nitrogen, and oxygen
are almost completely removed, and olefins are saturated so that products are a
mixture of essentially pure paraffins, naphthenes, and aromatics. Below given
table illustrates the wide range of applications of hydro-cracking by listing typical
chargestocks and the usual desired products.
The first eight chargestocks are virgin fractions of petroleum crude and gas
condensates. The last four are fractions produced from catalytic cracking and
thermal cracking. All these streams are being hydrocracked commercially to
produce one or more of the products listed.
This flexibility gives the hydro-cracking process a particularly important role as
refineries attempt to meet the challenges of today’s economic climate. The
7
Chapter 1 Introduction
combined influences of low-quality feed sources, capital spending limitations,
hydrogen limitations, environmental regulatory pressures, and intense
competition have created a complex optimization problem for refiners. The hydro-
cracking process is uniquely suited, with proper optimization, to assist in solving
these problems.
Applications of Process
8
Chapter 1 Introduction
Thermal Cracking – History
Because the simple distillation of crude oil produces amounts and types of
products that are not consistent with those required by the marketplace,
subsequent refinery processes change the product mix by altering the molecular
structure of the hydrocarbons. One of the ways of accomplishing this change is
through "cracking," a process that breaks or cracks the heavier, higher boiling-
point petroleum fractions into more valuable products such as gasoline, fuel oil,
and gas oils. The two basic types of cracking are thermal cracking, using heat
and pressure, and catalytic cracking.
The first thermal cracking process was developed around 1913. Distillate fuels
and heavy oils were heated under pressure in large drums until they cracked into
smaller molecules with better antiknock characteristics. However, this method
produced large
amounts of solid, unwanted coke. This early process has evolved into the following
applications of thermal cracking: visbreaking, steam cracking, and coking.
Dieselmax Process Unit
Dieselmax Process Unit is a combination of Mild Hydro-cracking with Thermal
Cracking for maximizing High Speed Diesel (HSD) production at relatively low
cost.
The Dieselmax Process Unit Catalytically desulfurizes and denitrifies a vacuum
gas oil (VGO) feedstock and converts the feedstock to a diesel product,
Kerosene, naphtha, and light ends including LPG in the presence of hydrogen.
Reactor effluent liquid is stripped and fractionated to separate the products from
unconverted VGO. The unconverted VGO from the Fractionator is thermally
9
Chapter 1 Introduction
cracked and fractionated to provide additional LPG, naphtha, and diesel range
materials.
The Dieselmax Process Unit consists of three processing sections:
Catalytic Reactor Section
Catalytic Fractionation Section
Thermal Section.
The Dieselmax process is a combination of catalytic and thermal processes
which converts vacuum gas oil to lighter, more valuable middle distillate
products. That portion of the Dieselmax feed which is not converted to distillate
range products is upgraded by removing contaminants and by hydrogen
addition. This unique combination of catalytic and thermal cracking allows a
refiner to achieve maximum yields of distillate range product from a vacuum
gas oil feed without using higher pressure operations associated with
conventional hydro-cracking.
10
Chapter 2 Present & Future Outlook
CHAPTER 02
Present
And future outlook
For petroleum sector
In Pakistan
11
Chapter 2 Present & Future Outlook
REFINERY PROCESS FLOW CHART
12
Chapter 2 Present & Future Outlook
Energy Outlook for future
World oil demand growth projections are from 80 million bpd in 2003, to 98
million bpd in 2015, to 118 million bpd in 2030. Non - OECD Asia (including
China & India) account for 43% of the total increase. 50% of Projected increase
in Oil over the 2003 to 2030 stage, occurs in Transportation sector. Industrial
sector accounts for 39% of projected oil demand growth, mostly for Chemical &
Petrochemical processes.
World Oil Consumption by Sector showing Projected Demand
Growth (2003-2030)
13
Chapter 2 Present & Future Outlook
World-wide Activity to Add Refining Capacity,
Refinery Margins
Estimated $770 billion investment in Oil Refining Capacity by 2030. International
Crude Prices are expected to remain well above US $ 90/barrel. New
Investments in the Global Refining Industry are expected by 2008-09 coupled
with World Oil demand expected to grow at 3%, the prices of Crude & Product
shall remain high and new investment in the sector will provide reasonable
returns to investors. Based on Long Term Projections, the Refinery Margins are
attractive for entering into Refining Business.
Regional Demand
On regional basis, two parts of the world lead the projected growth in world oil
demand;
Non - OECD includes China, India & others OECD includes USA, UK, Canada, Japan, France, Germany & others
The fastest growth in Oil demand is projected for the economies of Non - OECD Asia,
averaging 3% per year from 2003 to 2030.
In Asia Pacific also, beyond 2010 projected strong demand will outpace supply growth.
Necessity to Increase Refining Base
To fulfill the increasing petroleum product demand/supply gap, installation of new
refining capacity will have to be undertaken. A Coastal Refinery is therefore
necessary to balance the product supply to the country and to export surplus
products. The aim is to maximize middle distillates so that configurations can be
optimized to meet Pakistan’s Petroleum needs and to form a nucleus for a
Petrochemical complex.
14
Chapter 2 Present & Future Outlook
Expanding Refining Capacities Vs Importing
Refined Products
It is a good time for investment in the Refineries due to strong demand for
finished products, especially Gasoline in China. Poor Refining Margin from 1998
to 2002 caused the closure of many refineries in the region. Combination of
strong demand growth and decreasing capacity has transformed the Asian
Refineries from struggling to Break-Even into improved Refining Margins.
Petroleum Product Outlook for Pakistan
15
Chapter 2 Present & Future Outlook
Benefits of Expanding Refining Capacities Vs Importing Refined Products
Direct Benefits – Refinery Expansion
Foreign Exchange savings through local production. Strategic Self Reliance for Country’s Energy needs
hence;
• Secured Supply Line
• Strengthening Country’s Infrastructure Assets & Reserves
Trade Opportunity to export Petroleum products from Pakistan to Asia/Asia Pacific.
Indirect benefits
Socio-economic development in relatively under-developed areas;
Development of PARCO Mid-Country Refinery is an excellent example where socio-
economic development was achieved in districts of Muzaffargarh, D.G Khan, Multan.
Khalifa Coastal Refinery Study
IPIC and PARCO are jointly establishing Khalifa Coastal Refinery. Its capacity
will 200,000 to 300,000 BPSD. This project focuses on meeting Pakistan’s deficit
of middle distillates post 2011 and regional export market for surplus products.
For maximizing Middle distillates, Delayed Coker/Hydro-cracking processing
scheme has been considered.
Future Outlook
16
Chapter 2 Present & Future Outlook
Oil Prices have risen to current levels through a much faster mechanism. Regional demand
show that strong demand growth across Asia pacific will soak up extra capacity. Security of
supply and demand are mutually supportive. Uncertainty over future demand translates
into investment opportunity in this sector, while suppliers (OPEC) have risk in
meeting this demand.
Projected Refining Gap in Pakistan (2006-2020)
17
Chapter 2 Present & Future Outlook
The Way Forward
Enhancing Country’s Refining base
Enhancing Energy sources
Development of Storage Infrastructure
Development of reliable inflow of Energy Supply
Pakistan Existing Refining Capacities
18
Chapter 2 Present & Future Outlook
Things that Need to be Done
Conducive & Investor friendly Economic Reforms
Legal Protection for Policies & Procedures
Implementing De-regulation & Market-related pricing policies
Provide security of investment & returns
Consistency & continuity of pro-investment policies
Middle Distillate Production:
The quantity and quality of diesel produced is shown in Table ( where, ktpa=
“thousand [metric] tons per annum”). With the exception of ARL diesel, the level
of sulfur in diesel is close to 1%. Because of the large quantity of 1-percent-
sulfur diesel produced at PARCO.
The national average for domestically produced diesel is 0.9 percent.
This can be be lowered somewhat by blending kerosene into diesel.
19
Refinery DIESEL
ktpa %-sulphur
NRL 570 0.9
PRL 584 0.9
ARL 217 0.2
PARCO 1142 1
DHODAK 10 0.5
Total without Parco 1381 0.8
Total with Parco 2523 0.9
Chapter 2 Present & Future Outlook
Diesel is consumed mainly in four sectors: Power, Industry, Transport, and “Other government”. On the basis of indications from various consumers in these sectors,
OCAC (oil company advisory committee) develops forecasts.
20
Chapter 3 Reaction Chemistry
CHAPTER 03
Hydrocracking
And
Thermal Cracking
Reaction
Chemistry
21
Chapter 3 Reaction Chemistry
Hydrocracking Chemistry
Hydrocracking chemistry is bifunctional catalytic chemistry involving acid-
catalyzed isomerization and cracking reactions as well as metal-catalyzed
hydrogenation reactions. The resulting products are lower in aromatics and
contain naphthenes and highly branched paraffins due to the higher stability of
the tertiary carbenium ion intermediate. For paraffins, the reaction network,
shown below, is postulated to begin with a dehydrogenation step at a metal site
forming an olefin intermediate which is quickly protonated at an acid site to yield
a carbenium ion. This is quickly followed by a series of isomerization reactions to
the most stable tertiary carbenium ions and subsequent cracking to smaller
paraffin, which evolves off the catalyst surface and smaller carbenium ion
intermediate.
Postulated Paraffin-Cracking Mechanism is shown as.
22
Chapter 3 Reaction Chemistry
23
Chapter 3 Reaction Chemistry
Postulated Paraffin-Cracking Mechanism
24
Chapter 3 Reaction Chemistry
The carbenium ion can then eliminate a proton to form an olefinic intermediate,
which gets hydrogenated at a metal site or directly abstract a hydride ion from a
feed component to form a paraffin and desorb from the surface.
A typical hydrocracking reaction for a cycloparaffin, given on next page1 is known
as a paring reaction, in which methyl groups are rearranged and then selectively
removed from the cycloparaffin without severely affecting the ring itself. Normally
the main acyclic product is isobutane.
The hydrocracking of multiple-ring naphthene, such as decalin, is more rapid
than that of a corresponding paraffin. Naphthenes found in the product contain a
ratio of methylcyclopentane to methylcyclohexane that is far in excess of
thermodynamic equilibrium.
Reactions during the hydrocracking of alkyl aromatics, shown on next page2
include isomerization, dealkylation, paring, and cyclization. In the case of
alkylbenzenes, ring cleavage is almost absent, and methane formation is at a
minimum.
25
Chapter 3 Reaction Chemistry
Postulated Cracking-Mechanism for Naphthenes
2Postulated Aromatic Dealkylation Mechanism
26
Chapter 3 Reaction Chemistry
Reaction MechanismSulfur Removal:
Typical feed stocks to the Dieselmax Catalytic Section Unit contains simple
mercaptans, sulfides and disulfides. These compounds are easily converted to
H2S. However, feed stocks containing aromatic molecules are more difficult to
process. Thiophene is considered 15 times more difficult to process compared to
diethylsulfide.
Nitrogen Removal:
Denitrogenation is generally more difficult than desulfurization. Side reactions
may yield nitrogen compounds more difficult to hydrogenate than the original
reactant.
27
Chapter 3 Reaction Chemistry
The reaction mechanism steps are different compared to desulfurization. The
denitrogenation of pyridine proceeds by aromatic ring saturation, ring
hydrogenolysis, and finally denitrogenation.
Oxygen Removal:
Organically combined oxygen is removed by hydrogenation of the carbon-
hydroxyl bond forming water and the corresponding hydrocarbon.
28
Chapter 3 Reaction Chemistry
Olefin Saturation:
Olefin saturation reactions proceed very rapidly and have a high heat of reaction.
The distillate range recycle stream returning from the thermal section have a high
olefin
content. It is saturation of this thermally cracked material that greatly upgrades its
quality.
Aromatic saturation:
Aromatic saturation reactions are the most difficult. The reactions are influenced
by process conditions and are often equilibrium limited. The saturation reaction is
very exothermic.
29
Chapter 3 Reaction Chemistry
Metals removal:
The mechanism of the decomposition of organo-metallic compounds is not well
understood. However, it is known that metals are retained on the catalyst by a
combination of adsorption and chemical reaction. The catalyst has a certain
maximum tolerance for retaining metals. Removal of metals normally occurs in
plug flow fashion with respect to the catalyst bed. Typical organic metals native
to most crude oils are nickel and vanadium. Iron can be found concentrated at
the top of catalyst beds as iron sulfides which are corrosion products.
The useful life of the catalyst may be determined by the amount of metals that
are accumulated on it during the course of operation. Most Dieselmax Units are
able to go through several operating cycles without exceeding the ability of the
catalyst for removing metals. Metal removal is essentially complete above
temperatures of 3160C (6000F) to a metals loading of 2-3 wt% of the total
catalyst.
Halides removal:
Organic halides, such as chlorides and bromides, are decomposed in the reactor.
The inorganic ammonium halide salts which are produced when the reactants
are cooled are then dissolved by injecting water into the reactor effluent or leave
with the stripper off-gas.
HCl + NH3 NH4Cl
30
Chapter 3 Reaction Chemistry
Reaction Rates:
The approximate relative heats of reaction per unit of hydrogen consumption for
these reactions are:
Desulfurization 1
Olefin Saturation 2
Denitrification 1
Aromatics Saturation 1
All of the reactions discussed above are exothermic and result in a temperature
rise across the reactor. Olefin saturation and some desulfurization reactions have
similarly rapid reaction rates, but it is the saturation of olefins which generates
the greatest amount of heat. The temperature rise expected for a given charge
stock along with the desired product quality plays a very important role in
determining the number, size, and arrangement of the reactors, heat exchange,
and hydrogen circulation rate.
Thermal cracking processReaction Chemistry
When a hydrocarbon is heated and decomposed under thermal cracking
conditions, it may be assumed that it is broken up into two or more free radicals.
The free radicals then enter into a series of reactions that result in a total product
covering a broad range of molecular weights from hydrogen to bitumen and
cokes. In accordance with thermal cracking theory, the reactions may proceed
as:
31
Chapter 3 Reaction Chemistry
A portion of the compound disassociates to form free radicals, for example:
C10H22 C8H17 + C2H5
The highly reactive radicals do not appear in the thermally cracked product
effluent, but depending upon size and environment: (a) react with other
hydrocarbons, (b) decompose to olefins, (c) combine with other radicals, and (d)
react with metal surfaces.
In general, small radicals are more stable than larger radicals, and more readily
react with other hydrocarbons by capturing a hydrogen atom, for example;
C2H5 + C6H14 C2H6 + C6H13
Large radicals are unstable and decompose to form olefins and smaller radicals,
for example;
C6H13 C5H10 + CH3
C8H17 C4H8 + C4H9
C4H9 C4H8 + H
The free radical chain reactions are terminated when two radicals combine; for
example;
C8H17 + H C8H18
The polymerization and condensation reactions that occur at thermal cracking
conditions can go all the way to aromatic tars. Coke and bitumen are the ultimate
polymers. The molecules become very large with considerable cross linkage.
Lack of hydrogen coupled with high molecular weight decreases their solubility in
hydrocarbons.
32
Chapter 3 Reaction Chemistry
CATALYST
Hydrocracking catalysts combine acid and hydrogenation components in a
variety of types and proportions to achieve the desired activity, yield structure,
and product properties. Noble metals as well as combinations of certain base
metals are employed to provide the hydrogenation function. Platinum and
palladium are commonly used noble metals while the sulfided forms of
molybdenum and tungsten promoted nickel or cobalt are the most common base-
metal hydrogenation agents. The cracking function is provided by one or a
combination of zeolites and amorphous silica-aluminas selected to suit the
desired operating and product objectives.
A postulated network of reactions that occur in a typical hydrocracker processing
a heavy petroleum fraction is shown on next page. The reactions of the multiring
species should be noted. These species, generally coke precursors in
nonhydrogenative cracking, can be effectively converted to useful fuel products
in a hydrocracker because the aromatic rings can be first hydrogenated and then
cracked.
Amorphous silica-alumina was the first catalyst support material to be used
extensively in hydrocracking service. When combined with base-metal
hydrogenation promoters, these catalysts effectively converted vacuum gas oil
(VGO) feedstocks to products with lower molecular weight. Over three decades
of development, amorphous catalyst systems have been refined to improve
their performance by adjustment of the type and level of the acidic support as
well as the metal function. Catalysts such as UOP’s DHC-2 (desulfrization
catalyst) and DHC-8 (Hydrocracking catalyst) have a well-established
33
Chapter 3 Reaction Chemistry
performance history in this service, offering a range of activity and selectivity to
match a wide range of refiners’ needs.
Hydrocracking Reactions
Crystalline catalyst support materials, such as zeolites, have been used in
hydrocracking catalysts by UOP since the mid-1960s. The combination of
selective pore geometry and varying acidity has allowed the development of
catalysts that convert a wide range of feedstocks to virtually any desired product
slate. UOP now offers catalysts that will selectively produce LPG, naphtha,
middle distillates, or lube base oils at high conversion activity using molecular-
sieve catalyst support materials. The UOP zeolite materials used in
hydrocracking service are often grouped according to their selectivity patterns.
Base metal catalysts utilized for naphtha applications are HC-24, HC-34, and
HC-170. Flexible base metal catalysts (naphtha, jet, diesel) include DHC-41, HC-
43, HC-33, HC-26, and HC-29. 34
Chapter 3 Reaction Chemistry
The distillate catalysts, which offer a significantly enhanced activity over
amorphous catalysts while maintaining the excellent middle-distillate selectivity,
are HC-110, HC-115, DHC-32, and DHC-39. Noble metal catalysts are also
available for both naphtha (HC-28) and jet/naphtha (HC-35) service. Unlike the
amorphous-based catalysts, the zeolite-containing materials are usually more
selective to lighter products and thus more suitable when flexibility in product
choice is desired. In addition, zeolitic catalysts typically employ a
hydroprocessing catalyst upstream, specifically designed to remove nitrogen and
sulfur compounds from the feed prior to conversion. UOP catalysts such as HC-
P, HC-R, HC-T, UF-210, and UF-220 are used for this service. These materials
are specifically designed with high hydrogenation activity to effectively remove
these compounds, ensuring a clean feed and optimal performance over the
zeolitic-based catalyst.
One important consideration for catalyst selection is regenerability.
Hydrocracking catalysts typically operate for cycles of 2 years between
regenerations but can be operated for longer cycles, depending on process
conditions. When end-of-run conditions are reached, as dictated by either
temperature or product performance, the catalyst is typically regenerated.
Regeneration primarily involves combusting the coke off the catalyst in an
oxygen environment to recover fresh catalyst surface area and activity.
Regenerations can be performed either with plant equipment if it is properly
designed or at a vendor regeneration facility. Both amorphous and zeolitic
catalysts supplied by UOP are fully regenerable and recover almost full
catalyst activity after carbon burn.
35
Chapter 4 Process Selection
CHAPTER 04
Capacity
And
Process Selection
36
Chapter 4 Process Selection
Processes Available:
Basically there are two processes available for the cracking of vaccum gas oil
(VGO).
Fluid catalytic cracking
Catalytic cracking
Thermal cracking
Fluid Catalytic cracking:
Fluid catalytic cracking (FCC) is the most important conversion process used
in petroleum refineries. It is widely used to convert the high-boiling, high-
molecular weight hydrocarbonfractions of petroleum crude oils to more
valuable gasoline, olefinic gases, and other products.Cracking of petroleum
hydrocarbons was originally done by thermal cracking, which has been almost
completely replaced by catalytic cracking because it produces more gasoline with
a higher octane rating. It also produces byproduct gases that are more olefinic,
and hence more valuable, than those produced by thermal cracking.
The feedstock to an FCC is usually that portion of the crude oil that has an
initial boiling point of 340 °C or higher at atmospheric pressure and an
average molecular weight ranging from about 200 to 600 or higher. This portion
of crude oil is often referred to as heavy gas oil. The FCC process vaporizes and
breaks the long-chain molecules of the high-boiling hydrocarbon liquids into
much shorter molecules by contacting the feedstock, at high temperature and
moderate pressure, with a fluidized powdered catalyst.
In effect, refineries use fluid catalytic cracking to correct the imbalance between
the market demand for gasoline and the excess of heavy, high boiling range
products resulting from thedistillation of crude oil.
37
Chapter 4 Process Selection
As of 2006, FCC units were in operation at 400 petroleum refineries worldwide
and about one-third of the crude oil refined in those refineries is processed in an
FCC to produce high-octane gasoline and fuel oils.During 2007, the FCC units in
the United States processed a total of 5,300,000 barrels (834,300,000 litres) per
day of feedstock and FCC units worldwide processed about twice that amount.
Catalysts
Modern FCC catalysts are fine powders with a bulk density of 0.80 to 0.96 g/cc
and having a particle size distribution ranging from 10 to 150 μm and an average
particle size of 60 to 100 μm.The design and operation of an FCC unit is largely
dependent upon the chemical and physical properties of the catalyst. The
desirable properties of an FCC catalyst are:
Good stability to high temperature and to steam
High activity
Large pore sizes
Good resistance to attrition
Low coke production
Catalytic Cracking:
The catalytic cracking of hydrocarbons is not restricted to one single reaction.
Instead, several reactions occur, all resulting in different product compositions.
Here the catalytic cracking of diesel is investigated. Diesel mainly consists of
saturated hydrocarbons (CnH2n+2) ranging from C10H22 to C15H32. Therefore, in this
study the cracking of dodecane (C12H26) has been taken as the model reaction.
Because no hydrogen is added during the cracking process the product mostly
comprises of unsaturated hydrocarbons (CnH2n), called olefins.
Advantages
38
Chapter 4 Process Selection
Advantages of using catalytic cracking of liquid hydrocarbons on-board are:
Increased lower heating value of the fuel by about 6% Better burning due to usage of gaseous hydrocarbons Reaction conditions comparable with exhaust temperature
Disadvantages
Disadvantages of using catalytic cracking of liquid hydrocarbons on-board are:
Incomplete conversion of the fuel Polymerizing by olefins in the system Coking on the catalyst, which leads to deactivation
Solutions
To overcome the problem of coking on the catalyst in industrial processes the catalyst is regenerated by heating it up and burning of the cokes. In a car this has to be applied continuously. In another process called hydrocracking the problem of coking is circumvented by adding a high pressure hydrogen stream. This also might work on-board when the cracking system is combined with a hydrogen-generating process. Hydrocracking would provide a solution for the polymerization problem as well.
To reuse the unreacted part of the product stream a separation unit has to be incorporated. Possibly the unreacted diesel can be vaporized and introduced to the engine together with the gaseous hydrocarbons. The boiling point of diesel is about 350 °C so there is a possibility to run the system in this way.
Another option for operating a catalytic cracking process is provided in a US patent from 1985. The catalyst is placed inside the combustion chamber. Liquid fuel is injected into the combustion chamber, where it is cracked right before combustion. It would be interesting to investigate if the engine cycle of such a system corresponds to that of a gas engine
39
Chapter 4 Process Selection
Thermal Cracking:
Reaction Chemistry
When a hydrocarbon is heated and decomposed under thermal cracking
conditions, it may be assumed that it is broken up into two or more free radicals.
The free radicals then enter into a series of reactions that result in a total product
covering a broad range of molecular weights from hydrogen to bitumen and
cokes. In accordance with thermal cracking theory, the reactions may proceed
as:
A portion of the compound disassociates to form free radicals, for example:
C10H22 C8H17 + C2H5
The highly reactive radicals do not appear in the thermally cracked product
effluent, but depending upon size and environment: (a) react with other
hydrocarbons, (b) decompose to olefins, (c) combine with other radicals, and (d)
react with metal surfaces.
In general, small radicals are more stable than larger radicals, and more readily
react with other hydrocarbons by capturing a hydrogen atom, for example;
C2H5 + C6H14 C2H6 + C6H13
Large radicals are unstable and decompose to form olefins and smaller radicals,
for example;
C6H13 C5H10 + CH3
C8H17 C4H8 + C4H9
40
Chapter 4 Process Selection
C4H9 C4H8 + H
The free radical chain reactions are terminated when two radicals combine; for
example;
C8H17 + H C8H18
The polymerization and condensation reactions that occur at thermal cracking
conditions can go all the way to aromatic tars. Coke and bitumen are the ultimate
polymers. The molecules become very large with considerable cross linkage.
Lack of hydrogen coupled with high molecular weight decreases their solubility in
hydrocarbons.
41
Chapter 4 Process Selection
PROCESS SELECTION:
Dieselmax process licensors will need to strike the right balance between
complex, expensive, high pressure processes that offer flexibility and products of
superior quality and cheap, simple, low pressure designs with more restricted
options.
In an economic climate of low refining margins and emphasis on high returns on
investment, there is a strong incentive to design and construct hydrocrackers
with minimum capital investment. This often means “simple units”, i.e. single
reactor operating at moderate conditions.
This is the major reason that the mild hydrocracking process is now used. On the
other hand, the call for ultra low sulfur and in particular very low aromatics level
in finished products cannot easily be satisfied by applying a low hydrogen partial
pressure process. Moreover, catalyst activities in mild hydrocracking unit are
reduces as well.
Therefore, we select mild hydrocracking unit for the conversion of VGO feed
stock in our project, which is the best design as proved by above discussion.
Capacity Selection:
We selected 30000 BPSD of VGO feed because as presented by graphs on next
pages, these graphs clearly indicate that there is now a large consumption of
diesel in all provinces of Pakistan, and we have to maximize the production of
diesel and middle distillates.
42
Chapter 4 Process Selection
World Oil Consumption by Sector showing Projected Demand
Growth (2003-2030)
Petroleum Product outlook for Pakistan
43
Chapter 4 Process Selection
44
Chapter 5 Process Description
CHAPTER 05
Process
Description
45
Chapter 5 Process Description
TAGGING OF PLANT EQUIPTMENTS
46
Chapter 5 Process Description
PROCESS DESCRIPTIONThe Dieselmax process Unit can be divided into three (3) sections. These are
termed as follows:
Catalyst Reactor Section
Catalyst Fractionation Section
Thermal Section
Catalyst Reactor Section:
Fresh Feed System:
The VGO feed coming from an upstream vacuum distillation unit is sent to the
feed surge drum (D1) along with some recycled distillate coming from the thermal
section. The VGO feed stream is filtered by automatic backwash filters (F1). The
contaminated oil from the backwash contains solids and is sent to backwash
surge drum (D2) to refinery tanks. The reactor charge pump (P1) takes suction
from the feed surge drum (D1) and pump the raw oil to the reactor effluent-
combined feed exchangers (E1, 2).
Feed Preheating:
The temperature of the VGO feed from the feed surge drum (D1) is below to
Hydrocracker reactor (R1) inlet temperature. So, first feed is preheated by
reactor effluent-combined feed exchange (E1, 2) with hot reactor effluent coming
from hydrocracker and then heating in a fired heater (FH1).
47
Chapter 5 Process Description
Catalytic Reactor:
When the VGO feed has been heated to the desired temperature, the reactants
enter the top of the catalytic reactor (R1). As the reactants flow downward
through the catalyst bed, exothermic chemical reactions occur and the
temperature increases.
Reactor Effluent Cooling System:
Due to the exothermic nature of the reactions taking place in the reactor (R1), the
temperature of the material leaving is greater than the reactor inlet temperature.
The heat of reaction as well as a large portion of the heat contained in the reactor
feed is recovered with the help of heat exchanger (E3) which is used to preheat
the stripper feed. After exiting the heat exchanger (E3), wash water is injected
into the reactor effluent and this combined water-effluent stream is further cooled
in air cooled exchanger (AE1) before entering the high pressure separator (T1).
Vapor / Liquid Separation System:
After cooling the reactor effluent, the desired liquid products must be separated
from the recycle gas. The reactor effluent exits the air cooled exchanger (AE1)
and goes to the separator (T1) where the hydrocarbon liquid is separated from
the water and recycle gas and sent to the fractionation section.
The water collected in the boot attached to the separator (T1) is removed and
sour water is sent to treating unit. The hydrogen-rich recycle gas from the
separator (T1) is sent to the recycle gas scrubber for removal of H2S.
Reactor Effluent Water Wash System:
The sulfur and nitrogen contained in the VGO feed are converted to hydrogen
sulfide (H2S) and ammonia (NH3) in the reactor (R1). These two reaction
48
Chapter 5 Process Description
products combine to form ammonium salts which can solidify and precipitate as
the reactor effluent is cooled.
Reactor effluent is cooled in the air cooled exchanger (AE1). Water is injected
into the stream before it enters the air cooled condenser in order to prevent the
deposition of salts that can corrode and foul the condenser tubes.
Recycle Hydrogen Scrubbing System:
H2S is present in the recycle gas stream because it is a reaction by-product. So,
a recycle gas scrubber (S1) is used to remove H2S from the recycle gas.
After separation of the gas and liquid phases in the separator (T1), the gas
leaves from the top of the separator (T1), passes through the recycle gas cooler
(E4), and flows to the knock out drum (D4), where condensed liquid is removed.
The gas from the knock out drum (D4) enters the bottom section of the recycle
gas scrubber (S1) and is contacted counter-current with amine, entering from top
of the column. The amine flowing down and the gas flowing up the tower come
into contact over the trays. Intimate mixing between the two is achieved and the
amine absorbs the H2S from the gas. The "rich" amine falls to the bottom of the
recycle gas scrubber (S1). The H2S-free gas leaves the top of the tower (S1) and
goes through the centrifugal compressor (C1) before joining with the makeup
hydrogen.
Recycle Gas System:
After the recycle gas compressor (C1) discharge, some recycle gas is used as
quench gas between catalyst beds. Quench gas streams are used to reduce
reactor interbed temperatures.
49
Chapter 5 Process Description
50
Chapter 5 Process Description
Catalyst fractionation section:
The function of the Catalyst Fractionation Section is to separate the reactor liquid
product into the un-stabilized naphtha, kerosene, diesel and product fractionator
(R2) bottoms product. Liquid product from the reactor section is sent to the
stripper (S2) for the removal of H2S and light gas components.
Stripper overhead vapor are partially condensed and sent to the stripper receiver
(T2). The liquid from the receiver is pumped again to the feed stream to S2
From the stripper (S2) bottom the reactor liquid product is fed through stripper
bottoms-kerosene product exchanger (E5), stripper bottoms-diesel product
exchanger (E6), and product fractionator feed heater (FH2) to product
fractionator (R2). The design operation feed temperature to product fractionator
is 375oC.
A kerosene side draw from the Product Fractionator (R2) is stripped for light ends
removal in the reboiled kerosene stripper (S3). The overhead vapor from the
kerosene stripper (S3) is returned to the Product Fractionator (R2). The bottoms
are pumped by kerosene product pumps (P3) and go through stripper bottoms-
kerosene product exchanger (E5). Then Kerosene product is stored.
A diesel side draw from the product fractionator (R2) is steam stripped for light
ends removal in the diesel stripper (S4). The overhead vapor from the diesel
stripper (S4) is returned to the product fractionator (R2). The bottoms are
pumped by diesel product pumps (P4) and go through a stripper bottoms-diesel
product exchanger (E6), after which it is stored.
Overhead vapor of product fractionator are partially condensed and sent to the
product fractionator receiver (T3). The liquid from the receiver is returned to product
51
Chapter 5 Process Description
fractionator (R2) top section. The net liquid product, un-stabilized naphtha, is
sent to treating unit.
CATALYTIC FRACTIONATING SECTION
52
Chapter 5 Process Description
Thermal section
The Dieselmax Thermal Section consists of two main operating systems. The
Thermal Cracking system and Fractionation system.
Bottom fractionating feed is passed through the thermal cracker heaters (FH3).
The heater effluents combine and pass into a reactor chamber (R3). The
thermally cracked material exiting the reactor chamber (R3) is fed into the flash
fractionator (R4).
The function of the flash fractionator system is to separate the reactor chamber
effluent into the desired products. The overheads from the flash fractionator (R4)
leave the top of the flash fractionator and are condensed and collect in the flash
fractionator receiver (T4). The condensed un-stabilized naphtha is directed to
treating unit.
A distillate side draw from the flash fractionator (R4) is steam stripped for light
ends removal in the distillate stripper (S5). The overhead vapor from the distillate
stripper (S5) is returned to the flash fractionator (R4). The distillate is normally
recycled back the catalytic reactor section for hydrogenation.
The flash fractionator (R4) bottoms product is pumped by the flash fractionator
bottoms pumps (P5) and approximately 40 percent side stream of this
fractionator bottoms product is recycled. The remaining 60 percent of flash
fractionator bottoms product sent towards storage tanks.
53
Chapter 5 Process Description
54
Chapter 6 Material Balance
CHAPTER 06
Material
Balance
55
Chapter 6 Material Balance
Operation Basis = 1 hr
Feed Design Capacity = 40000 BPSD
Feed is VGO, from Vacuum Distillation Unit = 264.6 m3/hr (equivalent to 40000 BPSD)
Because given feed has API =22.3
Specific Gravity = 141.5
(API + 131.5)
So, the sp. Gr. Is = 0.92
Hence, the density of feed = 920 kg/m3
Also, Fresh Distillate from Thermal Cracker Section = 40000 kg/hr
So, total fresh feed = (40000 + 243432)
= 283432 kg/hr
Chemical Hydrogen Consumption
The hydrogen is consumed in the saturation, desulfurization, denitrification and
hydrocracking reactions.
Chemical Hydrogen Consumption = 126 m3 H2 / m3 of fresh VGO feed
Because VGO feed = 264.6 m3/hr
56
Chapter 6 Material Balance
= 33339.6 m3/hr
Density of Hydrogen = 0.185 kg/m3
So, Hydrogen Consumption flow rate = (33339.6 m3/ hr) * (0.185Kg / m3)
= 6167.826 kg/hr
Because from plat-forming Unit, The Hydrogen flow = 20000 to 30000 Nm3/hr
So, converting it into mass flow rate = 5000 kg/hr
Recycle Hydrogen Gas = 25000 kg/hr
Total recycle gas = (25000 + 5000) = 30000 kg/hr
Recycle hydrogen to fresh VGO = 45% of total recycle gas
= 13500 kg/hr
Recycle gas as Quench gas to catalytic reactor = 55% of total recycle gas
= 16500 kg/hr
Combined feed to catalytic reactor = (283432 + 13500)
= 296932 kg/hr ---------- IN
Also, the reactor effluent = 296932 kg/hr ---------- OUT
Hence, for Hydrocarcker ; IN = OUT
57
Chapter 6 Material Balance
58
Chapter 6 Material Balance
Reactor effluent = 296932 kg/hr
Wash water injected to reactor effluent = 5 vol. % of fresh feed
= (0.05*264.6) = 13.23 m3/hr
= (13.23*1000) = 13230 kg/hr
Total input to separator = 299632 kg/hr
Sour water collected from separator = 10000 kg/hr
Gases from separator = 30000 kg/hr
Liquid leaves the separator = 299632 – (10000 + 30000)
= 259632 kg/hr
So, for separator;
299632 = 259632 + 10000 + 30000
IN =OUT
Recycle Gas Scrubber
Input gas to scrubber = 30000 kg/hr
Amine Solution to scrubber = 150000 kg/hr
H2S free gas outlet flow rate = 25000 kg/hr
Rich amine outlet = 155000 kg/hr
59
Chapter 6 Material Balance
Stripper and Receiver
Liquid coming from separator = 259632 kg/hr
Liquid from receiver = 2500 kg/hr
Total feed to stripper = 259632 + 2500 = 262132 kg/hr
MP steam flow rate = 3000 kg/hr
Vapors leave the separator = 10000 kg/hr
Liquid leaves the separator = 191160 kg/hr
Feed to receiver = 10000 kg/hr
Liquid outlet from receiver = 2500 kg/hr
Off-gases leave = 5500 kg/hr, Sour water = 2000 kg/hr
Off gases Molecular wt. =27.8 g/gmole
Gas density = 1.2 kg/m3
Gas volumetric flow rate = (5500kg/hr) * (m 3 /1.2kg)
= 4580 m3/hr
Product Fractionator
Feed to product fractionator = 191160 kg/hr
Steam flow rate = 4000 kg/hr
Product fractionator bottoms = 100160 kg/hr
Receiver Section
60
Chapter 6 Material Balance
Feed to receiver = 70000 kg/hr
Water outlet from receiver = 6000 kg/hr
Volumetric flow rate of water = (6000kg/hr) x (m3 / 999kg) = 6.0 m3/hr
Un-stabilized naphtha from receiver = 64000 kg/hr
Un-stabilized naphtha taken as product or returning to gas concentration unit = 4000 kg/hr
Un-stabilized naphtha refluxed back to product fractionator = (64000 – 4000) = 60000 kg/hr
Un-stabilized naphtha taken as product, having mol. Wt. = 89.2 g/gmole
Density of Un-stabilized naphtha taken as product = 695 kg/m3
Volumetric flow rate of Un-stabilized naphtha taken as product = 5.75 m3/hr
61
Chapter 6 Material Balance
62
Chapter 6 Material Balance
Diesel Stripper
Feed to Diesel Stripper = 58000 kg/hr
Stripper steam to diesel stripper = 1000 kg/hr
Volumetric flow rate of stripper steam = (1000kg/hr)x(m3 / 0.8kg) = 1250 m3/hr
Diesel taken as product = 40000 kg/hr
Mol. Wt. of diesel product obtained = 249.3 g/gmole
Volumetric flow rate of diesel product =(40000kg/hr) x (m3 / 868kg) = 46 m3/hr
Vapor returned to product fractionator = (58000 + 1000) – 40000
= 19000 kg/hr
Kerosene Stripper
Feed to kerosene stripper = 55000 kg/hr
Kerosene taken as product = 45000 kg/hr
Volumetric flow rate of kerosene product = (45000kg/hr) x (m3 / 821kg) = 55 m3/hr
Vapor returned to product fractionator = (55000 – 45000) = 10000 kg/hr
Now,
Total feed to fractionator system = 191160 + 4000 = 195160 kg/hr
Total output products from fractionating section = (100160 + 40000 + 45000 + 4000 + 6000)
= 195160 kg/hr
63
Chapter 6 Material Balance
Thermal Section
Feed to flash fractionator column = 100160 kg/hr
Recycled bottom product = 30000 kg/hr
Total feed entering = (100160 + 30000) = 130160 kg/hr
Fractionator Receiver
Feed to Fractionator Receiver = 57160 kg/hr
Off gases leave = 6000 kg/hr
Sour water = 3160 kg/hr
Net liquid obtained = 48000 kg/hr
Un-stabilized naphtha obtained as product or sent to gas concentration unit = 18000 kg/hr
Un-stabilized naphtha recycled to flash fractionator = (48000 – 18000) = 30000 kg/hr
Distillate stripper
Feed to distillate stripper = 38000 kg/hr
Vapors leave = 9000 kg/hr
MP steam injection flow rate = 1000 kg/hr
Distillate recycled back to cat. Reactor section = 30000 kg/hr
MP steam injection to bottom of flash fractionator = 2000 kg/hr
Flash fractionator bottoms = 75000 kg/hr
Flash fractionator bottoms sent to storage tank = 60% of Flash fractionator bottoms
= (0.6*75000) = 45000 kg/hr
64
Chapter 6 Material Balance
Recycled back to feed to flash fractionator = (0.4*75000) = 30000 kg/hr
Flash fractionator IN = 100160 + 30000 + 2000 = 132160 kg/hr
Flash fractionator products obtained = 6000 + 3160 + 18000 + 30000 + 75000
= 132160 kg/hr = OUT
So, IN=OUT
Percentage of feed evaporated in Diesel stripper of Catalytic
Fractionating Section:65
Chapter 6 Material Balance
Assume, specific heat of diesel = 0.6 btu/lbm.F
100 is the latent heat;
The reduction in sensible heat of the diesel product equals;
(316 – 290)*0.6 = 15.6 btu/lbm
The percent of the feed to the stripper that evaporates is then;
(15.6 btu/lbm) / (100 btu/lbm. ) = 15.6%
I neglected the heat picked up by the steam in the preceding calculations,
because steam flow rate is quite small to the stripper feed, so this effect may be
disregarded.
66
Chapter 8 Equipment Design
CHAPTER 07
Energy
Balance
67
Chapter 8 Equipment Design
Catalytic Reactor Section:
Reactor effluent feed exchanger
E1:
Cold fluid:
T1 = 656.60F
T2 = 714.20F
Cp = 0.7 Btu/lb0F
m = 248524 lb/hr
Heat gain:
Q = m*Cp*ΔT
= 248524 (0.7) (714.2 - 656.6)
= 10E+06 Btu/hr
Hot fluid:
T1 = 757.40F
T2 = 707 0F
Cp = 0.8 Btu/lb0F
m = 248524 lb/hr
Heat loss:
Q = m*Cp*ΔT
68
Chapter 8 Equipment Design
= 248524 (0.8) (757.4 -707)
= 10E+06 Btu/hr
Therefore,
Heat gain = Heat loss
Reactor effluent feed exchanger
E2:
Cold fluid:
T1 = 656.60F
T2 = 714.20F
Cp = 0.7 Btu/lb0F
m = 248524 lb/hr
Heat gain:
Q = m*Cp*ΔT
= 248524 (0.7) (714.2 - 656.6)
= 10E+06 Btu/hr
Hot fluid:
T1 = 757.40F
T2 = 7070F
Cp = 0.8 Btu/lb0F
m = 248524 lb/hr
Heat loss:
Q = m*Cp*ΔT
69
Chapter 8 Equipment Design
= 248524 (0.8) (757.4 - 707)
= 10E+06 Btu/hr
Therefore,
Heat gain = Heat loss
Reactor Effluent/Separator liquid exchanger:
E3:
Cold fluid (shell side)
T1 = 138.20F
T2 = 325.40F
Cp = 0.798 Btu/lb0F
m = 430969.2 lb/hr
Heat gain:
Q = m*Cp*ΔT
= 430969.2 (0.798) (325.4 - 138.2)
= 64417480 Btu/hr
Hot fluid (tube side, reactor effluent):
T1 = 7160F
T2 = 5000F
Cp = 0.6 Btu/lb0F
m = 497048 lb/hr
Heat loss:
70
Chapter 8 Equipment Design
Q = m*Cp*ΔT
= 497048 (0.6) (716 - 500)
= 64417480 Btu/hr
Therefore,
Heat gain = Heat loss
Recycle gas cooler:
E4:
Cold fluid: (cooling water, tube side)
T 1= 94.10F
T 2= 105.80F
Cp = 1.0 Btu/lb0F
m = 77092.51 lb/hr
Heat gain:
Q = m*Cp*ΔT
= 77092.514 (1.0) (105.8 - 94.1)
= 901982.4 Btu/hr
Hot fluid ( recycle Hydrogen gas, shell side):
T1 = 1400F
T2 = 105.80F
Cp = 0.4 Btu/lb0F
m = 66079.3 lb/hr
71
Chapter 8 Equipment Design
Heat loss:
Q = m*Cp*ΔT
= 66079.3 (0.4) (140 - 105.8)
= 903964.8 Btu/hr
Therefore,
Heat gain = Heat loss
Stripper bottom kerosene product exchanger:
E5:
Cold fluid (stripper bottom ,shell side)
m = 421057.3lb/hr
Cp = 0.576 Btu/lb0F
T1 = 3290F
T2 = 3470F
Heat gain:
Q = m*Cp*ΔT
= 421057.3(0.576)(347 – 329)
= 4365522 Btu/hr
Hot fluid (Kerosene product ,tube side)
m = 99118.9 lb/hr
Cp = 0.7
T1 = 442.40F
T2 = 379.40F
72
Chapter 8 Equipment Design
Heat loss
Q = m*Cp*ΔT
= 99118.9 (0.7)(442.4 – 349.4)
= 4365522 Btu/hr
Therefore,
Heat gain = Heat loss
Stripper bottom Diesel product Exchanger
E6:
Cold fluid (Stripper bottom ,shell side)
m = 421057.3 lb/hr
T1 = 3470F
T2 = 386.60F
Cp = 0.496
Heat gain
Q = m*Cp*ΔT
= 421057.3 (0.496)(386.6 – 347)
= 8270238 Btu/hr
Hot fluid (Diesel product ,tube side):
m = 88105 lb/hr
Cp = 0.6
T1 = 5540F
73
Chapter 8 Equipment Design
T2 = 397.40F
Heat loss
Q = m*Cp*ΔT
= 88105 (0.6)(554 – 397.4)
= 8278414 Btu/hr
Therefore,
Heat gain = Heat loss
Fired Heaters:
FH1:
T1 = 714.20F
T2 = 728.60F
Cp = 0.7 Btu/lb0F
m = 497048.5 lb/hr
Q = m*Cp*ΔT
= 497048.5 (0.7) (728.6 -7 14.3)
= 5010248 Btu/hr
FH-2:
T1 = 386.60F
T2 = 7070F
Cp = 0.6 Btu/lb0F
m= 421057.3 lb/hr
Q = m*Cp*ΔT
= 421057.3 (0.6) (707 - 386.6)
74
Chapter 8 Equipment Design
= 80944049 Btu/hr
FH-3:
T1 = 609.80F
T2 = 924.80F
Cp = 0.8 Btu/lb0F
m = 220616.7 lb/hr
Q = m*Cp*ΔT
= 220616.7 (0.8) (924.8-609.8)
= 55595419 Btu/hr
Catalytic Reactor:
T1 = 728.60F
T2 = 757.40F
Cp = 0.7 Btu/lb0F
m = 497048.5 lb/hr
Q = m*Cp*ΔT
= 497048.5 (0.7) (757.4 - 728.6)
= 10020497 Btu/hr
Product Fractionator:
Inlet Streams:
1: Feed Stream:
T1 = 7070F
T2 = 770F
75
Chapter 8 Equipment Design
Cp = 0.8 Btu/lb0F
m = 421057.26 lb/hr
Q = m*Cp*ΔT
= 421057.26 (0.8) (707 - 77)
= 2.12E+08 Btu/hr
2: Overhead Reflux:
T1 = 1580F
T2 = 770F
Cp = 0.5 Btu/lb0F
m = 132158.6 lb/hr
Q = m*Cp*ΔT
= 132158.6 (0.5) (158 - 77)
= 5352413 Btu/hr
3: Kerosene Reflux:
T1 = 402.80F
T2 = 770F
Cp = 0.6 Btu/lb0F
m = 22026.43 lb/hr
Q = m*Cp*ΔT
= 22026.43 (0.6) (402.8 - 77)
= 4305727 Btu/hr
4: Diesel Reflux:
76
Chapter 8 Equipment Design
T1 = 588.20F
T2 = 770F
Cp = 0.7 Btu/lb0F
m = 41850.22 lb/hr
Q = m*Cp*ΔT
= 41850.22 (0.7) (588.2 - 77)
= 14975683 Btu/hr
4: Steam:
T = 1500C
m = 4000 kg/hr = 8810.57 lb/hr
λ at 1500C = 2113.99 kJ/kg
= 909.16 Btu/lbm
Q = mλ
= 8810.57 lb/hr *909.16 Btu/lb
= 8E+06 Btu/hr
Outlet Streams:
1: Overhead:
T1 = 201.20F
T2 = 770F
Cp = 0.6 Btu/lb0F
m = 154185 lb/hr
77
Chapter 8 Equipment Design
Q = m*Cp*ΔT
= 154185 (0.6) (201.2 - 77)
= 11489868 Btu/hr
2: Fractionator Bottoms:
T1 = 609.80F
T2 = 770F
Cp = 0.8 Btu/lb0F
m = 220616.7 lb/hr
Q = m*Cp*ΔT
= 220616.7 (0.8) (609.9 - 77)
= 94035679 Btu/hr
3: Diesel Draw off:
T1 = 600.80F
T2 = 770F
Cp = 0.75 Btu/lb0F
m = 127753.3 lb/hr
Q = m*Cp*ΔT
= 127753.3 (0.75) (600.8 - 77)
= 50187885 Btu/hr
4: Kerosene Draw off:
T1 = 3830F
78
Chapter 8 Equipment Design
T2 = 770F
Cp = 0.6 Btu/lb0F
m = 121145.4 lb/hr
Q = m*Cp*ΔT
= 121145.4 (0.6) (383 - 77)
= 22242291 Btu/hr
Diesel Stripper:
Inlet Stream:
1: Diesel Inlet:
T1 = 600.80F
T2 = 770F
Cp = 0.25 Btu/lb0F
m = 127753.3 lb/hr
Q = m*Cp*ΔT
= 127753.3 (0.25) (600.8 - 77)
= 50187885 Btu/hr
2: Steam:
T = 1500C
m = 2202.64 lb/hr
λ = 909.16 Btu/lb at 1500F
Q = mλ
=2202.64*909.16
79
Chapter 8 Equipment Design
= 2002552.18 Btu/hr
Outlet Streams:
1: Diesel Reflux:
T1 = 588.20F
T2 = 770F
Cp = 0.7 Btu/lb0F
m = 41850.22 lb/hr
Q = m*Cp*ΔT
= 41850.22 (0.7) (588.2 - 77)
= 14975683 Btu/hr
2: Diesel Product:
T1 = 5540F
T2 = 770F
Cp = 0.7 Btu/lb0F
m = 88105.73 lb/hr
Q = m*Cp*ΔT
= 88105.73 (0.7) (554 - 77)
= 29418502 Btu/hr
Rebolier Kerosene Stripper:
Inlet Stream:
1: Kerosene Inlet:
T1 = 3830F
T2 = 770F
80
Chapter 8 Equipment Design
Cp = 0.6 Btu/lb0F
m = 121145.4 lb/hr
Q = m*Cp*ΔT
= 121145.4 (0.6) (383 - 77)
= 22242291 Btu/hr
Outlet Streams:
1: Kerosene Reflux:
T1 = 402.80F
T2 = 770F
Cp = 0.6 Btu/lb0F
m = 22026.43 lb/hr
Q = m*Cp*ΔT
= 22026.43 (0.6) (402.8 - 77)
= 4305727 Btu/hr
2: Kerosene Product:
T1 = 442.40F
T2 = 770F
Cp = 0.7 Btu/lb0F
m = 99118.94 lb/hr
Q = m*Cp*ΔT
= 99118.94 (0.7) (442.4 - 77)
= 25352643 Btu/hr
81
Chapter 8 Equipment Design
Thermal Section:
Flash Fractionating Column:
1: Feed Stream:
T1 = 750.20F
T2 = 770F
Cp = 0.7 Btu/lb0F
m = 286696 lb/hr
Q = m*Cp*ΔT
= 286696 (0.7) (750.2 - 77)
= 1.35E+08 Btu/hr
2: Un-stabilized Naphtha Recycled back:
T1 = 1580F
T2 = 770F
Cp = 0.6 Btu/lb0F
m = 66079.3 lb/hr
Q = m*Cp*ΔT
= 66079.3 (0.6) (150-77)
= 3211454 Btu/hr
3: Distillate Reflux:
T1 = 4640F
T2 = 770F
Cp = 0.5 Btu/lb0F
82
Chapter 8 Equipment Design
m = 19823.79 lb/hr
Q = m*Cp*ΔT
= 19823.79 (0.5) (464 - 77)
= 3068722 Btu/hr
4: MP Stream:
T = 1500C
m = 1000 kg/hr
Q = mλ
= 2002552.18 Btu/hr
Outlet Stream:
1: Overhead:
T1 = 291.20F
T2 = 770F
Cp = 0.65 Btu/lb0F
m = 125903.1 lb/hr
Q = m*Cp*ΔT
= 125903.1 (0.65) (291.2 - 77)
= 17529486 Btu/hr
2: Flash Fractionator Bottom:
T1 = 719.60F
T2 = 770F
Cp = 0.8 Btu/lb0F
m = 165198.2 lb/hr
Q = m*Cp*ΔT
83
Chapter 8 Equipment Design
= 165198.2 (0.8) (719.6 - 77)
= 84925110 Btu/hr
3: Feed to Distillate Stripper:
T1 = 494.60F
T2 = 770F
Cp = 0.75 Btu/lb0F
m = 83700.44 lb/hr
Q = m*Cp*ΔT
= 83700.44 (0.75) (494.6 - 77)
= 26214978 Btu/hr
Distillate Stripper:
Inlet Stream:
Distillate stripper feed rate , Q = 26214978 Btu/hr
MP steam = 2202lb/hr, T= 1500C,
MP steam, Q = 2002552.18 Btu/hr
Outlet Stream:
1: Distillate Reflux:
m = 19823.7 lb/hr
Q = 3068722 Btu/hr
2: Distillate To Catalytic Reactor Section:
m = 66079.3 lb/hr
84
Chapter 8 Equipment Design
Cp = 0.7 Btu/lb0F
T1 = 656.60F
T2 = 770F
Q = m*Cp*ΔT
This implies,
Q = 26809692 Btu/hr
85
Chapter 8 Equipment Design
CHAPTER 08
Equipment
Design
86
Chapter 8 Equipment Design
PUMPS
Pumps of all types are used in every phase of petroleum production, transportation, and
refining. Production pumps include reciprocating units for mud circulation during drilling
and motor driven submersible centrifugal units for lifting crude to the surface. The most
common use of centrifugal pumps in production is for water flooding (secondary
recovery, subsidence prevention, or pressure maintenance). Transportation pumps
include units for gathering, for on and offshore production, for pipelining crude and
refined products, for loading and unloading tankers, tank cars, or tank trucks, and for
servicing airport fueling terminals. The majority of the units are centrifugal.
Refining units vary from single stage centrifugal units to horizontal and vertical
multistage barrel type pumps handling a variety of products over a full range of
temperatures and pressures. Centrifugal pumps are also used for auxiliary services, such
as cooling towers and cooling water.
Major refinery processes are crude distillation, vacuum tower separation, catalytic
:onversion, alkylation, hydrocracking, catalytic reforming, coking, and hydrotreatment
or the removal of sulfur and nitrogen. The products resulting from these processes
nclude motor gasoline, commercial jet fuel and kerosene, distillate fuel oil, residual fuel
II and lubricating oils. The American Petroleum Institute Standard 610, "Centrifugal
umps for Petroleum, Heavy Duty Chemical, and Gas Industry Services" (API 610), has
stablished specifications for the design features required for centrifugal pumps used
)r general refinery service.
hydrocracking unit, centrifugal pumps have been employed. It is the most common
87
Chapter 8 Equipment Design
ed type in the chemical process industry. It can be constructed in a wide range of
corrosion resistance materials. In it, basically the velocity energy is converted into
pressure energy.
Pump Design (P1)
According to mechanical energy balance equation;
g/gc dZ + VidVi/gc + vdP = W0 + F
Neglecting Kinetic term, and re-writing again;
g/gc (Z2 — Z1) + v(P2 — P1) + F = Wo
Assume for pump (P1)
(Z2– Zi) = 35 ft
Sp. Gr. Of liquid being pumped = 0.92
Density of liquid = 57.4 lbm / ft3
Suction pressure = P1 = 4 kgf/cm2
Suction pressure absolute = P1 = 4+1 = 5 kgf/cm2a
Discharge pressure = P2 = 103 kgf/cm2
Discharge pressure absolute =P2 = 103+1 =104 kgf/cm2 a
Pressure difference = AP = 99 kgf/cm2 a
vdP = 3539.8 ft.lbf / Ibm
Flow rate of liquid = 212160 kg/hr
Mass flow rate of liquid = (212160) / (0.454*3600) = m = 129.8 Ibm/sec
88
Chapter 8 Equipment Design
Volumetric flow rate of liquid = (212160)/(0.454*57.4*0.454*3600) = 2.264 ft3/sec
F= 2 * f *(L+Le) * v2 / D*gc
Assume; f = 0.005
Diam. Of pipe = 6 in. = 0.5 ft
Area of pipe = 0.196 ft2
Velocity of liquid in pipe = (2.264/0.196) = 11.52 fps
Assume; equivalent length = Le = 30 ft
Assume length of pipe = L = 400 ft
F= 35.48 ft . lbf / lbm
Total work done;
= 35 + 3539.8 + 35.48 = 3610.28 ft lbf / lbm
Hp = m*Wo / efficiency
Calculated horsepower = 1420 hp
89
Chapter 8 Equipment Design
90
Chapter 8 Equipment Design
Catalytic Reactor:
In a large number of industrially important processes, reactions are involved that require
the simultaneous contacting of a gas, a liquid and solid particles e.g. hydro-cracking
reactions.
The design of a gas-liquid-solid reactor is very much dependent upon the size of the
solid particles chosen for the reactions. Particles smaller than about lmm in diameter
cannot however be used in the form of a fixed bed , the pressure drop would be too
great and the possibility of the interstices between the particles to be blocked too
troublesome.
Since the size of the selected catalyst is greater than imm, a fixed bed reactor will be
used for the conversion in the hydro-cracking.
Fixed Bed reactor:
Apart from the particles size, the main choice to be made with the fixed bed reactor is
the direction of flow, i.e. upwards or downward flow of gas and liquid phases.
The configuration being used in our reactor is liquid and gas in co-current down-flow
which is sometimes called a trickle bed reactor, because at low to moderate gas and
liquid flows, the gas phase is continuous and the liquid flows as a thin film over the
surface of the catalyst. At higher gas flow rates there is more interaction between the
liquid and gas flow patterns.
Advantages:
Trickle bed reactors are widely used in the oil refinery because of the reliability of the
operation. The flow pattern is close to plug flow and relatively high reaction conversion
91
Chapter 8 Equipment Design
can be achieved in a single reactor.
Pressure drop with co-current down-flow is smaller and there is no problem of flooding
as compared with upward flow.
The particles of the bed are held firmly in place against the bottom support plate as a
result of the combined effect of the forces attributable to gravity and fluid drag.
The conversion in the hydro-cracking reactor is Garried out at high temperatures and
the reactions are exothermic as well so the temperature rise is controlled by using
hydrogen as a quench gas.
Reactor design:
Total fresh feed entering to the top of reactor = 225660 kg/hr
Sp. Gr of liquid = 0.92 = 920 kg/m3
Volumetric flow rate = 225660/920 = 245 m3/hr
Liquid hourly space velocity (LHSV) = 0.5 to 2.5 hr-1
Assume; LHSV = 0.7 hr-1
Space time = 1/0.7 = 1.428 hr
Volume of the reactor = 245 (m3/hr)* 1.428 hr;
= 350 m3
Assume; L /D = 9.0
92
Chapter 8 Equipment Design
L = 9.0 D;
Because, Volume = Area*Length = (0.785 D2* 9.0 D)
Volume = 7.065 D3
350= 7.065 D3; D = 3.67m
Now, length = L= (9.0 * 3.67) = 33m
Using four (4) catalyst beds of height 5, 6, 8.75 and 8.75m
Spacing between beds = 1.5m
So, total height of the reactor = 33m
Because it's a high pressure vessel, operating about 70 kgf/cm2 = 7091 kPa
Now, assuming that this vessel has hemispherical head because it has to withstand
high pressure, using formula to calculate the thickness of head for hemispherical head
type;
t = (Pi*Di) / (4fJ -1.2Pi)
Pi = Design pressure = 5 to 10% of working pressure
Working pressure = 7091 kPa
Design pressure = (7091 * 1.1) = 7800 kPa
Diam. Of the vessel = 3.67m
93
Chapter 8 Equipment Design
J= welded joint efficiency factor = 0.85
F= design stress = 500E+03 kPa
t = (7800*3.67) / (4*0.85*500E+03-1.2*780) = 16mm
Including corrosion allowances of 2mm, total thickness of the head material =
18mm
For calculation of the thickness of the shell, we used "Pressure Vessel Design
Manual" by DENNIS MOSS,
Vessel diameter = 145 in
Internal pressure = 1029 PSI
From Figure; The thickness of the shell = 96mm (ref. Dennis Moss)
First two beds of catalytic reactor contain guard catalysts (metallic), where
hydrogenation reaction sulfide and halide removal takes place. While the third
and fourth catalyst beds contain Zeolites catalysts (Amorphous Silica-alumina),
which promote hydro cracking and cracking reactions.
94
Chapter 8 Equipment Design
High Pressure Separator:
The separation of liquid droplets is essential from gas and liquid phases. When
some carry-over of fine droplets can be tolerated, it s sufficient to rely on gravity
in vertical or horizontal separation vessels. For the improved separation of liquid
droplets from the gas stream, vessels are equipped with a full diameter stainless
steel mesh blanket. Here, the purpose of the separator is to separate the recycle
gas, water and hydrocarbon in the reactor effluent. The mesh blanket helps
remove liquid droplets from the recycle gas and help coalesce water droplets out
of the hydrocarbon phase.
In case of water removal from the mixture, a water boot is also available. The
liquid level will also depend on the hold up time required for smooth operation
and control, typically 10 minutes is allowed.
Separator Design:
Total input (hydrocarbon + liquid water + recycle hydrogen gas)
to separator = 235660 kg/hr
= 519074 lb/hr
Flow rate of liquid (water+ hydrocarbon) = 205660 kg/hr = 452995.6 lb/hr
Liquid density = 57.7 IbM3 (sp.gr. =0.924)
Q= 452995.6 / 57.7 = 7850.87 ft3/hr
Assume residence time = 10 mins = 0.167 hr
95
Chapter 8 Equipment Design
Volume = 7850.87 (ft3 / hr)*0.167 hr;
= 1311 ft3
Assume, separator is half filled with liquid,
Liquid space = vapor space
Total volume of separator = 2*(volume of liquid in separator)
= 2*1131 = 2622 ft3
By taking 6% allowance;
Volume of separator = Q = 2780 ft3
Assuming, diam. Of separator = 12 ft
Including corrosion allowances of 2mm
Total diam. Of separator = 14mm
Volume of separator = 0.785 D2*L
2780 = 0.785 (12)2*L
Length of separator = 25 ft
96
Chapter 8 Equipment Design
Stripper Stripping is an operation used to remove lights ends from a fraction of product.
There are generally two methods used to carry out stripping action, these are
• Steam stripping
• Reboiler stripping
S2 is the steam stripper. Steam does the same job as reboiler. It is used when
high bottom temperatures are undesirable. Steam lowers the partial pressure of
the components in the bottoms liquid mixture and thus lowers the boiling point of
the bottom liquid.
This is a vertical vessel. Feed is introduced towards the top of the column via
distributor and stripping steam is injected below the bottom tray. This stripping
steam provides the needed lift to remove H2S and light components from the
stripper bottoms product.
Stripper Design:
MP steam flow rate = 3000 kg/hr
Liquid feed to stripper = 198160 kg/hr
Gm = 3000 /18 = 166.67 kgmole/hr
97
Chapter 8 Equipment Design
Lm = 198160 / 211.8 = 935.59 kgmole/hr
Stripper feed molecular weight = 211.8 kg/kgmole
The expression for a stripping operation is:
Where;
X2 = mole ratio of solute gas in liquid at top
X1= mole ratio of solute gas in liquid at bottom
Y1 = mole ratio of impurity in gas (steam) at bottom
1/A = mGm / Lm = Stripping factor
N = no. of plates in column
Assume, the equilibrium relationship is
Ye = 8.0 Xe;
Ye = m Xe (straight line equation)
1/A = 8*166.67 / 935.59 = 1.425;
So, assume feed oil containing 5 mole% hydrocarbon and we have to reduce the
hydrocarbon content to 0.05 mole% by assuming that the oil is non-volatile.
X2= 5 mole % = 0.05 = .05 /(1 - 0.05) = 0.052
X1=0.05 mole % = 0.0005
98
Chapter 8 Equipment Design
Putting values in equation (1);
Solving above relationship, a = 43.5;
Having, In (43.5) / In (1.425) = N+1
This implies; N = 10 plates
Now, maximum allowable superficial vapor velocity (based on cross-sectional
area of empty tower) is;
L = 800 kg/m3 = 49.92 lb/ft3
G = 0.597 kg/m3; from steam table at 1 atm and 100°C
Selecting a tray spacing of 12 in. = 0.304 m;
From graph, The value of ic = 0.18 (ref. TIMMERHAUS)
99
Chapter 8 Equipment Design
100
Chapter 8 Equipment Design
Recycle Gas scrubber (Si)
This is a column uses trays to contact recycle gas and amine. Recycle hydrogen
enters in the middle of the scrubbing section and flows up through the sieve trays
contacting the amine solution.
Assume H2S in inlet gas = 0.03 kmole H2S / kmole of gas;
The target is to reduce the H2S conc. In the outlet stream to 1% of present value;
Assume the equilibrium relationship is;
Y = 2X;
It is estimated that the rich amine leaves the scrubber with 0.013 kmole H2S /
kmole of solvent. Its is also known that the gas phase resistance controls the
process.
Yi = Mole ratio of H2S in inlet gas stream = 0.03
Y2 = Mole ratio of H2S in outlet gas stream = 0.0003
101
Chapter 8 Equipment Design
102
Chapter 8 Equipment Design
103
Chapter 8 Equipment Design
Fired Heaters
Most of the furnaces / fired heaters used in the petroleum refinery are pipe still
heaters, which are designed to heat the process fluids in tubes effectively by
burning fuels. The function of heater is similar to that of steam generating boiler
except that process fluids are heated instead of water. The heat is supplied by
gas or oil burners located in the floor or in walls of the combustion chamber. The
process fluid is fed and passed through tubes inside the heater. The feed is
heated to the required temperature and fed to the next unit in the process. The
purpose of the furnace is to raise the temperature of the process fluid. Box type
furnace and cylindrical furnaces are two major types of furnaces. The major
furnace parts are Walls, Refractory lining, Tubes, Burners, The air registor etc.
When a furnace is operating in a fuel gas only mode of firing, the excess air is
usually in the range of 10-20% is used. I think that the efficiency of the fired
heater is the most critical factor in saving or making money for the process plant.
Fired Heater (FH1):
Inlet temp. = T= 379°C = 714.2°F
Outlet temp. = T2 = 387°C = 728.6°F
Flow rate = 225660 kg/hr = 497048.5 lb/hr
Cp = 0.7 Btu / Ibm.F'
Q = m*cp*(T2 — T1) = 5010248 Btu/hr
Heating value of fuel oil = 19000 Btu/lbm (ref. NELSON)
Consumption of fuel oil = (5010248 / 19000) = 264 lb/hr
104
Chapter 8 Equipment Design
105
Chapter 8 Equipment Design
SPECIFICATION SHEET106
Chapter 8 Equipment Design
107
Chapter 8 Equipment Design
Distillation column (fractionator)
Column design: Designing of a distillation column constitutes the following steps;
• Specify the degree of separation required, set product specifications
• Select operating conditions
• Select type of contacting assembly
• Determine stages and reflux requirements
• Size of column, no. of real stages
• Design of column internals
• Mechanical design, vessel and internals
Plate spacing:
The overall height of the column depends on the plate spacing. Plate spacing
from 0.15 — 1 m (6 -36 in.) are normally used. The spacing chosen depends on
column diam. And operating conditions. Close spacing is used with small
diameter column. For columns above 1m diam., plate spacing of 0.6 m is
normally used .A large plate spacing is needed between certain plate to
accommodate fed and side streams arrangements.
The product fractionators is a vertical column. In operation, feed enters from the
product fractionator feed heater to the flash zone of the column which is typically
several trays above the bottom of the column. The vaporized lighter material
rises up through the column trays and the heavier oil condenses and falls down
the column. Low pressure stripping steam is injected into the column below the
bottom tray to provide additional lift for fractionation and aids in the stripping of
light material from the bottoms product. The bottoms material is removed out
from the bottom of the column for routing to the thermal section of Dieselmax
Unit.
108
Chapter 8 Equipment Design
109
Chapter 8 Equipment Design
Shell and Tube Heat ExchangersEquipment for transferring heat is used in essentially all the process industries.
Modern heat exchangers range from simple concentric-pipe exchangers to
complex surface condensers with thousands of square feet of heating area.
Between these two extremes are found the conventional shell-and-tube
exchangers, coil heaters, bayonet heaters, extended-surface finned exchangers,
plate exchangers, furnaces, and many varieties of other equipment. Exchangers
of the shell-and-tube type are used extensively in industry and are often identified
by their characteristic design features. For example, U-tube, fin-tube, fixed-tube
sheet, and floating-head exchangers are common types of shell-and tube
exchangers.
When designing heat-transfer equipment, it is necessary to consider the basic
process-design variables and also many other factors, such as temperature
strains, thickness of tubes and shell, types of baffles, tube pitch, and standard
tube lengths. Under ordinary conditions, the mechanical design of an exchanger
should meet the requirements of the ASME or API-ASME Safety Codes.
The standard length of tubes in a shell-and-tube heat exchanger is 8, 12, or 16 ft,
and these standard-length tubes are available in a variety of different diameters
and wall thickness.
Tube-wall thickness is usually specified by the Birmingham wire gauge, and
variations from the nominal thickness may be ±10 percent for "average-wall"
tubes and + 22 percent for "minimum-wall" tubes. Pressure, temperature,
corrosion, and allowances for expanding the individual tubes into the tube sheets
must be taken into consideration when the thickness is determined.
110
Chapter 8 Equipment Design
Tube pitch:
The shortest center-to-center distance between adjacent tubes, while the
shortest distance between two tubes is designated as the clearance. In most
shell-and-tube exchangers, the pitch is in the range of 1.25 to 1.50 times the tube
diameter. The clearance should not be less than one-fourth of the tube diameter,
and & in. is usually considered to be a minimum clearance. Tubes are commonly
laid out on a square pattern or on a triangular pattern. Although a square pitch
has the advantage of easier external cleaning, the triangular pitch is sometimes
preferred because it permits the use of more tubes in a given shell diameter.
Shell Size:
For shell diameters up to 24 in., nominal pipe sizes apply to the shell. Inside
diameters are usually indicated, and schedule number or wall thickness should
also be designated. In general, a shell thickness of % in. is used for shell
diameters between 12 and 24 in. unless the fluids are extremely corrosive or the
operating pressure on the shell side exceeds 300 psig.
Thermal Strains: Thermal expansion can occur when materials, such as the
metal components of a heat exchanger, are heated. In a shell-and-tube heat
exchanger, thermal expansion can cause an elongation of both the tube bundle
and the shell as the temperature of the unit is increased. Temperature stresses
due to tube elongation can be avoided by using U-shaped tubes.
Baffles: Although the presence of baffles in the shell side of a shell-and-tube
exchanger increases the pressure drop on the shell side, the advantage of better
mixing of the fluid
111
Chapter 8 Equipment Design
and increased turbulence more than offsets the pressure-drop disadvantage. The
distance between baffles is known as the Baffle spacing. In general, baffle
spacing is not greater than a distance equal to the diameter of the shell or less
than one-fifth of the shell diameter.
112
Chapter 8 Equipment Design
113
Chapter 8 Equipment Design
114
Chapter 8 Equipment Design
115
Chapter 8 Equipment Design
116
Chapter 8 Equipment Design
117
Chapter 8 Equipment Design
118
Chapter 8 Equipment Design
119
Chapter 9 Instrumentation & Control
CHAPTER 9
Plant
Instrumentation
And
Control
120
Chapter 9 Instrumentation & Control
INTRODUCTION
No plant can be operated unless it is adequately instrumented. The monitoring of
flow, pressure, temperature and level is necessary in almost every process in
order that the plant operator can see that all parts of plants are functioning as
required. Additionally it may be necessary to record and display many other
quantities, which are more specific to the particular process in question, e.g., the
composition of process stream, the heat radiation produced or humidity of a gas
stream.
Objectives:
The primary objectives of the designer when specifying instrumentation and
control scheme are:
Safe Plant Operation:
To keep the process variables within known safe operating limit.
To detect dangerous situation as they develop and to provide alarms and
automatic shut down systems.
Production Rate:
To achieve the design product output.
Product Quality:
To maintain the product composition within specified quality standards.
121
Chapter 9 Instrumentation & Control
Hardware Elements of Process Control System:
It represents the material together with equipment, with physical and chemical
operation that occurs.
1. The chemical process:
It represents the material equipment together with the physical or chemical
operations that occur.
2. The measuring instruments or sensors:
Such instruments are used to measure the disturbances, the controlled output
variables or to measure secondary variables, and are the main sources of
information about what is going on in the process. Characteristic examples are:
thermocouples or resistance thermometers, for measuring the
temperature,
Venturi meters, for measuring the flow rate,
gas chromatographs, for measuring the composition of a stream, etc.
Since good measurements are very crucial for good control, the measuring
devices should be rugged and reliable for an industrial environment.
3. Transducers or transmitters:
Many measurements cannot be used for control until they are converted to physical
quantities (like electric voltage or current, or a pneumatic signal, i.e. compressed air
or liquid) which can be transmitted easily. The transducers or transmitters are used
for that purpose. For example, the Strain Gauges are metallic conductors which
change their resistance when subjected to mechanical strain. Thus, they can be
used to convert a pressure signal to an electric one.
122
Chapter 9 Instrumentation & Control
4. Transmission lines:
They are used to carry the measurement signal from the measuring device to the
controller. In the past the transmission lines were pneumatic (compressed air or
compressed liquids) but with the advent of the electronic analog controllers and
especially the expanding usage of digital computers for control, the transmission
lines carry electric signals.
Many times the measurement signal coming out from a measuring device is very
weak, and it cannot be transmitted over a long distance. In such cases the
transmission lines are equipped with amplifiers which raise the level of the signal.
For example, the output of a thermocouple is of the order of a few (milli-volts)
mV. Before it is transmitted to the controller, it is amplified to the level of a few
volts.
5. The controller:
This is the hardware element that has "intelligence". It receives the information
from the measuring devices and decides what action should be taken. The older
controllers were of limited ,"intelligence", could perform very simple operations
and implement simple control laws. Today with the increasing usage of digital
computers as controllers the available machine intelligence has expanded
tremendously, and very complicated control laws can be implemented.
6. The final control element:
This is the hardware element that implements in real life the decision taken by
the controller. For example, if the controller “decides” that the flow rate of the
outlet stream should be increased (or decreased) in order to keep the liquid level
in the tank at, the desired value, it is the valve (on the effluent stream) that will
implement this decision, opening (or closing) by the commanded amount.
123
Chapter 9 Instrumentation & Control
The control valve is the most frequently encountered final control element but not
the only one. Other typical final control elements for a chemical processes are;
Relay switches, providing on-off control
variable speed pumps
variable speed compressors
Instruments and Controllers:
Locally mounted controllers means that the controller and display is located out
on plant near to the sensing instrument location. Main panel controller is in the
control room. Except on small plants, most controllers are mounted in the control
room. All the instruments of the Dieselmax Unit are main panel
mounted.
124
Chapter 9 Instrumentation & Control
Types of instruments:
Property
Measured
First
Letter
Indicating
Only
Recording
Only
Controlling
Only
Indicating
And
Controlling
Recording
And
Controlling
Flow rate F FI FR FC FIC FRC
Level L LI LR LC LIC LRC
Pressure P PI PR PC PIC PRC
Radiation R RI RP RC RIC PRC
Temperature T TI TR TC TIC TRC
Weight W WI WR WC WIC WRC
The first letter indicates the property measured; for example, F=flow,
Subsequent letters indicate the function; for example, I = Indicating
RC= Recording Controlling. The suffixes E and A can be added to indicate
emergency action and/or alarm functions.
Instruments are provided to monitor the key process variables during Plant
operation. They may be incorporated in automatic control loops, or used for the
manual monitoring of the process operation. It is desirable that the process
variable to be monitored be measured directly; Often, however this is impractical
to measure, is monitored in its place. For example , in the control of distillation
columns the continuous online, analysis of the overhead product is desirable but
difficult and expensive, so temperature is often monitored as an indication of
composition. The temperature instrument may from part of a control loop
controlling, say, reflux flow, with the composition of overheads checked
frequently by sampling and laboratory analysis.
125
Chapter 9 Instrumentation & Control
Level Control:
In any equipment where an interface exists between two phases (e.g. Liquid-
vapor), some means of maintaining the interface at the Required level must be
provided. This may be incorporated in the design of the equipment.
Pressure Control:
Pressure control will be necessary for most system handling vapors or gas. This
method of control will depend on nature of the process.
Flow Control:
Flow control is usually associated with inventory control in a storage tank or other
equipment. There must be a reservoir to take up the changes in flow rate.
Distillation Column Control:
The primary objective of distillation column control is to maintain the specified
composition of the top and bottom products, and any side streams; correcting for
the effect of disturbances in,
Feed flow rate, composition and temperature.
Steam supply pressure.
Cooling water pressure and header temperature.
Ambient conditions, which cause change in internal reflux.
126
Chapter 9 Instrumentation & Control
Typical control Systems:
127
Chapter 9 Instrumentation & Control
128
Chapter 9 Instrumentation & Control
129
Chapter 9 Instrumentation & Control
130
Chapter 9 Instrumentation & Control
131
Chapter 9 Instrumentation & Control
132
Chapter 9 Instrumentation & Control
133
Chapter 9 Instrumentation & Control
134
Chapter 9 Instrumentation & Control
135
Chapter 9 Instrumentation & Control
The Use of digital computers in process control:
The rapid technological development of digital computers in the last 10 years,
coupled with significant reduction of cost, had a very pro-found effect on how the
chemical plants are controlled. The expected future improvements along with the
growing sophistication of the control design technique make the digital computer
center piece for the development of a control system for chemical processes.
Already large chemical plants like petroleum refineries, ethylene plants and many
others are under digital control. The effects have been very substantial, leading
to better control and reduced operating costs.
136
Chapter 10 Cost Estimation
CHAPTER 10
Cost
Estimation
137
Chapter 10 Cost Estimation
COST ESTIMATION
In cost analysis of industrial process capital investment costs, manufacturing
costs and general expenses including income taxes are taken into consideration.
Fixed Capital Investment
Manufacturing fixed-capital investment represents the capital necessary for the
installed process equipment with all auxiliaries that are needed for complete
process operation. Expenses for piping, instruments, insulation, foundations, and
site preparation are examples of costs included in the manufacturing fixed-capital
investment.
Working Capital
The working capital for an industrial plant consists of the total amount of money
invested in
Raw materials and supplies carried in stock,
Finished products in stock and semi-finished products in the process of
being manufactured,
accounts receivable,
Cash kept on hand for monthly payment of operating expenses, such as
salaries, wages, and raw-material purchases,
Accounts payable, and
Taxes payable
Types of Capital Cost Estimates
138
Chapter 10 Cost Estimation
An estimate of the capital investment for a process may vary from a pre-design
estimate based on little information except the size of the proposed project to a
detailed estimate prepared from complete drawings and specifications. Between
these two
extremes of capital-investment estimates, there can be numerous other
estimates which vary in accuracy depending upon the stage of development of
the project. We used here, “Study estimate (factored estimate)” based on
knowledge of major items of equipment; probable accuracy of estimate up to ±30
percent.
Methods for estimating capital investment
Various methods can be employed for estimating capital investment. The choice
of any one method depends upon the amount of detailed information available
and the accuracy desired. There are about seven methods, we used here,
“Percentage of Delivered Equipment Cost”.
This method for estimating the fixed or total-capital investment requires
determination of the delivered-equipment cost. The other items included in the
total direct plant cost are then estimated as percentages of the delivered-
equipment cost. The additional components of the capital investment are based
on average percentages of the total direct plant cost, total direct and indirect
plant costs, or total capital investment.
Estimating by percentage of delivered-equipment cost is commonly used for
preliminary and study estimates. It yields most accurate results when applied to
projects similar in configuration to recently constructed plants.
139
Chapter 10 Cost Estimation
Estimation of purchased equipment cost
The purchased equipment cost of the unit is calculated by using graphs and table
given in “Plant design and Economics for Chemical Engineers” by Peters and
Timmerhaus.
The base index for these graphs and tables 924 in January 1990 (Marshall and
Swift installed equipment index). So to bring the values up to date, we used the
cost index for
Dec. 2007, i.e. 1362.2. These prices can be used for preliminary design
estimates; firm estimates should be based on manufacturer’s quotations.
The formula by which the present cost of the equipment from previous cost can
be determined as follows;
Cost indexes is used to give a general estimate, but no index can take into account all factors, such as special technological advancements or local conditions.
140
Chapter 10 Cost Estimation
Purchased Equipment Cost:
Back wash Filters, F1
From Timmerhaus, p-554, 4th ed., Fig. 14-62,
Assume, Filter area = 50 ft2, for “filter unit, mild steel”;
The purchased cost = 65000 dollars (Jan. 1990)
The present value = 109261 dollars
Feed surge drum, D1
From Timmerhaus, p-539, 4th ed., Fig. 14-56,
Because feed flow rate = 30000 BPSD;
i.e. 1.26E+06 gal/day or 52500 gal/hr
Assume 50000 gal/hr, also, for 304 stainless steel storage tank,
Purchased cost = 70000 dollars (Jan. 1990)
Present value = 117666 dollars
Back wash surge drum, D2
Assume, storage tank carbon steel,
Assume capacity = 50000 gal/hr
The purchased cost = 45000 dollars ( Jan. 1990)
Now, the present value = 75643 dollars
Centrifugal Pump, P1
From Timmerhaus, p-527, Fig. 14-41;
Because the volumetric flow rate = 2.264 ft3/sec
141
Chapter 10 Cost Estimation
On x-axis, there should be (gal*PSI) = capacity factor;
=
1470000;
For, API-610, Cast steel casing up to 150 PSI, horizontal;
Purchased cost = 100000 dollars; (Jan. 1990);
The present value = 168095 dollars
Centrifugal pump, P2
Capacity factor = 151000;
From same graph as used for P1;
Purchased cost = 15000 dollars (Jan. 1990)
The present cost = 25214 dollars
Centrifugal pump, P3
Capacity factor = 37000;
From same graph as used for P1;
Purchased cost = 7600 dollars (Jan. 1990)
The present cost = 12775 dollars
142
Chapter 10 Cost Estimation
Centrifugal pump, P4
Capacity factor = 34160;
From same graph as used for P1;
Purchased cost = 6500 dollars (Jan. 1990)
The present cost = 10926 dollars
Centrifugal pump, P5
Capacity factor = 51400;
From same graph as used for P1;
Purchased cost = 9000 dollars (Jan. 1990)
The present cost = 15128 dollars
Heat exchangers:
E1
From Timmerhaus, p-616, Fig. 15-13,
The purchased cost = 6000 dollars (Jan. 1990)
The present value = 10085 dollars
From same fig. we found the cost of E2 is same as that for E1.
For E3, the purchased cost = 10000 dollars (Jan. 1990)
The present value for E3 = 16809 dollars
143
Chapter 10 Cost Estimation
For E4, the purchased cost = 5000 dollars (Jan. 1990)
The present value for E4 = 8404 dollars
For E5, the purchased cost = 4000 dollars (Jan. 1990)
The present value for E5 = 6723 dollars
For E6, the purchased cost = 4300 dollars (Jan. 1990)
The present value for E6 = 7228 dollars
Compressor Cost, C1
From Timmerhaus, Fig. 14-48;
Because centrifugal turbine driven, Assume brake horsepower = 1000
The purchased cost = 400000 dollars (Jan. 1990)
The present value = 672380 dollars
Air cooled Exchanger, AE1
From Timmerhaus, Fig. 15-18, p-618;
Assume, bare tube surface area = 102 ft2 , for 8 tube rows,
The purchased cost = 15000 dollars (Jan. 1990)
The present value = 25214 dollars
144
Chapter 10 Cost Estimation
Air cooled Exchanger, AE2
Assume for 12 tube rows;
The purchased cost = 10000 dollars (Jan. 1990)
The present value = 16809 dollars
Fired Heaters;
FH 1;
From Timmerhaus, p-625, Fig. 15-30;
Heat duty for fired heater (FH1) = 6E+06 Btu/hr
Assume for Carbon steel tubes, 500 PSI,
The purchased cost = 80000 dollars (Jan. 1900)
The present value = 134476 dollars
FH2;
Because its heat duty = 8E+06 Btu/hr
The purchased cost = 90000 dollars (Jan. 1990)
The present cost = 151285 dollars
FH3;
Because its heat duty is = 55.59 E+06 Btu/hr
The purchased cost = 700000 dollars (Jan. 1990)
145
Chapter 10 Cost Estimation
The present worth = 1176666 dollars
Reactor, R1;
Assume for packed towers; Fig. 16-28;
The purchased cost = 100000 dollars (Jan. 1990)
The present value = 168095 dollars
R2;
For 152 in. diameter, and for sieve tray towers;
The purchased cost = 349000 dollars (Jan. 1990)
The present cost = 586652 dollars
R4;
Assume diameter = 140 in.
And for sieve tray tower;
The purchased cost = 196000 dollars (Jan. 1990)
The present cost = 329466 dollars
Recycle gas scrubber, S1;
Because diameter = 8 ft;
Height of tower = 23 m
For sieve tray tower,
146
Chapter 10 Cost Estimation
The purchased cost = 370000 dollars (Jan. 1990)
The present cost = 621952 dollars
Stripper, S2;
Because the diameter of the stripper = 0.942 m = 37 in.
For sieve tray towers;
The purchased cost = 14700 dollars (Jan. 1990)
The present cost = 24710 dollars
S4;
Because the diameter = 0.602 m = 23.7 in.
Height = 1.37 m = 4.49 ft
The purchased cost = 4041 dollars (Jan. 1990)
The present cost = 6792 dollars
Reboiler kerosene stripper, S3;
The purchased cost = 6000 dollars (Jan. 1990)
The present cost = 15128 dollars
K.O. Drums, D3;
From Fig. 14-56;
Assume 10000 gallons, 304 stainless steel,
147
Chapter 10 Cost Estimation
The purchased cost = 30000 dollars (Jan. 1990)
The present cost = 50428 dollars
K.O. Drums, D4;
From Fig. 14-56;
Assume 10000 gallons, 304 stainless steel,
The purchased cost = 30000 dollars (Jan. 1990)
The present cost = 50428 dollars
Separator,T1
Separator cost = 42000 dollars (Jan. 1990)
The present value of the separator = 70600 dollars
Three receiver; T2, T3, T4
Receiver cost = 84000 dollars (Jan. 1990)
The present value = 141200 dollars
There are three receivers in our unit.
Reaction Chamber, R3
From fig. 14-56, Assume 30 PSIg carbon steel tank,
Assume the capacity = 100 gal;
The purchased cost = 4000 dollars (Jan. 1990)
148
Chapter 10 Cost Estimation
The present cost = 6723 dollars Purchased Equipment Cost
Unit 2009 Cost in Dollar
Feed surge drum
Back wash filter
Back wash surge drum
Pump, P1
Pump, P2
Pump, P3
Pump, P4
Pump, P5
Exchanger, E1
Exchanger, E2
Exchanger, E3
Exchanger, E4
Exchanger, E5
Exchanger, E6
109261
117666
75643
168095
25214
12775
10926
15128
10085
16809
16809
8404
6723
7228
Centrifugal Compressor, C1
Air cooled exchanger, AC1
Air cooled exchanger, AC2
Fired heater, FH1
Fired heater, FH2
672380
25214
16809
134476
151285
149
Chapter 10 Cost Estimation
Fired heater, FH3
Reactor, R1
Reactor, R2
Reactor, R4
Scrubber, S1
Stripper, S2
Diesel stripper, S4
Kerosene stripper, S3
K.O.Drum, D3
K.O.Drum, D4
Separator, T1
Receivers, T2, T3, T4
Reaction chamber, R3
1176666
168095
586652
329466
621952
24710
6792
15128
50428
50428
70600
141200 (each)
6723
150
Chapter 10 Cost Estimation
Capital Investment Estimation:
(Based on Delivered Equipment Cost)
Direct Cost, D
Item Percent of delivered Equipment Cost
Cost (dollars)
Purchased Equipment delivered Cost
Purchased equipment installation
Instrumentation Control
Piping (installed)
Electrical (installed)
Building (including Services)
Yard improvements
Service Facilities
Land
100
48
18
66
11
18
10
70
6
4505100
2162448
810918
2973366
495561
810918
450510
3153570
270306
Total Direct Plant Cost 15632700
Indirect Cost, I
Engineering Supervision 32 1441632
151
Chapter 10 Cost Estimation
Construction Expenses 40 1802040
152
Chapter 10 Cost Estimation
Total direct & indirect Cost = (D+I) = 18876370 dollars
Contraction Fee 5% 0f (D+I) 943818
Contingency 10% of (D+I) 1887637
Fixed Capital Investment = 21707830 dollars
Working Capital = 15% of total Capital investment
OR = 85% of Purchased equipment cost
= 3829335 dollars
Total Capital Investment = Fixed Capital Investment + Working Capital
= 25537165 dollars
= 25.5 million dollars
153
Chapter 11 Material Selection
CHAPTER 11
Material
Selection
154
Chapter 11 Material Selection
MATERIAL SELECTION
Many factors have to be considered when selecting engineering materials, but for
chemical process plant, much consideration is usually given for the ability to
resist corrosion. Material selected should be suitable for the process conditions
i.e. the material selected must have sufficient strength and be easily worked; it
should give lowest cost over the working life of the plant, allowing for
maintenance and replacement.
Procedure for selection of materials
1. Preliminary Selection
It is done by experience, manufacturer’s data, relevant literature, availability,
safety aspects and preliminary laboratory test.
2. Laboratory Testing
It is the re-evaluation of apparently suitable materials under process conditions. In
laboratory tests, a study of the effect of excess temperature, excess pressure,
agitation, presence of possible impurities other factors are tested.
3. Economic and Final Selection
The cost of material to be selected and the maintenance cost effect the final
selection of material.
Material Properties
1. Mechanical Properties
155
Chapter 11 Material Selection
Strength – tensile strength
Stiffness – Elastic Modulus
Toughness – Fracture resistance
Hardness – wear resistance
Fatigue resistance
Creep resistance
2. The effect of high and low temperatures
3. Corrosion resistance
4. Any special properties required; such as, thermal conductivity, electrical
resistance magnetic properties
5. Ease of fabrication forming, welding, casting.
6. Availability in standard sizes – plate sections, tubes.
7. Cost
Effect of Temperature on the Mechanical Properties:
The tensile strength and elastic modulus of metals decreases with increasing
temperature. For example, the tensile strength of mild steel (low carbon steel, C
< 0.25 percent) is 450 N/mm2 at 25°C falling to 21 N/mm2 at 500°C and the value
of Yong's modulus 200,000 N/mm2 at 25°C falling to 150,000 N/mm2 at 500°C. If
equipment is being designed to operate at high temperatures, materials that
retain their strength must be selected. The stainless steel is superior in this
respect to plain carbon steel.
Creep resistance will he important if material is subjected to high stresses at
elevated temperatures.
Corrosion Resistance:
The conditions that cause corrosion can arise in variety of ways. The selection of
materials is convenient to classify corrosion into the following categories:
156
Chapter 11 Material Selection
1. General wastage of material - uniform corrosion.
2. Galvanic corrosion - dissimilar metal in contact.
3. Pitting – Localized attack.
4. Inter-granular corrosion.
5. Stress corrosion.
6. Erosion - corrosion.
7. Corrosion fatigue.
8. High temperature oxidation.
9. Hydrogen embrittlement.
Metallic corrosion is essentially an electrochemical process. Four components
are necessary to set up an electrochemical cell.
1. Anode - the corroding electrode.
2. Cathode - the passive, non-corroding electrode.
3. The conducting medium - the electrolyte - corroding fluid.
4. Completion of the electrical circuit - through the material.
Cathodic areas can arise in many ways:
Dissimilar metals.
Corrosion products.
Inclusion in the metal, such as slag.
Less well aerated areas.
Areas of differential concentration.
Differentially strained area.
Commonly Used Material of Construction:
Materials of construction may be divided into the two general classifications of
metals and non-metals. Pure metals and alloys are included under the first
classification.
157
Chapter 11 Material Selection
Metals:
Iron and steel
Stainless steel
Mild Steel
Cast Iron
Hastelloy
Copper and its alloys
Copper and its alloys
Nickel and its alloys
Aluminium
Silver
Lead (Amphoteric)
Non Metals:
Glass and Glassed steel
Carbon and Graphite
Stoneware and porcelain
Rubber and elastomers
Plastics
Wood
158
Chapter 11 Material Selection
Metals:
Material Properties
Iron and Steel - Easily available- Low cost of fabrication- Good Tensile strength and ductility- Non corrosion resistant- Used in non-corrosive atmosphere i.e.
reactors, vessels
Stainless Steel- Corrosion resistant material- Expensive- Heat and temperature resistant- Available in different types with respect to
their micro structure
Mild Steel - Low carbon steel- Most common engineering material- Available in large range of standard forms.- It can be easily worked and moulded- It has good tensile strength and ductility
Cast Iron - High carbon - iron alloy containing silicon - Least expensive of engineering material. - Can be readily cast with intricate shapes.
Hastelloy - It is an alloy of nickel, molybdenum, and chromium.
- Highly corrosion resistant material. - Expensive. - Used in valves, piping exchangers, vessels.
Nickel and its alloys - High corrosion resistance particularly to alkalis.
- Good mechanical strength and hard as carbon steel.
- Monel (Nickel alloy) is used in the food indust
Aluminium - Light metal. - Easy fabrication. - Resists attack of acid due to surface film of
inert hydrated aluminium oxide.
159
Chapter 11 Material Selection
Silver - Low mechanical strength. - High cost. - Used in the form of lining. - Resistant to alkalis and organic acids.
Lead - Amphoteric in nature. - Low creep. - Fatigue resistant.
- Used as coating.
Non-Metals:
Glass and Glassed Steel - Borosilicate glass (pyrex) is good resistant to thermal and chemical attack
- Used in laboratory equipment - Glassed steel is strongly resistant to
corrosive acid
Carbon and Graphite - Inert to oxidising conditions. - Good heat transfer medium. - Threshold oxidation temp is 400°C for
graphite. - Used in pipes pumps heat exchangers, as
brick.
Stoneware and porcelain - Used as coating. - Poor thermal conductivity. - Low tensile strength
Brick and Cement material
- Brick lined construction is used for corrosive conditions.
- Cement materials are used with brick. - Acid proof refractories can be used up to
900°C. - Sulphur based cements are limited up to
95°C. - Resins can be used to about 175°C.
Rubber and Elastomers - Used as linings or structural components. - Natural rubber is resistant to mineral acids,
alkalies and salts. - Oxidizing media, oil, benzene and ketones
will attack it.
160
Chapter 11 Material Selection
Plastics - These are light in weight and have low friction factor.
- Good thermal and electrical insulators. - Easy to fabricate.
- Examples are Teflon, polyethene, butadiene, PVC.
About Materials of Construction used:
1. Stainless Steel:
There are many different types of stainless steels. These materials are high
chromium or high nickel-chromium alloys of iron containing small amounts of
other essential constituents. The most common stainless steels, such as type
303 or type 304, contain approximately 18% chromium and 80% nickel, and are
designated as 18-8 stainless steels.
The addition of molybdenum to the alloy, as in type 316, increases the corrosion
resistance and high temperature strength. If nickel is not included, the low
temperature brittleness of the material is increased and the ductility and pit type
corrosion resistance are reduced. The presence of chromium in the alloy gives
resistance to oxidizing agents. Thus, type 430 which contains chromium but no
nickel or molybdenum, exhibits excellent corrosion resistance to nitric acid and
other oxidizing agents.
Although fabricating operation on stainless steels are more difficult than on
standard carbon steels, all types of stainless steels can be fabricated
successfully. The properties of the type 430 F, 416, 410, 310, 309, and 303 make
these materials particularly well suited for machining or other fabricating
operations. In general machine-ability is improved if small quantities of
phosphorus, selenium or sulfur is present in the alloy.
161
Chapter 11 Material Selection
The type of stainless steel included in the 300 series are harden-able only by
cold working; those included in 400 series are either non harden-able or harden-
able by heat-treating. As an example, type 410, containing 12% chromium and
no nickel, can be heat treated for hardening and has good mechanical properties
when heat-treated.
Carbon Steel:
Carbon steel is the most common cheapest and most versatile metal used in
industry. It has excellent ductility permitting many cool-forming operations. It is
easy to fabricate and is resistant to corrosion. The low carbon steel has a carbon
content of 0.2% and other elements present are manganese 0.5% to 0.8%. Their
tensile strength varies from 40000 to 70000 Ib/in2. Medium carbon steel has a
carbon content of 0.2 to 0.5%, phosphorus 0.5% maximum. Their tensile strength
varies from 65000 to 105000 lb/in. High carbon steel has a carbon content of
more than 0.5%. And also contains manganese 0.5 to 1.0%, silicon 0.2% to 0.7%
and phosphorus & sulfur 0.05% maximum. Fully annealed high carbons steel
exhibit a tensile strength of 95000 to 125000 Ib/in2.
A small increase in the carbon content of a steel even as little as a tenth of a 1%
has a strong effect on all the properties of steel. If the carbon content is
increased there are some of the effects.
The melting point of the steel is lowered
The steel becomes harder The steel has a higher tensile strength. The steel is less ductile. The steel becomes more wear resistant. The steel becomes less easily machined. The steel is more difficult to weld without cracking. The steel becomes heat treatable. The steel is more expensive due to small volume of production.
162
Chapter 11 Material Selection
The higher carbon steel however will have higher yield stress, higher tensile
strength and less elongation at rupture, carbon has a powerful effect on the
melting point of steels. A pure iron melts at 1537oC increasing carbon residues
the melting point until at 4.3% carbon the melting point falls at 1129.4oC, the high
melting pint of pure iron makes severe demand on the refractory lining of steel
melting furnaces and is one reason why pure iron is not in common use.
Carbon above 0.8% gives increased wear resistant of the steel and is necessary in
such tools as files, knives, wood cutting tools and facing welding electrodes.
If steel is cooled to room temperature the carbon is found to be combined with
iron as iron carbide (Fe3C) distributed through the steel. If a hard or wear
resistant steel is required, this is obtained by high carbon content to increase the
amount of hard ceramic carbide.
Other different materials, which are used in chemical process industry for the
construction of different equipments, pipes, burners, storage tanks, reactors,
vessels etc. are as under:
Iron and steel although many materials have greater corrosion resistance than iron
and steel, cost aspects favor the use of iron and steel. They are often used as a
material of construction when it is known that some corrosion will occur.
Hastelloy (alloy formed by the combination of nickel 56%, chromium 16%,
molybdenum 17%, iron 5%, tungsten 4%) is used as a construction of equipment
for which the structure strength and good corrosion resistance are necessary
under condition of high temperature.
Copper and its alloys they are relatively less expensive, possess fair mechanical
strength, and can be fabricated easily into a wide variety of shapes.
Killed Carbon Steel:163
Chapter 11 Material Selection
Mechanical properties of steel are largely dependent upon the amount and form
of oxygen & suffer in the steel. In killed steels, with low oxygen content, such as
when aluminium is used for deoxidation and grain size control, suffer combines
with manganese as highly deformable manganese sulfides. These manganese
sulfides have low M.P and as the last liquid to solidify in the steel, collect as films
at grain boundaries. During hot rolling, the manganese sulfides are plastically
deformed into elongated stringers extending parallel to the rolling direction. This
shape and distribution of sulfides can have a marked effect on the directional
properties of steel.
164
Chapter 11 Material Selection
Materials Selected for the Equipment of DIESELMAX Unit:
Sr. No. Equipment Material of Construction
1 Feed surge drum Carbon steel.
2 Reactor 11/4 Cr - 1/2 Mo base metal. The material of
construction of all internals is to be austenitic
stainless steel.
3 Separator Killed carbon steel.
4 Stripper Killed carbon steel trays constructed of
austenitic steel.
5 Receivers Killed carbon steel.
6 Fractionator Killed carbon steel
7 Kerosene stripper Carbon steel.
8 Diesel Stripper Carbon steel
9 Heat exchangers Austenitic stainless steel materials used in the
hottest heat exchangers, especially (E1,2) and its
associated piping
165
Chapter 12 Environmental Health & Safety Consideration
CHAPTER 13
Environment
Health
And
Safety Considerations
166
Chapter 12 Environmental Health & Safety Consideration
INTRODUCTION
Industrial environment is very hazardous by its nature. Advancement of technology has
brought various new hazards. The challenge we have to face in industry is to eliminate
hazard, as to know where and what the hazards are, and how to handle them, to help us to
meet the challenge
Name of Material
Maximum
Concentration
(ppm)
otherwise stated
Ammonia 100
Carbon Disulphide 10
Carbon monoxide 100
Chlorine 1
Gasoline 500
Hydrogen chloride 10
Hydrogen sulfide 20
Methanol 200
Chloro Benzene 75
Nitro Benzene 1
Sulphur Dioxide 5
Phosphine 0.5
167
Chapter 12 Environmental Health & Safety Consideration
Toluene 100
Coal Tar
Naphthalene
200
All manufacturing processes are, to some extent hazardous but in chemical
processes there are additional hazards associate with chemicals used the
process conditions. If healthy hazards are to be controlled, they must be
recognized and evaluated. Other materials such as catalysts, additives, cleaning
agents and maintenance materials need to be identified to complete the
inventory. Every attempt should be made to corporate facilities for health and
safety protection of plant personnel in the original design. This includes but is not
limited to, protected walkways, platforms, stairs and work areas. Physical
hazards if unavoidable must be clearly defined. All machinery must be guarded
with protective devices. In all cases medical services and first-aid must be readily
available for all workers.
In this project only the particular hazards associated with Dieselmax process will
be considered.
The Hazards
Toxicity:
The most common and most significant source of workplace exposure to
chemicals and also the most difficult to control is inhalation. Workers become
exposed when the contaminant is picked up by the air they breathe.
A highly toxic material that causes immediate injury such as phosgene or
chlorine would be classified as safety hazard. Whereas a materials, such as vinyl
chloride, would be classified as industrial health and hygiene hazards. The most
toxic gas produced by the hydro cracking reactions due to presence of sulfur in
the VGO feedstock.
168
Chapter 12 Environmental Health & Safety Consideration
Hydrogen Sulfide
H2S is a colorless gas slightly heavier than air (it accumulates in low spots). It is
highly flammable and a dangerous five risk. Hydrogen sulfide is an explosive gas
which will explode in concentration of 4.3% (3.4% at 1500C) to 45% by volume in
air, H2S is easily identified in very low, non fatal concentrations (0.13 ppm) by the
strong
pungent odor of rotten eggs. However, since H2S deadens the sense of smell, its
odor cannot be considered as a warning of its presence in lethal concentrations.
Precautions
H2S monitors have been provided to detect H2S leaks in particular areas of
moderate to high concentrations. Working in any concentration of H2S is not
desirable. Some other are gases encountered during operation and
maintenance.
N2 is an inert gas used for purging equipment or maintaining a positive pressure
inert gas blanket or a vessel.
N2 is neither poisonous nor flammable, but care must be exercised when working
inside equipment that has been N2 purged. Adequate ventilation must be
provided and appropriate breathing devices worn. Rapid vaporization of liquid
nitrogen can cause severe burns on contact with the skin.
Ammonia
Ammonia is a colorless gas with extremely pungent odor, may cause varying
degrees of irritation to the eyes, skin or mucous membranes.
Ammonia exposure for short term and under 100 ppm has caused nose and
throat irritation. Over 500ppm exposure for 30 minutes has caused upper
respiratory irritation, tearing, increased pulse rate and blood pressure. High level
169
Chapter 12 Environmental Health & Safety Consideration
exposures can cause long term respiratory problems and or death. Where
ammonia concentrations exist in concentrations above standard, respiratory, eye
and skin protection should be provided.
Safety Demonstration:
Fire:
A combustible chemical reaction between oxygen and any other element
accompanied by the evolution of heat, light and flame is called fire. The element,
which takes part in the combustible reaction, is termed as a fuel and the
temperature at which this reaction proceeds is known as ignition temperature and
it is different for different substances.
Hence for a fire to start there are three prerequisites:
fuel
oxygen
Ignition temperature.
Given below are some characteristics relevant to fire hazards of some combustible
material i.e. gases, liquids, and solids.
Combustible
Material / fuel
Relative Density
(Water=1)
Relative Vapor Density
(Air=1)
Flash Point (0C)
Ignition Temp. (0C)
Methane - 0.554 -180 540
Hydrogen - 0.100 -250 560
170
Chapter 12 Environmental Health & Safety Consideration
Acetylene - 0.90 -84 305
Propane 0.5 1.6 -42 465
Acetone 0.8 2.0 -19 465
Diethyl ether 0.7 2.6 -45 170
Petrol 0.7-0.8 4.0 <20 220
Kerosene oil 0.8-0.9 - 40 220-300
Explosion:
A violent and rapid increase in pressure in a confined space, which may occur as a
result of physical or chemical reaction. The substance that undergoes a rapid
chemical change with the production of gas on being heated or being struck is
called explosive.
Physical explosion:
An explosion that occurs as a result of a physical change i.e. compression or
heating is known as physical explosion.
Chemical explosion:
A chemical explosion is that which occurs as a result of pressure increase caused
by the energy released during a chemical reaction. Chemical explosion may also
occur as result of release of internal energy during an uncontrolled nuclear reaction.
When a piece of metal is put in water, it react violently producing sodium hydroxide
and hydrogen. The temperature rises so high that the hydrogen produced bursts
into flame and explosive occurs.
On next page, there are explosion limits and explosive ranges of some explosive fuels.
171
Chapter 12 Environmental Health & Safety Consideration
Fuel
Lower Explosion
Limit in Vol. %
LEL
Upper Explosion
Limit in Vol. %
UEL
Explosive
Range in
Vol. %
Carbon
monoxide
12.5 74 61.5
Methane 5 15 10
Hydrogen 4 74 70
Acetylene 2 81 79
Propane 2.5 9.5 7
Acetone 2.6 12.8 10.2
Diethyl ether 1.7 36 34.3
Petrol 1 8 7
Methanol 6 36 30
Ethanol 3 19 16
Benzene 1.2 8 6.8
Xylene 1 6 5
Carbon
disulphide
1 60 59
Safety Helmet:
172
Chapter 12 Environmental Health & Safety Consideration
Purpose:
It is used for protection against head injury. Its useful life is affected by heat, cold,
chemical and sunlight. Helmet provides limited protection, it reduce the effect of
force of falling object.
Safety Shoes:
Purpose:
It protects feet from injury.
Oil , acid and alkali resistant.
anti slip PVC sole.
The steel toe caps impact resistant up to 200 joules are fitted with rubber
protection strips, which eliminate pressure across your toes.
Ear Protection:
Purpose:
It is used for the protection against high noise level. It is designed to reduce the effect
of high noises found typically in factories and plants. It protects the eardrums by
means of a plastic shell insulated with urethane cushioned with a soft vinyl seal. It
reduces the noise level up to 30dB in the frequency range from 125-8000 Hz.
Ear Plugs:
Noise reduction 22 dB.
Ear plug should be regularly inspected and always protect the plug from dirt,
grease etc.
Safety Goggles:173
Chapter 12 Environmental Health & Safety Consideration
Have impact resistant lenses and strong frames to protect from flying particles,
encountered like chips, or sparks of high inertial energy at work with machines or
during transport.
Lens is also resistant to chemical attack.
Lens can absorb 99.9% of UV radiation.
Face Shields:
Give full face protection against sparks, splashes and splatter. They provide
secondary protection and must be worn with protective glasses or goggles.
Splash Goggles:
Designed to provide a shield around the entire eye area, to protect against
hazard from many directions.
Eye Washer Shower:
The combined eye and face wash fountain and shower are used for washing
eyes, face and body at the same time. Its use make it an essential first aid
facility.
174
Chapter 12 Environmental Health & Safety Consideration
175
References
176
References
177