Project

Chapter 1 Introduction

CHAPTER 01

Background

And

Introduction

1


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


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


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


5


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


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


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


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


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


REFINERY PROCESS FLOW CHART

12


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


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


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


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


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


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


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


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


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


23


Postulated Paraffin-Cracking Mechanism

24


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


Postulated Cracking-Mechanism for Naphthenes

2Postulated Aromatic Dealkylation Mechanism

26


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


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


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


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


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


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


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


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


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


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

http://en.wikipedia.org/wiki/Oil_refinery

http://en.wikipedia.org/wiki/Continuous_distillation#Continuous_distillation_of_crude_oil

http://en.wikipedia.org/wiki/Catalyst

http://en.wikipedia.org/wiki/Molecules

http://en.wikipedia.org/wiki/Vaporization

http://en.wikipedia.org/wiki/Molecular_weight

http://en.wikipedia.org/wiki/Atmospheric_pressure

http://en.wikipedia.org/wiki/Boiling_point

http://en.wikipedia.org/wiki/Feedstock

http://en.wikipedia.org/wiki/Octane_rating

http://en.wikipedia.org/wiki/Thermal_cracking

http://en.wikipedia.org/wiki/Olefin

http://en.wikipedia.org/wiki/Gasoline

http://en.wikipedia.org/wiki/Crude_oil

http://en.wikipedia.org/wiki/Petroleum

http://en.wikipedia.org/wiki/Hydrocarbon


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

http://en.wikipedia.org/wiki/Density

http://en.wikipedia.org/wiki/Litre

http://en.wikipedia.org/wiki/Barrel_(unit)

http://en.wikipedia.org/wiki/United_States

http://en.wikipedia.org/wiki/Fuel_oil


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


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


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


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


World Oil Consumption by Sector showing Projected Demand

Growth (2003-2030)

Petroleum Product outlook for Pakistan

43


44

Chapter 5 Process Description

CHAPTER 05

Process

Description

45


TAGGING OF PLANT EQUIPTMENTS

46


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


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


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


50


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


fractionator (R2) top section. The net liquid product, un-stabilized naphtha, is

sent to treating unit.

CATALYTIC FRACTIONATING SECTION

52


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


54

Chapter 6 Material Balance

CHAPTER 06

Material

Balance

55


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


= 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


58


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


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


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


62


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


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


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


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


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


= 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


= 248524 (0.8) (757.4 - 707)

= 10E+06 Btu/hr

Therefore,


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


Q = m*Cp*ΔT

= 497048 (0.6) (716 - 500)

= 64417480 Btu/hr

Therefore,


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


Heat loss:

Q = m*Cp*ΔT

= 66079.3 (0.4) (140 - 105.8)

= 903964.8 Btu/hr

Therefore,


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


Heat loss

Q = m*Cp*ΔT

= 99118.9 (0.7)(442.4 – 349.4)

= 4365522 Btu/hr

Therefore,


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


T2 = 397.40F

Heat loss

Q = m*Cp*ΔT

= 88105 (0.6)(554 – 397.4)

= 8278414 Btu/hr

Therefore,


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


= 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


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


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


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


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


= 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


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


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


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


= 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


Cp = 0.7 Btu/lb0F

T1 = 656.60F

T2 = 770F

Q = m*Cp*ΔT

This implies,

Q = 26809692 Btu/hr

85


CHAPTER 08

Equipment

Design

86


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


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


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


90


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


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


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


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


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


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


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


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


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


100


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


102


103


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


105


SPECIFICATION SHEET106


107


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


109


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


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


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


113


114


115


116


117


118


119

Chapter 9 Instrumentation & Control

CHAPTER 9

Plant

Instrumentation

And

Control

120


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


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


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


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


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


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


Typical control Systems:

127


128


129


130


131


132


133


134


135


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


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


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


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


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


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);


Centrifugal pump, P2

Capacity factor = 151000;

From same graph as used for P1;


The present cost = 25214 dollars






142












Heat exchangers:

E1

From Timmerhaus, p-616, Fig. 15-13,



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








Compressor Cost, C1

From Timmerhaus, Fig. 14-48;

Because centrifugal turbine driven, Assume brake horsepower = 1000



Air cooled Exchanger, AE1

From Timmerhaus, Fig. 15-18, p-618;

Assume, bare tube surface area = 102 ft2 , for 8 tube rows,



144


Air cooled Exchanger, AE2

Assume for 12 tube rows;



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,



FH2;

Because its heat duty = 8E+06 Btu/hr



FH3;

Because its heat duty is = 55.59 E+06 Btu/hr


145


The present worth = 1176666 dollars

Reactor, R1;

Assume for packed towers; Fig. 16-28;



R2;

For 152 in. diameter, and for sieve tray towers;



R4;

Assume diameter = 140 in.

And for sieve tray tower;



Recycle gas scrubber, S1;

Because diameter = 8 ft;

Height of tower = 23 m

For sieve tray tower,

146




Stripper, S2;

Because the diameter of the stripper = 0.942 m = 37 in.

For sieve tray towers;



S4;

Because the diameter = 0.602 m = 23.7 in.

Height = 1.37 m = 4.49 ft



Reboiler kerosene stripper, S3;



K.O. Drums, D3;

From Fig. 14-56;

Assume 10000 gallons, 304 stainless steel,

147




K.O. Drums, D4;

From Fig. 14-56;

Assume 10000 gallons, 304 stainless steel,



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)


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;


148


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


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


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


Construction Expenses 40 1802040

152


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


175

References

176

References

177

Project

Documents

heavy oils

ppm crude oil

original crude oil

inspection of crude

heavy fuel oil components

variety of crude oils

oil source

sulfur fuel oil