PRP UNIT - 2

UNIT 2: PRP by M.AHAZAM KHAN @ AHCET[Type text] Page 1

UNIT – 2: THE CHEMICAL CONSTITUENTS OF CRUDE OIL

Hundreds of different crude oils (usually identified by geographic origin) are processed, in

greater or lesser volumes, in the world’s refineries.

Each crude oil is unique and is a complex mixture of thousands of compounds. Most of the

compounds in crude oil are hydrocarbons (organic compounds composed of carbon and

hydrogen atoms). Other compounds in crude oil contain not only carbon and hydrogen, but

also small (but important) amounts of other (“hetero”-) elements –most notably sulfur, as

well as nitrogen and certain metals (e.g., nickel, vanadium, etc.). The compounds that make

up crude oil range from the smallest and simplest hydrocarbon molecule – CH4 (methane) –

to large, complex molecules containing up to 50 or more carbon atoms (as well hydrogen and

hetero-elements).

The physical and chemical properties of any given hydrocarbon species, or molecule,

depends not only on the number of carbon atoms in the molecule but also the nature of the

chemical bonds between them. Carbon atoms readily bond with one another (and with

hydrogen and hetero-atoms) in various ways – single bonds, double bonds, and triple bonds –

to form different classes of hydrocarbons.

Paraffins, aromatics, and naphthenesare natural constituents of crude oil, and are produced in

various refining operations as well. Olefins usually are not present in crude oil; they are

produced in certain refining operations that are dedicated mainly to gasoline production. As

Exhibit 1 indicates, aromatic compounds have higher carbon-to-hydrogen (C/H) ratios than

naphthenes, which in turn have higher C/H ratios than paraffins.

The heavier (more dense) the crude oil, the higher its C/H ratio. Due to the chemistry of oil

refining, the higher the C/H ratio of a crude oil, the more intense and costly the refinery

processing required to produce given volumes of gasoline and distillate fuels. Thus, the

chemical composition of a crude oil and its various boiling range fractions influence refinery

investment requirements and refinery energy use, the two largest components of total refining

cost The proportions of the various hydrocarbon classes, their carbon number distribution,

and the concentration of hetero-elements in a given crude oil determine the yields and

qualities of the refined products that a refinery can produce from that crude, and hence the


economic value of the crude. Different crude oils require different refinery facilities and

operations to maximize the value of the product slates that they yield.

Characterizing Crude Oils

Assessing the refining value of a crude oil requires afull description of the crude oil and its

components, involving scores of properties. However, two properties are especially useful for

quickly classifying and comparing crude oils: API gravity (a measure of density) and sulfur

content

API Gravity (Density)

The density of a crude oil indicates how light or heavy it is, as a whole. Lighter crudes

contain higher proportions of small molecules, which the refinery can process into gasoline,

jet fuel, and diesel (for which demand is growing). Heavier crudes contain higher proportions

of large molecules, which the refinery can either (1) use in heavy industrial fuels, asphalt, and

other heavy products (for which the markets are less dynamic and in some cases shrinking) or

(2) process into smaller molecules that can go into the transportation fuels products.

In the refining industry, the density of an oil is usually expressed in terms of API gravity, a

parameter whose units are degrees (o API) – e.g., 35oAPI. API gravity varies inversely with

density (i.e., the lighter the material, the higher its API gravity). By definition, water has API

gravity of 10o.

The natural yields of the heavy oils from both the light and the heavy crudes exceed the

demand for heavy refined products, and the natural yield of heavy oil from the heavy crude is

more than twice that of the light crude. These general characteristics of crude oils imply that

(1) refineries must be capable of converting at least some, and perhaps most, of theheavy oil

into light products, and (2) the heavier the crude, the more of this conversion capacity is

required to produce any given product slate.

Sulfur Content

Of all the hetero-elements in crude oil, sulfur has the most important effects on refining.

♦ Sufficiently high sulfur levels in refinery streams can (1) deactivate (“poison”) the catalysts

that promote desired chemical reactions in certain refining processes, (2) cause corrosion in

refinery equipment, and (3) lead to air emissions of sulfur compounds, which are undesirable

and may be subject to stringent regulatory controls.

♦ Sulfur in vehicle fuels leads to undesirable vehicle emissions of sulfur compounds and

interferes with vehicle emission control systems that are directed at regulated emissions such

as volatile organic compounds, nitrogen oxides, and particulates.


Consequently, refineries must have the capability to remove sulfur from crude oil and

refinery streams to the extent needed to mitigate these unwanted effects. The higher the sulfur

content of the crude, the greater the required degree of sulfur control and the higher the

associated cost.

The sulfur content of crude oil and refinery streams is usually expressed in weight percent

(wt%) or parts per million by weight (ppmw). In the refining industry, crude oil is called

sweet (low sulfur) if its sulfur level is less than a threshold value (e.g., 0.5 wt% (5,000

ppmw)) and sour (high sulfur) if its sulfur level is above a higher threshold. Most sour crudes

have sulfur levels in the range of 1.0–2.0 wt%, but some have sulfur levels > 4 wt%.

Within any given crude oil, sulfur concentration tends to increase progressively with

increasing carbon number. Thus, crude fractions in the fuel oil and asphalt boiling range have

higher sulfur content than those in the jet and diesel boiling range, which in turn have higher

sulfur content than those in the gasoline boiling range. Similarly, the heavier components in,

say, the gasoline boiling range have higher sulfur content than the lighter components in that

boiling range.

Crude oil Assay and Charaterstics of Petroleum Fractions. (Tests for Petroleum

Fractions)

The crude oil assay

The crude oil assay is a compilation of laboratory and pilot plant data that define the

properties of the specific crude oil. At a minimum the assay should contain a distillation

curve for the crude and a specific gravity curve. Most assays however contain data on pour

point (flowing criteria), sulfur content, viscosity, and many other properties. The assay is

usually prepared by the company selling the crude oil; it is used extensively by refiners in

their plant operation, development of product schedules, and examination of future

processing ventures. Engineering companies use the assay data in preparing the process

design of petroleum plants they are bidding on or, having been awarded the project, they are

now building. In order to utilize the crude oil assay it is necessary to understand the data it

provides and the significance of some of the laboratory tests that are used in its compilation.

The true boiling point curve

This is a plot of the boiling points of almost pure components, contained in the crude oil or

fractions of the crude oil. In earlier times this curve was produced in the laboratory using

complex batch distillation apparatus of a hundred or more equilibrium stages and a very high


reflux ratio. Nowadays this curve is produced by mass spectrometry techniques much quicker

and more accurately than by batch distillation.

The ASTM distillation curve

While the TBP curve is not produced on a routine basis the ASTM distillation curves are

rarely however is an ASTM curve conducted on the whole crude. This type of distillation

curve is used however on a routine basis for plant and product quality control. This test is

carried out on crude oil fractions using a simple apparatus designed to boil the test liquid and

to condense the vapors as they are produced. Vapor temperatures are noted as the distillation

proceeds and are plotted against the distillate recovered. Because only one equilibrium stage

is used and no reflux is returned, the separation of components is poor. Thus, the initial

boiling point (IBP) for ASTM is higher than the corresponding TBP point and the final

boiling point (FBP) of the ASTM is lower than that for the TBP curve.

API gravity

This is an expression of the density of an oil. Unless stated otherwise the API gravity refers to

density at 60◦F (15.6◦C). Its relationship with specific gravity is given by the expression

Flash points

The flash point of an oil is the temperature at which the vapor above the oil will momentarily

flash or explode. This temperature is determined by laboratory testing using an apparatus

consisting of a closed cup containing the oil, heating and stirring equipment, and a special

adjustable flame. The type of apparatus used for middle distillate and fuel oils is called the

Pensky Marten (PM), while the apparatus used in the case of Kerosene and lighter distillates

is called the Abel. There are many empirical methods for determining flash points from the

ASTM distillation curve. One such correlation is given by the expression

Flash point ◦F = 0.77 (ASTM 5% ◦F − 150◦F)

Octane numbers

Octane numbers are a measure of a gasoline’s resistance to knock or detonation in a cylinder

of a gasoline engine. The higher this resistance is the higher will be the efficiency of the fuel

to produce work. A relationship exists between the antiknock characteristic of the gasoline

(octane number) and the compression ratio of the engine in which it is to be used. The higher


the octane rating of the fuel the higher will be the compression ratio of engine in which it can

be used. By definition, an octane number is that percentage of isooctane in a blend of

isooctane and normal heptane that exactly matches the knock behavior of the gasoline. Thus,

a 90 octane gasoline matches the knock characteristic of a blend containing 90% isooctane

and 10% n-heptane. The knock characteristics are determined in the laboratory using a

standard single cylinder test engine equipped with a super sensitive knock meter. The

reference fuel (isooctane blend) is run and compared with a second run using the gasoline

sample. Two octane numbers are usually determined. The first is the research octane number

(ON res or RON) and the second is the motor octane number (ON mm or MON). The same

basic equipment is used to determine both octane numbers, but the engine speed for the motor

method is much higher than that used to determine the research number. The actual octane

number obtained in a commercial vehicle would be somewhere between these two. The

significance of these two octane numbers is to evaluate the sensitivity of the gasoline to the

severity of operating conditions in the engine. The research octane number is usually higher

than the motor number, the difference between them is termed the ‘sensitivity of the

gasoline.’

Viscosity

The viscosity of oil is a measure of its resistance to internal flow and is an indication of its

lubricating qualities. In the oil industry it is usual to quote viscosities either in centistokes

(which is the unit for kinematic viscosity), seconds Saybolt universal, seconds Saybolt furol,

or seconds Redwood. These units have been correlated and such correlations can be found in

most data books. In the laboratory, test data on viscosities is usually determined at

temperatures of 100◦F, 130◦F, or 210◦F. In the case of fuel oils temperatures of 122◦F and

210◦F are used.

Cloud and pour points

Cloud and Pour Points are tests that indicate the relative coagulation of wax in the oil. They

do not measure the actual wax content of the oil. In these tests, the oil is reduced in

temperature under strict control using an ice bath initially and then a frozen brine bath, and

finally a bath of dry ice (solid CO2). The temperature at which the oil becomes hazy or

cloudy is taken as its cloud point. The temperature at which the oil ceases to flow altogether

is its pour point.


Sulfur content

This is self explanatory and is usually quoted as %wt for the total sulfur in the oil. Assays

change in the data they provide as the oils from the various fields change with age. Some of

these changes may be quite significant and users usually request updated data for definitive

work, such as process design or evaluation. The larger producers of the crude oil provide

laboratory test services on an ‘on going’ basis for these users

Cetane number.

This is the result of an engine test that compares the ignition delay for a fuel. For this test two

reference fuels are chosen. The first is normal cetane (C16) and the second is an isomer of

cetane which is heptamethyl nonane. The normal cetane is arbitrarily given the cetane

number of 100, while the isomer as the second reference fuel is assigned a cetane number of

15. The fuel being tested is run in a standard test engine. The cetane number is derived by

comparing the ignition delay of the test diesel with a blend of the two reference fuels. The

cetane number is then calculated using the equation:

Cetane Number = % normal cetane + 0.15 × % heptamethylnonane.

Higher cetane numbers indicates that the fuel has a shorter ignition delay. The higher the

cetane number also results in less CO and unburnt hydrocarbons in the engine emission

gases. This has a greater effect in the older diesel engine. Modern engines are equipped with

retarded ignition timing and increasing the cetane number has a smaller effect on these more

modern engines.

Aromatics.

The aromatic content of diesel fuel can be measured for single ring aromatics, multi-ring or

poly-aromatic hydrocarbons (PAH). Some studies show that reducing the aromatics results in

the reduction of all regulated emissions, but other studies have indicated that the reduction of

emissions of unburned hydrocarbons, NOx, and particulates can only be achieved by reducing

multi-ring aromatics.


Carbon residue

The term “carbon residue” means the carbonaceous residue formed after evaporation and

pyrolysis of a petroleum product. The residue is not entirely composed of carbon, but is a

coke which can be further change by Pyrolysis. This method describes a procedure for the

determination of the amount of carbon residue left after evaporation and Pyrolysis of oil and

it provide some idea of relative coke forming propensities. The method is generally

applicable to relatively non volatile petroleum product which partially decomposes on

distillation at atmospheric pressure. Petroleum products containing ash forming constituents

as determine by ASTM method, “Test for ash from petroleum oil” will have erroneously high

carbon residue, depending upon the amount of ash formed. This method is applicable to base

fuels without additive. In this method the basic principle involves a weighed test portion of

sample in a crucible is subjected to destructive distillation. The residue undergoes cracking

and coking reactions during a fixed period of severe heating. At the end of the specified

heating period, the test crucible containing the carbonaceous residue is cooled in desiccators

and weighed. The remaining residue is calculated as a mass percentage of the original test

portion. The carbon residue value of burner fuel serves as a rough approximation of the

tendency of the fuel to form deposits. The carbon residue of diesel fuel correlates

approximately with combustion chamber deposits.

Copper Strip Corrosion Test

Petroleum products contain sulphur compounds, most of which are removed during refining.

Of the sulphur compounds remaining in the petroleum product, however, some can have a

corroding effect on various metals. This corrosivity is not necessarily directly related to the

total sulphur content. The effect can vary according to other chemicals and types of sulphur

compounds present.

A cleaned and smoothly polished copper strip is immersed in the sample, which is then

maintained at the specified temperature for the specified length of time. This strip is removed

from sample, washed with aromatic and sulphur free petroleum spirit and examined for

evidence of etching, pitting or discoloration. It is then compared with ASTM copper-strip

corrosion standard colour code. The classification code indicates that the numbers 1, 2, 3 and

4 designate slight tarnish, moderate tarnish, dark tarnish and corrosion, respectively.

Subscripts a-e describes a standard colour reproduction in the standard chart. For example,

the classification code 1a indicates slight tarnish with a light orange colour.


Crude petroleum contains sulphur compounds, most of which are removed during refining.

However, of the sulphur compounds remaining in the petroleum product, some can have a

corroding action on various metals and this corrosivity is not necessarily related directly to

total sulphur compounds present. The copper strip corrosion test is designed to-

1.) Assess relative degree of corrosivity of a petroleum product.

2.) Indicates the presence of sulphur compounds

This test serves as a measure of possible difficulties with copper, brass, or bronze parts of the

fuel system.

Evaluation or Classification Of Crude Oil.

Classification analysis of crude oil is important as it provides a guideline for the quality

measurement of the crude oil. Different methods are available for classifying the crude oil.

The common methods are as under.

1. BASE METHOD.

This method indicates the nature of the crude and talks about the chemical composition of

the particular crude oil. According to this method

(a) Crude oil which on distillation yields residue containing paraffin waxes is called

PARAFFINIC BASE CRUDE.

(b). Crude oil which on distillation yields residue containing asphaltic material is called

ASPHALTIC BASE CRUDE.

(c) Crude oil which on distillation yields residue containing both of paraffin waxes and

asphaltic materials is called INTERMIDIATE BASE CRUDE

2. U.S. BUREAU OF MINES METHOD

This method is based on specific gravity of two fractions known as KEY fractions. The

fraction which boils between 250 to 275 °C in Atmospheric distillation column is termed as

KEY fraction No 1, while the fraction which boils between 275 to 300 °C at 40 mm Hg is


termed as KER fraction No 2. According to this method the classification considering the two

key fractions is as follows…

For Key Fraction No 1 For Key Fraction No 2

API Type of crude

>40 Paraffinic

33 - 40 Intermediate

<33 Naphthenic

3. CHARACTERIZATION FACTOR ( K UOP) :

This factor correlates boiling point with specific gravity of the crude oil according to the

following equations

KUOP = (1/G) * (Tb)1/3

Where Tb is the average boiling point in °R at 1 atm and G specific gravity at 60° F. The classification based on

KUOP is as follows

Type of hydro carbon KUOP

PARAFFINIC 12.5 – 13.0

NAPHTHENIC 11.0 – 12.0

AROMATIC 9.0 – 11.0

API Type of crude

> 30 Paraffinic

20 – 30 Intermediate

< 20 Naphthenic


4. CORRELATION INDEX (CI) METHOD:

This method was developed by U.S Bureau of Mines. This method is based on the

following empirical relation

CI = [ (48640 / TB) + ( 473.7 * G) – 456.8]

Where Tb is the average boiling point in °R at 1 atm and G specific gravity at 60° F. the classification based on

CI values is as inder

Type of hydro carbon CI

PARAFFINIC 0 - 15

NAPHTHENIC 15 – 50

AROMATIC >50

Documents

PRP UNIT - 2