Lesson 2 Overview

Video: FSC 432 Lesson 2 (2:27)

Lesson 2 Breakdown

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Credit: Dutton Institute [1] © Penn State is licensed under CC BY-NC-SA 4.0 [2]

Overview

Physical properties and composition of crude oil provide critical information for the optimum operation of a petroleum refinery. This information does not only help predict the physical behavior of crude oil in refinery units, but also gives insight into its chemical composition. Therefore, the physical properties can be related to chemical properties of crude oil and its fractions and the characteristics of the resulting refinery products. The most important properties of crude include density, viscosity, boiling point distribution, pour point, and the concentration of various contaminants.

Learning Outcomes

By the end of this lesson, you should be able to:

define the significant properties of crude oil, including density, viscosity, average boiling point, sulfur, and salt content;
understand the significance of crude oil properties in terms of refinery objectives, and describe crude oil assay;
define and interpret the classification factors (Watson, UOP, VGC, and BMCI) as they relate to the hydrocarbon composition of crude oils;
calculate average boiling points for crude oils using different averaging techniques and differentiate Watson and UOP characterization factors;
analyze the elemental composition of crude oils and outline ternary classification of crude oils with respect to hydrocarbon composition, i.e., aromatics, paraffins, and naphthenes;
assess the use of ternary classification of crude oils to estimate the refinery product yields.

What is due for Lesson 2?

This lesson will take us one week to complete. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found on the Assignments page within the Lesson.

This table contains the reading and assignments for Lesson 2.
Readings	J. H. Gary, G. E. Handwerk, Mark J. Kaiser, Chapter 3, pp. 57-61, 65-70 and the course material from this site
Assignments	Exercise 1 - Submit to the Exercise 1 Assignment in the Lesson 2 Module. Calculation of API gravity of crude oil blends Calculation of Watson and UOP characterization factors for hydrocarbons and crude oil fractions Quiz 1: Assessment of learning outcomes in Lessons 1 and 2. Quiz 1 is found in the Lesson 2 folder.

Questions?

If you have any questions, please post them to our Help Discussion (not email), located in Canvas. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.

API Gravity

Density is defined as mass per unit volume of a fluid. The density of crude oil and liquid hydrocarbons is usually reported in terms of specific gravity (SG) or relative density, defined as the density of the liquid material at 60°F (15.6°C) divided by the density of liquid water at 60°F. At a reference temperature of 15.6°C, the density of liquid water is 0.999 g/cm³ (999 kg/m³), which is equivalent to 8.337 lb/gal (U.S.). Therefore, for a hydrocarbon or a petroleum fraction, the SG is defined as:

S G (60^{\circ F} / 60^{\circ F}), or ({15.6}^{\circ C} / {15.6}^{\circ C}) = (Density of liquid at 60^{\circ F} in g / {cm}^{3}) / (0.999 g / {cm}^{3})

In the early years of the petroleum industry, the American Petroleum Institute (API) adopted the API gravity (°API) as a measure of the crude oil density. The API gravity is calculated from the following equation:

$° A P I = \frac{141.5}{S G_{15.6 ° C / 15.6 ° C}} - 131.5$

The API scale for gravity was adapted from the Baumé scale, developed in the late 18th century to be used in hydrometers for measuring even small differences in the specific gravity of liquids, using water as a reference material in these devices. A liquid with SG of 1 (i.e., water) has an API gravity of 10. One can note from Eq. 1 that liquid hydrocarbons with lower SGs have higher API gravities. The API of crude oils varies typically between 10 and 50, with most crude oils falling in the range of 20-45. Using API gravity, the conventional crude oils can be generally considered as light (°API>30), medium (30>°API>22), and heavy (°API<22).

Note that the relationship between °API and specific gravity is not linear. Therefore, the °API gravity of crude blends cannot be calculated by linear averaging of the component °APIs. Specific gravities of the components can be averaged, though, to determine the specific gravity of the resulting blend. In practice, averaging °APIs is usually accepted because the error involved in averaging is small.

Among the hydrocarbons, aromatic hydrocarbons have higher SG (lower °API) than paraffinic hydrocarbons with the same number of carbon atoms. For example, benzene has an SG of 0.883 (°API of 28.7), whereas n-hexane has an SG of 0.665 (°API of 81.3). Therefore, the heavy (high-density) crude oils tend to have high concentrations of aromatic hydrocarbons, whereas the light (low-density) crude oils have high concentrations of paraffinic hydrocarbons.

Viscosity

Viscosity, commonly depicted by the symbol μ, is a physical property of a fluid that describes its tendency/resistance to flow. A high-viscosity fluid has a low tendency to flow, whereas low-viscosity fluids flow easily. Newton’s Law of Viscosity provides a physical definition of viscosity. Power requirement to transport (e.g., to pump) a fluid depends strongly on the fluid’s viscosity. Interestingly, the viscosity of liquid decreases with increasing temperature, while viscosity of gases increases with increasing temperature. Among petroleum products, viscosity constitutes a critically important characteristic of lubricating engine oils. Viscosity of liquids is usually measured in terms of kinematic viscosity, which is defined as the ratio of absolute (dynamic) viscosity to absolute density (ν = μ/ρ). Kinematic viscosity is expressed in units of centistokes (cSt), Saybolt Universal seconds (SUS), and Saybolt Furol seconds (SFS). Values of kinematic viscosity for pure liquid hydrocarbons are usually measured and reported at two reference temperatures, 38°C (100°F) and 99°C (210°F) in cSt. However, different reference temperatures, such as 40°C (104 °F), 50 °C (122 °F), and 60 °C(140 °F), are also used to report kinematic viscosities of petroleum fractions. The viscosity of crude oils can be measured using a standard method (ASTM D2983).

Knowledge Check

What are ASTM, ISO, IP?

Click for answer...

Pour Point

The pour point of a crude oil, or a petroleum fraction, is the lowest temperature at which the oil will pour or flow when it is cooled, without stirring, under standard cooling conditions. Pour point represents the lowest temperature at which oil is capable of flowing under gravity. It is one of the important low-temperature characteristics of high-boiling fractions. When the temperature is less than the pour point of a petroleum product, it cannot be stored or transferred through a pipeline. Standard test procedures for measuring pour points of crude oil or petroleum fractions are described in the ASTM D97 (ISO 3016 or IP 15) and ASTM D5985 methods. The pour point of crude oils relates to their paraffin content: the higher the paraffin content, the higher the pour point.

Knowledge Check

What are Waxes?

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Concentration of Various Contaminants

In addition to hydrocarbons, crude oil contains hetroatom (S, N, metals) species that need to be removed if their concentrations are higher than the specified thresholds. Other impurities in crude oil include salt and sediment and water. The acidity of crude oil is also important, particularly for concerns of corrosion in pipes or other process units. Carbon residue of a crude oil indicates the tendency to generate coke on heter tubes or rector surfaces. All of these contaminants and properties of crude oils are measured using standard methods, as described in this section.

Sulfur and Nitrogen Content

Sulfur Content

Sulfur content of crude oils is the second most important property of crude oils, next to API gravity. Sulfur content is expressed as weight percent of sulfur in oil and typically varies in the range from 0.1 to 5.0%wt. The standard methods that are used to measure the sulfur content are ASTM D129, D1552, and D2622, depending on the sulfur level. Crude oils with more than 0.5%wt sulfur need to be treated extensively during petroleum refining. Using the sulfur content, crude oils can be classified as sweet (<0.5%wt S) and sour (>0.5% %wt S). The distillation process segregates sulfur species in higher concentrations into the higher-boiling fractions and distillation residua. Removing sulfur from petroleum products is one of the most important processes in a refinery to produce fuels compliant with environmental regulations.

Nitrogen Content

Nitrogen content of crude oils is also expressed as weight percent of oil. Basic nitrogen compounds are particularly undesirable in crude oil fractions, as they deactivate the acidic sites on catalysts used in conversion processes. Some nitrogen compounds are also corrosive. Crude oils with nitrogen contents greater than 0.25%wt need treatment in refineries for nitrogen removal.

Metals Content and Total Acid Number

Metals Content

Most common metals that are found in crude oil are included in organometallic compounds like nickel, vanadium iron and copper, ranging in concentration from a few ppm up to 1000 ppm by weight, depending on the source of crude oil. Similar to sulfur species, the metallic compounds tend to concentrate in the higher-boiling fraction of crude oil. Higher metal contents also require treatment during petroleum refining because of the corrosion activity of some metals and their tendency to accumulate on catalyst surfaces, thus deactivating the catalysts in a number of refinery processes. Metal content can be measured using a standard EPA Method 3040.

Total Acid Number

Acidity of crude oil is measured by titration with potassium hydroxide (KOH), using the standard method ASTM D664. The measured acidity is expressed as the Total Acid Number (TAN) that is equivalent to milligrams of KOH required to neutralize 1 gram of oil. This number is particularly important to control corrosion in the distillation columns through selection of corrosion-resistant alloys for surfaces that come into contact with oil.

Carbon Residue, Basic Sediment and Water, and Salt Content

Carbon Residue

Carbon residue (as % wt of crude oil, or crude oil fraction) is determined as the weight of solid residue remaining after heating crude oil to coking temperatures (700-800°C). Two standard tests with slightly different procedures are used to measure carbon residue: ASTM D524 Ramsbottom Carbon Residue (RCR) and ASTM D189 Conradson Carbon Residue (CCR). Carbon residue relates to asphalt (or asphaltenes) content of oil and indicates the tendency of fouling in heater tubes and catalyst deactivation. The higher the carbon residue, the higher is the coking (fouling) propensity of crude oil.

Basic Sediment and Water (BS&W)

The standard method ASTM D4007 is used to measure the amount of suspended inorganic solid particles and water (BS&W) in crude oils. These contaminants are mixed with the oil during production, and high concentration of BS&W causes operational problems in a refinery.

Salt Content

Salt content of crude oils can be measured using the standard method ASTM D3230 and reported as lb NaCl/1000 bbl. Desalting (removing the salt) is necessary when NaCl content is greater than 10 lbs/1000 bbl. Such high salt contents lead to corrosion in distillation towers and other equipment.

Distillation and Boiling Points

The boiling point of a pure compound in the liquid state is defined as the temperature at which the vapor pressure of the compound equals the atmospheric pressure or 1 atm. The boiling point of pure hydrocarbons depends on carbon number, molecular size, and the type of hydrocarbons (aliphatic, naphthenic, or aromatic) as discussed in Lesson 1. Figure 2.1 shows the boiling points of n-alkanes as a function of carbon number.

Graph of Boiling points (°C) of n-alkanes as a function of carbon number. BP increases with carbon # but change is less at higher carbon #s

Figure 2.1. Boiling points (°C) of n-alkanes as a function of carbon number.

Source: M. R. Riazi and S. Eser, “Properties, Specifications, and Quality of Crude Oil and Petroleum Products,” In Petroleum Refining and Natural Gas Processing, Editors: M. R. Riazi, S. Eser, J. L. Peña, ASTM International, West Conshohocken, PA, 2013, p. 80.

Complex mixtures such as crude oil, or petroleum products with thousands of different compounds, boil over a temperature range as opposed to having a single point for a pure compound. The boiling range covers a temperature interval from the initial boiling point (IBP), defined as the temperature at which the first drop of distillation product is obtained, to a final boiling point, or endpoint (EP) when the highest-boiling compounds evaporate. The boiling range for crude oil may exceed 1000 °F.

The ASTM D86 and D1160 standards describe a simple distillation method for measuring the boiling point distribution of crude oil and petroleum products. Using ASTM, D86 boiling points are measured at 10, 30, 50, 70, and 90 vol% distilled. The points are also frequently reported at 0%, 5%, and 95% distilled. ASTM D1160 is carried out at reduced pressure to distill the high-boiling components of crude oil. As an alternative method, distillation data can be obtained by gas chromatography (GC), in which boiling points are reported versus the weight percent of the sample vaporized. This test method described in ASTM D2887 is called simulated distillation (SimDis).

Average Boiling Points

Average boiling points are useful in predicting physical properties and for characterization of complex hydrocarbon mixtures. The key here is to represent a mixture of compounds with a range of boiling points by a single characteristic boiling point. Since this is a formidable task, there are five different “average boiling points” that are used in different correlations. They are:

$V A B P (Volume Average Boiling Point)$
$M A B P (Molal Average Boiling Point)$
$W A B P (Weight Average Boiling Point)$
$C A B P (Cubic Average Boiling Point)$
$M e A B P (Mean Average Boiling Point) = (M A B P + C A B P) / 2$

1, 2, and 3 can be defined for a mixture of n components as:

(Vol, ​ Mol, or Weight) A B P = \sum x_{i} T_{b i}

where ABP is is expressed as VABP, MABP, or WABP and x_i is the corresponding volume, mole, or weight fraction of component i, and T_bi is the normal boiling point of component i. Cubic average boiling point (CABP) and Mean Average Boling Points (MeABP) can be calculated as follows.

C A B P = {[\sum x_{i volume} {(T_{b i})}^{1 / 3}]}^{3}

M e A B P = (M A B P + C A B P) / 2

For petroleum streams, volume, weight, or mole fractions of the components are not usually known. In this case, VABP is calculated from standard distillation (ASTM D86 Method) data, and empirical relationships (charts, or equations) are used to calculate the other average boiling points.

Here is the procedure:

Equation 1 (Ts are ASTM D86 temperatures for 10, 30, 50, 70, and 90% volume distilled, respectively):

V A B P = (T_{10 %} + T_{30 %} + T_{50 %} + T_{70 %} + T_{90 %}) / 5

Along with VABP, the slope of the ASTM D86, SL, is used for converting VABP to other average boiling points.

Equation 2:

S L = (T_{90 %} - T_{10 %}) / 80

The following empirical equations can, then, be used to obtain the temperature difference (ΔT) between VABP and other average boiling points (ABP) [2] :

Equation 3:

I n (- Δ T_{Weight Average}) = - 3.64991 - 0.02706 {(V A B P - 273.15)}^{0.6667} + 5.163875

S L 0.25

Equation 4:

I n (Δ T_{Molal Average}) = - 1.15158 - 0.01181 {(V A B P - 273.15)}^{0.6667} + 3.70612 S L^{0.333}

Equation 5:

I n (Δ T_{Cubic Average}) = - 0.82368 - 0.08997 {(V A B P - 273.15)}^{0.45} + 2.456791 S L^{0.45}

Equation 6:

I n (Δ T_{Mean Average}) = - 1.53181 - 0.0128 {(V A B P - 273.15)}^{0.6667} + 3.646064 S L^{0.333}

and

Equation 7:

(Weight, Molal, Cubic, or Mean) A B P = V A B P - Δ T_{(weight, molal, cubic, or mean)}

The temperature unit used for VABP, SL, and ΔT in these correlations is Kelvin.

The following script can be used to calculate VABP, MeABP by entering the distillation temperatures in the table.

You may also use the charts in Figure 4.1a and Figure 4.1b (p. 39) of your textbook [3] to obtain MeABP and MABP, respectively, from VABP. Note that the slope of the distillation curve used in those charts refers to True Boiling Point (TBP) distillation (not to ASTM distillation), and it is calculated as (T_70% -T_10%)/60.

[3] Petroleum Refining, by J. H. Gary, G. E. Handwerk, M. J. Kaiser, 5th Edition, CRC Press NY, 2007, Chapter 4, p.39.

Crude Assay

Crude oil assay consists of a compilation of data on properties and composition of crude oils. The assay provides critical information on the suitability of crude oil for a particular refinery and estimating the desired product yields and quality. It also indicates how extensively a given crude oil should be treated in a refinery to produce fuels that are in compliance with environmental regulations. A typical crude assay should include the following major specifications:

API Gravity
Total Sulfur (% wt)
Pour Point (°C)
Viscosity @ 20°C (cSt)
Viscosity @ 40°C (cSt)
Nickel (ppm)
Vanadium (ppm)
Total Nitrogen (ppm)
Total Acid Number (mgKOH/g)
Distillation Data
Characterization factor K_UOP, K_W

Characterization Factors

Since the early days of the petroleum industry, some physical properties of crude oil were used to define characterization factors for classification of crude oil with respect to hydrocarbon types [4] as shown in Equation 8.

$K (U O P, o r W a t s o n) = (\sqrt[3]{T b}) / S G (15 ° C)$

where: Tb = volume, or mean average normal boiling point in R (degree Rankine) and SG = specific gravity at 15.6°C (60°F). To calculate K_UOP or K_W, volume average boiling point (VABP) or mean average boiling point is used, respectively. Depending on the value of the Watson characterization factor, crude oils are classified as paraffinic (K_w = 11-12.9), naphthenic (K_w =10-11), or aromatic (K_w<10).

animation described in text proceeding the animation

Watson Characterization Factor Animation

Click here for a text alternative to the figure above

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [2]

Another parameter defined in the early years of petroleum characterization is the viscosity gravity constant (VGC). This parameter depends on viscosity expressed in Saybolt Universal Seconds (SUS) and specific gravity. According to a standard method (ASTM D2501), VGC can be calculated at a reference temperature of 100°F as follows in Equation 9:

$VCG= \frac{10 S G (15.6 ° C) - 1.0752 \log (V (100 ° F) - 38}{10 - \log ((V (100 ° F) - 38)}$

where V(100°F) is the viscosity in SUS and SG is the specific gravity at 15.6°C (60°F). VGC varies between 0.74 to 0.75 for paraffinic, 0.89 and 0,94 for naphthenic, and 0.95 and 1.13 for aromatic hydrocarbons.

The U.S. Bureau of Mines Correlation Index (BMCI) or (CI) is useful for characterization of crude oil fractions. CI is defined in terms of Mean Average Boiling Point (Tb) and specific gravity (SG) at 60°F as shown in Equation 10:

$C I = \frac{87, 552}{T b} + 473.7 S G - 456.8$

According to this CI scale, all n-paraffins have a CI value of 0, while cyclohexane (the simplest naphthene), has a CI value of 50, and benzene has a CI value of 100. Using the CI values, crude oils can be classified as follows:

Table 2.1
paraffinic	CI<29.8
naphthenic	CI<57.0
aromatic	CI>75.0

[4] K. M. Watson, E. F. Nelson , George B. Murphy, “Characterization of Petroleum Fractions,” Ind. Eng. Chem., 1935, 27 (12), pp 1460–1464

Elemental Analysis and Ternary Classification of Crude Oils

Despite a wide variety of crude oil found in different parts of the earth, the elemental composition of most crude oils changes in narrow ranges, as shown in Table 2.2.

Table 2.2: Elemental Composition of Crude Oils
Element	% Wt
C	84-86%
H	11-14%
S	0-6%
N	0-1%
O	0-2%

With such narrow ranges of change in elemental contents, elemental composition does not have much utility for classification of crude oil. Instead, variations in hydrocarbon composition (paraffins, naphthenes, and aromatics) are used to classify crude oils, using a ternary diagram, shown in Figure 2.2. Each apex of the triangle represents 100 percent weight of the corresponding compounds, and 0% of this particular type of hydrocarbons on the side of the triangle across from the apex. For example, the side at the bottom of the triangle (across from the apex of 100% aromatics) represents binary mixtures of paraffins and naphthenes.

Triangle diagram. Top: 100% Aromatics, Bottom left: 100% Paraffins, Bottom right: 100% Naphthenes

Figure 2.2. A ternary diagram for classification of crude oils

If you need to refresh your memory on reading ternary diagrams, you may check "Reading a Ternary Diagram [8]", or consult other sources. The list below shows the six classes of crude oil that are defined using a ternary diagram. These classes are shown as areas on the ternary diagram for paraffins, below. It is generally accepted that Class 1 (rich in paraffins) represents the most desirable type of crude oil because refining these crudes would readily lead to high yields of light and middle distillates that constitute the fuels such as gasoline, diesel fuel, and jet fuel which are in high demand. Extensive refining would be required to produce high yields of distillate fuels from aromatic crudes (e.g., Class 4-6). Class 1 crudes tend to have high °API and low sulfur contents and tend to be more expensive than the other types of crude oils.

Ternary Classification of Crude Oils

Paraffinic Crudes
paraffins + naphthenes > 50%
paraffins > naphthenes
paraffins > 40%
Naphthenic Crudes
paraffins +naphthenes > 50%
naphthenes > paraffins
naphthenes > 40%
Paraffinic-Naphthenic Crudes
Aromatics < 50%
paraffins < 40%
naphthenes < 40%
Aromatic-Naphthenic Crudes
Aromatics > 50%
naphthenes > 25%
paraffins < 10%
Aromatic-Intermediate Crudes
Aromatic > 50%
paraffins > 10%
Aromatic-Asphaltic Crudes
Naphthenes < 25%
paraffins < 10%

Video: Lesson 2 Paraffins (2:47)

Placement of Class 1 Paraffinic Crudes on the ternary diagram.

Click here for transcript of Lesson 2 Paraffins

Video: Lesson 2 Aromatics (2:34)

Placement of Class 4, 5, and 6 Crudes on the ternary diagram.

Click here for transcript of Lesson 2 Aromatics

Self-Check Questions

Take a few minutes to answer the questions below. When you are ready, Click Check to see the solutions.

Assignments

Assignment Reminder

Each week, you will have a number of assignments. This week's assignments are listed below. All assignments are submitted in Canvas. For due dates, please check your syllabus.

Quiz 1 is due next Monday. Quiz 1 will cover material in both Lessons 1 and 2.
Exercise 1 is due this week. Read the instructions carefully on what is acceptable.

Quiz 1

Quiz 1 is located in the Quizzes folder in Canvas. Quiz 1 will cover material in Lessons 1 and 2.

Exercise 1

Exercise 1 Instructions

Exercise 1 is provided in Canvas module Lesson 2 as a downloadable file. Submit your answers as a file in PDF format the Exercise 1 assignment in the Lesson 2 Module. For all the exerciase in this course, please make sure that you clearly indicate all the steps that you use to solve the problems and submit your own work.

Please note:

Scans of handwritten pages are not acceptable.

Summary and Final Tasks

Lesson 2 Summary

Selected properties of crude oil provide information on its quality and the conditions for optimum operation of a petroleum refinery for processing the crude oil to produce the desired fuels. Readily measurable physical properties of crude oil (such as density, boiling point, and viscosity) not only help predict the physical behavior of crude oil during refining but also give insight into the chemical composition of the oil. Therefore, physical properties can be used in developing characterization factors that relate to the chemical behavior of crude oil and the characteristics of the resulting refinery products. In addition to using characterization factors, crude oils are classified using ternary diagrams reflecting the hydrocarbon composition in terms of paraffins, naphthenes, and aromatics.

Learning Outcomes

By the end of this lesson, you should be able to:

define the significant properties of crude oil, including density, viscosity, average boiling point, sulfur, and salt content;
understand the significance of crude oil properties in terms of refinery objectives, and describe crude oil assay;
define and interpret the classification factors (Watson, UOP, VGC, and BMCI) as they relate to the hydrocarbon composition of crude oils;
calculate average boiling points for crude oils using different averaging techniques, and differentiate Watson and UOP characterization factors;
analyze the elemental composition of crude oils and outline ternary classification of crude oils with respect to hydrocarbon composition, i.e., aromatics, paraffins, and naphthenes;
assess the use of ternary classification of crude oils to estimate the refinery product yields.

Reminder - Complete all of the Lesson 2 tasks!

You have reached the end of Lesson 2! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 3. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignment below can be found within this lesson.

This table contains the reading and assignments for Lesson 2.
Readings	J. H. Gary, G. E. Handwerk, Mark J. Kaiser, Chapter 3, pp. 57-61, 65-70 and the course material from this site
Assignments	Exercise 1 - Submit to the Exercise 1 Assignment in the Lesson 2 Module. Calculation of API gravity of crude oil blends Calculation of Watson and UOP characterization factors for hydrocarbons and crude oil fractions Quiz 1: Assessment of learning outcomes in Lessons 1 and 2. Quiz 1 is found in the Lesson 2 module.

Questions?

If you have any questions, please post them to our Help Discussion Forum (not email), located in Canvas. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.

Lesson 2: Properties and Classification of Crude Oil

Lesson 2 Overview