Lesson 1 Overview

Video: FSC 432 Lesson 1 (2:04)

Overview

Petroleum provides the largest fraction of primary energy supply in the U.S. and in the world [Figure 1.1,eia1]. Resource consumption patterns shown in Figure 1.1 reflect major epochs in human history, such as The Industrial Revolution, ushering in the rapid increase in coal consumption.  Petroleum trace, for example, marks the mass production of automobiles with the introduction of Model T by Ford, world wars, supply crises of 1973 and 1979 and the economic recession in 2008. Transportation of people and goods in many parts of the world depends almost completely on petroleum fuels, such as gasoline, jet fuel, diesel fuel, and marine fuel. Apart from the fuels, materials that are necessary for operating the combustion engines of cars, trucks, planes, and trains also come from petroleum. These materials include lubricating oils (motor oils), greases, tires on the wheels of the vehicles, and asphalt to pave the roads for smooth rides in transportation vehicles. All petroleum fuels and many materials are produced by the processing of crude oil in petroleum refineries. Petroleum refineries also supply feedstock to the petrochemicals and chemical industry for producing all consumer goods from rubber and plastics (polymers) to cosmetics and medicine. Only ten percent of petroleum consumption, the portion that is not used for transportation or other energy outlets, is sufficient to manufacture all the materials used in human economy, with the exception of those derived from wood or minerals.

Figure 1.1. History of energy use in the United States. 1 Quadrillion (10¹⁵) Btu = 1.05 × 10¹⁸ Joules.

Click for a text description of Figure 1.1

Figure 1.1 is showing the history of energy consumption of the U.S. and the source of the energy. For nearly the first 100 years, the U.S. used only wood as our energy source until about the mid 1800’s. Afterward they started using more of what we think of as our standard energy materials such as coal and petroleum. The 20th century is when sources we now consider alternative started to appear such as hydraulic, nuclear, solar and natural gas.

Source: U.S. Energy Information Administration.

The petroleum industry consists of two separate operations: Upstream and Downstream Operations. Upstream operations involve exploration of new oil reserves, development of oil fields, constructing the well-head and crude oil production facilities. Downstream operations cover processing of crude oil in petroleum refineries to produce liquid and gaseous fuels and materials for the market. This course addresses petroleum refining to review how a variety of physical processes and chemical reactions in separate refinery units are integrated to process compliant fuels and materials.

Learning Outcomes

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

• recognize the significance of petroleum fuels in the U.S. energy supply;
• express the overall objectives of petroleum refining;
• identify the economic and environmental drivers of petroleum refining;
• describe the overall approach to petroleum refining and categorize refinery processes and products;
• portray chemical constitution of petroleum.

What is due for Lesson 1?

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 Assignment page within this lesson.

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.

Market Drivers for the Refining Industry

Markets and demand for refinery products depend on the dynamics of a global economy. It is generally agreed that oil and gas will continue to be the primary energy resource in the U.S. and world economies for decades to come. Because of the projected increase in the production of oil in tight formations, the United States is expected to become an exporter of petroleum products and crude oil after decades of being an importer (Figure 1.2, EIA Annual 2013, eia.gov). Petroleum fuels will continue to dominate the transportation sector, but the following trends should be noted:

• increasing fuel economy of vehicles (offset by increasing number of vehicles and miles driven);
• more strict environmental regulations with demand for cleaner fuels;
• biofuels as additives (e.g., ethanol, biodiesel) or alternative fuels in niche markets (jet fuel from algae);
• demand for high-quality, high-performance fuels

 

Figure 1.2. U.S. domestic crude oil production by source, 1990-2040 (million barrels per day)

Click for a text description of Figure 1.2

Figure 1.2 is showing both the history of U.S. crude oil production since 1990 as well as the prediction of U.S. crude oil production until the year 2040. Since 1990, we have been seeing a decline in oil production from Alaska, offshore drilling, and lower 48 offshore production until 2010 and then those sources are predicted to level off. After 2010 it is predicted that oil production from tight oil will continue to increase.

Source: EIA Annual 2013, US Energy Information Administration [4].

Competitive forces in the global economy lead to joint ventures and mergers and shutting down of inefficient refineries, or shutting down of processing units with low efficiency within refineries. Figure 1.3 shows the changes in the refinery capacity and number of refineries in the U.S. since 2000. The increasing refining capacity, with the decreasing number of refineries, results in the closing down of small inefficient refineries while expanding the large refineries.

Figure 1.3. Number and capacity of operable refineries in the United States.

Source: EIA Annual 2013, US Energy Information Administration [4].

Regarding the global competition, the technological advancement addresses the degrading quality of crude oils to produce cleaner and higher quality petroleum fuels. On the supply side, there is the increasing abundance of natural gas liquids (ethane, propane, n-butane, and isobutane) due to increased shale gas production in the U.S. and elsewhere. These liquids enter refineries as new feedstock in addition to crude oil supply.

Refineries need process improvements to advance their capabilities to deal with the changing crude oil base and changing environmental regulations. These improvements in refinery processes would need to create and use, for example:

• new catalysts and new chemistry;
• more sophisticated process modeling and computational methods;
• more effective use of computers in refinery management;
• online monitoring and property measurements;
• new materials to reduce maintenance and extend the useful life of the equipment.

Concerns for efficiency include running a refinery efficiently and producing fuels that will burn efficiently in the combustion engines, as follows:

• Efficiency of refinery processes
  • Minimize waste and optimize the yield and properties of the refinery products to obtain maximum value from the crude oil.
  • Increase the energy efficiency of each unit in the refinery.
• Fuel economy in internal combustion engines
  • Produce high-performance fuels for efficient operation of combustion engines.

An Overview of Refinery Products and Processes

Considering the market drivers just reviewed along the small profit margins that are often usually associated with petroleum refinery products, refineries should carefully select the crude oil feedstock and configure the refinery processes such that they produce the desirable petroleum products at the lowest cost.

In the U.S. refineries, a principal focus is on the production of gasoline because of high demand. Diesel fuel is the principal refinery product in most other parts of the world. Figure 1.4 shows a typical distribution of products from a barrel of crude oil in a U.S. refinery. Distillation process separates the crude oil into boiling point fractions. The liquefied petroleum gas (LPG) constitutes the lowest boiling point (most volatile) product from a refinery and higher boiling fractions lead to most desirable distillate liquids, such as gasoline, jet fuel, diesel fuel, and fuel oil in the increasing order of boiling points, while asphalt is made from the residual fraction remaining after distillation.

Figure 1.4: A typical distribution of products made from crude oil in a U.S. refinery.

Click here for text description of Figure 1.4

Products Made from a Barrel of Crude Oil

• 47% Gasoline

• 23% Diesel Fuel & Heating Oil

• 18% Other Products

• 10% Jet Fuel

• 4% Liquefied Petroleum

• 3% Asphalt

Source: U.S. Department of Energy

The following animation shows a refinery flow chart indicating some of the major refinery processes and refinery products. Note that the distillation process (Fractionation Tower) separates crude oil into a number of distillate fractions that are sent as feedstocks to different processes, some of which are interconnected. It is also important to recognize that petroleum refining not only produces transportation fuels and fuels for space heating or industrial furnaces, but also produces materials needed for the operation of the combustion engines and paving the roads for vehicles to travel on.

Video: FSC 432 Refinery Flow Chart (4:12)

Figure 1.5 indicates that chemical constitution and physical properties of crude oils are important parameters that guide the refinery configurations. The refining processes can be divided into four groups, as indicated. While the separation processes involve just physical phenomena, the conversion, finishing, and support processes require chemical changes, i.e., breaking chemical bonds to modify the molecular structure of the feedstocks. These changes are necessary to produce the fuels and materials in accordance with industrial/commercial specifications.

Figure 1.5. Classification of refining processes and types of refinery products.

Click here for an accessible version of the image above

This is a classification of refining processes and the types of refinery products, shown by a flow chart. The flow chart starts with crude oil. Above crude oil chemical constitution is written and below physical properties are written. Crude oil leads to the refining process including separation, conversion, finishing and support. From there it goes to products including fuels, petrochemicals and materials. Underneath this is written specifications.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 1.6 (progressive image, 25 seconds) shows a more detailed refinery block diagram to show how different processes are integrated for producing the desired fuels and materials.

Figure 1.6. A flow diagram integrating the four types of processes in a petroleum refinery (25 seconds).

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Separation processes, such as distillation, dewaxing, and deasphalting make use of the differences in the physical properties of crude oil components to separate groups of hydrocarbon compounds or inorganic impurities, whereas conversion processes cause chemical changes in the hydrocarbon composition of crude oils. For example, Fluid Catalytic Cracking process breaks chemical bonds in long-chain alkanes to produce shorter chain alkanes to produce gasoline from higher boiling gas oil fractions. Finishing processes involve hydrotreating to remove heteroatoms (S, N, and metals) and product blending to produce fuels and materials with desired specifications and in compliance with environmental and government regulations. Finally, supporting processes provide the recovery of the removed heteroatoms or heteroatom compounds, production of the hydrogen necessary for conversion and hydrotreating processes, and effluent water treatment systems.

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Knowledge Check

Why is diesel fuel preferred over gasoline in many countries in the world?

Click for answer...

ANSWER: Diesel fuel powers the engines in buses, locomotives, and ships used for public transport. Passenger vehicles fueled by gasoline are the most widely used means of transportation in the U.S.

Chemical Constitution of Crude Oil

Crude oil contains organic compounds, heteroatom compounds (S,N,O), hydrocarbons (C, H), metals and organic (Ni, V, Fe) and inorganic (Na⁺, Ca⁺⁺, Cl^-) compounds as listed in Figure 1.7. Compounds that contain only elements of carbon and hydrogen are called hydrocarbons and constitute the largest group of organic compounds found in petroleum. There might be as many as several thousand different hydrocarbon compounds in crude oil. Hydrocarbon compounds have a general formula of C_xH_y, where x and y are integer numbers.

Figure 1.7. Constituents of crude oil.

Click here for a text alternative to the figure above

Triangle labeled Crude Oil. On each corner is:

Inorganic Compounds (Na⁺, Ca²⁺, Cl^-)

Organic Compounds (Ni, V, Fe)

Organic Compounds

On each side they are labeled:

Between organic and inorganic compounds: Heteroatom compounds (S,N,O)

Between organic and Organic (Ni, V, Fe) compounds: Hydrocarbons (C,H)

Between Organic (Ni, V, Fe) and inorganic compounds: Metals

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Hydrocarbons are generally divided into four groups: (1) paraffins, (2) olefins, (3) naphthenes, and (4) aromatics (Figure 1.8). Among these groups, paraffins, olefins, and naphthenes are sometimes called aliphatic compounds, as different from aromatic compounds. The lightest hydrocarbon found as a dissolved gas is methane (CH₄), the main component of natural gas. Olefins are not usually found in crude oils, but produced in a number of refining processes.

Figure 1.8. Chemical bonding in hydrocarbons.

Click here for a text alternative to the figure above

Image reads:

Essential components of petroleum

-CH compounds based on quadrivalency of carbon atoms

-linked by a single bond (alkanes)

-liked by a double bond (alkenes)

-linked by conjugated double bonds in a ring structure (aromatics)

Saturated Aliphatic HC (n-alkanes or n-paraffins)

-straight chains of C atoms each with 2, 3 H atoms (except CH⁴)

-general formula: C_nH_2n+2

-CH³-(CH²)_n-(CH³): Ex) n-pentane: CH³-CH²-CH²-CH²-CH³

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Assignment Reminder

Each week, you will be required to do assignments. The assignment for this week is:

For your information (no submission), review the most recent supply of petroleum fuels from the data given at U.S. Energy Information Administration [4] and research how petroleum refining addresses the environmental concerns from the combustion of petroleum fuels in internal combustion engines.

Self-Check Questions

Take a few minutes to answer the five questions below. Use the arrow to go to the next question. When you are ready, click Check to see the solution.

Summary

Petroleum, the most important crude oil, consists of a mixture of hydrocarbon compounds including paraffinic, naphthenic, and aromatic hydrocarbons with small amounts of impurities including sulfur, nitrogen, oxygen, and metals. The first process in petroleum refining operations is the separation of crude oil into its major constituents, using distillation to separate the crude oil constituents into common boiling-point fractions. Other separation processes include deasphalting to remove the heaviest fraction of crude oil, asphalt, and dewaxing to remove long-chain n-paraffins called wax.

To meet the demands for high-octane gasoline, jet fuel, and diesel fuel, heavier components of crude oils are converted to gasolines and other distillate fuels. Among the conversion processes are cracking, coking, and visbreaking that are used to break large petroleum molecules into smaller ones. Polymerization and alkylation processes are used to combine molecules smaller than those in gasoline into larger ones to make more gasoline in the refinery. Isomerization and reforming processes are applied to rearrange and reform the structure of hydrocarbons to produce higher-value gasoline components of a similar molecular size.

Finishing processes in a refinery processes stabilize and upgrade petroleum products by hydrogenation and remove undesirable elements, such as sulfur and nitrogen, by hydrotreating processes. Blending of many product streams, to come up with commercial refinery products with the required specifications, also belong to the category of finishing processes.

Lesson Objectives

You should now be able to:

• recognize the significance of petroleum fuels in the U.S. energy supply;
• express the overall objectives of petroleum refining;
• identify the economic and environmental drivers of petroleum refining;
• describe the overall approach to petroleum refining and categorize refinery processes and products;
• portray chemical constitution of petroleum.

Reminder - Complete all of the Lesson 1 tasks!

You have reached the end of Lesson 1! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 2. 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.

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.

Lesson 2 Overview

Video: FSC 432 Lesson 2 (2:27)

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.

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:

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:

$$°API=\frac{141.5}{S{G}_{15.6°C/15.6°C}}-131.5$$

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).

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.

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.

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.

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).

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.

$$K(UOP,orWatson)=(\sqrt[3]{Tb})/SG(15°C)$$

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).

Watson Characterization Factor Animation

Click here for a text alternative to the figure above

UOP or Watson Characterization Factor

SG: Specific Gravity at 15ºC (60ºF)

T_b: average boiling point (ºR)

K_UOP, or Watson = (T_b)^1/3/SG_15ºC(60ºF)

K_UOP uses Volume Average Boiling Point (VAPB)

T_VABP = (T_10% + T_30% + T_50% + T_70% + T_90%)/5

T_v% = ASTM Distillation T at 10%, 30%, 50%, 70% and 90% distilled Volume

K_Watson uses Mean Average Boiling Point (MeAPB)

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

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:

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

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:

$$CI=\frac{87,552}{Tb}+473.7SG-456.8$$

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:

[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.

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.

Figure 2.2. A ternary diagram for classification of crude oils

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

If you need to refresh your memory on reading ternary diagrams, you may check "Reading a Ternary Diagram [11]", 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

1. Paraffinic Crudes
   paraffins + naphthenes > 50%
   paraffins > naphthenes
   paraffins > 40%
2. Naphthenic Crudes
   paraffins +naphthenes > 50%
   naphthenes > paraffins
   naphthenes > 40%
3. Paraffinic-Naphthenic Crudes
   Aromatics < 50%
   paraffins < 40%
   naphthenes < 40%
4. Aromatic-Naphthenic Crudes
   Aromatics > 50%
   naphthenes > 25%
   paraffins < 10%
5. Aromatic-Intermediate Crudes
   Aromatic > 50%
   paraffins > 10%
6. Aromatic-Asphaltic Crudes
   Naphthenes < 25%
   paraffins < 10%

Video: Lesson 2 Paraffins (2:47)

Video: Lesson 2 Aromatics (2:34)

Self-Check Questions

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

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.

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

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.

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.

Overview

Video: FSC 432 Lesson 3 (2:16)

Overview

Selected properties of crude oil provide information on its quality and the conditions for the 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 in predicting the physical behavior of crude oil during refinery 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.

As introduced in Lesson 1, petroleum refining integrates four types of processes: separation, conversion, finishing, and supporting processes. This lesson involves a quick walk through a simple refinery in the U.S. to see what happens to a barrel of crude oil, and to provide more detail on how different processes are sequenced for optimum operation. The simple animation below shows a simplified diagram of processing network to maximize gasoline yield and produce the other distillate fuels (jet fuel, diesel fuel, and fuel oil) in high yield.

The first sequence of processes in a refinery makes use of physical separation to wash the salt out and to fractionate the desalted crude into different boiling ranges in a distillation column. Following the distillation, these fractions are subjected to further separation processes, such as those in Light Ends Unit (LEU) dewaxing and deasphalting units; to finishing processes, such as hydrotreatment; and to conversion processes, such as catalytic cracking, hydrocracking, visbreaking, and delayed coking. As shown in the animation below, the final products from these processes include Liquefied Petroleum Gas (LPG), lubricating oil base stock, asphalt, jet fuel and diesel fuel, gasoline, fuel oil, and petroleum coke. Some fractions from LEU are sent to finishing processes (blending and hydrotreatment) and further to a conversion process (reforming) to produce additional gasoline. Light products from catalytic cracking are subjected to further conversion in the alkylation process to produce more gasoline. Finally, supporting processes, hydrogen production and sulfur recovery, help remove the major heteroatom contaminant, sulfur, from the petroleum fuels through hydrotreatment [1].

This refinery scheme is typical in U.S. refineries where the premium product is gasoline, as one could tell from the number of processes that lead to gasoline as the major product. The gasoline streams from different processes are blended in sophisticated linear and non-linear programming schemes to produce the three grades of gasoline sold in the U.S., regular, intermediate, and premium grades defined in reference to octane number. Elsewhere in the world, there is more emphasis on producing diesel fuel rather than gasoline, since the transportation systems are not as heavily dependent on gasoline-powered passenger vehicles. Diesel fuel is preferred for mass transport options (e.g., buses and trains), as diesel engines (with compression-ignition) can deliver more power than spark-ignition gasoline engines.

In the following sections, each major process group in a refinery network will be introduced in sequence. We will discuss how they fit in the “industrial ecology” of petroleum refining for the overall economic goal of maximizing profit in the prevailing markets for crude oil and the refined petroleum products. The video below presents a flow diagram integrating the four types of processes in a petroleum refinery.

Video: FSC 432 Simple Refinery Flow (4:36)

Learning Outcomes

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

• illustrate the refinery processes with examples for each category of processes;
• distinguish and evaluate the functions of different refinery processes to control refinery product yield and composition;
• evaluate the principles behind the major refinery processes and examine the products from each process from Distillation to Hydrocracking;
• formulate strategies for upgrading heavy oil.

What is due for Lesson 3?

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 this lesson.

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.

Desalting and Distillation

Although distillation is usually known as the first process in petroleum refineries, in many cases, desalting should take place before distillation (Figure 3.1). Salt dissolved in water (brine) enters the crude stream as a contaminant during the production or transportation of oil to refineries. If salt is not removed from crude oil, serious damage can result, especially in the heater tubes, due to corrosion caused by the presence of Cl. Salt in crude oil also causes reduction in heat transfer rates in heat exchangers and furnaces.

The three stages of desalting are:

1. adding dilution water to crude;
2. mixing dilution water with crude by a mixer;
3. dehydration of crude in a settling tank to separate crude and sediment and water (S&W).

Figure 3.1. Desalting and fractional distillation of crude oil.

Click here for a text alternative to the image above

Desalting and fractional distillation of crude oil schematic:

Crude oil enters an atmospheric distillation unit and starts at desalting. Crude oil and water are added and a brine of NaCl + H20 comes out. The resulting oil is separated into overhead distillate & full-range naphtha (gas-380ºF) [this goes to a light ends unit], Kerosene (380-480ºF), Light Gas oil (480*-610ºF), Heavy Gas Oil (610-690ºF), & Atmospheric Residue.

Atmospheric Residue goes to a vacuum distillation unit (10mmHg) which separates the residue into light vacuum gas oil (690-750ºF), Heavy Vacuum Gas Oil (750-985ºF), Vacuum Reside (1000ºF +)

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Desalting can be performed in a single-stage or two-stage units. The amount of water wash and the temperature of the mixing process depends mainly on the crude API gravity [2].

Distillation separates hydrocarbon compounds into distillate fractions based on their boiling points or volatility. More volatile compounds (with low boiling points) tend to vaporize more readily than heavy compounds, and this forms the basis of separation through distillation. In a distillation column, light components are removed from the top of the column, and the heavier part of the mixture appears in the bottom. For a crude that is a mixture of thousands of hydrocarbons, some very light compounds such as ethane and propane only appear in the top product, while extremely heavy and non-volatile compounds such as asphalts only appear in the bottom. Figure 2 shows a simple diagram of atmospheric and vacuum distillation units and the fractional separation of the crude oil into different boiling fractions with the indicated boiling ranges. The lightest compounds found in crude oil come out from the top of the distillation column (referred to as overhead distillate, or full-range naphtha) and are sent to the Light Ends Unit (LEU) for further separation into LPG and naphtha, as discussed later. The side streams separated in the atmospheric distillation column give fractions that include the “straight-run” products called kerosene, and light and heavy gas oils. The residue from the atmospheric distillation column generates two side streams, light and heavy vacuum gas oils, and vacuum residue from the bottom. All of these distillation products are subjected to subsequent processing to produce light and middle distillate fuels and non-fuel products, as described in the following sections, starting with LEU.

Light Ends Unit

As shown in Figure 3.2, the Light Ends Unit consists of a sequence of distillation processes to separate the overhead distillate product from the atmospheric distillation column into five streams consisting of methane and ethane (C₂ and lighter), to propane (C₃), butane (C₄), light naphtha, and heavy naphtha. The fraction C₂ and lighter is used as fuel gas in the refinery to provide heat or generate steam. Propane and butane are sold as liquefied petroleum gas (LPG) after removing H₂S. Light naphtha fraction that consists of C₅ and C₆ paraffins (pentane and hexane) is sent to the gasoline blending pool as straight-run gasoline, while the heavy naphtha fraction (rich in cycloalkanes, or naphthenes) is sent to a catalytic reforming process to produce gasoline with a high octane number.

Figure 3.2. Separations in light ends unit.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Catalytic Reformer

Catalytic reforming converts low-octane straight run naphtha fractions (particularly heavy naphtha that is rich in naphthenes) into a high-octane, low-sulfur reformate, which is a major blending product for gasoline (Figure 3.3). The most valuable byproduct from catalytic reforming is hydrogen, which is needed in refineries with increasing demand for hydrotreating and hydrocracking processes. Most reforming catalysts contain platinum supported on alumina, and some may contain additional metals such as rhenium and tin in bi-, or tri-metallic catalyst formulations. Early reforming processes were called platforming in reference to reforming with a platinum catalyst. In most cases for catalytic reforming, the naphtha feedstock needs to be hydrotreated before reforming, to protect the platinum catalyst from poisoning by sulfur or nitrogen species. The principal reactions in catalytic reforming include dehydrogenation of naphthenes to aromatics (with significant quantity of hydrogen as byproduct) and cracking/isomerization of n-paraffins into i-paraffins. The principal product from catalytic reforming is called reformate, consisting of C₄ to C₁₀ hydrocarbons. Reformate has a high octane number because of high concentration of aromatic compounds (benzene, toluene, and xylene) produced from naphthenes. With the more stringent requirements on benzene and total aromatics limit in US and Europe (less than 1% benzene, 15% total aromatics), the amount of reformate that can be used in gasoline blending has been limited, but the function of catalytic reforming as the only internal source of hydrogen continues to be important for refineries.

Figure 3.3. Catalytic reforming.

Click here for a text alternative to the figure above

Catalytic reforming schematic.

Heavy naphtha (low octane #) along with Co/Mo with Al₂O₃ support enter the hydrotreater. From there it goes to the catalytic reformer where Pt is used as a catalyst to turn cycloparaffins into aromatics + H₂ (high octane #) and n-alkanes into i-alkanes (high octane #). H₂ goes back into the hydrotreater and is removed as H₂S. Products from the catalytic reformer are called reformate and are added to the gasoline pool.

Also noted on the diagram is that for motor gasoline with high octane #’s benzene accounts for less than 1% while aromatics, total are <15%

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Catalytic Hydrotreatment

As seen with the catalytic reforming in the previous section, catalytic hydrotreatment can be used as a pretreatment step to protect catalysts from crude oil contaminants such as heteroatom (S, N, O) compounds, as well as metals (mainly Ni, V). Hydrotreatment is also used as a major finishing process in a petroleum refinery. Shifting to the side stream products from the distillation column, kerosene and light gas oil fractions can be hydrotreated to remove the heteroatoms to produce the final products of jet fuel, and diesel fuel, as shown in Figure 3.4. Particularly strict sulfur limits are imposed on diesel fuels so that the particulate emissions from diesel engines can be reduced. In the U.S., the government regulations [3] require that highway and non-road locomotive and marine (NRLM) use diesel fuel that meets a maximum specification of 15 parts per million (ppm) sulfur by 2014, with a full compliance for highway use and non-road diesel fuel since December 2010. Note in Figure 5 that typical catalysts used for hydrotreating are Co and Mo compounds supported on alumina (Al₂O₃). Jet fuel consists of C₁₀ to C₁₅ hydrocarbons, and diesel fuel consists of C₁₅ to C₂₀ hydrocarbons. Analogous to octane number for gasoline, a performance parameter for diesel fuel is cetane number (n-C₁₆H₃₄, n-hexadecane) that measures, in contrast to octane number, the tendency (not resistance) of diesel fuel to ignite upon compression with air. As a side note, light gas oil fraction is not typically used in the U.S. for producing diesel fuel, but sent to catalytic cracking to make gasoline.

Figure 3.4. Catalytic hydrotreatment of jet fuel and diesel fuel.

Source: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Conversion of Heavy Gas Oil

Moving down to the side streams of the distillation column, heavy gas oil constitutes the next fraction in line. Some generic conversion processes for the heavy distillates, such as heavy gas oil (consisting of C₂₀ to C₂₅ hydrocarbons), are shown in Figure 3.5. These processes, aimed at reducing the molecular size or the boiling point of gas oil compounds, involve thermal cracking or catalytic cracking. A mild thermal cracking process, called visbreaking, is applied to reduce the viscosity of the feedstock, and it is more frequently applied to residual fractions, such as vacuum distillation residue. A more severe thermal cracking of heavy gas oil can be used to produce LPG and ethylene and light and middle distillates from heavy gas oil. A highly aromatic byproduct from thermal cracking is called ethylene tar. Ethylene is an important petrochemical feedstock, while ethylene tar can be used as feedstock to produce carbon blacks. Catalytic cracking is more frequently used for conversion of heavy gas oil to gasoline.

Figure 3.5. Conversion of heavy gas oil.

Click here for a text alternative to the figure above

Products and processes of heavy Gas Oil Conversion

Start: Heavy Gas Oil (from atm Distillation) > 20 – 25 Carbons goes to

• Visbreaking (mild thermal treatment)
  • Fuel oil
• Thermal Cracking
  • LPG, ethylene
  • Naphtha
  • Middle distillate (kerosene +light gas oil)
  • Ethylene Tar
• Catalytic Cracking
  • Produces branched chain alkanes
  • Slurry Oil
    •  clarified
      • Clarified slurry oil

Source: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

A particular process of catalytic cracking, Fluid Catalytic Cracking, is almost exclusively used worldwide in heavy gas oil and light vacuum gas oil conversion. This process produces high octane gasoline primarily, with important byproducts, including LPG, light olefins and i-alkanes, light cycle oil (LCO), heavy cycle oil (HCO), and clarified slurry oil (also called decant oil), as shown in Figure 3.6. LCO is used in the U.S. to produce diesel oil by hydrocracking, and decant oil can be used as fuel oil, feedstock for carbon black manufacturing, and to produce a special type of petroleum coke called needle coke. Needle coke has a microstructure that makes it a good precursor to graphite electrodes that are used in electric-arc furnaces to recycle scrap iron and steel. The manufacturing of graphite electrodes, using a byproduct from FCC used to produce gasoline, is considered a principal interface between petroleum refining and the iron and steel industry.

Figure 3.6. Fluid Catalytic Cracking (FCC) of heavy gas oil.

Click here for a text alternative to the figure above

Products and Processes of FCC

Start: Heavy Gas Oil (HGO) goes to

• FCC with Al3O3 + Zeolite catalysis
  • C2, LPG
  • Motor Gasoline
  • Light Cycle Oil (LCO)
  • FCC Slurry Oil
    • Decanting
      • Clarified Slurry Oil (CSO/Decant Oil)
        • Fuel Oil
      • Delayed Coking
        • Premium (needle) coke
          • Graphite electrodes

Source: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Conversion and Processing of Vacuum Gas Oils

Moving to the vacuum distillation column, the vacuum distillates, light vacuum gas oil (LVGO) and heavy vacuum gas oil (HVGO) can be processed by some advanced FCC processes. However, hydrocracking is more frequently used to convert LVGO and HVGO into light and middle distillates, using particular catalysts and hydrogen. Similar to LCO, the LVGO and HVGO fractions from vacuum distillation tend to be highly aromatic. Catalytic hydrocracking combines hydrogenation and cracking to handle feedstocks that are heavier than those that can be processed by FCC, because of excessive coke deposition on the catalyst in the absence of hydrogen. Middle distillates (e.g., kerosene and diesel fuel) are the principal products of hydrocracking.  In addition to light and middle distillates, hydrocracking also produces light distillates and LPG, as shown in Figure 3.7.

HVGO can also be used as a feedstock to produce lubricating oil base stock, through a sequence of solvent extraction processes to remove aromatic hydrocarbons by furfural extraction, and to remove long-chain paraffins by dewaxing (Figure 3.8).

Figure 3.7. Hydrocracking of light vacuum gas oil.

Click here for a text alternative to the figure above

Schematic of Hydrocracking Light Vacuum Gas Oil (25-35 Carbon Chains).

The carbon molecules undergo hydrocracking in the presence of hydrogen gas. The products come out as C3 and C4 molecules, along with light and medium distillates. The schematic also notes that the catalytic process includes hydrogenation (to saturate aromatic rings) and the cracking of C-C bonds.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 3.8. Solvent extraction and processing heavy vacuum gas oil.

Click here for a text alternative to the figure above

Schematic of Hydrocracking Heavy Vacuum Gas Oil (25-35 Carbon Chains).

The Heavy vacuum gas oil goes into solvent extraction with furfural which extracts the heavy aromatics. Then the products go into dewaxing which separates out long-chain b-paraffins (wax). That yields lube oil base stock, which becomes lubrication oils.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Processing and Conversion of Vacuum Distillation Residue

The heaviest and the most contaminated component of crude oil is the vacuum distillation residue (VDR), also referred to as the bottom-of-the-barrel. There are multiple processing paths to upgrade VDR into usable products. One process is called deasphalting, which removes the heaviest fraction of VDR as asphalt that is used mainly to pave roadways. The lighter fraction obtained in the deasphalting process, deasphalted oil (DAO), can be used as fuel oil after hydrotreatment (Figure 3.9).

Figure 3.9. Deasphalting of vacuum distillation residue.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Thermal processes, such as visbreaking and coking, also provide options for upgrading VDR, which is normally a solid at ambient temperature. As shown in Figure 3.10, the visbreaking operation involves mild thermal cracking, with the primary purpose of producing a relatively low grade fuel oil (with a much lower pour point than VDR) and byproducts such as middle and light (naphtha) distillates and LPG. The yield of these byproducts would normally not exceed 10%wt of VDR. As a general rule in refinery conversion processes, producing a lighter product with a higher H/C ratio (e.g., fuel oil, middle distillates, LPG) from a feedstock (e.g., VDR) would require the simultaneous formation of a heavier product (e.g., coke) with a lower H/C ratio than the feedstock. Clearly, this compensation is dictated by the hydrogen balance, or hydrogen distribution among the products. With no external hydrogen entering the conversion unit (as it would in hydrogenation, or hydrocracking reactions), making a product(s) with a higher H/C ratio than that of the feed would require making other product(s) with a lower H/C ratio than that in the feedstock. In the case of visbreaking, what enables the production of lighter (or lower viscosity) fuel oil and other products from VDR is the formation of small quantities of coke with an extremely low H/C ratio. Hence, the term disproportination describes this unequal distribution of C or H in the conversion products, or losing (rejecting) C in the coke that accumulates on reactor tubes and is periodically burned out to clean the reactor tubes.

Figure 3.10. Thermal processing of VDR by visbreaking, or coking processes.

Click here for a text alternative to the figure above

Visbreaking of VDR with mild thermal cracking yields C3 and C4 carbons, naphtha, middle distillates and fuel oil. As a penalty, it also produced coke (disproportionation!).

Coking of VDR with severe thermal cracking which yields light and middle distillates, and sponge coke & fuel grade coke which becomes anode coke, (low sulfur metals) which are used for aluminum production. This process also has some disproportionation.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

As different from visbreaking, coking involves severe thermal cracking with intentional production of coke with a low H/C, so that lighter fuels can be obtained from VDR (by disproportionation), as can also be seen in Figure 3.10. The product coke obtained from VDR with relatively low heteroatom concepts, termed sponge coke, can be used in manufacturing carbon anodes that are used in electrolysis of alumina (Al₂O₃) to produce aluminum metal. This is another important interface between petroleum refining and metals industries, similar to the coke produced from decant oil used for making needle coke for manufacturing graphite electrodes to operate electric-arc furnaces, as mentioned before.

Paths for Upgrading Heavy Oil

It should be clear from this quick tour of a refinery, that the most valuable products from a refinery include light distillates (gasoline) and middle distillates (jet fuel and diesel). These products are mostly paraffinic and contain relatively short paraffin chains, or small molecules, or, in other words, high H/C ratios. In this context, one could summarize the overall goal of petroleum refining as managing the H/C ratio of the products for the optimum distribution of hydrogen into products to maximize profits. Controlling the H/C ratio of the products would require either lowering the C content of the products (i.e., carbon rejection), or increasing the H content (i.e., hydrogen addition). The animation below depicts these two major paths for upgrading heavy oil (or crude oil) with some examples for each path. The processes, coking, solvent extraction (e.g., deasphalting), visbreaking, and catalytic cracking reject carbon in the coke (carbonaceous) product so that lighter products (with high H/C) ratios can be obtained in these processes. Carbon in the coke, or in the heavier product, is considered to have been rejected (and potentially lost) since the carbonaceous byproducts have much lower value in comparison to those of the lighter products. In contrast, hydrogen addition, as in the processes of hydrogenation and hydrocracking, enables the conversion of all the carbon present in heavy oil (or crude oil) to high value products without rejecting, or sacrificing, any. One might ask, then, why would any refinery carry out any carbon rejection process instead of hydrogen addition? A short answer to this question involves basic refinery economics; the hydrogen addition processes cost much more than carbon rejection processes, because producing hydrogen and the catalysts used in hydrogen addition processes are very expensive.

Video: FSC 432 Upgrading Heavy Oil (3:48)

Self-Check Questions

Please take a few minutes to answer the following questions. When you are happy with your responses, click Check below.

Assignment Reminder

Each week, you will have a number of assignments. This week's assignments are listed below with instructions on what to do. For due dates, please check your Syllabus.

Petroleum refining may be considered as the most sophisticated scheme of integrated physical and chemical processes to meet the market demand for a number of fuels and materials in the economy. In addition to satisfying the performance specifications required by combustion engines, the composition of the produced fuels, such as gasoline, jet fuel, and diesel fuel, should be in compliance with environmental regulations. Considering that crude oil is a natural material that displays a wide range of variability in hydrocarbon composition and the distribution of heteroatom species, it is vital to practice an optimum sequence of the four types of processes that make up petroleum refining: separation, conversion, finishing, and support. These processes are integrated as an example of industrial ecology, such that every drop of crude oil ends up as a marketable product, including the contaminants such as sulfur. The U.S. refineries are configured to maximize the yield of gasoline (a light distillate) as the major product, along with jet fuel and diesel fuel (middle distillates). A number of processes produce different gasoline streams that are blended in sophisticated linear and non-linear programming schemes to produce the three grades of gasoline sold in the U.S. for profit. A quick walk through the network of refinery processes reveals the two general strategies that are in place to create the most value in the operation: carbon rejection and hydrogen addition. The balance between these two strategies hangs in the refinery economics and the markets for crude oil and refined petroleum products.

Learning Objectives

You should now be able to:

• illustrate the refinery processes with examples for each category of processes;
• distinguish and evaluate the functions of different refinery processes to control refinery product yield and composition;
• evaluate the principles behind the major refinery processes and examine the products from each process, from Distillation to Hydrocracking;
• formulate strategies for upgrading heavy oil.

Reminder - Complete all of the Lesson 3 tasks!

You have reached the end of Lesson 3! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 4. 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.

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.

Overview

Video: FSC 432 Lesson 4 (2:23)

Overview

As introduced in Lesson 3, distillation is a key separation process that fractionates crude oil into a number of streams with specific boiling point ranges, or distillation cuts. Removing salt from crude oil usually precedes the distillation process to protect the downstream units from corrosion caused by Cl¯. Desalting process could also remove metals (e.g., Fe, Ni, V) and other inorganic solids and sediments that may deactivate catalysts used in conversion and finishing units. Depending on the specific gravity and the amount of salt present in a crude oil, refineries conduct from one up to three stages of desalting [1]. Heavy and crudes may require three stages of desalting, using processes such as gravity settling, electrostatic coalescence, and packed column separation [2]. Figure 4.1 shows a simple desalting process that uses gravity settling to separate brine (NaCl +H₂O) from crude oil after diluting the crude with water and adding de-emulsifiers (chemical additives) to facilitate phase separation.

Learning Outcomes

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

• compare and evaluate different distillation methods;
• define boiling point ranges (TBP) of distillation fractions of crude oil;
• identify and exemplify distillation terminology, including cut points and product yields in distillation ranges;
• illustrate the crude fractionation in Atmospheric Distillation and calculate the extent of separation between the distillation fractions;
• illustrate Vacuum Distillation and assess the application of Watson Characterization Factor to select the temperature in Vacuum Distillation Tower.

What is due for Lesson 4?

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 assignment below can be found on the Assignments page within this lesson.

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.

Atmospheric and Vacuum Distillation Units

Distillation of crude oil is carried out in two units, first in an Atmospheric Distillation Unit (also known as Crude Distillation Unit, CDU), with further processing of the residue from atmospheric distillation in the Vacuum Distillation Unit (VDU), as illustrated in Figure 4.2. For sake of simplicity, Figure 4.2 does not include the network of heat exchangers and pump around loops to pre-heat the desalted crude before it is fed into the fired furnace. In the furnace, the crude is heated to the desired temperatures (700-750° F) such that all the distillate fraction and roughly 10-20% of the bottom product are evaporated, depending on the volatility of crude oil. The two-phase mixture is then introduced into the CDU flash zone for separation of vapor and liquid streams, where the vapor fraction rises toward the top of the column and the liquid fraction is subjected to stripping with steam to recover the low-boiling distillate components dissolved in heavier liquid before sending the bottom product (i.e., atmospheric distillation residue) to the vacuum distillation unit.

Figure 4.1. Desalting by using gravity settling to separate brine from crude oil.

Source: S. Eser and M. R. Riazi, “Crude Oil Refining Processes” In Petroleum Refining and Natural Gas Processing, Editors: M. R. Riazi, S. Eser, J. L. Peña, ASTM International, West Conshohocken, PA, 2013, p. 105.

Figure 4.2. An overall flow for fractional distillation of crude oil.

Click here for a text alternative to the figure above

Schematic of an overall flow for fractional distillation.

Crude oil enters a desalter and then a heater. It then undergoes an atmospheric distillation where it refluxes. From that Heavy Gas Oil, Light Gas Oil, Kerosene, Light. & Heavy Naphtha and LPG and Fuel gas are separated out. The atmospheric residue goes to a separate heater and then into a vacuum distillation right where light vacuum gas oil and heavy vacuum gas oil are separated out along with vacuum residue.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

A temperature gradient is established in the column by removing heat from the overhead vapor. The column condenses the naphtha fraction and sends a portion of the liquid naphtha, as reflux, to the column to achieve a good separation of the distillate products drawn from the side of the distillation column, such as kerosene, LGO, and HGO, as seen in the diagram. Steam strippers on the side of the column also provide reflux to the main column to help with clean separation of the distillate products. Additional reflux is provided to the main column by pump around loops associated with heat exchangers (see Figure 4.3, below, and Figure 4.8 in the textbook) for preheating the crude. Counter-current flow of vapor and liquid streams through the contact stages (e.g., trays) in the main column, enabling good separation of the distillate fractions. The temperature at the bottom of CDU is limited to 700-750° F to prevent cracking – breaking of the chemical bonds between carbon atoms in the aliphatic hydrocarbons constituting the crude oil. Cracking would cause coking (accumulation of carbonaceous solids) on the metal surfaces in the column and interferes with fractionation in distillation. Vacuum distillation is necessary to fractionate the heavy distillates because further increase in temperature would cause thermal cracking of the feed components. In HYSYS Project 1 assignment, you will learn how to introduce crude assay data to a distillation simulator and calculate the yields of naphtha, kerosene, diesel, atmospheric gas oil, and residue for different crudes.

Figure 4.3. A schematic diagram of atmospheric distillation unit illustrating the feed heat exchangers, pump around loops, and side steam strippers (adapted from [3]).

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

As shown in Figure 4.4, below (and in Figure 4.10 in the textbook), the atmospheric residue is reheated in a fired furnace to 730-850° F before introduction into the vacuum distillation unit (VDU). The furnace outlet temperature is selected depending on the thermal reactivity (or coking propensity of crude oil, as will be discussed further) and the desired level of separation in the column. Steam ejectors, or, more recently, vacuum pumps, are used to create a vacuum for evaporation of the light vacuum gas oil and heavy vacuum gas oil fractions. The temperature and pressure in VDU also depend on whether steam is introduced, or the separation is carried out without the steam addition in “dry” towers, varying between 10 to 30 mmHg at the bottom of the tower. Lower pressures and higher temperatures are used in dry towers. To minimize the pressure difference between the bottom and top of the column, some special packing materials are used (see, for example, Figure 4.5) instead of trays for providing contact between liquid and vapor streams to improve fractionation.

Figure 4.4. Vacuum distillation unit and processing paths for vacuum distillates.

Click here for a text alternative to the figure above

Schematic of a vacuum distillation unit.

Atmospheric residue enters a heater and then a vacuum distillation tower. This tower has a pressure of 3 mmHg at the top and 28mgHG at the bottom. Steam is used to create the vacuuming the tower and flaring and sour water are products of steam production. The vacuum distillation tower yields heavy distillate, which can become lube oil base stocks or be sent to conversion units (hydrocracking). Additionally, there is some vacuum residue which goes to desasphalting or coking

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 4.5. Examples of packing materials to achieve low-pressure drop in vacuum distillation columns [4].

Credit: [4]Tower Packing [12]. Retrieved on April 16, 2014

The heavy distillates (light vacuum gas oil and heavy vacuum gas oil) separated in VDU are further processed in downstream separation and conversion units to produce lubricating oil base stocks, or as feedstock for hydrocracking to produce light and middle distillates. The residue from vacuum distillation (VDR) can be upgraded into marketable products and fuels using processes such as visbreaking, deasphalting, and coking, as will be discussed in later sections.

Distillation Methods

Three different distillation methods are commonly used to generate laboratory data on crude oil:

1. True Boiling Point Distillation (TBP)
2. ASTM Distillation (ASTM)
3. Equilibrium Flash Vaporization (EFV)

The degree of separation between the distillation fractions obtained in these methods decreases significantly as one moves down the list from TBP through ASTM to EFV. Each method and the associated distillation data have different applications in the refinery practice.

Distillation Terminology

It is important to use the correct terms to clearly represent the fractionation of crude oil by distillation. The distillation temperatures, or cut points, are used to delineate the distiilate fractions and define commercial fuels and solvents.

Assignment Reminder

Each week, you will be required to do a number of assignments. This week, in addition to the reading assignments listed on the overview page, you are also required to complete the exercise questions and take a quiz which will cover the material in Lessons 3 and 4.

Take a few minutes to answer the questions below to check your knowledge before taking the quiz or submitting your exercises.

Summary

Distillation, a key separation process in petroleum refining, is considered as a gateway to all refinery processes. Fractionation of crude oil by distillation into a number of streams generates feedstocks for all the subsequent separation, conversion, and finishing processes that lead to the refinery

products. Prior to distillation, crude oil is subjected to desalting to remove in particular the Cl^¯ion to prevent corrosion in downstream processes. Both atmospheric and vacuum distillation processes are used to separate the desired fractions from crude oil which has a boiling range of over a 1000° F. Three different distillation methods used in the laboratory include True Boiling Point distillation, used for characterization of crude oils, ASTM distillation for product characterization, and Equilibrium Flash Vaporization for conducting efficient flash operations in the refinery. The performance of an atmospheric distillation column can be monitored through using the ASTM distillation data obtained for the distillate products. The three parameters that control the performance of a distillation column in terms of the quality of separation achieved in the process are a number of plates, reflux ratio, and the amount of steam used in the operations. Empirical correlation relates these three factors to control the quality of separation in an operating distillation column or help design a new distillation column.

Learning Outcomes

You should now be able to:

• compare and evaluate different distillation methods;
• define boiling point ranges (TBP) of distillation fractions of crude oil;
• identify and exemplify distillation terminology, including cut points and product yields in distillation ranges;
• illustrate the crude fractionation in Atmospheric Distillation and calculate the extent of separation between the distillation fractions;
• analyze the vapor-liquid equilibrium and evaluate the application of Fenske Equation to distillation in Light Ends Unit;
• illustrate Vacuum Distillation and assess the application of Watson Characterization Factor to select the temperature in Vacuum Distillation Tower.

Reminder - Complete all of the Lesson 4 tasks!

You have reached the end of Lesson 4! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 5. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found within this lesson.

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.

Overview

Video: FSC 432 Lesson 5 (3:29)

Overview

This section will continue to discuss the separation processes that are carried out on the distillate products obtained from the atmospheric and vacuum distillation units, and the residue from the vacuum distillation unit, as introduced in Section 4. Light Ends Unit (LEU) fractionates the lightest fraction of crude oil obtained as overhead distillate from the atmospheric column in a series of distillation towers to produce LPG as a refinery product and straight-run light, and heavy naphtha for further processing in finishing and conversion units to produce gasoline streams for the blending pool (Section 3). Vacuum distillation residue (VDR) can be fractionated using solvent extraction (deasphalting) to produce an insoluble (asphalt) and a soluble fraction, deasphalted oil (DAO). DAO can be further processed by freezing point separation in a suitable solvent to separate wax. The remaining dewaxed oil is used as base stock for producing lubricating oil. Heavy vacuum gas oil (HVGO) can also be used as a feedstock for dewaxing.

Learning Outcomes

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

• analyze the vapor-liquid equilibrium and evaluate the application of Fenske Equation to distillation in Light Ends Unit;
• describe the principles of solvent fractionation as a separation technique;
• place the Deasphalting Process in the refinery and interpret the significance of this process for refining;
• interpret the gradient solubility model that explains the solution of asphaltenes in resin and oil fractions and analyze the structure of asphaltenes;
• analyze the process parameters for deasphalting and assess the anti-solvent effect;
• evaluate the unit operations of deasphalting and assemble the process flow diagram;
• explain the purpose of dewaxing and examine the physical and chemical dewaxing processes.

What is due for Lesson 5?

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 this lesson.

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.

Fractionation in Light Ends Unit (LEU)

Because of the low molecular weight and high volatility of the constituents in the overhead distillate, the feedstock to LEU can be analyzed on a molecular basis, using, for example, a gas chromatograph. The hydrocarbon range in overhead distillate (over a boiling point of gas to 380°F mid-boiling point) covers carbon numbers C₁ through C₁₀. Because of the relatively simple composition of this feed, the quality of separation in LEU units can be defined in terms of the concentrations of selected hydrocarbon compounds such as propane, butane, and i- butane. Remember that one needs to use the distillation data to define the quality of separation (in terms of ASTM gap, or ASTM overlap) between the adjacent cuts obtained from the side of atmospheric distillation column (Lesson 4).

Figure 5.1 shows the separation scheme in light end towers, where the feed is separated into the distillate (low-boiling point) and bottom (high-boiling point) fractions. Considering a depropanizer unit, the distillate will consist mainly of propane and lighter compounds, whereas the bottoms will contain butane and heavier hydrocarbons. To determine the degree of separation in the light end towers, the first step is to select the key components, which may be real compounds (such as butane, or i-butane), or a pseudo component which is defined by the mid-boiling point of the boiling range (i.e., temperature at which 50%_vol of the selected component is evaporated). Two key components (light key and heavy key) must be selected using the two selection rules, as shown in Figure 5.1.

Figure 5.1. Distillation in the light end towers.

Click here for a text alternative to the figure above

Fractionation in Light End Towers

- Measured by the distribution of “key” components in distillate and bottoms.

-Key components are selected as adjacent compounds/components in the feed stream

1) real compounds – C₄, i-C₄, C₅, i-C₅

2) Pseudo-components defined by mid-boiling points

-Two key components are selected as

1) Light Key – component with a lower boiling point

2) Heavy Key – component with a higher boiling point

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

The key component selection rules are:

1. Light key and heavy key should be adjacent compounds (in terms of boiling points) in the feed stream.
2. Both light key and heavy key must be present in the distillate and bottom fractions.

Once the key components are selected, their concentrations in the distillate and bottom fractions and their respective vapor liquid equilibrium coefficients (K values) can be used in the Fenske Equation to calculate the number of theoretical plates (including a reboiler) needed in the distillation column under the ideal condition of total reflux (100% reflux). Figure 5.2 shows the Fenske Equation and defines all the terms used in the equation. The ideal conditions assumed for using the Fenske Equation include 100% plate efficiency (for perfect separation in a plate) and total reflux in the column where no product is drawn as distillate. Total reflux means the whole overhead product is refluxed back to the column. Obviously, to get data on an actual (not an ideal) case of distillation, one needs to make two corrections to obtain the actual number of plates from the number of theoretical plates used in, or calculated by the Fenske Equation: 1) by assuming an actual plate efficiency to correct for 100% plate efficiency), 2) by assuming a correction factor to correct from total reflux (or infinite reflux ratio to the operational (actual) reflux conditions).

Figure 5.2. Fenske Equation and the definition of all terms in the equation.

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

It is common to use an actual plate efficiency of 75% (for plate efficiency correction), and a correction factor of 1.5 (for reflux ratio correction) for the operation under a finite (actual) reflux ratio from the total reflux condition. Therefore, these corrections could be made as follows:

# [actual plates (at 75% efficiency) at total reflux] = [theoretical # plates (at 100% efficiency)]/0.75

# [actual plates (at normal reflux)] = 1.5 x [actual plates (at 75% efficiency) at total reflux]

In other words, making both corrections from #theoretical plates used in Fenske equation to #actual plates after both corrections (for plate efficiency and reflux conditions) would give:

# actual plates = ([#theoretical plates used in Fenske Equation]/0.75) x 1.5

Deasphalting

While distillation achieves separation/fractionation of the feed components with respect to differences in their boiling point, deasphalting (as a solvent extraction process) fractionates the feedstock, atmospheric, or more often vacuum distillation residue (VDR), with respect to solubility/insolubility of molecular components in a given solvent. Figure 5.5 shows a solvent fractionation scheme used in laboratories to separate VDR into fractions that are defined based on the solubility behavior. VDR, which could be a solid at ambient temperature, is completely dissolved in aromatic solvents such as benzene and toluene. The highest molecular weight components of VDR classified as “asphaltene” can be separated by precipitation (as solid material) when a light paraffin solvent is mixed with VDR solubilized in an aromatic solvent (e.g., toluene). The paraffin solvent used (e.g., n-heptane) defines the identity of the separated asphaltenes (e.g., toluene soluble and n-heptane insolubles). The portion of VDR that is soluble in the paraffin solvent is called maltenes, but also labeled with respect to the solvent used in the separation, i.e., n-heptane maltenes. As can be seen in Figure 5.5, the n-heptane solubles can further be separated using n-pentane (a lighter and a weaker solvent) into insoluble (hard resin) and soluble (n-pentane solubles) fractions. The n-pentane solubles can also be separated using a lighter solvent yet (propane) to soft resin and oil products. In refinery practice, only one stage of separation is used, using the lightest solvent (e.g., propane) to produce asphalt and deasphalted oil (DAO) fractions, as discussed later in this section.

Asphaltenes consist of high-molecular weight compounds with strong aromatic character and contain the highest concentrations of heteroatom (S, N, and metal) species. Because of the low H/C ratio of asphaltenes and resins, the deasphalting process can be considered as a “carbon rejection” process, yielding a high H/C ratio product (i.e., oil) after removing the asphaltenes and resins, as, typically, lower value byproducts.

Figure 5.5. Solvent fractionation of vacuum distillation residue (VDR).

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

Gradient Solubility Model

Because of the large disparity in structure and properties of asphaltenes and oil fractions in VDR, it is surprising that VDR appears as a solution (one-phase material) rather than a suspension of discrete asphaltene particles in VDR. A commonly accepted hypothesis to explain the single phase observed with VDR is known as the gradient solubility model, illustrated in Figure 5.6. The model claims that asphaltene molecules (depicted as dark spheres in Figure 5.6a) can be dissolved in resins (light spheres) and the resulting solution can be dissolved in oil (wiggly lines), thus producing a single phase solution. Some model molecular structures proposed for asphaltenes are shown in Figures 5.6b and 5.6c. There is a more widespread acceptance of the smaller molecular structures shown in 6c, as better representatives of asphaltenes molecules among the asphaltene researchers.

Figure 5.6a. Gradient-solubility model to explain dissolution of asphaltenes in crude oil.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 5.6b. Proposed molecular structures for asphaltene molecules.

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

Figure 5.6c. Another proposed molecular structures for asphaltene molecules.

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

The gradient solubility model offers an explanation of how asphaltenes can be forced out of the solution in VDR by solvent extraction. Briefly, the solubility of a compound in a given solvent depends on the strength of the solvent that is measured by Hildebrand Solubility Parameters (HSP) for non-polar solvents. The two definitions of HSP are given in Figure 5.7, indicating the dependence of the parameter values on surface tension and molar volume of the solvent (1st Hildebrand parameter), or on the energy of vaporization (heat necessary to evaporate the solvent under constant volume conditions) and molar volume (2nd Hildebrand Parameter), respectively. These parameters correlate well with one another, and each can be used without any preference to express the dissolving power of a solvent. A discussion of the Solution Theory is beyond the scope of this course, but it would suffice to consider that solubility parameter increases with the increasing density (decreasing molar volume) and increasing surface tension, or increasing latent heat of vaporization. This explains why aromatic solvents have higher solvent power than aliphatic hydrocarbons, and why the solvent power of paraffins decreases with the decreasing carbon number.

It is now possible to explain that using a large volume of a paraffin solvent, added to dissolved VDR in a laboratory experiment, effectively disrupts the gradient solubility of asphaltenes, and as a result, asphaltenes precipitate as solid particles and can be filtered out for recovery. In refinery deasphalting process, however, e.g., in propane deasphalting [1], lower quantities of solvent (or lower solvent to resid (S/R) ratio) is used to separate asphalt (asphaltenes + resins) and deasphalted oil (DAO).

Figure 5.7. Hildebrand solubility parameters for non-polar solvents.

Click here for a text alternative to the figure above

Strength of non-polar solvents are described by Hildebrand Solubility Parameters.

1^st Hildebrand Parameter:

$$\delta _ { 1 } = \frac { \alpha } { V ^ { 1 / 3 } }$$

2^nd Hildebrand Parameter:

$$\delta _ { 2 } = ( \frac { \Delta E } { V } ) ^ { 1 / 2 }$$

$$\Delta E = \Delta H ^ { v } – RT$$

$$\delta _ { 2 } = ( \frac { ( \Delta H ^ { v } - R T ) } { V } ) ^ { 1 / 2 }$$

Key: α = Surface Tension, V = Molar Volume; ΔE = Energy of Vaporization;ΔH=Enthalpy of Vaporization

$$$$  

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

Deasphalting Process

Figure 5.8 places the deasphalting process in a refinery flow scheme as an intermediate process between vacuum distillation and dewaxing processes, for producing the refinery output streams as asphalt deasphalted oil (DAO), which can be directed to another separation process, dewaxing, to produce lubricating oil base stock and wax, or can be sent to conversion units such as hydrocracking to produce light and middle distillate fuels. It is important to note that the deasphalting process is an upgrading process to transform VDR into marketable products, and/or convert it to distillate fuels that command high demands.

Figure 5.8. Configuration of deasphalting and dewaxing processes in a petroleum refinery.

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

The two objectives of the deasphalting process are:

1. Produce asphalt - as final product.
2. Remove asphaltenes to prevent coke, or metal buildup on catalyst in further processing of DAO.

Depending on the properties of the VDR and prevailing markets, the emphasis could be placed on one of these objectives. Remember that aromatic asphaltic crudes are more expensive to convert into distillate fuels. Such crudes could be processed readily into making high yields of asphalt and serve the asphalt market. With lighter crudes, the principal focus could be on removing the asphaltenes from VDR so that DAO produced can be used in conversion processes with a lower extent of problems caused by asphaltenes such as coke buildup, or metals buildup on catalysts in, for example, hydrotreating or hydrocracking reactions.

Dewaxing

Another important separation process in petroleum refining is removal of wax. The process of dewaxing is introduced and discussed in the next subsection.

Figure 5.11 locates the dewaxing process in the refinery landscape. The feedstocks to dewaxing include DAO from deasphalting, and HVGO from vacuum distillation as shown in Figure 5.11 along with some compositional characteristics of the feedstock and the dewaxing product. Note that wax (long-chain paraffins) obtained in dewaxing is a marketable by-product. Lubricating oil base stock is the principal product of interest. The main purpose of dewaxing is to remove hydrocarbons that solidify readily (i.e., wax) for making lubricating oil base stock with low pour points (-9 to 14°F).

Figure 5.11. Feedstock for dewaxing and hydrocarbon composition of the feed and the products.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

In addition to low pour points, other important properties of lube oil base stocks include:

1. Volatility – should be low to keep oil in the liquid phase during engine operation. Vapors are not good lubricants.
2. Viscosity– important to control because of lubrication and heat transfer considerations. Moderate viscosities are desired. Low viscosity may not provide the required lubrication and lead to high friction between metal parts. High viscosity causes loss of energy.
3. Viscosity Index (change in viscosity with temperature) – small change in viscosity is desired over a wide temperature oil, i.e., high viscosity index (HVI). HVI ensures that the lube oil functions well at both cold start and at high temperatures generated by the engines.
4. Thermal Stability – High thermal stability (or small degree of thermal degradation at high temperatures) is necessary to minimize viscosity loss and coke deposition on metal surfaces.

All of these properties depend on the molecular composition of the hydrocarbons constituting the lubricating oil base stocks. Commercial engine oils and other commercial lube oils are formulated with chemical additives that would enhance the performance of the base stocks.

Two commercial methods of dewaxing are:

1. Solvent dewaxing - physical process; separation of wax by freezing and solvent transport.
2. Catalytic dewaxing - chemical process; removal of wax by selective reaction of long chain n-alkanes (wax).

Please take a few minutes to answer the questions before attempting this week's assessments. Click Check when you are happy with your answers.

Assignment Reminder

Each week, you will be required to do a number of assignments. This week, in addition to the reading assignments listed on the overview page, Exercise 4 is due as well as Exam 1 which will cover everything in Lesson 1-5.

Summary

Separation of the lowest-boiling fraction of the crude oil is carried out in Light Ends Unit using distillation columns that may yield almost pure products, such as propane and butane. Because of the simple molecular composition of the light ends, it is possible to use the data on vapor liquid equilibrium coefficients of pure compounds. On the heaviest end of the crude oil, Vacuum Distillation Residue can be processed using solvent extraction to separate asphalt from the residue to produce deasphalted oil for further treatment either by dewaxing to produce lubricating oil base stock, or by conversion reactions to produce distillate fuels from the deasphalted oil.

Learning Outcomes

You should now be able to:

• analyze the vapor-liquid equilibrium and evaluate the application of Fenske Equation to distillation in Light Ends Unit;
• describe the principles of solvent fractionation as a separation technique;
• place the Deasphalting Process in the refinery and interpret the significance of this process for refining;
• interpret the gradient solubility model that explains the solution of asphaltenes in resin and oil fractions and analyze the structure of asphaltenes;
• analyze the process parameters for deasphalting and assess the anti-solvent effect;
• evaluate the unit operations of deasphalting and assemble the process flow diagram;
• explain the purpose of dewaxing and examine the physical and chemical dewaxing processes.

Reminder - Complete all of the Lesson 5 tasks!

You have reached the end of Lesson 5! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 6. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found within this lesson.

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.

Video: FSC 432 Lesson 6 (3:47)

Overview

Thermal cracking is the first commercial conversion process developed in the early 1900s principally to produce more motor gasoline from crude oils and produce high-octane gasoline for aircraft use, initiating an attempt to change the composition of crude oil in petroleum refinery. The purpose of thermal cracking is to make light middle distillates from heavier ends by pyrolysis, or thermolysis. With the advent of catalytic cracking in the 1930s and 1940s and its capability to produce higher yields of gasoline with higher octane number, thermal cracking of gas oils has ceased to be an important process for gasoline production in modern refineries. In countries where the principal petroleum fuel with a high demand is diesel fuel, thermal cracking is still important in fuel refineries. A principal application of thermal cracking of distillate fractions in current refineries is limited to naphtha cracking for the purpose of producing ethylene (C₂H₄) for the petrochemical industry. However, thermal cracking of residual fractions, particularly VDR, is still practiced in association with visbreaking and coking processes in the refineries. The chemistry of thermal cracking and thermal cracking processes is discussed in this section.

Learning Outcomes

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

• summarize the chemistry of thermal cracking and free radical chain reactions;
• apply thermal cracking of gas oil to produce lighter distillates and examine how thermal reactivity affects process configuration;
• appraise thermal cracking for upgrading of residual fractions (visbreaking and coking) and interpret thermal severity to compare visbreaking processes;
• analyze and compare different coking processes: Delayed Coking, Fluid Coking and Flexicoking.

What is due for Lesson 6?

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 this lesson.

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.

Chemistry of Thermal Cracking

Thermal cracking produces shorter straight chain alkanes from longer straight chains found in gas oils or other crude oil fractions. Free radicals (reactive species with unpaired electrons, but no electronic charge) are the active species that govern thermal cracking reactions. Because of the free radical chemistry, thermal cracking of gas oil would produce gasoline with relatively low octane numbers, as will be discussed later in this section.

Figure 6.1 lists the three steps of free radical chain reactions as initiation, propagation, and termination. In the figure, R-H represents a paraffin chain which can be expanded such as (H₃-(CH₂)_n – H) where n represents the number of carbon atoms in the alkane. In other words, R represents a radical with an unpaired electron that becomes an alkane (R-H) when combined with a hydrogen atom. A Hydrogen atom with one proton and one electron is the simplest radical.

The free radical chain reaction starts with breaking the weakest C-C bond in the reactant alkane (R-H) to form two free radicals R₁ and R₂, each with one unpaired electron resulting from the homolysis of the C-C bond (initiation). Once formed by the initiation step, each free radical can go through two different propagation reactions:

1. Hydrogen abstraction
2. Beta (β) scission

Figure 6.1. Free radical chain reactions.

Click here for a text alternative to the figure above

Initiation

R-H → R₁• +R₂•.                                                                           Homolysis -homolytic bond cleavage

Propagation

R₁• + R-H → R₁-H + R•.                                                               Hydrogen abstraction – favored at high pressures

R₁• → olefin + R•.                                                                        β Scission – Favored at low pressures

Termination

R₄• + R₅• → R-R.                                                                          Radical combinations

2R₄• → olefin + alkane.                                                             Disproportionation

Isomerization reactions

C – C – C – C – C – C• → C – C• – C – C – C – C.                        Not favored

C = C + •C – C – C – C.                                                                 β Scission, faster than isomerization

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

In a hydrogen abstraction reaction, for example, the radical R₁ removes (abstracts) a hydrogen atom from an alkane (R-H) to produce a shorter chain alkane product (R₁-H) and a new radical R (hydrogen abstraction), thus propagating the free radical chain. Alternatively, the radical R_1, (or R₂) can go through a β scission reaction to produce an olefin (ethylene) as a product, and a radical R to propagate the chain. The β scission refers to the breaking of the covalent bond in the β position relative to the position of the unpaired electron, as shown below:

Figure 6.1b. The β scission

Note that the initiation step produces two free radicals, the propagation step produces a reaction product and one radical to continue the chain. The last step in the chain reaction, the termination step, removes two radicals to produce one or two stable compounds depending on the termination reaction, as seen in Figure 6.1. The principal end result of the free radical chain reactions in thermal cracking is to produce from long chain alkanes shorter-chain alkanes, light olefins, and some aromatic compounds. One important feature of free radical reactions is that isomerization reactions, e.g., shifting of the unpaired electron site from an edge atom of a molecule to the interior atoms (as shown in Figure 6.1), are not favored reactions. In other words, isomerization reactions take place at a slower rate than other propagation reactions, e.g., β scission reaction. The critical importance of this observation is that the thermal cracking reactions produce shorter straight-chain alkanes and olefins without any significant formation of branched-chain (or iso-alkanes). This is the reason why catalytic cracking processes have virtually replaced thermal cracking processes to produce high octane number gasoline, as will be discussed in the next section on catalytic cracking.

Knowledge Check

Please take a few minutes to answer the question below. Click "Check My Answer" to see some feedback.

Thermal Reactivity Considerations in Processing 

Management of thermal reactivity is important in thermal cracking processes for optimum conversion of the feeds with a wide boiling range. Figure 6.2 shows an example of a thermal cracking process to convert a heavy gas oil fraction primarily to light gas oil (LGO). Typically, lighter products (gasoline and gas) and the heavier product (fuel oil) are considered by-products in this process. A heavy gas oil feedstock with a wide boiling range is fed to a fractionator to separate the feed into a light oil and a heavy oil fraction, depending on the desired cut points. Light oil (which would have a relatively low thermal reactivity) is heated in a separate furnace to higher temperatures so that the cracking takes place in a vapor phase. Heavy oil fraction (with a high thermal reactivity) is heated to a lower temperature for cracking in the liquid phase. The heated feed streams are combined in a soak drum to provide sufficient time for the completion of the cracking reactions. After the soaker, the products are sent to a flash separator to separate the heavy end as a side product (fuel oil) and the lighter products are sent to the fractionator for separation into LGO, gasoline and the gaseous products. Separating the feed into two fractions will avoid heating the reactive longer alkane chains to high temperatures to keep coke formation and gas production under control to maximize the LGO yield. In naphtha cracking for ethylene production, all reactions are carried out in vapor phase at low pressures to promote β scission reactions for high ethylene yields. Coking of reactor tubes creates a major maintenance problem in naphtha cracking for ethylene production.

Figure 6.2. Thermal cracking process configuration.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Visbreaking

Visbreaking is a mild thermal cracking process applied to reduce the viscosity of VDR to produce fuel oil and some light products to increase the distillate yield in a refinery [1]. Depending on the feedstock properties and thermal severity in the reactor, the process will typically achieve 10–25% of conversion of the heavy ends to gas, gasoline, and distillates while producing fuel oil with the desired specifications. Carbon rejection in small quantities on the reactor surfaces during thermal cracking helps reduce the viscosity of the fuel oil product (Figure 6.3). The process decreases the demand for a cutter stock used as diluent (e.g., kerosene) that might otherwise be used to reduce the viscosity of the heavy ends to meet the fuel oil specifications. Adding a diluent may still be needed, depending on the sulfur content of the product and the fuel oil specifications. Although the principal objective of visbreaking is to reduce viscosity, some refineries may use this mild cracking process to convert fuel oil into lighter distillates.

Figure 6.3. Overall chemistry of visbreaking – breaking up long chains of hydrocarbons.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

As in all chemical reactions, conversion in visbreaking depends primarily on temperature and time. As a measure of “thermal severity” under reactions conditions, one can use a thermal severity index (TSI) as a function of temperature and time that is shown in Figure 6.4. The exponential dependence of TSI on temperature relates to the general exponential term that constitutes the chemical reaction rate constants. The chemical conversion in visbreaking reactions can be expressed as the reduction in concentration (c_A) of long-chain alkane (or high-molecular weight compounds) in the feedstocks. One can see from Figure 6.4 that the conversion in the visbreaking reaction can be expressed by the integral in Figure 6.4, assuming an apparent first-order kinetics for the reaction. It can also be seen, in Figure 6.4, that the conversion that can be related to the extent of visbreaking depends on (kt); and the TSI to establish the interchangeability of T and t for a given conversion relates to (e^(-Ea^/RT)t), where E_a is the apparent activation energy of the reaction, R is the universal gas constant, T is the temperature, and t is time. In using the TSI for comparing thermal severity of different T and t combinations as major operating variables of visbreaking, care should be taken to use the right units for R and T. As a general convention, an apparent activation of energy of 50 kcal/mol is assumed for thermal cracking reactions involving the homolysis of C-C bonds to produce free radicals.

Higher visbreaking severity would produce a higher reduction in viscosity. Thermal severity is limited by the reactivity of the feedstock and the storage stability of the residual fuel in accordance with the desired conversion level and desired reduction in viscosity. Asphaltene content and concarbon of the feedstocks are important factors to consider when selecting an appropriate thermal severity for the process to prevent excessive coking in the visbreaking reactor.

Figure 6.4. A definition of thermal severity index as a function of temperature (T) and time (t) in a visbreaker.

Click here for a text alternative to the figure above

“Thermal severity” of visbreaking is measured by a time and temperature relationship

TSI = Thermal severity index,    TSI = f (T, t)

$$ - \frac { d c _ { A } } { dt } = k c _ { A } \Rightarrow \int - \frac { d c _ { A } } { c _ { A } } = k t$$

Arrhenius equation:  $$k = A e ^ { - \frac { Ea } { RT } }$$

$$TSI = e ^ { - \frac { Ea } { RT } } t$$

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Coking

Despite the development of catalytic cracking processes, coking processes have survived as a popular refining process all over the world to refine the heavy end of crudes or heavy oils through carbon rejection as coke. Coking is the most severe thermal process used in the refinery to treat the very bottom-of-the-barrel of crude oil, i.e., vacuum residue.

Because of the high severity of thermal cracking during coking, the residue feed is completely converted to gas, light and medium distillates, and coke with no production of residual oil. Three different coking processes are used in the refineries: delayed coking, fluid coking, and flexi-coking (a variation of fluid coking). The common objective of the three coking processes is to maximize the yield of distillate products in a refinery by rejecting large quantities of carbon in the residue as solid coke, known as petroleum coke. Complete rejection of metals with the coke product provides an attractive alternative for upgrading the extra-heavy crude and bitumen, and that is particularly useful for initial processing of tar (or oil) sands for liberating the hydrocarbons from the sand that is left behind with the coke. Finding markets for the coke product as fuel or as filler for manufacturing anodes for the electrolysis of alumina (possible only with petroleum coke from delayed coking) makes the economics of coking more attractive by creating value for the rejected carbon. Sulfur and metal contents of the petroleum coke, as determined by the sulfur and metal contents of the residue feed, are two important factors that affect the commercial value of petroleum coke. Of the two coking processes, delayed coking is the preferred approach in many refineries that process heavy crudes.

Self-Check Questions

Please take a few minutes to answer the questions below before attempting to complete the assignments for this lesson. Click Check when you want to check your answers. 

Assignment Reminder

Each week, you will be required to do a number of assignments. This week, in addition to the reading assignments listed on the overview page, you are required to complete Exercise 5.

Summary

Physical separation of crude oil was not sufficient to meet the demand for motor fuels that had increased significantly with the increasing number of automobiles. Thermal cracking was therefore introduced as the first conversion process to produce more distillate fuels from petroleum refining. Thermal cracking, starting typically with breaking the C-C bonds in alkanes, proceeds with free radical chain reactions. One of the common outcomes of thermal cracking is to make light or medium distillates from the heavier fractions of the crude oil. Visbreaking, a mild (low-severity) thermal cracking process, reduces the viscosity of the VDR by rejecting a small quantity of coke as deposits on reactor surfaces. The principal product of visbreaking from VDR is a heavy fuel oil. On the other end of the thermal conversion spectrum, coking, the most severe thermal cracking process, converts VDR to light distillates and gaseous products by rejecting carbon in large quantities in the form of petroleum coke. If the sulfur and metal contents of VDR are sufficiently low, the petroleum coke can be a valuable by-product that is used for producing anode coke for electrolysis of alumina to produce metallic aluminum.

Learning Outcomes

You should now be able to:

• summarize the chemistry of thermal cracking and free radical chain reactions;
• apply thermal cracking of gas oil to produce lighter distillates and examine how thermal reactivity affects process configuration;
• appraise thermal cracking for upgrading of residual fractions (visbreaking and coking) and interpret thermal severity to compare visbreaking processes;
• analyze and compare different coking processes: Delayed Coking, Fluid Coking and Flexicoking.

Reminder - Complete all of the Lesson 6 tasks!

You have reached the end of Lesson 6! Double-check the to-do list on the Lesson 6 Overview page to make sure you have completed all of the activities listed there before you begin Lesson 7.

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.

Overview

Video: FSC 432 Lesson 7 (5:00)

Overview

Catalytic conversion processes became important in petroleum refining after the Second World War. Catalytic cracking has been developed to produce high yields of gasoline with high octane # from high-boiling stocks using catalysts. As different from thermal cracking, catalytic cracking.

• uses a catalyst;
• takes place at lower temperature and lower pressure;
• is more selective and flexible.

One particular catalytic cracking process, Fluid Catalytic Cracking (FCC), has captured universal acceptance in the refining industry because of its feed flexibility, ability to modify product yields through minor changes in the process operating conditions. FCC is used to produce high-octane gasoline mainly from straight-run atmospheric gas oil and light vacuum gas oil (LVGO) [1]. This process involves breaking up long chains of n-alkanes into shorter chains of branched alkanes (isoalkanes), cycloalkanes (naphthenes), and aromatics by using acidic catalysts. In addition to high-octane gasoline, catalytic cracking produces LPG, cycle oils, and olefin-rich light hydrocarbons (C3, C4). The olefins are used as petrochemical feedstocks, or as reactants in alkylation and polymerization reactions, to produce higher molecular weight branched alkanes and olefins to contribute to the high-octane gasoline pool.

Hydrocracking processes have been introduced for upgrading heavier crude oil fractions such as heavy vacuum gas oil (HVGO) and vacuum distillation residue VDR. The heaviest fractions of crude oil, HVGO and VDR, may not be easily processed by FCC because of potential problems with excessive coking on the catalysts. For upgrading these high-boiling and aromatic-rich feedstocks, hydrogen is introduced in the hydrocracking process, along with bi-functional catalysts systems, to keep coking under control while upgrading the heavy fractions to light and middle distillates.

Learning Outcomes

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

• distinguish the chemistry of catalytic cracking from chemistry of thermal cracking and illustrate the formation of carbocations and IUPAC terminology for classification of carbocations;
• categorize the formation of different carbocations on active sites of cracking catalysts and assess the classification of acid sites (Lewis vs Bronsted) on catalyst surfaces;
• compare, with examples, how the product yields and composition obtained from catalytic differ from those from thermal cracking;
• analyze the thermodynamics of carbocation formation and evaluate how ionic chain reactions produce hydrocarbons with high octane numbers;
• appraise the historical evolution of catalytic cracking processes and formulate the driving forces that have shaped this evolution in reactor design and catalyst development;
• locate the hydrocracking process and hydroprocessing in the refinery flow diagram, illustrate hydrocracking processes and evaluate different process objectives.

What is due for Lesson 7?

This lesson will take us less than 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 this lesson.

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.

Chemistry of Catalytic Cracking

As opposed to thermal cracking governed by free radicals, catalytic cracking proceeds through the formation of ionic species on catalyst surfaces, and produces shorter, but branched-chain (not straight-chain) alkanes by cracking the long straight-chain alkanes. The formation of branched-chain alkanes, or iso-alkanes, leads to the production of gasoline with high octane numbers. This is the fundamental reason why catalytic cracking has replaced thermal cracking as the central process in a refinery geared to maximize gasoline production. A high octane number of gasoline is needed for current spark-ignition engines to run at high compression ratios without knocking. High compression ratios in spark-ignition engines translate to high power and high efficiency.

Figure 7.1 introduces the two types of ionic species, carbocations, that are active in catalytic cracking reactions as carbenium, and carbonium ions, using the IUPAC terminology. Carbocations are the positively charged ions made from hydrocarbons. Figure 7.1 shows that removing a hydride ion (H^-, a hydrogen atom with an additional electron) from an alkane (e.g., methane) produces carbenium ions (path 1a). Also, adding a proton (H⁺, a hydrogen atom without the electron) to an olefin (e.g., ethylene) can produce carbenium ions, as shown in path 1b.

Figure 7.1. Definition and formation of carbocations from hydrocarbons.

Click here for a text alternative to the figure above

Formation of Carbocations

IUPAC terminology

-Carbenium ions: CH₄ (arrow) H^- + CH3⁺ (alkane – hydride ion)

-C₂H₄ + H⁺ (arrow) C₂H₅⁺. (olefin + proton)

-Carbonium Ions: CH₄ + H⁺ (arrow) CH4

KEY: H^- (hydride ion), H⁺ (proton)

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Analogous to the terminology used for free radicals, C⁺H₃ is called methyl carbenium ion, and C₂⁺H₅ is called an ethyl carbenium ion. Carbonium ions are produced by adding a proton to an alkane, say methane, as shown in Figure 7.1. The resulting ion C⁺H₅ is called methanium. Note that there is some confusion in the literature about naming the carbocations. Carbenium ions used to be called carbonium ions in some sources, including your textbook [2]. All references to carbonium ions in Section 6.3 Cracking Reactions in the textbook should be corrected as carbenium ions.

Catalytic Cracking Processes

Increasing demand for gasoline, along with the need to produce high-octane gasoline for increasingly more powerful spark ignition engines, led to the development and maturation of catalytic cracking processes just before and during World War II. Following the development of a fixed-bed (Houdry process, 1936) and a moving-bed (Thermafor Catalytic Cracking, 1941) catalytic cracking process, fluid-bed catalytic cracking (FCC, 1942) became the most widely used process worldwide because of the improved thermal efficiency of the process and the high product selectivity achieved, particularly after the introduction of crystalline zeolites as catalysts in the 1960s.

The list below shows a timeline for the development of the catalytic cracking processes. The evolution of catalytic cracking processes is an exemplary showcase in chemical engineering for discussing the advancement of reactor configuration, driven by energy conservation and process kinetics. The evolution of these processes is discussed in the following subsections.

Historical Time-Line for Catalytic Cracking Processes

1. McAfee (1915)

   • Batch reactor catalytic cracking to produce light distillates

   • Catalyst: A1Cl3 – A Lewis acid, electron acceptor

   • Alkane – electron(abstracted by A1Cl3)→ a carbocation⁽⁺⁾→ ionic chain reactions to crack long chains

2. Houdry (1936) - a commercial process

   • Continuous feedstock flow with multiple fixed-bed reactors

   • Cracking/catalyst regeneration cycles

   • Catalyst: clays, natural alumina/silica particles

3. Thermafor Catalytic Cracking (TCC) (1942)

   • Continues feedstock flow with moving-bed catalysts

   • Catalyst: synthetic alumina/silica particles

   • Higher thermal efficiency by process integration

4. Fluid Catalytic Cracking (FCC) (1942)

   • Continuous feedstock flow with fluidized-bed catalysts

   • Catalyst: synthetic alumina/silica+zeolites (1965)

Catalytic Hydrocracking

Catalytic hydrocracking is one of the latest additions to petroleum refining processes, with the first modern commercial unit started up by Chevron in 1958. The interest in hydrocracking has been attributed to the increasing demand for light and middle distillates, the availability of byproduct hydrogen in large quantities from catalytic reforming, and the environmental regulations limiting sulfur and aromatic hydrocarbons in motor fuels [5]. The advantages of hydrocracking include its ability to handle a wide range of feedstocks that may be difficult to process by catalytic cracking and its flexibility in selectivity between light and middle distillates. The principal objective of hydrocracking is to decrease the molecular weight and boiling point of heavy oils to produce saturated hydrocarbons (diesel and jet fuel) from highly aromatic feedstocks (e.g., LCO from FCC) and distillation residua.

The hydrocracking process has two dimensions: Hydrogenation of aromatic rings and cracking of aliphatic compounds, as shown in Figure 7.10, using naphthalene as an example for an aromatic ring system. One should note that the aromatic rings cannot be cracked before they are saturated with hydrogen. With hydrocracking, it is possible to convert an aromatic compound to a paraffinic compound without any loss of carbon, as shown in Figure 7.10. As a hydrogen-addition process, hydrocracking provides high yields of valuable distillates without producing low-grade byproducts (e.g., heavy oils, gas, or coke) as experienced in carbon rejection processes such as coking.

Figure 7.10. Reactions of hydrocracking.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Self-Check Questions

Please take a few minutes to answer the questions below. When you are satisfied with your responses, click Check My Answers to see how well you understood this lesson. These questions will help you study for the next quiz.

Assignment Reminders

Exercise 6: Solve a problem on the material balance for the regenerator in Fluid Catalytic Cracking Process.

Quiz 3. Will cover material in Lessons 6 and 7. Check the Syllabus, or Course Calendar for Quiz 3 schedule.

Summary

Catalytic processes constitute the core of the petroleum refineries to accomplish a number of conversion and finishing tasks. Catalytic cracking has been developed to produce high yields of gasoline with high octane # from high-boiling stocks using catalysts. Compared to thermal cracking, catalytic cracking takes place at lower temperatures and pressures and proceeds through carbocationic active species produced on acidic sites on catalyst surfaces. Fluid Catalytic Cracking (FCC) has become a universal refining process because of its high efficiency and feed flexibility. This process involves breaking up long chains of n-alkanes into shorter chains of branched alkanes (isoalkanes), cycloalkanes (naphthenes), and aromatics in high yields. Although the main product from FCC is high-octane number gasoline, it also produces LPG, cycle oils, and olefin-rich light hydrocarbons (C3, C4). The olefins are used as petrochemical feedstocks, or as reactants in alkylation and polymerization reactions, to produce higher molecular weight branched alkanes and olefins to contribute to the high-octane gasoline pool. Hydrocracking processes have been introduced for upgrading heavier crude oil fractions such as heavy vacuum gas oil (HVGO) and vacuum distillation residue VDR. The heaviest fractions of crude oil, HVGO and VDR, may not be easily processed by FCC because of potential problems with excessive coking on the catalysts. For upgrading these high-boiling and aromatic-rich feedstocks, hydrogen is introduced in the hydrocracking process, along with bifunctional catalysts systems, to keep coking under control while upgrading the heavy fractions to light and middle distillates.

Learning Outcomes

You should now be able to:

• distinguish the chemistry of catalytic cracking from the chemistry of thermal cracking and illustrate the formation of carbocations and IUPAC terminology for classification of carbocations;
• categorize the formation of different carbocations on active sites of cracking catalysts and assess the classification of acid sites (Lewis vs Bronsted) on catalyst surfaces;
• compare with examples how the product yields and composition obtained from catalytic processes differ from those from thermal cracking processes;
• analyze the thermodynamics of carbocation formation and evaluate how ionic chain reactions produce hydrocarbons with high octane numbers;
• appraise the historical evolution of catalytic cracking processes and formulate the driving forces that have shaped this evolution in reactor design and catalyst development;
• locate the hydrocracking process and hydroprocessing in the refinery flow diagram, illustrate hydrocracking processes, and evaluate different process objectives.

Reminder - Complete all of the Lesson 7 tasks!

You have reached the end of Lesson 7! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 8. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found within this lesson.

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.

Overview

Video: FSC 432 Lesson 8 (7:52)

Overview

Among the catalytic conversion processes developed just before and during the Second World War are included, in addition to catalytic cracking, polymerization processes that were introduced in the mid- to late 1930s, and alkylation and isomerization processes that were developed in the early 1940s. The principal impetus for developing these processes was to meet the demand for high-octane-number gasoline required by the high compression gasoline engines, including those used in the aircraft. Catalytic reforming and catalytic isomerization were developed in the 1950s to increase the high-octane-number gasoline yields from refineries. These processes are still important in current refineries that are directed to maximize gasoline yield from the crude oil feedstock. By-products from some of these processes, such as LPG and hydrogen, have gained significance because of the increasing demand in modern refineries for LPG recently used as automobile fuel and for hydrogen to supply the increasing demand for hydrotreating and hydrocracking processes.

Learning Outcomes

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

• locate the catalytic reforming process in the refinery flow diagram, summarize the process objectives and evaluate the chemical reactions that take place in catalytic reforming to realize the process objectives;
• identify the catalysts used for catalytic reforming, evaluate the reaction network and the activity of catalysts, and illustrate the desirable reactions with specific examples;
• outline the principles of thermodynamics, kinetics, and transport phenomena to formulate limits on reaction conditions for controlling desirable and undesirable reactions in catalytic reforming;
• assess the commercial catalytic reforming processes and compare catalyst regeneration practice in each process;
• place the alkylation process in the refinery flow diagram particularly in relation to FCC process and describe the purpose of alkylation;
• demonstrate alkylation reaction mechanisms and evaluate the use of concentrated acid catalysis of alkylation;
• demonstrate polymerization reaction mechanisms and compare alkylation and polymerization reactions and catalysis.

What is due for Lesson 8?

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 this lesson.

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.

Catalytic Reforming

Catalytic reforming converts low-octane, straight-run naphtha fractions, particularly heavy naphtha that is rich in naphthenes, into a high-octane, low-sulfur reformate, which is a major blending product for gasoline. The most valuable byproduct from catalytic reforming is hydrogen to satisfy the increasing demand for hydrogen in hydrotreating and hydrocracking processes. Most reforming catalysts contain platinum as the active metal supported on alumina, and some may contain additional metals such as rhenium and tin in bi- or tri-metallic catalyst formulations. In most cases, the naphtha feedstock needs to be hydrotreated before reforming to protect the platinum catalyst from poisoning by sulfur or nitrogen species. With the more stringent requirements on benzene and the total aromatics limit for gasoline in the United States and Europe, the amount of reformate that can be used in gasoline blending has been limited, but the function of catalytic reforming as the only internal source of hydrogen continues to be important for refineries.

Figure 8.1 locates the catalytic reforming process in a refinery. The feedstock for catalytic reforming is straight-run (directly from the crude oil) heavy naphtha that is separated in the naphtha fractionator of the Light Ends Unit, as discussed in Lesson 4. Light naphtha from the naphtha fractionator, inherently a low-octane-number fraction, can be sent directly to blending in gasoline pool after hydrotreating, if necessary, or sent to an isomerization process to increase its octane number. As discussed in Lesson 3, hydrotreating heavy naphtha is often necessary before catalytic reforming to protect the noble metal catalyst (e.g., Pt) used in the reforming process. The intended product from catalytic reforming is the high-octane-number reformate and the most significant by-product is hydrogen gas.

Figure 8.1. Placement of catalytic reforming process in a refinery.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Chemistry of Catalytic Reforming

The general categories of the desired reactions in catalytic reforming are identified in the list below, along with the catalysts used in the process. Considering that the main purpose of the process is to increase the octane number of heavy naphtha, conversion of naphthenes to aromatics and isomerization of n-paraffins to i-paraffins are the most important reactions of interest. Under the right reaction conditions, aromatics in the feed, or those produced by dehydrogenation naphthenes, should remain unchanged. The reforming reactions produce large quantities of hydrogen, and one should remember that the dehydrogenation catalysts used in reforming can also catalyze hydrogenation and hydrocracking of aromatics during catalytic reforming. It is, therefore, important to keep these side reactions to a minimum by controlling the reactor conditions such as temperature and hydrogen pressure, as discussed in more detail later in this section.

The catalysts used in reforming contains platinum (Pt), palladium (Pd), or, in some processes, bimetallic formulations of Pt with Iridium or Rhenium supported on alumina (Al₂O₃).

Catalytic Reforming Reactions and Catalysts

Reactions of Interest

1. naphthenes → aromatics
2. paraffins are isomerized
3. aromatics are unchanged

Catalysts Used

Platinum catalyst on metal oxide support (platforming)

Pt/Al2O₃

Bimetallic – Iridium or Rhenium

Pt-Re/Al2O₃
 

The information above shows the ranges of composition for feedstock heavy naphtha and the reformate product (high-octane gasoline). Comparing the compositions of the feedstock and the product, one can see that the largest change in feedstock composition is a substantial increase in the aromatics content of the feedstock, with attendant decreases in naphthene and paraffin contents to constitute the product.

Catalytic Reforming Feedstock and Product

Low severity (relatively low octane) → low paraffin conversion

High severity → high paraffin conversion

Lean naphtha → high n-paraffinic content - difficult to process

Rich naphtha → low n-paraffinic (high naphthene) content - easy to process

The information above also defines some specific terms for catalytic reforming related to the feedstock composition (lean, or rich naphtha), or to the extent of n-paraffin conversion in the process (low-, or high-severity). One could conclude from these terms that reforming of heavy naphtha that contains higher n-paraffin content requires more severe conditions in the reactor.

Catalytic Reforming Processes

Even in the presence of hydrogen during reforming reactions, catalysts are deactivated by coke deposition. Commercial catalytic cracking processes are classified based on how catalysts are regenerated, as shown below, as semi-regenerative, cyclic, and continuous reforming processes. The first commercial catalytic reforming process was introduced by UOP in 1949 as the Platforming^TM process that used three fixed-bed reactors. Figure 8.4 (on next page), shows a process with two reactors. The reactors operate in series with furnaces placed before each reactor to heat the feedstock and the reactor effluents to 500–530°C before entering each reactor because the predominant reforming reactions are highly endothermic. These units, called “semi-regenerative catalytic reformers,” need to be shut down once every 6–24 months for the in-situ regeneration of catalysts that are deactivated by coke deposition. Later designs included an extra reactor (a swing reactor) to enable isolation of one reactor at a time to undergo catalyst regeneration, whereas the other three reactors are running (Cyclic). This configuration enables longer on-stream times (up to 5 years) before scheduled shutdowns for catalyst regeneration, but it has not become popular. In the HYSYS Project 2, you will be comparing the performance of the three different configurations of catalytic reforming processes.

Catalytic Reforming Processes

Catalytic Reforming Processes Based on Catalyst Regeneration

1. Semi-regenerative (1949) – unit taken off-stream anywhere from every 3 to 24 months
2. Cyclic (1960) – involves swing reactor. Basically, operate 3 out of 4 and use extra reactor to take one offline.
3. Continuous (1971) – catalyst is removed and replaced during the operation. Maintains high activity. Expensive.

Licenced Processes (differences in catalysts and reactor configurations)

1. Platforming (UOP process) (1949)
2. Powerforming (Exxon)
3. Ultraforming (Amoco)
4. Catalytic Reforming (Engelhard)
5. Magnaforming (Arco)
6. Reforming (IEP)
7. Rheniforming (Chevron)

Alkylation 

The alkylation process combines light iso-paraffins, most commonly isobutane, with C₃–C₄ olefins, to produce a mixture of higher molecular weight iso-paraffins (i.e., alkylate) as a high-octane number blending component for the gasoline pool. Iso-butane and C₃–C₄ olefins are produced as by-products from FCC and other catalytic and thermal conversion processes in a refinery. The alkylation process was developed in the 1930s and 1940s to initially produce high-octane aviation gasoline, but later it became important for producing motor gasoline because the spark ignition engines have become more powerful with higher compression ratios that require fuel with higher octane numbers. With the recent restrictions on benzene and the total aromatic hydrocarbon contents of gasoline by environmental regulations, alkylation has gained favor as an octane number booster over catalytic reforming. Alkylate does not contain any olefinic or aromatic hydrocarbons.

Alkylation reactions are catalyzed by strong acids (i.e., sulfuric acid [H₂SO₄] and hydrofluoric acid [HF]) to take place more selectively at low temperatures of 70°F for H₂SO₄ and 100°F for HF. By careful selection of the operating conditions, a high proportion of products can fall in the gasoline boiling range with motor octane numbers (MONs) of 88–94 and RONs of 94–99 [15]. Early commercial units used H₂SO₄, but more recently, HF alkylation has been used more commonly in petroleum refineries. HF can be more easily regenerated than H₂SO₄ in the alkylation process, and HF alkylation is less sensitive to temperature fluctuations than H₂SO₄ alkylation [3]. In both processes, the volume of acid used is approximately equal to the volume of liquid hydrocarbon feed. Important operating variables include acid strength, reaction temperature, iso-butane/olefin ratio, and olefin space velocity. The reactions are run at sufficiently high pressures to keep the hydrocarbons and the acid in the liquid phase. Good mixing of acid with hydrocarbons is essential for high conversions.

Some examples of desired alkylation reactions (combination of iso-paraffins with olefins) are given in Figure 8.6. These occur through ionic chain reactions (Figure 8.7) initiated by donation of a proton from the acid catalyst to an olefin to produce a carbocation that reacts with iso-butane to form a tert-butyl cation. Subsequent propagation reactions involve the reactions of a tert-butyl cation with olefins to form larger iso-paraffin cations that lead to final products through reactions with iso-butane to form a new tert-butyl cation to sustain the chain reaction [3]. The alkylation reaction is highly exothermic; therefore, cooling the reactor contents during alkylation is important.

Figure 8.6. Principal alkylation reactions.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 8.7. Acid catalyzed alkylation reactions.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Polymerization

The polymerization process combines propenes and butenes to produce higher olefins with high-octane numbers (97 RON and 83 MON) for the gasoline pool. The polymerization process was used extensively in the 1930s and 1940s, but it was replaced to a large extent by the alkylation process after World War II. It has gained favor after phasing out the addition of tetraethyl lead (TEL) to gasoline, and the demand for unleaded gasoline has increased. Typical polymerization reactions are shown in Figure 8.9 [5].

The most commonly licensed polymerization process is the UOP polymerization process, which uses phosphoric acid as catalyst. IFP licenses a Dimersol® process that produces dimers from propene or butene using a homogeneous aluminum alkyl catalyst.

Figure 8.9. Typical polymerization reactions [5].

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Isomerization

Isomerization processes have been used to isomerize n-butane to iso-butane used in alkylation and C₅ /C₆ n-paraffins in light naphtha to the corresponding iso-paraffins to produce high-octane number gasoline stocks after the adoption of lead-free gasoline. Catalytic isomerization processes that use hydrogen have been developed to operate under moderate conditions. Typical feedstocks for the isomerization process include hydrotreated light straight-run naphtha, light natural gasoline, or condensate. The fresh C₅/C₆ feed combined with make-up and recycled hydrogen is directed to a heat exchanger for heating the reactants to reaction temperature. Hot oil or high-pressure steam can be used as the heat source in this exchanger. The heated feed is sent to the reactor. Typical isomerate product (C₅₊) yields are 97 wt% of the fresh feed, and the product octane number ranges from 81 to 87, depending on the flow configuration and feedstock properties.

Self-Check Questions

Before attempting to take the quiz this week, spend a few minutes answering the questions below. Make sure to click Check to see how well you understand the content.

Assignment Reminder

Each week, you will have a number of assignments. This week's assignments are listed below with instructions on how and where to submit them. For due dates, please check your syllabus.

Summary

Catalytic reforming, alkylation and polymerization processes aim at increasing the yield of high-octane-number gasoline in the refineries. Catalytic reforming uses naphthene-rich, straight-run heavy naphtha as feedstock and produces a high-octane number reformate for the gasoline blending pool in a refinery. Principal catalytic reactions that take place on noble metals (e.g., Pt) and on acidic catalyst supports (e.g., Al₂O₃) produce high yields of aromatic hydrocarbons and i-alkanes, respectively, to result in a high-octane number product. A valuable by-product from catalytic reforming is hydrogen gas for which the demand is increasing in the refineries, particularly for finishing processes, such as hydrotreatment. Alkylation and polymerization reactions take shorter chains of C₃, C₄ alkanes and olefins and combine them to get branched C₇, C₈ alkanes in alkylate, and polymerate, respectively, to increase the yield of high-octane gasoline. Isomerization processes convert n-butane to i-butane to be used as feed in alkylation processes, or isomerize n-C₅ and n-C₆ to the corresponding i-alkane to produce, again, high-octane-number gasoline stock.

Learning Outcomes

You should now be able to:

• locate the catalytic reforming process in the refinery flow diagram, summarize the process objectives and evaluate the chemical reactions that take place in catalytic reforming to realize the process objectives;
• identify the catalysts used for catalytic reforming, evaluate the reaction network and the activity of catalysts, and illustrate the desirable reactions with specific examples;
• outline the principles of thermodynamics, kinetics and transport phenomena to formulate limits on reaction conditions for controlling desirable and undesirable reactions in catalytic reforming;
• assess the commercial catalytic reforming processes and compare catalyst regeneration practice in each process;
• place the alkylation process in the refinery flow diagram particularly in relation to FCC process and describe the purpose of alkylation;
• demonstrate alkylation reaction mechanisms and evaluate the use of concentrated acid catalysis of alkylation;
• demonstrate polymerization reaction mechanisms and compare alkylation and polymerization reactions and catalysis.

Reminder - Complete all of the Lesson 8 tasks (Blog 8 and Quiz 4)!

You have reached the end of Lesson 8! Double-check the to-do list in the table below to make sure you have completed all of the activities listed there before you begin Lesson 9. 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.

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.

Overview

Video: FSC 432 Lesson 9 (7:46)

Overview

Following our discussion on separation and conversion processes, this lesson will cover the third type of refining processes – finishing processes. Finishing processes include hydrogenation for stabilization of petroleum products, hydrotreating to remove heteroatoms (S, N, and metals) and product blending to attain the product specifications and assure compliance with environmental and government regulations on petroleum fuels and materials. The finishing step is the last stage before the hydrocarbon streams from different units leave the refinery as commercial fuels and materials. Therefore, the challenges involved both hydrotreatment and blending operations are diverse and complex. The constraints on the commercial fuels that need to be satisfied simultaneously range from composition and performance specifications to seasonal fluctuations in demand for different fuels and materials. A brief overview of only the basic concepts in finishing operations is presented in this lesson.

Learning Outcomes

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

• compare hydrogenation and hydrotreatment with respect to process goals, catalysis, and chemistry;
• categorize and evaluate HDS, HDN, and HDM processes;
• assess hydrotreatment catalysts, kinetics and process configurations;
• demonstrate procedures to calculate critical properties of blended products, e.g., octane number, pour point, and viscosity.

What is due for Lesson 9?

Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found in this lesson.

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.

Hydrogenation

Hydrogenation, or adding hydrogen to unsaturated hydrocarbons, is used for stabilization of petroleum products and aromatic reduction [1]. One particular application of hydrogenation is to saturate unstable olefins and di-olefins that are implicated in producing gums (high-molecular-weight sticky semi-solid material) during the storage of fuels, such as gasoline and jet fuel. Gum formation is detrimental, particularly, to the operation of fuel injectors in combustion engines. Narrow passages found in fuel injectors can be partially or completely plugged with deposition/accumulation of gums on flow surfaces, causing engine failures. Figure 9.1 on the next page shows examples of hydrogenation of an aromatic compound (alkylated naphthalene) and an olefin. The objective of hydrogenation is just adding hydrogen to unsaturated hydrocarbons using precious metal (Pt, Pd) or Ni catalysts at low temperatures to avoid cracking or other chemical changes.

Hydrotreatment

As a natural substance, crude oil contains heteroatom (S, N, and O) compounds as well as metals (mainly Ni and V) in addition to hydrocarbons. The sulfur content of crude oils normally ranges from 0.05 to 6 wt %, nitrogen content varies from 0.1 to 1 wt %, oxygen from 0.1 to 2.0 wt %, and metals from 10 to 1000 ppm. Once crude is fractionated by distillation, the heteroatoms (particularly S, N, and metal compounds) are distributed in the products. Heteroatom compounds are mainly associated with the higher boiling fractions and the residues that are rich in aromatic compounds. The presence of heteroatom compounds in petroleum products is undesirable because they reduce fuel stability, contribute to the emission of pollutants, and damage engines. Heteroatom compounds in refinery streams (e.g., basic nitrogen compounds, sulfur compounds, and metals) can deactivate catalysts and promote coke formation [2].

Figure 9.1. Hydrogenation of unsaturated hydrocarbons for stabilization.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

The light products such as LPG and naphthas have low concentrations of sulfur and require minimal treatment, such as absorption in alkaline solvents (e.g., H₂S or mercaptan sulfur) or conversion of mercaptans to sulfides to eliminate odor. For example, the UOP Merox^TM process is widely used to remove H₂S and mercaptan sulfur (Merox extraction) or to convert mercaptan sulfur to less-objectionable disulfides (Merox sweetening) [2]. The Merox process can be used to treat liquids such as LPG, naphtha, and kerosene. Removing sulfur from higher molecular weight and more complex molecules requires hydrotreatment processes that use hydrogen.

Hydrodesulfurization

Desulfurization of fuels is commonly achieved by catalytic hydrodesulfurization (HDS), in which the organic sulfur species are converted to H₂S and the corresponding hydrocarbon, as in the following reaction: R-SH + H₂ → R-H + H₂S. Here R represents an alkyl group, such as methyl (CH₃–), or ethyl (C₂H₅–). Figure 9.2 shows the type and relative reactivity of different sulfur species in HDS reactions. The reactivity of R-SH (mercaptan, or thiol) compounds is higher than that of disulfides (R-S-S-R). The H₂S is easily removed from the desulfurized oil by absorption in a gas treatment unit and subsequently converted to elemental sulfur by the Claus process, as will be discussed in Lesson 10.

Figure 9.2. Types of sulfur compounds found in crude oil and their relative reactivity in HDS reactions.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Some HDS reactions are shown in Figure 9.3. Note that the objective of hydrotreatment reactions is to take the heteroatom out with minimum hydrogen consumption. The ideal scenario is to get the hydrogen atoms to break the carbon-sulfur bonds and to remove sulfur as H₂S. This may not always be possible because of problems with the accessibility of sulfur atoms to hydrogen atoms. Sulfur ring compounds such as methylated dibenzothiophenes have the lowest reactivity in HDS reactions because they are planar compounds, and in some methylated DBTs the S atom is shielded by the methyl groups (See Figure 9.4). Removing sulfur from these compounds requires more hydrogen consumption in order to saturate the aromatic rings in dibenzothiophene (DBT) to form non-planar compounds. Remember that, as opposed to aromatic compounds, cycloalkanes are not planar compounds. Therefore, saturation of the aromatic rings in methylated DBTs eliminates the steric hindrance (shielding) of methyl groups to make the S atom accessible to active sites on the catalyst surface for removal as H₂S. The geometry of this proposition is better understood when one looks at the configuration of active sites on the HDS catalysts shown in Figure 9.5.

Figure 9.3. Hydrodesulfurization reactions.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 9.4. Numbering of sites in the 4,6 DMDBT- a challenging compound for HDS.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Hydrodenitrogenation

Hydrodenitrogenation (HDN) is a similar process to HDS in which hydrogen is used to remove nitrogen, and for this reason during HDS the nitrogen content of fuels is also reduced. Figure 9.6 shows different types of nitrogen-containing compounds in crude oil and refinery unit products. In addition to reducing the N content in fuels as a finishing process, basic nitrogen compounds such as pyridine and quinoline shown in Figure 9.6 should also be removed as a pretreatment step to protect the acidic catalysts used in processes such as FCC. This is similar to HDS being an important pretreatment process for feedstocks that would be exposed to noble metal catalysts (such as Pt in a catalytic reforming process) that are poisoned by sulfur compounds. Figure 9.7 shows examples of HDN reactions and catalysts used for HDN. Similar to HDN reactions for quinoline, shown in Figure 9.7, pyridine (C₅H₅N) can be reduced to pentane (C₅H₁₂) and ammonia (NH₃) by adding 5 molesH₂ in three steps. The overall HDN reaction for pyridine is C₅H₅N + 5H₂ → C₅H₁₂ + NH₃.

Figure 9.6. Types of nitrogen containing compounds found in crude oil.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 9.7. HDN reactions and catalysts.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Hydrodemetallation

Similar to HDS and HDN, hydrodemetallation (HDM) is carried out: 1) as a pretreatment operation to remove metals (mostly nickel and vanadium) to protect the catalysts in subsequent conversion reactions, and 2) for removing metals in petroleum fuels to prevent corrosion in furnaces and toxic emissions from combustion engines. As mentioned in Lesson 1, metals (Ni, V) are mostly incorporated in the cage-like structures of highly stable organometallic compounds called porphyrins. As seen in Figure 9.8, to remove the metals, the cage structure of porphryins needs to be broken up. Similar to HDS and HDN, hydrotreatment on a Mo/Al₂O₃ catalyst first breaks up the chemical bonds in porphyrins to free the metals. The metals are then reacted with H₂S and precipitated as metal sulfides, e.g., Ni_xS_y, on catalyst surfaces. Note that this is different from HDS and HDN where the heteroatoms are removed as gas (H₂S and NH₃, respectively). [Think: What would be the significance of removing metals as metal sulfides as far as the morphology of the HDM catalysts is concerned? Save your answer for the Self-Check question later in this lesson. ] Metals Ni and V deposited on the catalysts can be recovered by post treatment of the used catalysts.

Figure 9.8. Hydrodemetallation reactions.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

In addition to HDS, HDM, and HDN, there may be a need for hydrodeoxygenation and hydrodehalogenation processes to remove O, or Cl in petroleum products [1].

Hydrotreatment Processes

Process objectives, conditions, and configurations are similar for all hydrotreatment processes [1]. As an example, HDS list, below, lists the project objectives and selected conditions for HDS processes. Minimization of cracking (or any other chemical change that is not needed for removing heteroatoms) and minimization of hydrogen consumption are the two principal objectives of hydrotreatment processes for reducing the heteroatom concentrations to the desired levels in the reaction products. These objectives are achieved by careful selection of process conditions that need to be adjusted based on the chemical composition of the feedstock. You can see in HDS list, that more severe reaction conditions (e.g., higher reaction temperatures, higher hydrogen/feed ratios, and lower space velocities) are necessary for treating heavy residue compared to treating light distillates. Catalysts have shorter lives in residue treatment processes, as well, because of harsh reaction conditions and more excessive deposition on catalysts during the treatment of heavy residue.

HDS (Hydrodesulfurization)

Objectives

• minimizing cracking
• minimizing hydrogen consumption

Note: LHSV (Liquid Hourly Space Velocity) – the volumetric flow rate of liquid reactant passing through a reactor divided by the volume of the catalyst in the reactor, measured in units of h^-1. Lower LHSV (i.e., longer exposure to catalyst in the reactor) is needed for more challenging hydrotreatment tasks.

Figure 9.9 shows a process flow diagram for HDS. The feed is introduced into a fixed-bed catalytic reactor along with hydrogen, and the products are sent to a high-pressure separator to separate H₂ and H₂S gases from the hydrocarbons. The gases are sent to a scrubber with a basic solution (containing ethanol amine or diethanol amine) to remove H₂S that is sent to the sulfur recovery unit and H₂ is recycled to the treatment reactor. Desulfurized products are sent to a fractionator to separate C₃ and C₄ alkanes (LPG) and the liquid products.

Figure 9.9. HDS Process Configuration.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

For HDS, HDN and HDM sequential reactors can be configured with different catalysts optimized for the targeted heteroatom removal. Figure 9.10 shows staging of the HDM and HDS operations. The first step in a series of reactors is always HDM because of the unique removal mechanism of the metals (Ni and V), as solid materials on catalyst surfaces, catalysts with large pores in the support materials are needed so that the problems with reactor plugging can be avoided. Following the removal of metals, HDS and HDN can be conducted on medium-pore and small-pore catalysts, in some cases simultaneously in the same reactor or the same catalyst bed.

Figure 9.10. Staging of hydrotreatment processes.

Click here for a text alternative to the figure below

Staging of Hydrotreatment Processes

-Feed w/high metals + high S content

-First HDM

-H2S, Ni_xS_y, V_xS_y

-Mo/Alumina, large pores

-Finish HDM then HDS

-CoMo/Alumina, medium pores

-Finish HDS

-CoMo/Alumina, small pores

-Product

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Increasing sulfur contents of the crude oils available for the U.S. refineries on one hand, and decreasing sulfur contents of regulated fuels on the other, have increased the sulfur production in the U.S. refineries as a by-product to 40,000 tons/day [4]. This is sufficient capacity to meet all sulfur demand for the chemical industry, particularly for H₂SO₄ production used in many chemical industries. One should note that this quantity of sulfur comes only from desulfurization of the fuels that are subject to sulfur regulation. A significant fraction of sulfur in crude oil (>60%) is concentrated in the heavy ends (e.g., residual fuel oil, asphalt) that are not regulated for sulfur content.

Product Blending

Product blending plays a key role in preparing the refinery products for the market to satisfy the product specifications and environmental regulations. The objective of product blending is to assign all available blend components to satisfy the product demand and specifications to minimize cost and maximize overall profit [5]. Almost all refinery products are blended for the optimal use of all of the intermediate product streams for the most efficient and profitable conversion of petroleum to marketable products. For example, typical motor gasolines may consist of straight-run naphtha from distillation, crackate (from FCC), reformate, alkylate, isomerate, and polymerate, in proportions to make the desired grades of gasoline and the specifications.

Basic intermediate streams can be blended into different finished products. For example, naphthas can be blended into gasoline, or jet fuel streams, depending on the demand. Until the 1960s, the blending was performed in batch operations. With computerization and the availability of the required equipment, online blending operations have replaced blending in batch processes. Keeping inventories of the blending stocks along with cost and physical data has increased the flexibility of and profits from online blending through optimization programs. In most cases, the components blend nonlinearly for a given property (e.g., vapor pressure, octane number, cetane number, viscosity, pour point), and correlations and programming are required for reliable predictions of the specified properties in the blends [3].

Self-Check Questions

Please take a few minutes to answer the questions below. When you are happy with your answers, click Check.

Assignment Reminder

The assignments for this week are listed below. Please be aware that you have an exam next week!

Summary

Finishing processes make sure that the refinery products fully comply with the commercial specifications and environmental regulations. Hydrotreatment removes heteroatoms from intermediate refinery products to protect the catalysts in the subsequent processes, or from final products to be sent out to the market. A particular challenge for hydrotreatment is that while the crude oil slate is getting more contaminated, the demand for cleaner fuels is mandated by the increasingly stringent environmental regulations. Major hydrotreatment processes include hydrodesulfurization, hydrodenitrogenation, and hydrodemetallation, all using hydrogen and specially designed catalysts to remove heteroatoms with minimal change to the hydrocarbon constitution of petroleum products. Product blending as a major finishing process takes up the challenge of the optimum allocation of many intermediate streams in the refinery to make up the refinery products to satisfy all performance parameters and environmental mandates. Product blending is carried out using linear and non-linear programming techniques for online blending.

Learning Outcomes

You should now be able to:

• compare hydrogenation and hydrotreatment with respect to process goals, catalysis, and chemistry;
• categorize and evaluate HDS, HDN, and HDM processes;
• assess hydrotreatment catalysts, kinetics, and process configurations;
• demonstarate procedures to calculate critical properties of blended products, e.g., octane number, pour point, and viscosity.

Reminder - Complete all of the Lesson 9 tasks

You have reached the end of Lesson 9! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 10.

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.

Overview

Video: FSC 432 Lesson 10 (6:33)

Overview

The fourth type of refining processes constitutes the supporting processes. Figure 10.1 lists the supporting role of these processes as:

1. acid gas removal to separate and concentrate H₂S and other acid gases produced in hydrotreatment and conversion operations;
2. sulfur recovery from H₂S captured in acid gas removal unit;
3. hydrogen production for hydrocracking and hydrotreatment processes; and
4. wastewater treatment.

Although these processes and units are not involved directly in hydrocarbon fuels production, their roles are essential for the operation of a refinery.

Figure 10.1. Refinery supporting processes.

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Learning Outcomes

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

• outline and assess the processes for acid gas removal and elemental sulfur recovery from H₂S;
• discuss and illustrate sources of hydrogen and hydrogen production processes;
• assess primary water toxicants and waste water characterization parameters, and outline waste water treatment processes.

What is due for Lesson 10?

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 assignment below can be found in this lesson.

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.

Gas Processing Unit

The gas streams produced in refinery units such as catalytic crackers, cokers, hydrocrackers, and reformers are sent to the Gas Processing Unit [1] in order to:

1. recover C₃-C₆ hydrocarbons for LPG production (C₃ and C₄) and feedstocks (C₅ and C₆) for isomerization (light naphtha) and reformer (heavy naphtha) units;
2. separate H₂S in a sour gas stream that also contains C₁ and C₂ gases.

In some refineries, Gas Processing Units also function as Light End Units.

Sulfur Recovery

As indicated in Figure 10.3, the objective of the sulfur recovery process is to convert H₂S to elemental sulfur. Sulfur recovery takes place in a series of two steps: Claus Process and SCOT Process [3]. In the Modified Claus Process, partial combustion of H₂S takes place to generate SO₂ that is reacted with the remaining H₂S to recover sulfur as elemental sulfur. The Modified Claus Process, once-through burner operation, works only with acid gases that contain more than 50% H₂S by volume. In the process, hydrogen in H₂S is converted to H₂O. The second stage, the SCOT Process, functions as a tail gas clean-up operation to remove the sulfur compounds produced in the side reactions of the Claus Process, i.e., carbonyl sulfide (COS) and carbon disulfide (CS₂).

Figure 10.3. Sulfur recovery processes.

Click here for a text alternative to the figure above

Sulfur Recovery Process

Objective: to convert H2S to elemental S

First stage: Modified Clause Process

-partial combustion of H₂S

-primary S recovery

-works for acid gas with >50% H₂S

Second Stage: SCOT Process – Claus tail gas clean-up

-removes COS and CS₂ produced by side reactions in the Clause Process

-reduces COS and CS₂ to H₂S

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Hydrogen Production

Although refineries produce a significant quantity of hydrogen needed for hydrotreating and hydroconversion processes, in most cases, additional hydrogen is needed particularly for refining the sour crudes. Therefore, a Hydrogen Plant is needed on site to provide the additional hydrogen demand. As seen in Figure 10.7, steam reforming of natural gas is most commonly used in the U.S. to produce hydrogen, whereas partial oxidation of heavy hydrocarbons is preferred in Europe [4].

For the partial oxidation process, a heavy hydrocarbon fraction, typically fuel oil, is reacted at high pressures (1300-1800 psig) with pure oxygen supplied in strictly controlled quantities for partial oxidation of hydrocarbons to carbon monoxide and hydrogen, as shown in Figure 10.7. Carbon monoxide produced in the reaction is converted to hydrogen by catalytic shift reaction with steam. In the purification step, CO₂ produced in the shift reaction is removed by absorption in a basic solvent such as potassium carbonate.

Figure 10.7. Hydrogen demand and additional hydrogen production on site in the US and European refineries.

Click here for a text alternative to the figure above

Image reads:

Hydrogen Production

Demand: hydrotreating, hydrocracking

Supply: Catalytic reforming – not sufficient

Additional hydrogen needs to be produced

The principle method of hydrogen production in US refineries:

-Steam reforming of natural gas (CH4)

The principle method of hydrogen production in European refineries:

-Partain oxidation of heavy HC (e.g., fuel oil) is used to produce hydrogen

2CnHm + nO₂ → 2nCO + mH₂ (oxidation)

2nCO + 2nH₂O → 2nCO₂ (removed by absorption) + 2nH₂

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Figure 10.8 illustrates the reactions in steam reforming of natural gas (CH₄) to produce hydrogen in the U.S. refineries. In the reforming reaction, CH₄ is converted to H₂ and CO on a NiO/SiO₂-Al₂O₃ catalyst at temperatures of 760-816°C. Reforming is followed by the water gas shift reaction at 343°C to shift CO to H₂ and CO₂ on a Cr₂O₃ and Fe₂O₃ catalyst in multiple catalyst beds with external cooling to control the temperature to achieve high conversion in the exothermic reaction. The product gas is purified by absorption of CO₂ in an Amine Unit. In the final step of methanation, residual CO and CO₂ is removed by hydrogenation on a Ni/Al₂O₃ catalyst at 370-427°C.

Figure 10.8.  Steam reforming of CH₄ for hydrogen production.

Click here for a text alternative to the figure above

Image reads:

Steam Reforming of CH4

1) Reforming

CH₄ + H₂O → CO + 3H₂ (endothermic)

Catalyst: 25-40% NiO/low SiO₂/ Al₂O₃

Carried out at 760-816ºC

2) Shift

CO + H_{​​​​​​​2​​​​​​​}O → CO_{​​​​​​​2} + H_{​​​​​​​2} (exothermic)

Catalyst: Cr_{​​​​​​​2}O_{​​​​​​​3} and Fe_{​​​​​​​2}O_{​​​​​​​3}

Carried out at 343ºC in multiple catalyst beds w/ external cooling

3) Gas Purification

CO_{​​​​​​​2} absorption in amine unit

4) Methanation - to remove residual CO and CO₂

CO + 3H_{​​​​​​​2} → CH_{​​​​​​​2} + H_{​​​​​​​2}O (Exothermic)

CO2 + 4H_{​​​​​​​2} → CH_{​​​​​​​2} + 2H_{​​​​​​​2}O (Exothermic)

Carried out at 370-427ºC

Catalyst: Ni/Al_{​​​​​​​2}O_{​​​​​​​3}

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Wastewater Treatment 

Considering the vast amounts of water used in a refinery, wastewater treatment constitutes a very significant supporting process for safe operation. Figure 10.9 lists the different types of wastewater, pollutants involved in wastewater streams, and the major refinery units that generate significant amounts of wastewater. The four types of refinery wastewater include cooling water, process water and steam, storm water, and sanitary sewage water. Among these, the most heavily polluted wastewater stream that requires serious treatment is the process water and steam that come into direct contact with petroleum fractions. Storm water may be contaminated because of incidental exposure to pollutant sources on refinery surfaces and accidental spills. Cooling water and sanitary sewage water may not require much treatment before they are sent to public water treatment facilities. One rule of thumb is to avoid mixing different types of wastewater streams to reduce the load on the treatment units.

Pollutants found in the wastewater streams include hydrocarbons with particular concern for toxic aromatic compounds, such as benzene; heteroatom compounds, such as mercaptans, amines, phenols, and cyanides; dissolved gases such as H₂S and NH₃, and acids, such as H₂SO₄ and HF; and suspended and dissolved solids. The refinery units that generate the most significant amount of wastewater are desalting, distillation, thermal and catalytic cracking, coking, as well as heat exchangers and storage tanks [5].

Figure 10.9.  Refinery wastewater, water pollutants, and refinery units.

Click here for a text alternative to the figure above

Image reads:

Types of wastewater

a. Cooling water

b. Process water and steam

-heavily polluted

c. Stormwater

d. Sanitary sewage water

Pollutants involved

a. Liquid hydrocarbons

b. Suspended solids, dissolved solids

c. Mercaptans (RSH)

d. Phenols (RC6H5O), amines (-NH2)

e. H2S, NH3, cyanides (-CN)

f. H2SO4, HF

Refinery units involved

Desalter, distillation, thermal cracking, visbreaking, coking, catalytic cracking, heat exchangers, storage tank drainage

Credit: Dr. Semih Eser © Penn State is licensed under CC BY-NC-SA 4.0 [5]

Environmental Regulation of Refineries

Air pollutant emissions from the refinery processes are also controlled. Figure 10.13 lists the major legislations and regulations that affect the environmental impact of refineries in the U.S. [6].

Self-Check Questions

Please take a few minutes to complete the exercise and then answer the questions below.

Assignment Reminder

This week Exercise 9 is due.

Summary

Supporting processes are essential to the operation of a refinery. These processes have become more important as the crude oil base has become more sour. The demand for hydrogen has increased to support the required finishing processes for heteroatom removal and recovery of sulfur and metals. Refineries have become major producers of elemental sulfur for the chemical industry.

Learning Outcomes

You should now be able to:

• outline and assess the processes for acid gas removal and elemental sulfur recovery from H₂S;
• discuss and illustrate sources of hydrogen and hydrogen production processes;
• assess primary water toxicants and waste water characterization parameters, and outline waste water treatment processes.

Reminder - Complete all of the Lesson 10 tasks.

You have reached the end of Lesson 10! Double-check the to-do list below to make sure you have completed all of the activities listed there before you begin Lesson 11.

What is due for Lesson 10?

Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignments below can be found within this lesson.

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.

Overview

Video: FSC 432 Lesson 11 (5:18)

Overview

In the roughly 150-year history of petroleum refining, remarkable changes have taken place in refining processes and refinery configurations. These changes were driven by transitions and developments in combustion engines, the wars (World War I and, most notably, World War II), variations in the crude oil slate available for refining, and the environmental regulations. This historical evolution has taken place with the introduction of new processes more or less in the order of the four refinery processes that we have discussed: separation, conversion, finishing, and support. The new petroleum refining processes were developed and incorporated into the refinery to control the yield and properties of the desired fuels and refineries. Through the stages of the refinery evolution, it is interesting to note that the demand for even the same petroleum product has changed not only in the desired composition, as it is linked to properties, but also in its application to a particular commercial sector. In this regard, kerosene provides a good example of this change from being primarily a source of light in lamps (as a replacement for whale oil which allegedly saved the sperm whales from extinction) in the 1850s to becoming an established base fuel for jet aircraft since the end of World War II. Kerosene has also been used as a fuel for domestic heating and cooking in many parts of the world, long after the introduction of electric lamps.

This lesson will provide an overview of the historical evolution of the petroleum refinery and discuss some current developments in crude oil supply and in related energy technologies to catch a glimpse of what the near future could bring to the refinery practice. The overview and discussions will often reflect on specific aspects of different refinery processes that have been introduced in previous lessons.

Learning Outcomes

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

• review, illustrate, appraise, and critique discrete stages in the history of petroleum refining;
• evaluate driving forces that could impact the future of petroleum refineries and propose scenarios for responding to the driving forces.

What is due for Lesson 11?

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 assignment below can be found in this lesson.

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.

Refinery Evolution

The configuration and complexity of a petroleum refinery has evolved from one-pot batch distillation to produce kerosene as the major product (1850s) to the complex refinery of the day [1] that produces a multitude of fuels and petrochemical feedstocks from a wide range of crude oils, as discussed in Lessons 1 and 2. Different stages of this evolution, in tune with the changing demand for petroleum products as well as the changing crude oil base over time, are presented in the following sections listed below and in your menu.

Future Trends in Petroleum Refining

Speculation about the future of refining is risky at best, but some trends are described as to be more certain by Self, Ekholm, and Bowers [5], as follows:

• Computers will increasingly be used for research, design, control and operation, maintenance, information handling, supply chain management, marketing execution, and distribution. As a result, research will broaden and manufacturing facilities will become more complex.

• The sophistication of competitors and customers, both domestic and international, will drive more transparent and efficient markets.
• Consumers will continue to search for energy sources that are reliable and independent of political forces, sustainable, environmentally acceptable, simple to generate and store and distribute, and inexpensive. Consequently, companies will hasten to reconcile the position of fossil fuels within emerging energy alternatives. Meanwhile, fuel formulations and usage will evolve, particularly for better performance and pollution prevention. This will progress despite the apparent trend of heavier crudes with increased sulfur, metals, solids, and water.
• Sensitivity will spread for the concerns and desires of consumers, communities, investors, and other stakeholders in all aspects of refining. Interaction with all stakeholders will be critical.

• Strategic consolidation of the size, number, and ownership of facilities and companies will continue. New partnerships will form among customers, competitors, and suppliers. Companies will attempt to maximize their return on assets, optimize allocation of capital, and reduce operating costs. In particular, efforts at hazard elimination and pollution prevention will intensify to reduce operational and liability costs.

Please take a few minutes to work through the review questions. These questions will help you study for the final.

Assignment Reminder

The assignments for this week include Exercise 10 and Quiz 4.

Summary

The evolution of petroleum refinery can be considered to have taken in four stages from being just a separation refinery (distillation and dewaxing) to a conversion refinery in accordance with the demand for petroleum products. The conversion refinery evolved first as a thermal refinery with the development of thermal cracking, reforming, and polymerization, and transitioned into the catalytic refinery during World War II, with the development of processes such as catalytic cracking, catalytic reforming, alkylation, and catalytic hydrotreatment to define the finishing processes. The next stage of evolution after the catalytic refinery, high-end conversion refinery, has kept all the catalytic processes and added hydrocracking with emphasis on processing the heavy crude oils and production of cleaner fuels in compliance with environmental regulations. The increasing demand for hydrogen for hydrocracking and hydrotreatment operations and the need to recover increasing quantities of elemental sulfur highlighted the requirement of supporting processes for the operation of this refinery.

Learning Outcomes

• Comprehension of discrete stages in the history of petroleum refining and the driving forces that ushered in these stages.
• Evaluation of the driving forces that could impact the future of petroleum refineries and consideration of different scenarios for responding to the driving forces.

Reminder - Complete all of the Lesson 11 tasks!

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.

Overview

Video: Lesson 12 (5:38)

Overview

Natural gas has become a very significant fossil fuel in the U.S. because of a sharp increase in shale gas production starting in 2006. The U.S. Energy Information Administration projects that the U.S. natural gas production will increase 44% from 23.0 trillion cubic feet in 2011 to 33.1 trillion cubic feet in 2040 [1]. Almost all of this increase in domestic natural gas production is due to projected growth in shale gas production, which is projected to grow from 7.8 trillion cubic feet in 2011 to 16.7 trillion cubic feet in 2040. It is interesting to note that before the shale gas boom (that has taken place largely in Pennsylvania), the U.S. was planning to import liquefied natural gas (LNG) from countries as far as Peru with the planned construction of LNG ports in California and other states. Currently, there are prospects of exporting LNG overseas in the near future. One particular aspect of the natural gas boom that concerns the petroleum refining industry is the increased production of natural gas liquids (NGL) that are co-produced with natural gas. NGL consist of light hydrocarbons, and they have become an important non-conventional feedstock for refineries, contributing mainly to gasoline production. This new input to refineries along with the increased domestic oil production by the new drilling technology has helped small inland refineries that do not have easy access to imported crude oil as, for example, Gulf Coast refineries.

This lesson will provide an overview of the natural gas processing that employs the same techniques and processes as we have covered in petroleum refining operations, such as in Light Ends Unit for fractionation of light hydrocarbons, and recovering H₂S, as well as its conversion to S. Brief introductions to shale gas and natural gas liquids will be presented before discussing the natural gas processing.

Learning Outcomes

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

• appraise different natural gas reserves (conventional, tight, and shale) and assess the contribution of natural gas to energy supply;
• illustrate and evaluate the different stages of natural gas processing, including condensate removal, acid gas removal, water removal, fractionation of natural gas liquids.

What is due for Lesson 12?

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 assignment below can be found in this lesson.

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.

Shale Gas

Shale gas refers to natural gas that is trapped within shale formations, as different from conventional natural gas resources, such as associated (produced with crude oil), or non-associated (without crude oil) natural gas that is found mostly in sandstone formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has invigorated the natural gas industry and the small inland refineries in the United States.

Figure 12.1 shows the EIA data and projections on dry natural gas production in the U.S., indicating the surge in shale gas production, while the conventional associated and non-associated gas production are expected to decline [3]. Dry natural gas refers to natural gas that consists, essentially, of methane without any significant concentration of condensable hydrocarbons, such as propane and butane, that are present in natural gas liquids.

Figure 12.1. History and projections of dry natural gas production in the U.S. [2].

Source: U.S. Energy Information Administration, Annual Energy Outlook Early Release

Natural Gas Liquids

Natural gas liquids (NGLs) are composed of hydrocarbons, including ethane, propane, butane, isobutane, pentane, and higher alkanes. Although ethane cannot be readily liquefied by pressure at ambient temperature such as propane and butane (LPG) it is considered a component of NGL. There are many uses for NGLs, as summarized in Table 12.1 [3]. NGLs are extracted from the natural gas production stream in field processing plants, using techniques discussed related to petroleum refining operations.

NGL field production is growing in the United States, representing an important part of the supply picture.

C indicates carbon, H indicates hydrogen; Ethane contains two carbon atoms and six hydrogen atoms

*Pentanes plus is also known as "natural gasoline." Contains pentane and heavier hydrocarbons. 

Table 12.2. Some components and applications of natural gas liquids [3].

Source: US Energy Information Administration 

Natural Gas Composition and Specifications

Natural gas as recovered at the wellhead consists of mostly methane (C₁), but it contains other hydrocarbons, principally ethane (C₂), propane (C₃), butanes (C₄), and pentanes C₅ that constitute the natural gas liquids, as discussed in the previous section. Raw natural gas also contains water vapor, hydrogen sulfide (H₂S), carbon dioxide, nitrogen, helium, and other impurities, such as mercury. Table 12.3 gives some examples of the composition of natural gas produced in three different locations, to give an example that methane content of natural gas can be as low as 65%. One can also note in Figure 12.2 that some natural gas streams may contain high concentrations of H₂S and N₂. Some natural gas streams could be a commercial source for helium [4]. One of the important objectives of natural gas processing is to remove the corrosive and toxic gas H₂S and convert it to elemental sulfur, as will be discussed later. Important impurities, including those shown in Table 12.3, that need to be removed from natural gas are listed below [5].

Important impurities found in natural gas [5].

• Water: Most gas produced contains water, which must be removed. Concentrations range from trace amounts to saturation.
• Sulfur species: If the hydrogen sulfide (H₂S) concentration is greater than 2 to 3%, carbonyl sulfide (COS), carbon disulfide (CS2), elemental sulfur, and mercaptans may be present.
• Mercury: Trace quantities of mercury may be present in some gases; levels reported vary from 0.01 to 180 μg/Nm³. Typically, the mercury level in pipeline gas should be reduced to 0.01 μg/Nm³.
• Diluents: Although the gases shown in Figure 12.2 are typical, some gases have extreme amounts of undesirable components. For example, some wells in Colorado contain as much as 92% carbon dioxide. High hydrogen sulfide contents (e.g., in Alberta, Canada), and nitrogen contents (e.g., in Texas) have also been observed.
• Oxygen: Some gas-gathering systems in the United States operate below atmospheric pressure. As a result of leaking pipelines, open valves, and other system compromises, oxygen is an important impurity to monitor. A significant amount of corrosion in gas processing is related to oxygen contamination.

Considering that the principal transportation of natural gas over land is by pipeline, natural gas specifications for pipeline transmission have been developed. Table 12.4 gives the natural gas specifications that need to be satisfied for pipeline transportation. Note that in addition to the specified impurity levels for the contaminants, the specifications include the heating value of natural gas (950 -1150 Btu/scf) which depends on the composition, particularly the concentration of inert gases (e.g., N₂ and CO₂) and other diluents.

Table 12.4. Specifications for pipeline quality natural gas [6].

Click for a text description of Table 12.4

Specifications for Pipeline Quality Gas

Major Components	Minimum Mol%	Maximum Mol%
Methane	75	None
Ethane	None	10
Propane	None	5
Butanes	None	2
Pentanes and heavier	None	0.5
Nitrogen and other inerts	None	3
Carbon dioxide	None	2-3
Total diluent gases	None	4-5

Trace Components:

• Hydrogen sulfide: 0.25-0.3 g/100 scf  (6-7 mg/m³)
• Total sulfur: 5-20 g/100 scf (115-460 mg/m³)
• Water Vapor: 4.0-7.0 lb/MM scf (60-110 mg/m³)
• Oxygen: 1.0%

Other Characteristics:

• Heating calculated (gross, saturated): 950-1,150 Btu/scf (35,400-42,800 kJ/m³)
• Liquids: Free of liquid water and hydrocarbons at delivery temperature and pressure.
• Solids: Free of particulates in amounts deleterious to transmission and utilization equipment.

Natural Gas Processing 

A comparison of Images 12.2 and 12.3 illustrates the significance of natural gas processing for purification of the raw natural gas to obtain a pipeline quality gas. In general, natural gas processing includes the following steps:

• Condensate and Water Removal
• Acid Gas Removal
• Dehydration – moisture removal
• Mercury Removal
• Nitrogen Rejection
• NGL Recovery, Separation, Fractionation, and Treatment of Natural Gas Liquids

In addition to these processes, it is often necessary to install scrubbers and heaters at or near the wellhead. The scrubbers remove sand and other large-particle impurities. The heaters ensure that the temperature of the natural gas does not drop too low and form a hydrate with the water in the gas stream. Natural gas hydrates are crystalline ice-like solids or semi-solids that can impede the passage of natural gas through valves and pipes.

A generalized natural gas flow diagram is shown in Figure 12.2 [7]. After initial scrubbing to remove particles, the first step in natural gas processing is the removal of condensate (oil) and water that is achieved by controlling the temperature and pressure of the inlet stream from the well, as shown in Figure 12.4. Gas separated in this unit is sent to acid gas recovery; the condensate or the oil recovered is usually sent to a refinery for processing, while water is disposed, or treated as wastewater.

Figure 12.2. A generalized natural gas processing flow diagram [7].

Figure 12.3. Condensate and water removal [6].

Acid gases (H₂S and CO₂) are separated usually by absorption in an amine solution, as discussed for H₂S recovery in a petroleum refinery in Lesson 10. The recovered H₂S is sent to a combined Claus-SCOT (Tail Gas Treating) unit to be converted to elemental sulfur, as was also discussed in Lesson 10. After removing the acid gases, the natural gas stream is sent to a dehydration unit to remove water typically by absorption in a glycol unit, followed by mercury removal (by adsorption on activated carbons or other sorbents), and nitrogen rejection either cryogenically, or by adsorption, or absorption depending on the nitrogen concentration. The last step in the processing sequence is the Natural Gas Liquids (NGL) extraction, fractionation, and treatment, as described in Figure 12.4.

Figure 12.4: Separation and Fractionation of Natural Gas Liquids [6]

Natural gas liquids (NGLs) have a higher value as separate products. 

Two basic steps: 1) Extraction, 2) Fractionation

1. NGL Extraction
   Absorption Method
   • Similar to using absorption for dehydration, using a different absorbing oil for hydrocarbons. 
   Cryogenic Expansion Process
   • Dropping the temperature of the gas stream to around -120°F by expansion and external refrigeration
2. Natural Gas Liquid Fractionation - works like Light Ends Unit
   • Deethanizer - separates ethane from the NGL stream
   • Depropanizer - separates propane.
   • Debutanizer - boils off the butanes
   • Butane Splitter or Deisobutanizer - separates iso and n-butanes.

NGL extraction can be carried out by absorption in oil that selectively absorbs hydrocarbons heavier than methane, or by a cryogenic expansion and external refrigeration to condense NGL.

Following the NGL extraction, the treated natural gas stream that is, now, mostly methane, or a gas compliant with the natural gas specifications is sent to the pipeline for transmission to the point of use. The extracted NGL, on the other hand, is sent to a fractionation unit that operates like Light Ends Unit in a refinery, as discussed in Lesson 5, separating ethane, propane, butane, and naphtha (>C₅, natural gasoline). Note that the fractionation unit may also include a butane splitter or deisobutanizer to separate n-butane and iso-butane. You may remember from Lesson 8 that iso-butane is a feedstock to alkylation to produce high-octane gasoline when reacted with C₃ and C₄ olefins. NGL from highly sour gases may need additional treatment to remove mercaptans and other sulfur species before NGL leaves the processing plant.

Please take a few minutes to work through the questions below. They will help you study for the quiz this week.

Assignment Reminder

Review the US DOE web page on shale gas [20].

The material in the section on Shale Gas Basics is included in the coverage of the final exam.

Summary

Natural gas has gained prominence in the energy scene as a rising fossil fuel following the development of new drilling technology that set up a boom in shale gas production. As crude oil, natural gas contains wide-ranging impurities in addition to the main component, methane. Natural Gas Processing removes the contaminants in the raw gas and recovers some valuable byproducts, such as natural gas liquids. A number of separation and recovery processes used in a petroleum refinery can also be used for natural gas processing.   

Learning Outcomes

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

• appraise different natural gas reserves (conventional, tight, and shale) and assess the contribution of natural gas to energy supply;
• illustrate and evaluate the different stages of natural gas processing, including condensate removal, acid gas removal, water removal, fractionation of natural gas liquids.

Reminder - Complete all Lesson 12 tasks!

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.