Introduction to Petroleum Refinery Processing

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Introduction to Petroleum Refinery Processing

Gennaro J. (Jerry) Maffia; Professor of Chemical Engineering and Process

Engineering Manager, Petrochemicals Industry

Introduction 2

Introduction

Introduction 3

“The ground begins to rumble, then shake. The hero of the film – a lean excowboy with a square jaw under his hat and a gorgeous brunette on his arm – reaches out to brace himself against his horse. A smile creases his face as the rumbling grows louder. Suddenly, a gush of black goo spurts into the air and splashes down on him, his side-kick and his best gal. They dance with ecstasy until the music swells and the credits start to roll. Why is our hero so happy? Because he’s rich! After years of drilling dry holes in every county between the Red River and the Rio Grande, he finally struck oil.”

Paul R. Robinson

Introduction- What is petroleum ? 4

What is petroleum ?

• Petroleum is a thick, flammable, yellow-to-black combustible mixture of gaseous, liquid, and solid hydrocarbons that occur naturally beneath the earth’s surface.

• After processing it is usually separated to fractions, which can be used as fuel, or as raw material for chemical or petrochemical plants.

Introduction- What is petroleum ? 5

• Petroleum produced from a well is not pure hydrocarbons, it has some impurities including water, brine, inert gasses, mercaptants, carbon dioxide, H2S, drilling sands and others.

• It can be classified as light, intermediate or heavy according to its specific gravity. And as sweet or sour according to the amount of sulfur compounds present in it.

What is petroleum ?

Introduction- Importance of petroleum

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• Petroleum can be refined (fractionated)and split to it’s components each of which can be either used directly or processed to give a wide range of products.

• These products include: fuels, lubricating oils, solvents, ink, polymers, adhesives, soap, waxes, alcohols, fertilizers, and a lot others.

Importance of Petroleum

Introduction- Production of petroleum- Generation, Migration, Accumelation

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Steps of production in nature

Introduction- Production of petroleum- Generation, Migration, Accumulation

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In oceans: • Dead animals and plants sank to the bottom

of the ocean.• Buried under sediments of sand and mud. • Layers increase in thickness with time.• Temperature and pressure increase.• Causing the change to sedimentary rocks.

Generation


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• In absence of oxygen conditions deposits are changed to kerogen.

• At high temperature (greater than 110oC) and pressure kerogen is thermally degraded to oil and gas.

• This process takes hundreds millions of years to occur.

Generation


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On land:• dead plants and animals undergo similar processes to

become coal, which is if deeply buried under high temperature conditions is transformed to gas and petroleum.

• The factor that determined the transformations is to gas or oil is the severity of the conditions of which the organisms are buried the more severer the conditions, the smaller is the hydrocarbon produced, in extreme cases methane (natural gas).

Generation


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• Once the deposits are converted to oil it must move from the source rock to the reservoir to accumulate there to form reserves that can be exploited by human.

• Migration is controlled by the physical properties of the sedimentary strata the oil is moving through (permeability, porosity, etc).

• The driving force is mainly pressure.

• There are two types of migration; primary and secondary.

Migration


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Primary migration• where the oil is moved from the center of the source rock to the

contact with the reservoir strata.

• The main driving force for primary migration is sediment compaction due to overburden load.

• Saturated hydrocarbons are preferentially expelled, while NSO compounds remain preferentially within the pore space of the source rock.

• Migration of gas is by dissolving in oil or at great depths where high pressures causes both natural gas and oil to be a single phase.

Migration


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Secondary Migration

• After the oil has crossed the source/reservoir contact and entered the reservoir rock.

• The main driving force is buoyancy which is due to the density difference between oil, gas and water.

• The reservoir rock has much higher porosity and permeability.

• Since the driving force is buoyancy, the diffusion is in the upward direction where gas is at the top and oil is below it.

Migration

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Migration


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Migration



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• Oil and gas continue to move upwards through permeable rock until they encounter an impermeable layer of rock.

• The most common traps are anticlines which are culminations of folds.

• Since the gas is lightest it is at the top of the formation forming the gas cap, followed by oil then water.

• The trap is formed if impermeable cap rock at the top mainly clay or salts where there is a very small number of pores or very small pore diameter that it cannot be entered by the oil or gas.

Accumulation


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• Very special cases of gas accumulations occur in the form of so-called gas hydrates.

• These are solid, ice-like compounds whereby water molecules are arranged in crystal lattices forming cages (called clathrate compounds).

• Methane molecules are arranged inside these cages. Per unit volume of reservoir pore space, more methane can be stored in hydrate condition as compared to free gas.

Accumulation


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Accumulation


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The following is needed for crude to be produced in commercially attractive amounts:

1- A source rock (sedimentary type) should be present to be the source of the oil. (generation step)

2- Sediment compaction or other factor that leads to the expulsion of petroleum from the source rock to the reservoir.

3- Presence of a reservoir rock that has sufficient porosity and permeability to allow for the flow of the formed petroleum. (migration step)

Summary of Crude generation & migration

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4- Structural configurations whereby reservoir rocks form traps to allow for the accumulation of the oil and gas.

5- Traps should be sealed from the top by impermeable layers (cap rocks) to prevent petroleum and gas from leaving the trap. (4, 5 for the accumulation step)

6- The absence of factors that can lead to the destruction of the geological trap which can cause the release of the accumulated gas and oil.

Summary of crude generation & migration



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Summary

Introduction- History 22

• First the crude oil was obtained by collecting the oil that seeped out cracks in the ground or was mined.

• It’s uses were limited to waterproofing ships, as adhesives in construction and for flaming projectiles.

• Over time the uses of petroleum increased slowly till the year 1859.

• The invention of countless applications at that date, that used the fractions of petroleum in their operation caused a huge increase in the demand for petroleum products.

History

Introduction- History 23

• An example is the kerosene lamp and the depletion of other sources of fuel for lighting such as whale oil.

• Since then the uses of petroleum products have increased greatly the demand for the production of larger amounts of petroleum products increased.

• Nowadays it is used to provide fuel, lubricants for all vehicles and provides raw materials for petrochemical industry, reaching a point that the stoppage of the steady flow of petroleum products will lead to a halt in most of the human activities.

History

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Discussion

Discussion

Discussion- Characterization of crude oil

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• The ultimate goal of oil processing is turning it into useful products such as fuel, lubricants and polymers.

• It is important to know the properties of crude oil to be able to determine the processes needed to give the desired product.

• Crude assays include two types of information, bulk properties, and fractional properties.

Characterization of crude oil

Discussion- Characterization of crude oil- Bulk properties

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• Bulk properties are properties for the crude as a whole such as specific gravity, sulfur content, nitrogen content, pour point, flash point, freeze point, smoke point, aniline point, cloud point, carbon residue, boiling point curve, and others.

1- Bulk properties


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Important Bulk properties

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• The specific gravity is expressed using the API gravity (American Petroleum Institute), API= (141.5/SG)-131.5.

• It is the ratio between the density of the crude and that of water both at 15.6oC.

• It should be noted that the API gravity decreases with increase in specific gravity.

1- Specific gravity


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Specific gravity


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Specific gravity



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• The viscosity is the ability of the fluid to resist shearing forces mainly during flow, and is due to the frictional forces between liquid layers.

• It is measures in centistokes or saybolt seconds or redwood seconds usually at 100oF and 210oF and is the time taken by a specific volume of liquid to flow through a standardized weir. Viscosity specifications are different from summer to winter due to difference in temperature.

2- Viscosity


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• The viscosity index which is the rate of change of viscosity with temperature. It is high if the rate of change of viscosity with temperature is high. This property can be improved by adding specific polymers which act as viscosity index improvers.

3- Viscosity index


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• The sulfur content is expressed as the weight percentage of sulfur in the crude.

• Crude oils with less than 1% sulfur are called low sulfur (sweet) crudes, and those with more sulfur than 1% are called high sulfur (sour) crudes.

• Sulfur containing compounds are mainly mercaptants, sulfides and polycyclic acids.

4- Sulfur content

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• The pour point is a measure of how easy it is to pump the crude; it becomes of importance in cold weather. It is the lowest temperature at which crude oil will behave as liquid.

• The dew point is the temperature at which the hydrocarbons in the gas phase will start to condense out of the gaseous phase.

5- Pour point & Dew point


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• The bubble point is the temperature at which the liquid hydrocarbon begins to boil and form vapor bubbles. It should be the same as the dew point for pure components but for mixtures it is different as boiling occurs on a range of temperatures.

• The flash point is the lowest temperature at which there is sufficient vapor is produced above the liquid to form an explosive mixture with air, which can cause ignition if a spark is present.

6- Bubble point & Flash point


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• The fire point is a temperature well above the flash point where the products can catch fire easily.

• The freeze point is the temperature at which the hydrocarbons solidify at atmospheric pressure. It should be noted that it is different from the pour point as reaching the pour point will make the oil very viscous that it will not flow under the effect of gravity but is still a liquid.

7- Fire point & Freeze point

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• The smoke point is the maximum height of a smokeless flame from burning a fuel measured in meters.

• The cloud point it the temperature at which waxes start to crystallize and separate from the solution when cooling.

8- Smoke point & Cloud point



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• The aniline point represents the minimum temperature for complete miscibility of equal volumes of aniline and crude oil, it is an important property of diesel fuels and a low aniline point indicates the presence of a larger amount of aromatics.

• The true boiling point curve is the boiling point of the oil fraction versus the fraction of oil vaporized.

9- Aniline point & TBP curve

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• The Conradson carbon residue is a measure of the coke forming tendency of oil. It is determined by destructive distillation of oil to elemental carbon in absence of air, expressed as a weight percentage of the original sample.

• The heating value is the amount of heat released from burning a unit mass of the oil. It can be higher heating value or lower heating value depending on whether the heat of vaporization of the produced water from combustion is subtracted.

10- C residue 7 Heating value


40Discussion- Characterization of crude oil-

Bulk properties

Properties of crude from different locations

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• Bulk properties provide a quick understanding of the type of crude as a whole.

• Fractional properties provides the properties of a specific boiling point range.

• Fractional properties usually include properties for paraffins, naphthenes, and aromatics contents, sulfur, and nitrogen contents for each boiling point range.

• And other properties each specific for a product such as octane number for gasoline and smoke point for kerosene and diesel.

2- Fractional properties

Discussion- Characterization of crude oil- Fractional properties

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Important fractional properties

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• The octane number is a measure of the knocking properties of a fuel (gasoline). In other words it is a measure of how difficult is it for the fuel (gasoline) to self ignite before the spark plug fires.

• A high octane number indicates a higher self ignition temperature meaning that this fuel will withstand higher compression ratios before self-igniting.

1- Octane number


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• It is determined by measuring the knocking value of the fuel compared to that of a mixture of n-heptane and isooctane.

• It is between 0 and 100 where the octane number 90 is for the same knocking properties as 90% iso octane and 10% n-heptane mixture.

Octane number



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• There are two types of octane number, the motor octane number which is at 900 rpm at severe conditions.

• While the research octane number is at normal conditions (600 rpm) the second is usually higher due to higher efficiency of engine at lower rpm.

Octane number

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• The pump octane number is the one used by consumers and is the average between the two. The octane number can be improved by using additives to gasoline such as tetra ethyl lead (TEL), lead chlorides, and oxygentates (MTBE methyl tertiary butyl ether) which will be discussed later.

• If the use of additives improved the ignition properties beyond pure iso octane the octane number will be higher than 100.

Octane number



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• It can be measured by comparison of the ignition property of the fuel with that of pure iso-octane with different TEL additions.

• Or using the performance number which is the ratio of the knock limited power of the fuel to that of pure iso octane then this ratio converted to octane number by a simple equation.

Octane number


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• The cetane number is the ease of self ignition of a diesel fuel, and can be considered s the opposite of the octane number where high cetane number means easier self ignition at lower temperatures. This is desired in diesel engines as these do not have spark plugs so self ignition is desired.

2- Cetane number


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• It is represented by the percentage of pure cetane in a mixture of cetane and alpha methyl-naphthalene that has the same knocking properties (ignition quality) of the fuel. The knocking properties in both the cetane and octane number are measured in a special test engine which has a single cylinder, a multi bowl carburetor for different mixtures of fuel, and a pressure gauge to measure the intensity of the knock.

Cetane number

Discussion- Composition of crude oil 50

Composition of Crude Oil


• 84-87% carbon, • 11-14% hydrogen,• 0-3% sulfur, • 0-2% oxygen, • 0-0.6, and • metals 0-100ppm.

All by weight percent.

Ultimate analysis of crude oil


1- Paraffins: Alkanes such as methane, ethane, propane, etc. They are present in large amounts in the crude oil.

2- Olefins: Alkenes such as ethylene, propylene and butylene, these have a double bond and are more reactive than paraffins are present in very small amounts.

Crude can be classified into 9 functional groups


3- Naphthenes: Cycloalkanes such as cyclopropane, they are not aromatics so do not increase the octane number so are a target in refining to convert to aromatics.

4- Aromatics: Such as benzene and toluene they are present in moderate amounts and contribute to increasing the octane number. They can be considered as dehydrogenated cycloalkanes.



5- Naphthalenes: Polycyclic aromatics consisting of two or more aromatic rings such as naphthalene.

6- Organic sulfur compounds: organic molecules that do not only include carbon and hydrogen but also include sulfur such as pyridine. problems caused by sulfur compounds are environmental effects are corrosion, and catalyst poisoning.



7- Oxygen containing compounds: Present in small amounts such as acetic and benzoic acid, the main problem is corrosion so they have to be removed.

8- Resins: Polynuclear aromatics with long side chains of paraffins and a small ring of aromatics they are of high molecular weight. These compounds also contain sulfur, nitrogen, and metals.

9-Asphaltenes: Polynuclear aromatics with 20 or more rings along with paraffinic and naphthenic chains, and usually an indication for the possible use of the crude in coke production if present in large amounts.


Discussion- main products of the refinery

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Main products of a refinery


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1- Volatile products• May be bottled in cylinders and sold or used as fuel.• Propane LPG• Butane LPG• Light naphtha

2- Light distillates• Gasoline used as motor fuel.• Heavy naphtha used in petrochemical industries• Kerosene use for lighting, cleaning, tractor fuel and jet fuel



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3- Middle distillates• Diesel fuel used as fuel in diesel engines and as lubricant.• Benzene• Heating oils• Gas oils

4- Fuel oils• Marine diesel• Bunker fuels (used for ships)



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5- Lubricating oils• Use to reduce friction and hence wear in moving parts.• Motor• Spindle• Machine oils

6- Waxes• Food and paper coating industry• Pharmaceutical uses

7- Bitumen• Asphalt, used for paving roads.• Coke


Discussion- The Refinery 60

The Refinery

Discussion- The Refinery- Overveiw 61

• Sources of oil to the refinery are, the liquid product from separation of natural gas and the directly from the well.

• Before the oil is processed to give final products it is separated into several fractions of boiling point ranges. This is accomplished by distillation (atmospheric, and vacuum).

• The distillation column separates the crude into five main products; gases, kerosenes, light gas oil, fuel oil, and heavy gas oil.

Overview

Discussion- The Refinery- Overview 62

• Each of these products is passed to the next level of treatment, an example is kerosene and light gas oil are passed to vapor recovery units and catalytic cracking units to give gasoline, jet fuel, diesel fuels and others.

• Heavy gas oil is passed to the dewaxing units to give lubricating oils.

• Finally the residue is processed to give asphalt and coke. Usually the residue from the atmospheric tower is fed to a vacuum tower before treatment for better separation. The products of vacuum distillation are light vacuum gas oil, heavy vacuum gas oil, and bitumen.

Overview

Discussion- The Refinery- Overview 63

Overview

Discussion- The Refinery- Main refinery processes

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• Distillation: Separating crude oil to fractions of boiling point ranges, making it ready for further processing. Distillation can be atmospheric or vacuum.

• Cracking: breaking the heavy crude fractions into lighter products which can be further processed or blended with other streams to give final products. Cracking can be either thermal or catalytic.

Different refinery processes


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• Upgrading (reforming): Rearranging of molecular structures to improve the properties and value of the products. Such as catalytic reforming, alkylation, and isomerization.

• Treating: Removal of hetero atm impurities such as sulfur from streams and blends.

• Separation: By physical or chemical means for quality control or further processing.



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• Blending: Combining of different streams to give a final product with the desired specifications and standards. Such as gasoline blending, and jet and diesel fuel blending.

• Utilities: Provide fuel for refinery, power, steam, storage, emission control.


Discussion- The Refinery- Main units of the refinery

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Main units of the refinery


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1. Crude distillation unit (CDU) 2. Vacuum distillation unit (VDU) 3. Thermal cracker 4. Hydrotreaters 5. Fluidized catalytic cracker 6. Separators 7. Naphtha splitter 8. Reformer 9. Alkylation and isomerisation 10. Gas treating 11. Blending pools 12. Stream splitters

Main Units of the refinery

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Main Units of the refinery


Discussion- The Refinery- Distillation 70

1- Distillation, atmospheric & vacuum

Discussion- The Refinery- Overveiw of Distillation

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• Distillation is the separation of completely miscible mixtures of liquids according to the difference of the boiling point and volatility of the components in the mixture.

• Distillation is the first unit operation in any refinery it can be only preceded with smaller units which perform pretreatment of the oil to prepare it for distillation such as desalting and dehydration both will be discussed later.

• Distillation separates raw crude oil into several refinery streams known as fractions or cuts each has it’s own boiling point.

Overview of distillation

Discussion- The Refinery- Overveiw of Distillation

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• The main fractions are light gasses, naphthas, distillates, gas oils and residual oils ordered from the top to bottom.

• Each fraction goes to a different refinery process to be further processed to give final products.

• There are two types of distillation units the first is atmospheric distillation where the operation pressure is close to the atmospheric pressure.


Discussion- The Refinery- Overview of Distillation

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• The second type is the vacuum distillation where the pressure is reduced inside the tower allowing for the vaporization of a part of the high boiling point (heavy) residue from the atmospheric tower at lower temperature, so no decomposition of hydrocarbons will occur.

• The pressure is reduced to 25-40 mmHg and the temperature is around 380-420oC.

• Several unit operations that follow the “main” distillation step also use smaller distillation columns to separate their products into several streams.


Discussion- The Refinery- Atmospheric Distillation

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Atmospheric distillation


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Before the tower• Atmospheric distillation is preceded by a desalting unit to remove salts,

water, and suspended solids.

• Desalting is either chemical or electrostatic. Both use water to dissolve the salts and collect the suspended solids.

• In Chemical desalting surfactants are added along with water to facilitate the separation of the salt water. The mixture is then sent to a settling tank where the oil and water are separated.

• In electrostatic desalting chemicals are separated with a strong electrostatic charge which facilitates the separation of the added water from oil.



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Discussion- The Refinery- Atmospheric Distillation- The tower

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• Modern distillation towers can process 200,000 barrels of oil per day.

• They can be up to 150 feet (50 meters) tall and contain 20 to 40 trays spaced at regular intervals.

• Sometimes trays are replaced with packing made of an inert material mainly ceramics.

• The main aim of packing or trays is providing intimate contact between the vapor phase moving upwards and the liquid phase moving downwards.

The atmospheric tower

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The atmospheric towerPacking and Trays


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• Before the crude enters the tower it is desalted then goes through a network of heat exchangers and a fired heater which pre-heats the feed to the desired temperature then enter the tower just above the bottom of the tower.

• The heat exchangers use the heat from the product streams of the tower to heat the feed crude.

• This decreases the cost of fuel needed for preheating.



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• Steam is added to enhance separation, by decreasing the vapor pressure of the hydrocarbons so stimulates it’s further evaporation.

• Products are collected at the top, bottom and the side of the column.

• Side products are taken from trays at which the temperature corresponds to the boiling point range that is desired for the product.

• In modern towers, a fraction of each side stream is returned to the tower to control the tower temperature so further enhances separation. This goes for the top product and sometimes the bottom product.



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• After leaving the atmospheric tower the products are transferred to storage tanks of fed to other equipment to undergo further processing.


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Discussion- The Refinery- Atmospheric Distillation- The tower- Design & Principle

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• Distillation is an equilibrium stage operation. In each stage a liquid phase is contacted with a vapor phase, and mass transfer occurs from vapor to liquid and vice versa.

• When the crude enters the tower the vapors move upwards and the heavy liquids drop to the bottom of the tower. The liquids are drawn off and sent to the vacuum tower.

• The vapors rise through the trays, coming in contact with the condensed liquid coming from the top.

Design and principle


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• This provides good contact between the vapor and liquid which allows for mass transfer between the two phases.

• The heavier hydrocarbons condense moving from the vapor phase moving upwards to the liquid phase moving downwards and vice versa.

• When the vapor reaches the top it would have lost most of it’s heavy hydrocarbons (HCs) and gained extra light HCs.

• Hence the stream leaving the top will mainly have light HCs and the stream at the bottom having mainly heavy HCs and the side streams in between have intermediate boiling point HCs.



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• The feed can be liquid, vapor or a liquid-vapor mixture, this can enter the column at any point.

• The product streams are at the top and bottom, however side streams can be used to withdraw products at the desired tray with the desired composition.



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Design of column• The column is divided to two sections the section above the

feed tray is the rectifying section, and the section below it is the stripping section.

• The base of the column is used as a reservoir for holding the liquid leaving the bottom tray.

• This liquid is fed to a heat exchanger ”re-boiler” which is used to boil this liquid, the “boil up” resulting from this is recycled to the bottom of the tower, and the liquid stream leaving the re boiler is the bottom product or residue.


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• The column is divided into a series of stages, each is considered at equilibrium (equilibrium stages), with liquid flowing downwards and vapor moving upwards.

• For mass transfer to occur, intimate contact between the phases should be promoted.

• This is done using either trays or packing, both have the ability to force the phases into close contact and giving the sufficient time for the mass transfer to occur.

• After several stages (trays) enough mass transfer has occurred, to ensure that the desired degree of separation has been achieved.



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• The product leaving from the top is called the overhead product or the distillate, this can be a vapor or liquid depending on the type of condenser.

• The product leaving at the bottom is called bottoms, it is a liquid which is produced from the bottom reboiler after the light components were evaporated.

• The vapor leaving the top of the column is passed through a condenser where it is partially or totally condensed. A liquid stream is withdrawn and recycled to the top tray (reflux) and the remainder is the top product stream.


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• The reflux is the amount of liquid recycled from the cooler back to the top plate of the tower. The ratio of the amount of recycled HCs to the amount of HCs in the product stream is the reflux ratio.

• Increasing the reflux improves the purity of the overhead product but decreases it’s amount, and increases the recovery in the bottom stream.

• Hence, increasing the reflux ratio decreases the number of plates (stages) needed for a certain degree of purity, as it gives better separation for the same number of trays.



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• This drives us to two important conclusions, the first is that the smallest number of trays can be known for a specific degree of purity when total reflux is employed.

• The second is that below a certain reflux ratio the separation is impossible no matter the number of trays due to the absence of liquid coming from the top to mix with the vapor.

• Therefore the refinery should operate between the minimum reflux and the total reflux ratios.

• The optimum reflux ratio that is practically employed is between 1:2 to 1:5 times the minimum reflux ratio.



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• In normal operation the five parameters that can be adjusted to control the behavior of the distillation tower are the feed flow, the product streams flow, the reflux ratio or flow, and the boiler duty or the boil up flow.

• A normal column has a temperature gradient and a pressure gradient from bottom to top.

• The operating pressure is controlled by adjusting the heat removal of the condenser.


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Stages• Stages as previously discussed are used to maximize the contact

between he liquid and vapor so mass transfer can occur.

• Each stage is considered to be ideal meaning that the vapor and liquid leaving the stage are considered to be in equilibrium. Meaning that the liquid is at it’s bubble point, and the vapor is at it’s dew point.

• Consequently the vapor composition will depend on the liquid composition. Vapor and liquid leaving the stage are never at equilibrium, ideality is only an approximation, but stage efficiencies are used to describe how far are the leaving fluids from equilibrium.



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• Theoretically speaking there is no limit to the purity of the products, providing that there is enough reflux and number of stages. But in practice there are limits to both, so not any degree of purity can be accomplished. Theoretical limits are calculated by assuming total reflux (minimum stages) and minimum reflux (infinite number of stages).



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CondensersThere are two types of condensers, the total condensers and the partial condensers. • The total condenser condenses all the vapor leaving the tower,

consequently the composition of the liquid leaving the condenser is identical to the vapor leaving the column. Part of the liquid is recycled to the column as reflux and the other is the overhead product stream.

• The partial condenser only liquefies a part of the vapor. The liquid produced is recycled to the column, and the vapor is the product stream. Thus the composition of the vapor entering the condenser and the two product streams will be different. Partial condensers are considered an extra stage as they operate as an equilibrium separation stage.



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• The reflux ratio is defined as the ratio of reflux to distillate which represents the fraction of the vapor product from the column that is recycled back to it.



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Re boilers• Most reboilers are partial reboilers that are that they vaporize only part of

the liquid in the column base which is recycled to the column and the remaining liquid is the product stream or residue. This also is considered as an extra stage as it also operates as an equilibrium separation stage.

• In large columns side stream reboilers can be used to draw liquid off a tray, heat it, then return the vapor-liquid mixture to the same or a different tray.



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Feed conditionsThe column internal flows are determined by the thermal condition of the feed.

• If the feed is below it’s bubble point, heat should be added to raise the temperature and allow it to vaporize.

• This heat is provided by the condensing vapor rising through the column, so this fed liquid condensed vapor thus decreasing the off product produced. If the feed is as a superheated vapor, it will vaporize some liquid so the liquid flow is decreased and the vapor flow is increased.



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• If the feed is saturated, no additional heat must be added or removed and the feed directly is part of the normal flow in the column.

• This is due to that inside the column the liquid and vapor are at the bubble and dew points respectively so adding feed at a different temperature will cause a disturbance in the amounts of gas and liquid present which will change phases to give the required energy to change the temperature of the feed to the dew or bubble points.


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Side cut strippers• Kerosene and Diesel are products that are withdrawn form the column as

sidestreams, these usually contain hydrocarbons form other cuts. These are stripped in a small trayed (usually 5-6 trays) columns after being withdrawn using steam which allows for lower boiling point hydrocarbons are stripped out at the flash point of the other cuts that these hydrocarbons belong to.

Side operations

Discussion- The Refinery- Atmospheric Distillation-

The tower- Side ops.

Discussion- The Refinery- Atmospheric Distillation- The tower- Side ops.

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Pump arounds• Pumparounds are side operations where part of the liquid is withdrawn

from a tray then heated then fed to the same or a different tray.

• This allows for the utilization of the available column heat using the heat exchanger network, and maintaining the stability of the vapor loading of the column and maintaining the amount of liquid moving in the column.

• Pumparound also control and distribute fractions between the products as the control the flow of vapor. If the rate of pumparound is decreased the vapor flow will increase.

Side operations

Discussion- The Refinery- Atmospheric Distillation- The tower- Side ops.

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• If there are no pump around the liquid flow with be highest at the top as the vapor load will increase then condense in the condenser then recycle to the top of the tower.

• The capital cost is increased by the addition of a pumparound, this is due to the need of a pump and a heat exchanger. Distillation columns usually have 3 pump arounds.

Side operations

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Products of Atmospheric distillation

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Products of Atmospheric distillation

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Products of Atmospheric distillationEach of these products goes to a different unit to undergo further processing to give the final product. Examples are

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Atmospheric column schematic

Preheating, desalting, tower, side strippers, pump arounds, cooler, reboiler, and products.

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Vacuum distillation

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• The residue from atmospheric distillation is sent to a vacuum distillation tower which recovers additional liquid at 0.7 to 1.5 psia (atmospheric pressure is 14.7 psia) and temperature between 380-420oC.

• The vacuum is created by vacuum pumps or steam ejectors is pulled from the top of the tower.

• Vacuum towers have larger diameters and are simpler in design than atmospheric columns.

Overview

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• Random packing and demister pads are used mostly instead of trays.

• This usually has a smaller number of streams than the atmospheric tower.

• The overhead stream- light vacuum gas oil can be used as a lube base stock, heavy fuel oil, as feed to a conversion unit.

• The side draw is heavy vacuum gas oil.

• The vacuum residue can be used to make asphalt or sent to a coker or visbreaker for further processing.

Overview

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• The vacuum residue can be used to make asphalt or sent to a coker or visbreaker for further processing.

• Processing the residue at lower pressure will allow for the vaporization of the hydrocarbons.

• Tis will reduce the need for increasing the temperature, which can cause the decomposition of the hydrocarbons.

• The vacuum distillation unit is supported with side strippers to allow for the refining of the side draws.

Overview

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• Dry vacuum distillation: without the injection of steam. It runs at a very low pressure (10-15 mmHg at the top) so requires the use of a booster ejector before the first condenser.

• Wet vacuum distillation: With the injection of steam in the furnace feed and stripping stream in the bottom of the tower. It uses higher pressure (40- 60mmHg at the top). A precondenser is used before the tower.

Types of vacuum distillation

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113


114

• Semi-wet vacuum distillation: is when only steam is injected at the bottom of the column. A booster ejector is needed. It is positioned upstream of the first overhead condenser and designed to boost process pressure high enough to allow condensation.


115

• LVGO: light vacuum gas oil.

• MVGO: medium vacuum gas oil.

• HVGO: heavy vacuum gas oil.

• Cracked hydrocarbons: hydrocarbons produced when the feed is cracked at the furnace. They are found at the top of the tower with the noncondensables and the steam injected in the process.

Definitions

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• Noncondensables: compounds that can not be condensed by the vacuum system. This is made from air entering from leaks, noncondensables dissolved in the feed when stored in the storage tank, and light hydrocarbons produced by cracking in the furnace.

• Slop cut and overflash: the two are the internal reflux coming from the first tray above the feed inlet. Overflash is 3-5% of the feed, is the section seen with the feed liquid to the bottom of the column.

Definitions

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• The atmospheric residue is sent directly to the vacuum tower, it is sometimes stored at 150oC to ensure it’s viscosity.

• It us preheated in a group of exchangers by heat recovery from products and pump arounds.

• Then it is heated in a furnace to 380-415oC and fed to the distillation column. It should be noted that flashing occurs in the transfer line.

The vacuum tower

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• In wet vacuum distillation, the furnace banks are often equipped with dilution steam injection to limit the temperature thus reduce coking.

• The number of side streams is usually based on the needs of the units downstream. The distillate is withdrawn in two cuts MVGO and HVGO.

• The HVGO is used in pump around due to it’s adequate temperature.

The vacuum tower

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• If it is required to increase the value of the gas oil or if the downstream units require special initial cut point, three cuts are drawn off from the column.

• An LVGO which is sent to atmospheric gas oil to produce commercial products.

• An MVGO and HVGO which are the feed for the downstream units.

The vacuum tower

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The vacuum tower

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• The vacuum column has two main targets the first is the recovery of light hydrocarbons from the atmospheric residue and the preparation of feed for the following units.

Description of the column

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1- Column without a fractionation zoneIf no end or initial point requirement for the vacuum distillate.

Configuration:• One or two wash zones fed by internal reflux of the HVGO

draw tray.• A heat exchanger zone above the HVGO side draw tray.• A heat exchanger zone above the HVGO side draw tray.

Preparing the feed for catalytic units

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2- Column with fractionation zonesIf the downstream units require a specified distillate end point.

Configuration• The feed for this zone is made up of internal reflux under

HVGO.

• If better values are desired for the gas oil in the feed then a fractional zone is installed between the LVGO and the MVGO offtakes.


124

3- Bottom of the column

• The bottom of the column has 4 to 6 valve trays to perform stripping in wet vacuum distillation, In dry vacuum distillation the bottom of the column is equipped with simple horizontal baffles.

• The vacuum residue in the bottom of the column must be as short as possible to prevent coking.


125

Special case, two stage vacuum distillation

Configuration• In some cases the solution of two stage vacuum distillation

can be used to obtain very heavy cuts.

• The first tower is dry and the second is wet. The bottom of the first tower supplies the feed for the second.


126

• These are equipped with side strippers to the side draw distillates.

• And the column has fractionation zones between each side stream and the other one.

Vacuum distillation design to give lube oils

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• These have a stripping column at the bottom of the tower and are therefore at semi wet.

• They operate under higher vacuum than the other towers.

Vacuum distillation design to produce bitumen

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The choice is dependent on economic considerations

• The pressure drop in the column as a result of the fractionation.

• The available utilities (whether the cooling air temperature allows for the condensation of the overhead vapors.

Choosing the type of vacuum distillation

129

Technology

130

• Fractionation and heat exchanger zones are equipped with packing to curb pressure drop.

• The bottom zone is equipped with reinforced valve trays.• There are two types of packing.

• The first is random packing, made of metal rings and grates. This is used for heat exchanger zones.

• The second is Structured packing which is made of stacks folded and perforated corrugated metal grates.

Packing and distributors

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• This type of packing is more expensive and more effective and is mainly used in fractionation zones.

• It is today being used for all the column above the wash zones. The wash zones can be equipped with less sophisticated grates.

• The liquid is supplied to the packing by two types of distributors. The first is sprays and the second is gravity.

Packing and distributors

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• Pumps and jet ejectors are used to create vacuum.

• Ejectors recompress the gasses by speeding them up (venture effect) through a nozzle. Where the working fluid is medium or low pressure steam.

• The vapor phase at the ejector exit is partially condensed in a heat exchanger with cooling water.

Vacuum pumps and ejector- condensers

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134


135

• These are direct contact condensers which generate pollution and have been phased out.

• The liquid phase is sent to an overhead drum via barometric leg. The vapor phase goes from the condenser to another ejector-condenser stage.

• The overhead drum allows the hydrocarbons to settle so separate from the water.


136

• Liquid pumps have a compression ratio of about 10 and therefore replace two or three stages of ejectors in dry or wet vacuum distillation.

• Pumps are less reliable than ejectors.

• The higher investment cost required by pumps are offset by the reduced steam consumptions and lower installation costs.

• Even with the addition of the cost of electric power consumed by the pumps.


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138


Types of vacuum pumps

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140

The whole tower with the vacuum system

141

Products of the vacuum distillation unit

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Products of the vacuum distillation unit1- Multiple gas oils.• Sent to the hydrotreating unit.2- Vacuum residue:• Blended to give asphalt and heavy fuel oil.• Further processing. Thermal treatment or solvent extraction.

143

Configuration• Reduced pressure to allow for lower temperatures.

• Larger diameter than atmospheric column.

• Liquid reflux from pumparounds.

• No reboiler.

• Stripping steam can be used.

• Needed for deep cuts.

Vacuum distillation summary

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Feed• Residue from atmospheric distillation.

• All the vapor comes from the heated feed.

• Under vacuum.

• Separate higher boiling materials at lower temperatures so minimize thermal cracking.

Vacuum distillation summary

145

Cracking

146

• Cracking is the process (chemical reaction) where large high boiling point hydrocarbons are broken “cracked” into smaller, lighter molecules.

• These can be suitable after further processing for blending to different products such as gasoline, jet fuel, diesel fuel, petrochemical feedstock, and other high value light products.

Overview

147

• Cracking units are an essential component in the refinery:

• Allow the refinery to achieve high yields of transportation fuels and valuable light products.

• Provide operating flexibility to maintain the output of the light products in the face of normal crude oil quality fluctuation.

• Allows the economic use of the heavy and sour crude oils when burned during cracking.

Overview

148

Thermal cracking

149

• Thermal cracking followed by the separation using physical differences (distillation).

• The products are usually naphtha, gas, gas oil, and thermal cracked residue.

• Sometimes thermal cracking is replaced with delayed coking to give coke as one of the products.

Thermal cracking

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• The operating temperature is about 450-500oC.

• And the operating pressure is 2-3 bar.

Thermal cracking

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• Products (Residue) from the atmospheric and vacuum column are used.

• The feed is preheated in a furnace to about 1000oF.

• The space velocity is high to prevent reactions from occurring in the furnace tubes.

• The effluent form the furnace goes to the reaction chamber for a few munities, however the pressure is kept as high as 140 psi which favors only cracking not coking.

The process

152

• The effluent form the reaction chamber is passed through a quench to stop the cracking.

• Quenching is done by mixing this stream with a cooler recycle stream.

• This stream is then fed to a flash chamber where the light products go overhead then are fed to a fractionator.

• The C4 and lighter streams from the fractionator are sent for further processing usually alkylation.

The process

153

• The thermally cracked gasoline and naphtha from the fractionator are sued for gasoline blending.

• The gas oil from the fractionator is used as a distillate fuel.

• The residue from the bottom of the flash chamber is diluted by gas oil to reduce it’s viscosity then sold as residual fuel and heavy industrial fuel oil.

The process

154

The process

155

Coking

156

• A sub category of a variant of thermal cracking is coking.

• Coking is thermal cracking under severe conditions to allow to the breaking of the hydrocarbons completely to give carbon (coke).

• Coking was used to preheat vacuum residues to prepare coker gas oil, which is a suitable feed for the catalytic cracker. This has the advantages of the amount of coke depositing on the catalyst.

Coking

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The main uses of petroleum coke:

• Fuel.• Manufacture of anodes for electrolytic cell.• Direct use as chemical carbon source for manufacture of

elemental phosphorus, calcium carbide.• Manufacture of electrodes for use in electric furnace .• Manufacture of graphite

Coking

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• The delayed coking process was developed to minimize refinery yields of residual fuel oil.

• This is achieved by severe thermal cracking of stocks such as vacuum residuals. Thermal tars, and aromatic gas oils.

• In early refineries, the severe thermal cracking of these stocks caused the formation of large amounts of residual coke.

Delayed coking

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• Gradual evolution of refineries lead to that heaters were designed to raise the feedstock temperature above the coking temperature without significant coke formation in the heaters.

• This was achieved by increasing the velocity of flow in the heather (minimum retention time).

• Then providing an insulated surge drum on the exit of the heater which will give sufficient time for coking to occur.

Delayed coking

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Delayed coking

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• The higher the outlet temperature of the furnace the greater the tendency to produce shot coke.

• And the shorter the time before the furnace tubes have to be decoked.

• Usually the furnace tube have to be decoked every 3-5 months.

Delayed coking

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• Hot fresh liquid feed is fed to the fractionator two to four trays above the bottom vapor zone.

• Vapors from the top of the fractionator return to the base of the fractionator.

• These consist of steam along with the products of thermal cracking.

The process

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• These vapors; afterbeing fed to the fractionator are passed through the quench trays.

• Quench trays are trays where the fresh feed is mixed with the gasses from the reactor.

• There are usually 2-3 trays above the feed trays which are below the gas oil draw tray.

• These trays are refluxed with partially cooled gas oil to provide control over the gas oil end point.

The process

164

• Steam and vaporized light ends are returned from the top of the gas oil stripper to the fractionator 1-2 trays above the gas oil draw tray.

• Eight to ten trays are between the gas oil draw and the naphtha draw (column top).

The process

165

The process

166

• The coke drum is continuously being filled during service to a safe margin from the top.

• There are two coke drums installed in parallel, one is in operation and getting filled by coke. And the other is already full and being cleared from the coke.

• When one drum is full the heater is switched to the other drum and the full drum is isolated.

Coke removal

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• After isolation, the empty drum is steamed to remove the hydrocarbon vapors.

• Then cooled by filling with water, opened, drained then the coke removed.

• In some plants decoking is accomplished by a mechanical drill.

• However, most plants use hydraulic systems.

Coke removal

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• The hydraulic system, is a number of high pressure (13800 to 31000 kPa) water jets which are lowered into the coke bed on a rotating drill stem.

• A small whole in diameter is first cut all the way through the bed from the top to the bottom using a special jet.

• This is done to allow the main drill stem to enter and allow the movement of coke and water through the bed.

Coke removal

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• The bulk of the coke is then cut from the drum, usually starting at the bottom.

• Some operators prefer to start at the top to avoid the chance of dropping large pieces of coke which can trap the drill stem or cause problems in the following units.

Coke removal

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• A newly developed technique called chipping is now used to remove the coke from the surge drum.

• In this technique the cutting bit is repeatedly transferred back and forth from the top to the bottom as it rotates.

• Then the coke is cut from the center to the wall.

• This reduces the cutting time, produces fewer fines, and eliminates the problem of the bit being trapped.

Coke removal

171

• The coke which falls from the drum is often collected directly in railroad cars.

• An alternative is that the coke is sluiced or pumped as a water slurry or conveyed by a belt.

Coke removal

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Coke removal

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• The coke drums are filled and emptied and filled on time cycles.

• The fractionation column is operated continuously.

• Usually 2 drums are present one for reaction and the other for releasing coke.

• However units having 4 drums are being widely used.

Operation

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• The table shows time schedules for the different stages of operation of the unit.

Operation

175

• The capacity can be increased by operating in shorter cycle times.

• Usual design factors will allow for a 20% increase in capacity by decreasing the coking time from 24 to 20 hours.

• Shorter times will cause a decrease in yield of liquid products, and reduce the remaining drum life by 25%.

Operation

176

Operation

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Flexicoking

178

• The feed to flexicoking can be any heavy oil such as vacuum residue, coal tar or sand bitumen.

• The feed is preheated to about 315 to 370oC then sprayed into the reactor where it contacts a hot fluidized bed of coke.

• This coke is recycled to the reactor from the coke heater at the rate which is sufficient to maintain the reactor fluid bed temperature between 510-540oC.

Flexicoking

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• The coke recycle thus provides the sensible heat and heat of vaporization for the feed.

• And the endothermic heat for the cracking reactions.

• The cracked vapor products pass through several cyclones in the top of the reactors to separate them from the entrained coke particles.

• Then are quenched in a scrubber vessel at the top of the reactor.

Flexicoking

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• Some of the high boiling point cracked vapors are condensed in the scrubber then recycled to the reactor.

• The remainder is sent to the cocker fractionator to be separated to several cuts.

• The coke produced by cracking is deposited as thin films on the existing coke particles in the reactor fluidized bed.

Flexicoking

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• The coke is stripped with steam in a baffled section at the bottom of the reactor to prevent the reaction products, other than coke, from being entrained with coke leaving the reactor.

• Coke flows from the reactor to the heater where it is reheated to 600oC.

• The coke heater is also a fluidized bed with the primary function of transferring heat from the gasifier to the reactor.

Flexicoking

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Flexicoking

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• Coke flows from the coke heater to a third fluidized bed in the gasifier where it is reacted with air and steam to give a fuel gas product consisting of CO, hydrogen, carbondioxide, and nitrogen.

• Sulfur in the coke is converted to H2S and a small amount of COS.

• Nitrogen in the coke is converted to NH3 and N2.

Flexicoking

184

Flexicoking

185

• This gas flows from the top of the gasifier to the bottom of the heater where it is used to fluidize the heater bed.

• And provide the heat needed in the reactor.

• As previously mentioned, the heat required by the reactor is supplied by recirculation hot coke from the gasifier to the heater.

Flexicoking

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• The system can be designed and operated to gasify about 60-97% of the coke product from the reactor.

• The overall coke inventory of the system is maintained by withdrawing a stream of purge coke from the heater.

• The coke gas leaving the heater is cooled in a waste heat steam generator.

• Then passed through external cyclones and a wet scrubber.

Flexicoking

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• The coke fines collected in the wet scrubber plus the purge coke from the heater represent the net coke yield and contain all of the metal and ash components of the reactor feedstock.

• After removal of the entrained coke fines the coke gas is treated to remove the hydrogen sulfide in a Stretford unit then used as refinery fuel.

• This gas has a much lower heating value than natural gas, so modifications to boilers an furnaces may be necessary for efficient combustion.

Flexicoking

188

Fluid coking

189

• Fluid coking is a simplified version of flexicoking.

• In the fluid coking process, only enough of the coke is burned to satisfy the heat requirements of the reactor and the feed preheat.

• This is about 20-25% of the produced coke from the reactor.

• The remainder of the coke is withdrawn from the burner vessel and is not gasified.

Fluid coking

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• Therefore only two fluid beds are used in a fluid coker; a reactor and a burner which replaces the heater.

• The main advantage of the flexicoker over the more simple fluid coker is that most of the heating value of the coke produced is made available as low sulfur gas.

• This gas can be burned without a sulfur dioxide removal system on the stack.

Fluid coking

191

• Also the coke gas can be used to displace liquid and gaseous hydrocarbon fuels in the refinery heaters.

• And does not have to be used only in boilers as the case with fluid coke.

Fluid coking

192

• The products from Flexicoking and fluid coking are the same as those from the delayed coking except for the amount of reactor coke product which is burned or gasified.

• Thus the coke yield from fluid coking will be about 75-80% of the coke yield from a delayed coker.

• And the yield from a flexicoker will be in the range of 2-40 wt% of the delayed coker.

Yields from Flexicoking and Fluid coking

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Visbreaking

194

• Visbreaking is relatively, mild thermal cracking operation.

• It is mainly used to reduce the viscosities and pour points of vacuum tower bottoms to meet specific oil specifications.

• Or to reduce the amount of cutting stock required to dilute the residue to meet the desired specifications.

• The cutting stock is a feedstock mixed with the product to decrease it’s viscosity.

Visbreaking

195

• Refinery product of heavy fuel oils can be reduced by 20-35%.

• And the cutter stock requirements can be reduced by 20-30% by visbreaking.

• Also the gas oil fraction produced by visbreaking is also used to increase catalytic cracker feed stocks and increase gasoline yields.

Visbreaking

196

• Long paraffinic side chains attached to aromatic rings are the main cause of high pour points and viscosities for paraffinic base residues.

• Visbreaking is carried out at conditions to allow the breaking off of these side chains and their subsequent cracking to shorter molecules with lower viscosities and pour points.

• The amount of cracking is limited, because if the operation is too severe, the resulting product becomes unstable and can be liable to polymerize during storage.

Visbreaking

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• The degree of viscosity and pour point reduction is a function of the composition of the residues which are fed to the visbreaker.

• Waxy feed achieve pour point reduction of 15-35oF and final viscosities from 25-75% of the feed.

• High asphaltene content in the feed reduces the conversion ratio at which a stable fuel can be made which results in smaller changes in the properties.

Visbreaking

198

• The properties of the cutter stocks used to blend with the visbreaker tars also have an effect on the severity of the visbreaking operation.

• Aromatics cutter stocks such as catalytic have good effect on fuel stability and permit higher visbreaker conversion levels.

• The molecular structures of the compounds in petroleum which have boiling points above 538oC are highly complex and are classified as oils, resins, and asphaltenes according to solubility in light paraffinic hydrocarbons.

Visbreaking

199

• The oil fraction is soluble in propane.

• The resin fraction is soluble in either pentane, hexane, n-heptane, or octane. Depending on the investigator.

• The solvent selected has an effect on the amounts and properties of the fractions obtained.

Visbreaking

200

The main reactions that occur during visbreaking are:

• Cracking of the side chains attached to cycloparaffin and aromatic rings. Which are either removed or shortened.

• Cracking of resins to light hydrocarbons (mainly olefins) and compounds which convert to asphaltenes.

• At temperatures above 480oC some cracking of naphthene rings occurs.

Visbreaking

201

The severity of the visbreaking operation can be expressed in several ways:

• The yield of the material boiling below 166oC.

• The reduction in product viscosity.

• The amount of standard cutter stock needed to be blended with the visbreaker to give the desired specifications compared to the amount needed for the feedstock.

Visbreaking

202

• In the US the severity is expressed as the volume % product gasoline in a specified boiling range.

• In Europe as the weight % yield of gas plus gasoline.

Visbreaking

203

• There are two types of visbreaking operations, coil and furnace cracking and soaker cracking.

• As in all cracking reactions the reactions are time and temperature dependent.

• Compromise must be done between temperature and time to give the highest yields.

Visbreaking

204

• Coil cracking uses higher furnace outlet temperatures 473-500oC and reaction times from 1 to 3 minutes.

• While soaker cracking use lowers the furnace outlet temperatures (427-443oC) and longer reaction times.

• The product yields and properties are similar, but the soaker operation with it’s lower furnace outlet temperatures ahs the advantages of lower energy consumption and longer run times before having to shut down to remove coke from the furnace tubes.

Visbreaking

205

Visbreaker

206

• Run times are in the range of 3-6 months for furnace visbreakers.

• And 6-18 months for soaker visbreakers.

• The apparent advantage of the soaker visbreaker is partially balanced by the greater difficulty in cleaning the soaking drum.

Visbreaking

207

Soaker visbreaker

208

Coil visbreaker

209

Coil visbreaker

210

Soaker visbreaker

211

• The feed is introduced into the furnace and heated to the process temperature.

• In both the furnace and coil cracking process the feed is heated to the cracking temperature 475-500oC.

• Then the feed is quenched with gas oil or tower bottoms.

• This is to stop the cracking reaction.

Process

212

• In soaker cracking operation the feed leaves the furnace at 425-440oC.

• Before it is quenched it is passes through the soaking drum where additional reaction time is provided.

• Pressure is an important design parameter.

• Units are designed to operate as high as 5170 kPa for liquid phase visbreaking and as low as 690-200 kPa for 20-40% vaporization at the furnace outlet.

Process

213

• In furnace cracking, fuel consumption accounts for nearly 80% of the operating cost.

• Fuel requirement for soaker visbreaking is about 30-35% lower.

Process

214

• The properties of the products of visbreaking change with the conversion and the characteristics of the feedstocks.

• However some properties such as the diesel index and octane number are more closely related to feed quality and the density and viscosity of the gas oil uesd.

products

215

products

216

products

217

Fluid Catalytic cracking

218

• Catalytic cracking is the most important and widely used process in the refineries for converting heavy oils into gasoline and lighter products.

• Originally cracking was accomplished thermally. Bit the catalytic process has almost completely replaced it.

• This is due to that the catalytic process produces higher octane number gasoline and les heavy fuel oils and light gasses.

Overview

219

• Fluid catalytic cracking (FCC) operates at high temperature and low pressure conditions and employs a catalyst.

• It converts heavy gas oil from atmospheric distillation and other streams to light gasses, petrochemical feedstock, gasoline blendstock (FCC naphtha), and diesel fuel blendstock.

Overview

220

• The cracking process produces coke as a side product which remains on the catalyst surface and lowers it’s activity.

• It is important to regenerate the catalyst by burning this coke in air.

• The cracking reaction is endothermic and regeneration is exothermic. Hence the regeneration heat can be used to supply the heat needed to preheat the feed to the reactor.

Overview

221

• The FCC process employs a catalyst in the form of very fine metallic particles about 70 micrometers.

• These particles behave as fluid when aerated with vapor.

• The fluidized catalyst is continuously circulated between the reaction zone and the regenerator. Thus acting as a “vehicle” to transport heat between the two processes.

The process

222

There are two types of FCC units

• The first is side by side type, where the reactor and the regenerator are separate vessels adjacent to each other.

• The second is the orthoflow or stacked type where the reactor is mounted on top of the regenerator.

The process

223

The process

224

• Until 1965 most units were a discrete dense phase fluidized catalyst bed in the reactor.

• The unit operated so that most of the cracking occurred in the reactor bed.

• The extent of cracking was controlled by changing the depth of the reactor bed and hence the residence time.

• Most recently designed units operate with a minimum bed level in the reactor and the reaction rate is controlled by varying the catalyst circulation rate.

The process

225

The process

• The fresh feed and recycle streams are preheated by heat exchangers or a furnace and enter the unit at the base of the feed riser where they are mixed with the hot regenerated catalyst.

• The heat from the catalyst vaporizes the feed and raises it’s temperature to the reaction temperature.

• The mixture of the catalyst and hydrocarbons travel up the riser to the reactors.

226

The process

227

The process

• The cracking reactions start when the feed contacts the hot catalyst in the riser and continues until the oil vapors are separated from the catalyst in the reactor.

• The vapors produced are sent to a fractionator to be separated into liquid and gaseous products.

• The catalyst leaving is called the spent catalyst, and contains hydrocarbons adsorbed on it’s surface as well as coke.

228

The process

229

The process

• Part of the adsorbed hydrocarbons is removed by steam before the catalyst is fed to the regenerator.

• In the regenerator coke is burned with air. The temperature and coke burn off are controlled by changing the air flow rate.

• The heat of combustion raises the catalyst temperature to 620-845oC, most of which is transferred to the feed in the riser.

• The regenerated catalyst contains 0.01-0.4 weight % coke.

230

The process

• The regenerator can be designed to operate to burn the cohe on the catalyst to:

• Either a mixture of carbon dioxide and carbon monoxide.

• Or completely to carbon dioxide.

• Older units were designed to give CO to minimize the blower operating and capital costs. As only half the amount of air is needed to be compressed to burn the carbon to CO not CO2.

231

The process

• The flue gas leaving the regenerator will have large amounts of carbon monoxide which is burned to carbon dioxide in a CO furnace (waste heat boiler).

• This is done to recover the available fuel energy.

• The hot gases produced in this process can be used to generate steam or to power expansion turbines.

232

The process

• Newer units are design to burn the coke to CO2 in the regenerator as they can burn to a much lower residual carbon level on the regenerated catalyst.

• This gives a more reactive and selective catalyst after regeneration.

• And better product distribution results at the same equilibrium catalyst activity and conversion level.

233

The process

234

FCC

235

FCC• The products formed in catalytic cracking are the result of

primary and secondary reactions.

• The primary reactions are these having the initial carbon-carbon bond breaking and the immediate neutralization of the carbonium ion.

236

Advantages• High yields of gasoline.

• High reliability and low operating cost.

• Operating flexibility to adapt to changes in crude oil quality.

In large transportation fuels oriented refinery 40% of the production of gasoline and distillates is produced from the FCC unit only.

FCC

237

• FCC produces significant amounts of light gasses including olefins.

• Olefins are highly reactive unsaturated chemicals that can be used as petrochemical feedstock or as feedstock for the upgrading units in the refinery.

• With suitable catalyst selection FCC units can be designed to maximize the production of gasoline blendstock or petrochemical feedstock.

FCC

238

• Zeolite catalysts have a higher cracking activity than amorphous catalysts, and shorter reaction times are needed to prevent over cracking.

• This has resulted in units which have a catalyst-oil separator in place of the fluidized bed reactor to achieve maximum gasoline yields at a given conversion level.

• Newer units are redesigned to have up to 25% reduced crude in the FCC feed.

New designs for fluidized bed catalytic cracking units

239

Commercial cracking catalysts are divided to 3 classes:• Acid- treated natural aluminosilicates.

• Amorphous synthetic silica-alumina combinations.

• Crystalline synthetic silica-alumina catalysts (zeolites).

• Most catalysts used today are either type 3 or mixtures of types 2 and 3 catalysts.

Cracking catalyst

240

The advantages of the zeolite catalysts are:

• Higher activity.

• Higher gasoline yields at a given conversion.

• Production of gasolines containing a larger percentage of paraffinic and aromatic hydrocarbons.

Cracking catalyst

241

• Lower coke yield.

• Increased isobutane production.

• Ability to go to higher conversions per pass without overcracking.

Cracking catalyst

242

• The high activity of zeolite cracking catalyst allows for shorter residence time.

• Basic nitrogen compounds, iron, nickel, vanadium, and copper in the oil act as poisons to cracking catalysts.

• The nitrogen reacts with the acid centers on the catalyst and lowers it’s activity.

Cracking catalyst

243

• The metals deposit and accumulate on the catalyst and cause a reduction in throughput.

• By increasing coke formation and decreasing the amount of coke burn-off per unit air.

• This is due to the catalysis effect of the metal where the coke is converted to carbon dioxide rather carbon monoxide.

Cracking catalyst

244

• It is generally accepted that nickel has four times the effect on catalyst selectivity as vanadium.

• Although nickel and vanadium deposits reduce the catalyst activity by occupying the catalyst’s active sites.

• The major effects are the promotion of the formation of gas and coke and reduce the gasoline yield.

Cracking catalyst

245

• Metals removal processes can be used to reactivate the catalyst.

• This is done by cycling a slip stream through a metals removal system.

• This allows the equilibrium catalyst metal concentration to be controlled at the level which fresh catalyst is required to maintain activity and selectivity equals catalyst losses.

Cracking catalyst

246

Catalytic hydrocracking

247

• Hydrocracking was commercially developed to convert liginite to gasoline.

• It was then used to upgrade petroleum feedstocks and products.

• It has the advantage of the production of hydrogen as a byproduct in large amounts and at low cost.

Overview

248

The advantages of hydrocracking are

• Better balance of gasoline and distillate production.

• Greater gasoline yield.

• Improved gasoline pool octane quality and sensitivity.

• Supplementing of fluid catalytic cracking to upgrade heavy cracking stocks, aromatics, cycle oils, and coker oils to gasoline, jet fuels, and light fuel oils.

Overview

249

• In a modern refinery catalytic cracking and hydrocracking work as a team.

• The catalytic cracker takes the more easily cracked paraffinic atmospheric and vacuum gas oils.

• And the hydrocracker uses the more aromatic cycle oils and coker distillates as feed. These streams resist catalytic cracking even when the newly developed zeolites are used.

• The higher pressure and the hydrogen atmosphere makes them easier to break.

Overview

250

• In addition to cycle oils and middle distillates, it is also possible to use residual fuel oils and reduced crude as feed to the hydrocracking unit.

Overview

251

There are two types of hydrocracking:• Those which operate on distilled feed (hydrocracking).

• And those which operate on residual materials (hydroprocessing).

• These processes are similar and some processes can be adapted to operate on both types of feed.

• The major difference is in the type of catalyst and the operating conditions.

Overview

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• There are hundreds of simultaneous reactions occurring in hydrocracking. It is the general opinion that the mechanism of hydrocracking is the mechanism of catalytic cracking with hydrogen superimposed.

• Catalytic cracking is the breaking of a carbon-carbon single bond.

• Hydrogenation is the addition of hydrogen to a double bond.

The reactions

253

The reactions

254

• This shows that cracking and hydrogenation are complementary.

• Cracking provides olefins for hydrogenation.

• And hydrogenation provides heat for cracking.

• The cracking reaction is endothermic and the hydrogenation is exothermic. The overall reaction provides excess heat.

The reactions

255

• This heat causes an increase in temperature and an increase in the rate of the reaction.

• This is controlled by the injection of cold hydrogen as a quench in the reactor to absorb the excess heat.

• Other reactions that occur are the hydrogenation of condensed aromatics to cycloparafins and isomerization.

The reactions

256

• Hydrocracking is usually carried out at temperatures between 290 and 400oC an pressures between 8275 and 13800 kPa.

• The circulation of large quantities of hydrogen along with the feedstocks prevent the excessive fouling of catalyst and allows for long runs before catalyst regeneration is needed.

The process

257

• The hydrocracking catalyst is susceptible to poisoning by metallic salts, oxygen, sulfur, and organic nitrogen compounds present in the feedstocks.

• During hydrocracking molecules containing metals are cracked and the metals are deposited on the catalyst.

• The nitrogen an sulfur compounds released are removed by conversion to ammonia and hydrogen sulfide during the reaction.

The process

258

• It is nectary to reduce the waster content of the feed to less than 25 ppm, as at the temperatures required by hydrocracking steam causes the crystalline structure of the catalyst to collapse.

• This is accomplished by passing the feed through a silica gel or molecular sieve dryer.

• On average, the hydrotreating process requires about 150 to 300 ft3 of hydrogen per barrel of feed.

The process

259

• The hydrocracking process may require one or two stages depending on the process itself and the feed used.

• The GOFining process is a fixed bed regenerative process, which has a molecular sieve catalyst impregnated with rare earth metal.

• The process employs either single stage or two stage hydrocracking with typical operating conditions ranging from 350-420oC and 6900-13800kPa.

The process

260

The process

261

• The decision weather to use single or two stage system depends on the size of the unit and the product desired.

• For most feedstocks the use of a single stage will allow the complete conversion of the feed to gasoline and lighter products by recycling the heavier material to the reactor.

• The next slide has the figure of the two stage system. The one stage system will have the same flow sheet with the addition of the recycle of the fractionation tower bottoms to the reactor feed.

The process

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The process

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• The fresh feed is mixed with the make up hydrogen and recycle gas which also has a high hydrogen content and passed through a heater then fed to the first reactor.

• If the heed has not been hydrotreated it is passed first through a guard reactor.

The process

264

• This reactor is placed before the first hydrocracking reactor.

• It has a modified hydrotreating catalyst (cobalt based) which converts organic sulfur and nitrogen compounds to hydrogen sulfide, ammonia, and hydrocarbons.

• This is to protect the precious metals in the first reactor.

The process

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The process

266

• The hydrocracking reactors are operated at a temperature that is sufficiently high to convert 40-50 vol% of the effluent from the reactor.

• The reactor effluent goes through a series of heat exchangers to a high pressure separator.

• Where the hydrogen rich gasses are separated and recycled to the first stage for mixing with the feed.

The process

267

• The liquid product from the separator is sent to a distillation column.

• Where the C4 and lighter gasses are taken off as overhead.

• And the light and heavy Naphtha, jet fuel, and diesel boiling point range streams as liquid side streams.

• The bottoms are used as feed to the second stage reactor system.

The process

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The process

269

• The bottoms stream from the fractionator is mixed with thee recycle hydrogen from the second stage and sent through a furnace to the second stage rector.

• In this reactor the temperature is maintained to bring the total conversion of the unconverted product from the first stage and the second stage recycle to 50-70 vol% per pass.

• The second stage product is combined with the first stage product before fractionation.

The process

270

The process

271

• Both the first and second stage reactors contain several beds of catalyst.

• The main reason for having separate beds is to provide locations for the injection of the recycled cold hydrogen into the reactors for temperature control.

• Also this will allow for the redistribution of the feed and hydrogen between the beds.

• So allows for more uniform utilization of the catalyst.

The process

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• Most of the hydrocracking catalysts consist of a crystalline mixture of silica-alumina.

• With a small uniformly distributed amounts od rare earth metals contained within the crystalline lattice.

• The silica-alumina part provides the cracking activity.

• While the rare earth metals promote hydrogenation.

The hydrocracking catalyst

273

• The catalyst activity decreases with use, and reactor temperatures are raised during a run to increase reaction rate and maintain conversion.

• The catalyst selectivity also changes with age, and more gas is made and less naphtha is produced as the temperature is raised to maintain the conversion.

• It will take 2 to 4 years with typical feedstocks for the catalyst activity to decrease from the accumulation of coke and other deposits for the level to require regeneration.


274

• Regeneration is done by burning off the catalyst deposits.

• After regeneration catalyst activity is restored to close to it’s original level.

• The catalyst can undergo several regenerations before it is necessary to replace it.


275

• Almost all hydrocracking catalysts use silica- alumina as the cracking base.

• The use of the rare earth metals vary according to the manufacturer.

• These include platinum, palladium, tungsten, and nickel.


276

Hydroprocessing and Resid processing

277

• The term resid means the bottom of the barrel.

• It is usually the atmospheric tower bottoms with an initial boiling point (IBP) of 343oC or vacuum tower bottoms with an IBP of 566oC.

• In both cases the stream will have higher concentrations of sulfur, nitrogen, and metals.


278

• And the hydrogen/carbon ratios are much lower.

• This H/C ratio will give high carbon forming potentials of resids. This will cause rapid catalyst deactivation and high catalyst costs.

• Also the nickel and vanadium in the resid act as resid for the formation of gas and coke.

• The case is more severe in the VRC case.


279

• In recent years the density and sulfur content of crude oils charged to the refineries changed.

• Consequently a higher fraction of crude is in the vacuum residue.

• Previously it was sold as asphalt or as heavy fuel oil.


280

• Recent environmental emission standards made it more difficult and expensive to burn these fuels.

• So the need aroused for converting more oil in the refinery feedstock to transportation fuel blending stocks.


281


282

• As a result, catalytic processes for converting resid usually use atmospheric reduced crude (ARC) for their feedstocks.

• And the vacuum reduced crude (VRC) are processed in non catalytic units.

• The processes used for the ARC feedstocks are catalytic cracking and hydro processing.

• Thermal cracking processes are used for VRC feedstocks.


283

• The types of processes can be classified as catalytic or non catalytic.

• Catalytic processes are used for ARC feedstocks.

• Non catalytic processes use VRC feed socks and include; solvent extraction, delayed coking, and flexicoking.

Processing options

284

• The types of processes can be classified as catalytic or non catalytic.

• Catalytic processes are used for ARC feedstocks.

• Non catalytic processes use VRC feed socks and include; solvent extraction, delayed coking, and flexicoking.

Processing options

285

Hydroprocessing

286

• The term hydroprocessing is used to represent the processes used to reduce the boiling point range of the feedstock and to remove impurities.

• These impurities include metals, sulfur, nitrogen, and high carbon forming compounds.

• Other names of this process are hydroconversion, hydrorefining, and resid HDS.

Hydroprocessing

287

• In US refineries, hydroprocessing units are used to prepare residual stream feedstocks for cracking and coking units.

• Vacuum resids can be used but most refineries use atmospheric resids as feedstocks.

• This us due to that it has lower viscosities and impurity levels. So give higher overall impurity reduction and better operation.

Hydroprocessing

288

• The heavy naphtha fraction of the products will be catalytically reformed to improve octanes.

• The atmospheric gas oil fraction is hydrotreated to decrease the aromatic content and improve the cetane number.

• Vacuum gas oil fraction is used as conventional FCC unit feed.

• And the vacuum tower bottoms is sent to a heavy oil cracker or coker.

Hydroprocessing

289

Fixed bed reactors

290

• Most processes have fixed bed reactors and usually require the units to shut down and the catalyst changed.

• This is when the catalyst activity declines below the accepted level.

• All units operate at very high pressures (above 13.8 Mpa).

• And low space velocities of 0.2-0.5 v/hr/v.

Fixed bed reactors

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Fixed bed reactors

292

• The low space velocities and high pressure limit the charge rates to 4760-6360 M3/SD per train of reactors.

• Each train of reactors will have a guard reactor to reduce the metals content and carbon forming potential of the feed stock.

• This is followed by three to four hydroprocessing reactors in series.

Fixed bed reactors

293

• The guard reactor’s catalyst has large pore sized (150-200 A˚) silica-alumina catalyst with a low level loading of hydrogenation metals such as cobalt and molybdenum.

• The catalysts in the other reactors are tailor-made for the feedstock and the conversion levels desired.

• These may contain a range of pore size and particle size as well as different catalytic metal loadings and types.

Fixed bed reactors

294

• Typical pore sizes will be in the range 80-100 A˚.

• The process flow is similar to that of the hydrocracking unit.

• With the exception of the amine absorption unit to remove hydrogen sulfide from the recycle hydrogen stream and the Guard reactor.

• This is added to protect the catalyst in the reactors train.

Fixed bed reactors

295

• The heavy crude oil fed to the atmospheric distillation unit is desalted to remove as much of the inorganic salt and suspended solids.

• This is due to that these will be concentrated in the resids.

• The atmospheric resids are filtered before being fed to the hydroprocessing unit to remove solids greater than 25 A˚ in size.

The process

296

• After filtration the resid is mixed with the recycle hydrogen.

• Then heated to the reaction temperature, then charged to the top of the guard reactor.

• Suspended solids in the feed will deposit in the top of the guard reactor.

• And most of the metals will deposit on the catalyst.

The process

297

• There is a significant reduction in the Conradson and Ramsbottom carbons in the guard reactor.

• And the feed to the following reactors is low in metals and carbon forming materials.

• The reactors following the guard reactor are operated to remove sulfur and nitrogen and to crack the 566+oC material to lower boiling point compounds.

The process

298

The process

299

• The recycle hydrogen is separated and the hydrocarbon liquid stream is fractionated in atmospheric and vacuum distillation columns.

• The table shows the results of hydroprocessing in this reactor.

The process

300

Expanded Bed Hydrocracking

301

• The term expanded bed or elbullated bed is given by HRI and C-E Lummus to a fluidized bed type operation which utilizes a mixture of liquids and gasses to expand the catalyst bed rather than just gases.

• Both use similar technologies but offer different mechanical designs.


302

Expanded Bed Hydrocracking Hi-oil

303

Expanded Bed Hydrocracking LC-fining

304

Expanded Bed Hydrocracking LC-fining

305

• The preheated feed, recycle and make up hydrogen are charged to the first reactor of the unit.

• The liquid passes upward through the catalyst which is maintained as an ebullient bed.

• The first- stage reactor effluent is sent to the second stage reactor for additional conversion.


306

• The product from the second reactor is passed through a heat exchanger.

• Then sent to a high pressure separator where the recycle (hydrogen) gas is removed.

• The liquid from the high pressure separator is sent to a low pressure flash drum to remove additional gasses.


307

• The liquid stream at low pressure is sent to a rectification column for separation into products.

• The operating pressure is a function of feed boiling point. The pressure can be as high as 3000 psig when charging with vacuum tower resid.

• The operating temperature is a function of feed and conversion and is in the range of 800-850oF.


308


309

The advantages of the ebullated bed reactor process are:

• The ability to add and remove catalyst while remaining on stream.

• And to maintain catalyst activity by either regeneration or the addition of fresh catalyst.

• Also the small solid particles are flushed out of the reactor and do not contribute to plugging or increasing in pressure drop.


310

The advantages of the ebullated bed reactor process are:

• Because the unit runs all the time with an equilibrium activity catalyst with a constant quality feedstock, and constant operating conditions.

• The product yields and quality will also be constant.


311

• It is necessary to recycle effluent from each reactor’s catalyst bed into the feed of that reactor.

• This is in order to have velocities that are high enough to keep the bed expanded, minimize channeling, to control the reaction rates and to keep heat released by the exothermic hydrogenation at a safe level.


312

• This back mixing dilutes the reactants so slows down thee rates of reactions compared to the fixed bed reactors.

• Ebullated bed reactors require up to 3 times the amount of catalyst per barrel of feed to obtain the same conversion as the fixed bed reactors.


313

Products from LC- fining cracking

314

Moving Bed Hydroprocessors

315

• This technology combines advantages of fixed bed and ebullated bed hydroprocessing.

• These systems use reactors designed for catalyst flow by gravity from the top to bottom with mechanisms designed to allow spent catalyst to be removed continuously or periodically.

• This removal is from the bottom and fresh catalyst is added to the top.


316

• This allows low activity high metal catalyst to be removed from the reactor and replaced with fresh catalyst while on-line.

• This design gives lower catalyst consumption rates than ebullated bed systems.

• This is due to that the ebullated bed system, equilibrium activity and metals loaded catalyst is removed rather than the lowest activity spent catalyst.


317

• As there is no recycling of product from the reactor outlets to the reactor inlet, the reactors operate in a plug flow condition.

• And reaction rates are the same as in a fixed bed operation.


318


319

Solvent Extraction

320

• Solvent extraction is used to extract up to two thirds of the vacuum reduced crude to be used as good quality feed for a fluid catalytic cracking unit to convert it to gasoline and diesel fuel blending stock.

• This technology uses light hydrocarbons (propanes to pentanes) as the solvents and use subcritical extractions but use supercritical techniques to recover the solvents.

Solvent extraction

321

• Light hydrocarbons have reverse solubility curves.

• As temperature increases the solubility of higher molecular weight hydrocarbons decreases.

• Also, paraffinic hydrocarbons have higher solubilities than aromatic hydrocarbons.

Solvent extraction

322

• A temperature can be selected at which all of the paraffins go into solution along with the desired percentage of the resid fraction.

• The higher the molecular weight resins will precipitate along with asphaltenes.

• The extract is then separated from the precipitated raffinate fraction and stripped from the solvent by increasing the temperature to above the critical temperature of the solvent.

Solvent extraction

323

• At the critical temperature the oil plus resin portion will separate from the solvent.

• And the solvent can be recovered without having to supply latent heat of vaporization.

• This will reduce the energy requirements by 20-30% compared to recovery by evaporation.

Solvent extraction

324

• The solvent used is feedstock dependent.

• As the molecular weight of the solvent increases (propane to pentane), the amount of solvent needed for a given amount of material extracted decreases.

• But the selectivity of the solvent also decreases.

Solvent extraction

325

• Therefore, the choice of solvent is an economic choice.

• Because for a given recovery of FCC unit feedstock from a resid, propane will give better quality extract but will use more solvent.

• Solvent recovery cost will be greater than if the higher molecular weight solvent is used because more solvent must be recovered.

Solvent extraction

326

• The higher the molecular weight solvents give lower solvent recovery cost.

• However, for a given feedstock and yield, give a lower quality extract and has higher capital costs due to that the critical pressure of the solvent increases with molecular weight.

• So higher equipment design pressure must be used.

Solvent extraction

327

• Since 80-90% of the metals in the crude are in the asphaltenes.

• And most of the remaining metals are in the resin fraction. A good quality FCC unit feed stock is obtained.

• The figure shows the solvent extraction unit flow.

Solvent extraction

328

Solvent extraction

329

Summary of resid treatment

330

• Thermal processes (delayed coking and Flexicoking) have the advantage that the vacuum reduced crude is eliminated so there is no residual fuel for disposal.

• And most of the VRC is converted to lower-boiling hydrocarbon fractions suitable for feedstocks to other processing units to convert them into transportation fuels.

• However, for high-sulfur crude oils, delayed coking produces a fuel grade coke of high sulfur content.


331

• This coke may be very difficult to sell. The alternative is to hydroprocess the feed to the coker to reduce the coker feed sulfur level and make a low-sulfur coke.

• Flexicoking is more costly than delayed coking, both from a capital and operating cost viewpoint.

• But has the advantage of converting the coke to a low heating value fuel gas to supply refinery energy needs and elemental sulfur for which there is a market.


332

• A disadvantage is that the fuel gas produced is more than the typical refinery can use and energy of compression does not permit it to be transported very far.

• It can be used for cogeneration purposes or sold to nearby users.

• Hydroprocessing reduces the sulfur and metal contents of the VRC and improves the hydrogen/carbon ratio of the products by adding hydrogen.


333

• But the products are very aromatic and may require a severe hydrotreating operation to obtain satisfactory middle distillate fuel blending stocks.

• Crude oils with high sulfur and metal levels will also have high catalyst replacement costs.

• Solvent extraction recovers 55–70% of the VRC for FCC or hydrocracker feedstocks to be converted into transportation fuel blending stocks, but the asphaltene fraction can be difficult process or sell.


334

Catalytic reforming and Isomerization

335

• The demand of today’s cars for high octane number gasolines has stimulated the use of catalytic reforming.

• Catalytic reforming products furnish about 30-40% of the US gasoline requirements.

• This is however expected to decrease due to the implementation of restrictions on the aromatics (produced in reforming) content of gasoline.


336

• The catalytic reforming does not change the boiling point of the feed significantly.

• This is because the small hydrocarbons rearranged to give higher octane number aromatics.

• With only a minor amount of cracking.


337

• This means that catalytic reforming increases the octane number of gasoline rather than increasing it’s yield.

• In fact the yield decreases slightly due to the hydrocracking reactions which are side reaction to the main reforming operation.

• The feedstocks to catalytic reforming are heavy straight-run (HSR) gasolines and naphthas (82-190oC) and heavy hydrocracker naphthas.


338

• These are composed mainly of paraffins, olefins, naphthenes, and aromatics (PONA analysis).

• The table shows typical PONA analysis for the feed and products of catalytic reforming.


339

• The paraffins and naphthenes undergo two types of reactions while being converted to higher octane number components.

• These reactions are crystallization and isomerization.

• The ease and probability of either of these occurring increases with the number of carbon atoms in the molecules.

• This is why only HSR gasoline is used for catalytic reformer feed.


340

• The light straight run gasoline (C5 82oC) is largely composed of lower molecular weight paraffins.

• These tend to break to butane and lighter fractions.

• This makes it not economic to process this stream in a catalytic reformer.

• Hydrocarbons with high boiling point (204oC) are easily hydrocracked and cause excessive carbon deposit on catalyst.


341

Reactions

342

• In any series of complex reactions, side reactions occur which produce undesirable products along with the main reaction producing the desired products.

• Reaction conditions must be chosen to favor the desired reactions over the undesired ones.

Reactions

343

Desirable reactions in a catalytic reformer all lead to the formation of aromatics and iso-paraffins:• Paraffins are isomerized and to some extent converted to

naphthenes. The naphthenes are subsequently converted to aromatics.

• Olefins are saturated to form paraffins which then react as previous.

• Naphthenes are converted to aromatics.

• Aromatics are left essentially unchanged.

Reactions

344

Reactions leading to the formation of undesirable products:

• Dealkylation of side chains on naphthenes and aromatics to form butane and lighter paraffins

• Cracking of paraffins and naphthenes to form butane and lighter paraffins

Reactions

345

• As the catalyst ages, it is necessary to change the process operating conditions.

• This is to maintain the reaction severity.

• And so suppress the undesired side reactions which give the undesired products.

Reactions

346

There are four major reactions that take place during reforming:• Dehydrogenation of naphthenes to aromatics.

• Dehydrocyclization of paraffins to aromatics.

• Isomerization.

• Hydrocracking. The first two of these reactions involve dehydrogenation and will be discussed together.

Reactions

347

Dehydrogenation Reactions

348

• The dehydrogenation reactions are highly endothermic and cause a decrease in temperature as the reaction goes on.

• Also they have the highest rates of the reforming reactions which necessitates the use of interheaters between catalyst beds.

• This is to keep the mixture at sufficiently high temperature for the reactions to proceed as the desired rates.


349

The major dehydrogenation reactions are:1- Dehydrogenation of alkylcyclohexanes to aromatics.


350

The major dehydrogenation reactions are:2- Dehydroisomerization of alkylcyclopentanes to aromatics.


351

The major dehydrogenation reactions are:3- Dehydrocyclization of paraffins to aromatics.


352

• The dehydrogenation of cyclohexane derivatives is much faster than the dehydroisomerization and the dehydrocyclization.

• However all three reactions take place simultaneously.

• And are necessary to obtain the aromatic concentration needed the reformate product.


353

• Aromatics have higher liquid density than paraffins or naphthenes with the same number of carbon atoms.

• So 1 volume of paraffins produces 0.77 volumes of aromatics.

• And 1 volume of naphthenes produces 0.87 volume of aromatics.

• Also conversion to aromatics increases the gasoline end point because the boiling point of aromatics is higher than that of paraffins and naphthenes with the same number of C atoms.


354

The yield of aromatics is increased by:• High temperature (increases reaction rate but adversely

affects chemical equilibrium).

• Low pressure (shifts chemical equilibrium ‘‘to the right’’).

• Low space velocity (promotes approach to equilibrium).

• Low hydrogen-to-hydrocarbon mole ratios (shifts chemical equilibrium ‘‘to the right’’)


355

Isomerization reactions

356

• Isomerization of paraffins and cyclopentanes usually results in lower octane products than conversion to aromatics.

• However there is a significant increase over the un-isomerized materials.

• These are fairly rapid reactions with small heat effects.


357

Isomerization reactions include:1- Isomerization of normal paraffins to isoparaffins.


358

Isomerization reactions include:2- Isomerization of alkylcyclopentanes to cyclohexanes and subsequent conversion to benzene.


359

Isomerization yield is increased by:

• High temperature (which increases reaction rate).

• Low space velocity.

• Low pressure.

• There is no isomerization effect due to the hydrogen to carbon mole ratio. But high hydrogen to carbon ratios reduce the carbon partial pressure thus favor the formation of isomers.


360

Hydrocracking Reactions

361

• The hydrocracking reactions are exothermic and result in the production of lighter liquid and gas products.

• They are relatively slow reactions and therefore most of the hydrocracking occurs in the last section of the reactor.

• The concentration of paraffins in the charge stock determines the extent of the hydrocracking reaction.

• But the relative fractions of isomers produced in any molecular weight group is independent of the charge stock.


362


• The major hydrocracking reactions involve cracking and saturation of paraffins.

363

Hydrocracking yields are increased by:

• High temperature.

• High pressure.

• Low space velocity.

• In order to obtain high product quality and yields, it is necessary to control the hydrocracking and aromatization reactions. This is done by monitoring the reactor temperatures. To observe the extent of each reaction.


364

• The active material in most catalytic reforming catalysts is platinum.

• Some metals along with hydrogen sulfide, ammonia, and organic nitrogen and sulfur compounds will deactivate the catalyst.

• Feed preparation in the form of hydrotreating is usually employed to remove these materials.

Feed preparation

365

• The hydrotreater employs a cobalt-molybdenum catalyst to convert organic sulfur and nitrogen compounds to hydrogen sulfide and ammonia.

• These are then removed from the system with the unreacted hydrogen.

• The metals in the feed are retained by the hydrotreater catalyst.

Feed preparation

366

• Hydrogen needed for the hydrotreater is obtained from the catalytic reformer.

• If the boiling point range of the charge stock must be changed the feed is redistilled before being charged to the catalytic reformer.

Feed preparation

367

Catalytic reforming process

368

• Reforming processes are classified as continuous, cyclic, or semiregenerative depending upon the frequency of catalyst regeneration.

• The equipment for the continuous process is designed to permit the removal and replacement of catalyst during operation.

• As a result, the catalyst can be regenerated continuously and maintained at a high activity.


369

• As increased coke laydown and thermodynamic equilibrium yields of reformate are both favored by low pressure.

• The ability to maintain high catalyst activities and selectivities by continuous catalyst regeneration is the major advantage of the continuous type.

• This advantage has to be evaluated with respect to the higher capital costs and possible lower operating costs due to lower hydrogen recycle rates and pressure needed to keep coke laydown as low as possible.


370

• The semi regenerative unit is at the other end of the spectrum and has the advantage of minimum capital cost.

• Regeneration requires the unit to be taken off-stream.

• Depending upon the severity of operation, regeneration is required at intervals of 3 to 24 months.

• High hydrogen recycle rates along with the operating pressures are utilized to minimize coke laydown.


371

• The cyclic process is a compromise between these extremes and is characterized by having a swing reactor in addition to those on-stream.

• Which catalyst can be regenerated without shutting the unit down.

• When the activity of the catalyst in one of the on-stream reactors drops below the desired level, this reactor is isolated from the system and replaced by the swing reactor.


372

• The catalyst in the replaced reactor is then regenerated by feeding hot air to it to burn the carbon off the catalyst.

• After regeneration it is used to replace the next reactor needing regeneration.

• The reforming process can be done as continuous or semiregenerative operation.

• And other processes as either continuous, cyclic or semiregenerative.


373

• The reforming semiregenerative process is typically a fixed bed reactor.

• The pretreated feed and recycle hydrogen are heated to 500-520oC then fed to the first reactor.

• In the first reactor the major reaction is the dehydrogenation of naphthenes to aromatics.

• This reaction is strongly endothermic, so a large drop in temperature occurs.

The process

374

Continuous reforming

375

Semi regenerative reforming

376

• To maintain the reaction rate, the gases are reheated before being passed over the catalyst in the second reactor.

• As the charge proceeds through the reactors, the reaction rate decreases and the reactors become larger, and the reheat needed becomes less.

• Three or four reactors are sufficient to provide the desired degree of reaction and heaters are needed before each reactor to bring the mixture to the reaction temperature.

The process

377

Semi regenerative reforming

378

• Several heaters can be used or one heater with several separate coils.

• The table shows the gas composition leaving each reactor.

The process

379

• The reaction mixture from the last reactor is cooled and the liquid products are condensed.

• The hydrogen rich gas stream is split into a hydrogen recycle stream and a net hydrogen by-product.

• This is used in hydrotreating or hydrocracking or as fuel.

The process

380

• The reformer operating pressure and hydrogen/feed ratio are compromised among obtaining maximum yields, long operating times between regeneration, and stable operation.

• The operating pressure is 350-2400 kPa. And the hydrogen to charge ratio is 3-8 mol hydrogen/mol feed.

• The liquid hourly space velocity is in the range of 1-3.

Operating conditions

381

• The original reforming process is classified as a semi regenerative type.

• Because catalyst regeneration is infrequent and runs 6 to 24 months before needing regeneration.

• The cyclic process regeneration is done on a 24 or a 48 hour cycle.

The process

382

• And a spare reactor is provided so regeneration can be done while on stream.

• Because of the extra facilities the cyclic process is more expensive.

• But offer the advantaged of lower pressure operation and higher yields of reformate at the same severity.

The process

383

Reforming Catalyst

384

• The reforming catalysts used today contain platinum supported on an alumina base.

• In most cases rhenium is combined with platinum to form a more stable catalyst which permits operation at lower pressures.

• Platinum serves as a catalytic site for hydrogenation and dehydrogenation reactions.

Reforming Catalyst

385

• And chlorinated alumina provides acid sites for isomerization, cyclization, and hydrocracking reactions.

• Reforming catalyst activity is a function of surface area, pore volume, and active platinum and chloride content.

• Catalyst activity is reduced during operation by coke deposition and chloride loss.

Reforming Catalyst

386

• In a high pressure process, up to 200 barrels of feed can be processed per pound of catalyst before regeneration is needed.

• The catalyst can be regenerated by high temperature oxidation of the carbon followed by chlorination.

• This process is referred to as semiregenerative and can operate for 6-24 month periods between regenerations.

Reforming Catalyst

387

• The activity of the catalyst decreases during the on stream period and the reaction temperature is increased as the catalyst ages to maintain the desired severity.

• Normally the catalyst can be regenerated in situ at least 3 times before It has to be replaced and returned to the manufacturer for reclamation.

Reforming Catalyst

388

• Catalysts for fixed bed reactors are extruded into cylinders 0.8-1.6 mm diameter with lengths about 5mm.

• Catalyst for continuous units is spherical with diameters approximately 0.8 to 1.6 mm.

Reforming Catalyst

389

Reactor Design

390

• Fixed bed reactors used for semi regenerative and cyclic catalytic vary in size and mechanical details.

• But all have the same basic features.

• Very similar reactors are used for hydrotreating, isomerization, and hydrocracking.

Reactor Design

391

• The reactors have an internal refractory lining which is provided to insulate the shell from the high reaction temperatures.

• Thus reduces the metal thickness needed.

• Metal parts exposed to the high temperature hydrogen atmosphere are constructed from steel.

• Containing at least 5% chromium and 0.5% molybdenum.

Reactor Design

392

• This steel is used to resist hydrogen embrittelment.

• Proper distribution of the inlet vapor is necessary to make maximum use of the available catalyst.

• Some reactor designs provide radial vapor flow rather than the simpler straight-through type in the figure.

Reactor Design

393

Reactor Design

394

• The important feature of vapor distribution is to provide maximum contact time with minimum pressure drop.

• Temperature measurement of 3 elevations in the catalyst bed is considered essential.

• This is to determine the catalyst activity and as an aid during coke burn off operation.

Reactor Design

395

• The catalyst pellets are generally supported on a bed of ceramic spheres about 30-40 cm deep.

• The spheres vary in size from about 25mm on the bottom to about 9mm on the top.

Reactor Design

396

Isomerization

397

• The octane number of the LSR naphtha (C5 82oC) can be improved by the use of an isomerization process.

• This is to convert normal paraffins to their isomers.

• This results in significant octane increases as n-pentane has an octane number of 61.7 and isopentane has a rating of 92.3.

Isomerization

398

• In once through isomerization where thermodynamic equilibrium is reached the octane number of naphtha increased from 70 to 84.

• If the normal components are recycled the resulting octane number will be 87-93.

• All octane numbers specified are research octane numbers (ROC).

Isomerization

399

• Reaction temperatures of about 95-205oC are preferred to higher temperatures.

• Because the equilibrium conversion to isomers is enhanced at lower temperatures.

• At these low temperatures, very active catalyst is necessary to provide a reasonable reaction rate.

Isomerization

400

• The available catalysts used for isomerization contain platinum on various bases.

• Some types of catalysts require the continuous addition of very small amounts of organic chlorides to maintain high catalyst activities.

• This is converted to hydrogen chloride in the reactor and consequently the feed to these units must be free of water and other oxygen sources to avoid catalyst deactivation.

Isomerization

401

• The second type of catalyst used is the molecular sieve base, and is reported to tolerate feeds saturated with water at ambient temperature.

• The third type of catalyst is the type that contains platinum supported on a novel metal oxide base.

• This catalyst has 83oC higher activity than conventional zeolite isomerization catalyst and can be regenerated.

Isomerization

402

• Catalyst life is usually 3 years or more for all these catalysts.

• Hydrogen at 1 atmosphere is used to minimize carbon deposits on the catalyst.

• Hydrogen consumption in this process is negligible.

• The composition of the reactor products can closely approach chemical equilibrium.

Isomerization

403

• The actual product distribution is dependent upon the type and age of the catalyst, the space velocity, and the reactor temperature.

• The pentane fraction of the reactor product is about 75-80 wt% iso-pentane, and the hexane fraction is 86-90 wt% hexane isomers.

Isomerization

404

• If the normal pentane in the reactor product is separated and recycled, the product RON can be increased from 83 to 86.

• If both normal pentane and normal hexane are recycled, the product RON can be improved to about 87-90.

• Separation of the normals from the isomers can be done by fractionation or by vapor phase adsorption of the normals on a molecular sieve bed.

Isomerization

405

• Some hydrocracking occurs during the reactions, resulting in a loss of gasoline and the production of light gas.

• The amount of gas formed varies with the catalyst type and age and is sometimes a significant economic factor.

• The light gas produced is typically in the range of 1-4 wt% of the HC feed.

Isomerization

406

Isomerization

407

• The composition of the gas can be assumed to be 95 wt% methane and 5 wt% ethane.

• For refineries that do not have hydrocracking facilities to supply isobutane for alkylation unit feed.

• The necessary isobutane can be made from n-butane by isomerization.

Isomerization

408

• The process is very similar to LSR gasoline isomerization but a feed deisobutanizer is used to concentrate the n-butane in the reactor charge.

• The reactor product is about 58-62 wt% isobutane.

Isomerization

409

Isomerization

410

Isomerization operating conditions

411

Alkylation and Polymerization

412

• The alkylation reaction is the addition of an alky group to any compound.

• But in petroleum refining terminology the term alkylation is used for the reaction of a low molecular weight olefin with an iso paraffin to form higher molecular weight iso paraffins.

• Although this reaction is simply the reverse of cracking, the belief that paraffin hydrocarbons are chemically inert delayed its discovery until about 1935.


413

• The need for high-octane aviation fuels during World War II acted as a stimulus to the development of the alkylation process for production of isoparaffinic gasolines of high octane number.

• Although alkylation can take place at high temperatures and pressures without catalysts, the only processes of commercial importance involve low-temperature alkylation conducted in the presence of either sulfuric or hydrofluoric acid.


414

• The reactions occurring in both processes are complex and the product has a rather wide boiling range.

• By proper choice of operating conditions, most of the product can be made to fall within the gasoline boiling range.

• With motor octane numbers from 88 to 94 and research octane numbers from 94 to 99.


415

Alkylation Reactions

416

• In alkylation processes using hydrofluoric or sulfuric acids as catalysts, only iso-paraffins with tertiary carbon atoms, such as iso butane or iso pentane, react with olefins.

• In practice only iso butane is used because iso pentane has a sufficiently high octane number and low vapor pressure to allow it to be effectively blended directly into finished gasolines.

• The process using sulfuric acid as a catalyst is much more sensitive to temperature than the hydrofluoric acid process.


417

• With sulfuric acid it is necessary to carryout the reactions at 5to 21°C or lower.

• To minimize oxidation reduction reactions which result in the formation of tars and the evolution of sulfur dioxide.

• When anhydrous hydrofluoric acid is the catalyst, the temperature is usually limited to 38°C or lower.


418

• In both processes the volume of acid employed is about equal to that of the liquid hydrocarbon charge.

• And sufficient pressure is maintained on the system to keep the hydrocarbons and the acid in the liquid state.

• High iso paraffin/olefin ratios (4:1 to 15:1) are used to minimize polymerization and to increase product octane.


419

• Efficient agitation is needed to promote contact between the acid and hydrocarbon phases to ensure high product quality and yields.

• Contact times from 10 to 40 minutes are in general use.

• The yield, volatility, and octane number of the product is regulated by adjusting the temperature, acid/hydrocarbon ratio, and iso paraffin/olefin ratio.


420

• At the same operating conditions, the products from the hydrofluoric and sulfuric acid alkylation process are quite similar.

• In practice, however, the plants are operated at different conditions and the products are somewhat different.


421

For both processes the more important variables are:

• Reaction temperature.• Acid strength.• Isobutane concentration.• Olefin space velocity.


422

• The main reactions which occur in alkylation are the combination of olefins with iso paraffins.


Isobutane Isobutylene 2, 2, 4-trimethylpentane (Isooctane)

423

• Another significant reaction in propylene alkylation is the combination of propylene with iso butane to form propane plus isobutylene. The isobutylene then reacts with more iso butane to form 2,2,4-trimethylpentane (isooctane).


424

• The first step involving the formation of propane is referred to as a hydrogen transfer reaction.

• Research on catalyst modifiers is being conducted to promote this step since it produces a higher octane alkylate than is obtained by formation of iso heptanes.

• The alkylation reaction is highly exothermic, with the liberation of 124,000 to 140,000Btu per barrel of iso butane reacting.


425

The most important process variables are:• Reaction temperature:

Greater effect in sulfuric acid processes. Lower temperature means higher quality.

• Acid strength:

Has varying effects on alkylate quality depending on the effectives of the reactor mixing and the water content in the acid. The water concentration in the acid lowers it’s catalytic activity about 3 to 5 times as much as the HC diluents.

Process Variables

426

• Iso butane concentration:

Is expressed in terms of iso butane/olefin ratio. High ratio increases the octane number and yield and reduce the side reactions and acid consumption.

• Olefin space velocity:

Is defined as the volume of olefin charged per hour divided by the volume of the acid in the reactor. Lowering it reduces the amount of high boiling HC and increases the octane. It is used to express the reaction time.

Process Variables

427

Alkylation Feedstocks

428

• Olefins and iso butane are used as alkylation unit feedstocks.

• The chief sources of olefins are catalytic cracking and coking operations.

• Butenes and propene are the most common olefins used, but pentenes are included in some cases.

• Some refineries include pentenes in alkylation unit feed to lower the FCC gasoline vapor pressure and reduce the bromine number in the final gasoline blend.


429

• Alkylation of pentenes is also considered as a way to reduce the C5 olefin content of final gasoline blends.

• And reduce its effects on ozone reduction and visual pollution in the atmosphere.

• Olefins can be produced by dehydrogenation of paraffins, and isobutane is cracked commercially to provide alkylation unit feed.


430

• Hydrocrackers and catalytic crackers produce a great deal of the iso butane used in alkylation.

• But it is also obtained from catalytic reformers, crude distillation, and natural gas processing.

• In some cases, normal butane is isomerized to produce additional isobutane for alkylation unit feed.


431

Alkylation Products

432

• The products leaving the alkylation unit include the alkylate stream.

• And propane and normal butane that enter with the saturated and unsaturated feed streams.

• As well as a small quantity of tar produced by polymerization reactions.

Alkylation Products

433

The product streams leaving an alkylation unit are:

• LPG grade propane liquid.

• 2.Normal butane liquid.

• C5+alkylate.

• Tar.

Alkylation Products

434

Catalysts

435

• Concentrated sulfuric and hydrofluoric acids are the only catalysts used commercially today for the production of high octane alkylate gasoline.

• However other catalysts are used to produce ethyl benzene, cumene, and long-chain C12to C16) alkylated benzenes.

Catalysts

436

• As previously discussed, the desirable reactions are the formation of C8 carbonium ions and the subsequent formation of alkylate.

• The main undesirable reaction is polymerization of olefins.

• Only strong acids can catalyze the alkylation reaction but weaker acids can cause polymerization to take place.

Catalysts

437

• Therefore, the acid strengths must be kept above 88% by weightH2SO4or HF in order to prevent excessive polymerization.

• Sulfuric acid containing free SO3also causes undesired side reactions and concentrations greater than 99.3% H2SO4 are not generally used.

Catalysts

438

• Iso butane is soluble in the acid phase only to the extent of about 0.1% by weight in sulfuric acid.

• And about 3% in hydrofluoric acid.

• Olefins are more soluble in the acid phase and a slight amount of polymerization of the olefins is desirable.

• This is due to that polymerization products dissolve in the acid and increase the solubility of iso butane in the acid phase.

Catalysts

439

• If the concentration of the acid becomes less than 88%, some of the acid must be removed and replaced with stronger acid.

• In hydrofluoric acid units the acid removed is redistilled and the polymerization products removed as a thick, dark ‘‘acid soluble oil’’ (ASO).

• The concentrated HF is recycled in the unit. The net consumption is about 0.3 lb per barrel of alkylate produced

Catalysts

440

• Unit inventory of hydrofluoric acid is about 25–40 lb acid per BPD of feed.

• The sulfuric acid removed usually is regenerated in a sulfuric acid plant which is generally not a part of the alkylation unit.

• The acid consumption typically ranges from 13 to 30 lb per barrel of alkylate produced.

• Makeup acid is usually 98.5 to 99.3 wt% H2SO4.

Catalysts

441

Yields and Isobutane Requirements

442

• Only about 0.1% by volume of olefin feed is converted into tar.

• This is not truly a tar but a thick dark brown oil containing complex mixtures of conjugated cyclopentadienes with side chains

Yields and Isobutane Requirements

443

Operating Conditions

444

Hydrofluoric Acid Processes

445

• Both the olefin and isobutane feeds are dehydrated by passing the feed-stocks through a solid bed desiccant unit.

• Good dehydration is essential to minimize potential corrosion of process equipment which results from addition of water to hydrofluoric acid.

• After dehydration the olefin and isobutane feeds are mixed with hydrofluoric acid at sufficient pressure to maintain all components in the liquid phase.


446


447

• The bottom product from the rerun column is a mixture of tar and an HF–water azeotrope.

• These components are separated in a tar settler (not shown on the flow diagram).

• The tar is used for fuel and the HF–water mixture is neutralized with lime or caustic.

• This rerun operation is necessary to maintain the activity of the hydrofluoric acid catalyst.


448

• The reaction mixture is allowed to settle into two liquid layers.

• The acid has a higher density than the hydrocarbon mixture and is withdrawn from the bottom of the settler.

• And passed through a cooler to remove the heat gained from the exothermic reaction.

• The acid is then recycled and mixed with more fresh feed, thus completing the acid circuit.


449

• A small slip-stream of acid is withdrawn from the settler and fed to an acid rerun column to remove dissolved water and polymerized hydrocarbons.

• The acid rerun column contains about five trays and operates at 1034 kPa.

• The overhead product from the rerun column is clear hydrofluoric acid which is condensed and returned to the system.


450

• The hydrocarbon layer removed from the top of the acid settler is a mixture of propane, isobutane, normal butane, and alkylate along with small amounts of hydrofluoric acid.

• These components are separated by fractionation and the iso butane is recycled to the feed.

• Propane and normal butane products are passed through caustic treaters to remove trace quantities and hydrofluoric acid.


451

• Although the flow sheet shows the fractionation of propane, isobutane, normal butane, and alkylate to require three separate fractionators.

• Many alkylation plants have a single tower where propane is taken off overhead.

• A partially purified isobutane recycle is withdrawn as a liquid several trays above the feed tray.


452

• A normal butane product is taken off as a vapor several trays below the feed tray and the alkylate is removed from the bottom.

• The design of the acid settler–cooler–reactor section is critical to the good conversion in a hydrofluoric acid alkylation system.

• Many of the reactor systems are similar to a horizontal shell and tube heat exchanger with cooling water flowing inside the tubes to control the reaction temperatures.


453


454

• Good mixing is achieved in the reactor by using a recirculating pump to force the mixture through the reactor.

• A second type of reactors design is that acid circulation in this system is by gravity differential.

• Thus a relatively expensive acid circulation pump is not necessary.


455


456

• In portions of the process system where it is possible to have HF–water mixtures, the process equipment is fabricated from Monel metal or Monel-cladsteel. The other parts of the system are carbon steel.

• Special precautions are taken to protect maintenance and operating personnel from injury by accidental contact with acid.


457

• In portions of the process system where it is possible to have HF–water mixtures, the process equipment is fabricated from Monel metal or Monel-cladsteel. The other parts of the system are carbon steel.

• Special precautions are taken to protect maintenance and operating personnel from injury by accidental contact with acid.


458

Hydrofluoric Acid Processes Yields

459

Alkylate Properties

460

Sulfuric Acid Alkylation Process

461

• There are two major processes that use sulfuric acid as catalyst.

• Autorefrigeration process, and the effluent refrigeration process.

• The autorefrigeration process uses a multistage cascade reactor with mixers in each stage to emulsify the hydrocarbon–acid mixture.


462

• Olefin feed or a mixture of olefin feed and isobutane feed is introduced into the mixing compartments.

• And enough mixing energy is introduced to obtain sufficient contacting of the acid catalyst with the hydrocarbon reactants to obtain good reaction selectivity.

• The reaction is held at a pressure of approximately 69 kPag in order to maintain the temperature at about 5°C.


463

• In the Stratco, or similar type of reactor system, pressure is kept high enough 310–420 kPag to prevent vaporization of the hydrocarbons.

• In the first process, acid and iso butane enter the first stage of the reactor and pass in series through the remaining stages.

• The olefin hydrocarbon feed is split and injected into each of the stages.


464

• Then the olefin feed is mixed with the recycle isobutane and introduces the mixture into the individual reactor sections.

• The gases vaporized to remove the heats of reaction and mixing energy are compressed and liquefied.

• A portion of this liquid is vaporized in an economizer to cool the olefin hydrocarbon feed before it is sent to the reactor.

• The vapors are returned for recompression.


465

• The remainder of the liquefied hydrocarbon is sent to a depropanizer column for removal of the excess propane which accumulates in the system.

• The liquid isobutane from the bottom of the depropanizer is pumped to the first stage of the reactor.

• The acid–hydrocarbon emulsion from the last reactor stage is separated into acid and hydrocarbon phases in a settler.


466

• The acid is removed from the system for reclamation, and the hydrocarbon phase is pumped through a caustic wash followed by a water wash to eliminate trace amounts of acid and then sent to a deisobutanizer.

• The deisobutanizer separates the hydrocarbon feed stream into isobutane, n-butane, and alkylate product.


467

Autorefrigeration sulfuric acid alkylation unit

468

• The effluent refrigeration process (Stratco) uses a single-stage reactor in which the temperature is maintained by cooling coils.

• The reactor contains an impeller that emulsifies the acid–hydrocarbon mixture and recirculates it in the reactor.

• Average residence time in the reactor is on the order of 20 to 25 minutes.


469

Stratco contactor

470

• Emulsion removed from the reactor is sent to a settler for phase separation.

• The acid is recirculated and the pressure of the hydrocarbon phase is lowered to flash vaporize a portion of the stream and reduce the liquid temperature to about -1°C.

• The cold liquid is used as coolant in the reactor tube bundle.


471

• The flashed gases are compressed and liquefied, then sent to the depropanizer where LPG grade propane and recycle isobutane are separated.

• The hydrocarbon liquid from the reactor tube bundle is separated into isobutane, n-butane, and alkylate streams in the deisobutanizer column.

• The isobutane is recycled and n-butane and alkylate are product streams.


472

• A separate distillation column can be used to separate the n-butane from the mixture or it can be removed as a side stream from the deisobutanizing column.

• Separating n-butane as a side stream from the deisobutanizing can be restricted because the pentane content is usually too high to meet butane sales specifications.

• The side-stream n-butane can be used for gasoline blending.


473

Sulfuric Acid Alkylation Process yields and qualities

474

Polymerization

475

• Propene and butenes can be polymerized to form a high-octane product boiling in the gasoline boiling range.

• The product is an olefin having unleaded octane numbers of 97 RON and 83 MON.

• The polymerization process was widely used in the 1930s and 1940s to convert low-boiling olefins into gasoline blending stocks.

Polymerization

476

• But was supplanted by the alkylation process after World War II.

• The mandated reduction in use of lead in gasoline and the increasing proportion of the market demand for unleaded gasolines created a need for low-cost processes to produce high-octane gasoline blending components.

• Polymerization produces about 0.7 barrels of polymer gasoline per barrel of olefin feed as compared with about 1.5 barrels of alkylate by alkylation.

Polymerization

477

• And the product has a high octane sensitivity, but capital and operating costs are much lower than for alkylation.

• As a result, polymerization processes are being added to some refineries.

Polymerization

478

• while iC4H8 reacts to give primarily diisobutylene, propene gives mostly trimers and dimers with only about 10% conversion to dimer.

Polymerization Reactions

479

• The most widely used catalyst is phosphoric acid on an inert support.

• This can be in the form of phosphoric acid mixed with kieselguhr (a natural clay).

• Or a film of liquid phosphoric acid on crushed quartz.

• Sulfur in the feed poisons the catalyst and any basic materials neutralize the acid and increase catalyst consumption.


480

• Oxygen dissolved in the feed adversely affects the reactions and must be removed.

• Normal catalyst consumption rates are in the range of one pound of catalyst per 100 to 200 gallons of polymer produced (830 to 1660 l/kg).


481

• The feed, consisting of propane and butane as well as propene and butene, is contacted with an amine solution to remove hydrogen sulfide.

• Then caustic washed to remove mercaptans.

• It is then scrubbed with water to remove any caustic or amines and then dried by passing through a silica gel or molecular sieve bed.

The process

482

• Finally, a small amount of water (350–400 ppm) is added to promote ionization of the acid.

• Then the olefin feed steam is heated to about 204°C and passed over the catalyst bed.

• Reactor pressures are about 3450 kPa.

• The polymerization reaction is highly exothermic and temperature is controlled either by injecting a cold propane quench or by generating steam.

The process

483

• The propane and butane in the feed act as diluents and a heat sink to help control the rate of reaction and the rate of heat release.

• Propane is also recycled to help control the temperature.

• After leaving the reactor the product is fractionated to separate the butane and lighter material from the polymer gasoline.

The process

484

• Gasoline boiling range polymer production is normally 90–97 wt% on olefin feed or about 0.7 barrel of polymer per barrel of olefin feed.

• The next slide has the process flow diagram for the (Universal oil products company (UOP) unit. And the following has the operating conditions.

The process

485

The UOP Unit

486

Operating Conditions

487

• Insitut Francais du Petrole licenses a process to produce dimate (isohexene) from propene.

• Tis uses a homogeneous aluminum alkyl catalyst which is not recovered.

• The process requires a feed stream that is better than 99% propane.

• And propene because C2s and C4s poison the catalyst.

The process

488

• Dienes and triple bonded hydro-carbons can create problems.

• And in some cases it is necessary to selectively hydrogenate the feed to eliminate these compounds.

• The major advantage of this process is the low capital cost because it operates at low pressures.

The process

489

The Insitut Francais du Petrole Unit

490

Product Blending

491

• Increased operating flexibility and profits result when refinery operations produce basic intermediate streams that can be blended to produce a variety of on-specification finished products.

• For example, naphthas can be blended into either gasoline or jet fuel, depending upon the product demand.

• Aside from lubricating oils, the major refinery products produced by blending are gasolines, jet fuels, heating oils, and diesel fuels.

Product Blending

492

• The objective of product blending is to allocate the available blending components in such a way as to meet product demands and specifications.

• At the least cost and to produce incremental products which maximize overall profit.

• The volumes of products sold, even by a medium-sized refiner, are so large that savings of a fraction of a cent per gallon will produce a substantial increase in profit over the period of one year.

Product Blending

493

• For example, if a refiner sells about one billion gallons of gasoline per year (about 65,000 BPCD; several refiners sell more than that in the United States).

• A saving of one one-hundredth of a cent per gallon results in an additional profit of $100,000 per year.

• Today most refineries use computer-controlled in-line blending for blending gasolines and other high-volume products.

Product Blending

494

• Inventories of blending stocks, together with cost and physical property data are maintained in the computer.

• When a certain volume of a given quality product is specified, the computer uses linear programming models to optimize the blending operations.

• This is to select the blending components to produce the required volume of the specified product at the lowest cost.

Product Blending

495

• To ensure that the blended streams meet the desired specifications, stream analyzers measuring the properties of the product are needed.

• These include boiling point, specific gravity, RVP, and research and motor octane.

• These analyzers provide feedback control of additives and blending streams.

Product Blending

496

• Blending components to meet all critical specifications most economically is a trial-and-error procedure.

• Which is easy to handle with the use of a computer.

• The large number of variables makes it probable there will be a number of equivalent solutions that give the approximate equivalent total overall cost or profit.

Product Blending

497

• Optimization programs permit the computer to provide the optimum blend to minimize cost and maximize profit.

• The same basic techniques are used for calculating the blending components for any of the blended refinery products.

• Gasoline is the largest volume refinery product and will be used as an example to help clarify the procedures.

Product Blending

498

Reid Vapor Pressure

499

• The desired RVP of a gasoline is obtained by blending n-butane with C5 193°C naphtha.

• The amount of n-butane required to give the needed RVP is calculated by:

Reid Vapor Pressure

500

• The theoretical method for blending to the desired Reid vapor pressure requires that the average molecular weight of each of the streams be known.

• There are accepted ways of estimating the average molecular weight of a refinery stream from boiling point, gravity, and characterization factor.

• However a more convenient way is to use the empirical method developed by Chevron Research Company.

Reid Vapor Pressure

501

• Vapor pressure blending indices (VPBI) have been compiled as a function of the RVP of the blending.

• The Reid vapor pressure of the blend is closely approximated by the sum of all the products of the volume fraction (v) times the VPBI for each component.

Reid Vapor Pressure

502

• In equation form:

• In the case where the volume of the butane to be blended for a given RVP is desired:

• A(VPBI)a + B(BPBI)b + + W(VPBI)⋅ ⋅ ⋅ w = (Y + W)(VPBI)m

Reid Vapor Pressure

503

Blending component values for gasoline blending

504

• Octane numbers are blended on a volumetric basis using the blending octane numbers of the components.

• True octane numbers do not blend linearly and it is necessary to use blending octane numbers in making calculations.

Octane Blending

505

• Blending octane numbers are based upon experience and are those numbers which, when added on a volumetric average basis, will give the true octane of the blend.

• True octane is defined as the octane number obtained using a CFR test engine.

Octane Blending

506

• The formula used for calculations is:

Octane Blending

507

Blending For Other Properties

• There are several methods of estimating the physical properties of a blend from the properties of the blending stocks.

• One of the most convenient methods of estimating properties that do not blend linearly is to substitute for the value of the inspection to be blended another value which has the property of blending approximately linear.

• Such values are called blending factors or blending index numbers.

508


• The Chevron Research Company has compiled factors or index numbers for vapor pressures, viscosities, flash points, and aniline points.

• The table in the next slide is for the blending values of octane improvers.

• Since it is more complicated than the others, viscosity blending is more fully discussed in the next few slides.

509

Blending values of Octane improvers

510


• Viscosity is not an additive property.

• And it is necessary to use special techniques to estimate the viscosity of a mixture from the viscosities of its components.

• The method most commonly accepted is the use of special charts developed by and obtainable from ASTM.

• Blending of viscosities may be calculated conveniently by using viscosity factors.

511


• It is usually true to a satisfactory approximation that the viscosity factor (VF) of the blend can be easily calculated by a simple equation.

• Which is the sum of all the products of the volume fraction times the viscosity factor for each component.

In equation form:

512

Cost Estimation

513

Cost EstimationAll capital cost estimates of industrial process plants can be classified as one of four types:1. Rule-of-thumb estimates.

2. Cost-curve estimates.

3. Major equipment factor estimates.

4. Definitive estimates.

The capital cost data presented in this work are of the second type—cost-curve estimates.

514

1- Rule Of- Thumb Estimates

• The rule-of-thumb estimates are, in most cases, only an approximation of the order of magnitude of cost.

• These estimates are simply a fixed cost per unit of feed or product.

• These rule-of-thumb factors are useful for quick ballpark costs.

• Many assumptions are implicit in these values and the average deviation from actual practice can often be more than 50%.

515

1- Rule Of- Thumb Estimates

Some examples are:

• Complete coal-fired electric power plant: $2,500/kW.

• Complete synthetic ammonia plant: $200,000/TPD.

• Complete petroleum refinery: $25,000/BPD.

516

2- Cost- Curve Estimates

• The cost-curve method of estimating corrects for the major deficiency in the previous method.

• By reflecting the significant effect of size or capacity on cost.

• These curves indicate that costs of similar process units or plants are related to capacity by an equation of the following form:

517

2- Cost- Curve Estimates

• This relationship was reported by Lang, who suggested an average value of 0.6 for the exponent (X).

• It is important to note that most of the cost plots have an exponent which differs somewhat from the 0.6 value.

• Some of the plots actually show a curvature in the log–log slope which indicates that the cost exponent for these process units varies with capacity.

518

Major Equipment Factor Estimates

• Major equipment factor estimates are made by applying multipliers to the costs of all major equipment required for the plant or process facility.

• Different factors are applicable to different types of equipment, such as pumps, heat exchangers, pressure vessels, etc.

• Equipment size also has an effect on the factors.

• It is obvious that prices of major equipment must first be developed to use this method.

519

3- Major Equipment Factor Estimates

• This requires that heat and material balances be completed in order to develop the size and basic specifications for the major equipment.

• This method of estimating, if carefully followed, can predict actual costs within 10 to 20%.

• A shortcut modification of this method uses a single factor for all equipment. A commonly used factor for petroleum refining facilities is 4.5.

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4- Definitive estimates

• Definitive cost estimates are the most time-consuming and difficult to prepare but are also the most accurate.

• These estimates require preparation of plot plans, detailed flow sheets and preliminary construction drawings.

• Scale models are sometimes used. All material and equipment are listed and priced.

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4- Definitive estimates

• The number of man-hours for each construction activity is estimated.

• Indirect field costs, such as crane rentals, costs of tools, supervision, etc., are also estimated.

• This type of estimate usually results in an accuracy of +/-5%.

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Summary Form For Cost Estimates

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Summary Form For Cost Estimates

The items to be considered when estimating investment from cost-curves are:

• Process units • Storage facilities• Steam systems• Cooling water systems• Subtotal A• Offsites

• Subtotal B• Special costs• Subtotal C• Location factor• Subtotal D• Contingency• Total

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1- Storage Facilities

• Storage facilities represent a significant item of investment costs in most refineries.

• Storage capacity for crude oil and products varies widely at different refineries.

• The following must be considered: the number and type of products, method of marketing, source of crude oil, and location and size of refinery.

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• Installed costs for ‘‘tank-farms’’ vary from $60 to $80 per barrel of storage capacity.

• This includes tanks, piping, transfer pumps, dikes, fire protection equipment, and tank-car or truck loading facilities.

• The value is applicable to low vapor pressure products such as gasoline and heavier liquids.

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• Installed costs for butane storage ranges from $90 to $120 per barrel, depending on size.

• Costs for propane storage range from $100 to $130 per barrel.

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2- Land And Storage Requirements

• Each refinery has its own land and storage requirements.

• Depending on location with respect to markets and crude supply, methods of transportation of the crude and products, and number and size of processing units.

• Availability of storage tanks for short-term leasing is also a factor as the maximum amount of storage required is usually based on shutdown of processing units for turnaround at 18-to 24-month intervals rather than on day-to-day processing requirements.

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• As the land area required for storage tanks is a major portion of refinery land requirements.

• Three types of tankage are required: crude, intermediate, and product.

• For a typical refinery which receives the majority of its crude by pipeline and distributes its products in the same manner, about 13 days of crude storage and 25 days of product storage should be provided.

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• The 25 days of product storage is based on a three-week shutdown of a major process unit.

• This generally occurs only every 18 months or two years, but sufficient storage is necessary to provide products to customers over this extended period.

• A rule-of-thumb figure for total tankage, including intermediate storage, is approximately 50 barrels of storage per BPD crude oil processed.

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3- Steam Systems

• An investment cost of $150.00 per lb/hr of total steam generation capacity issued for preliminary estimates.

• This represents the total installed costs for gas-or oil-fired, forced draft boilers, operating at 250 to 300 psig.

• And all appurtenant items such as water treating, deaerating, feed pumps, yard piping for steam, and condensate.

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3- Steam Systems

• Total fuel requirements for steam generation can be assumed to be 1200Btu (LHV) per pound of steam.

• A contingency of 25% should be applied to preliminary estimates of steam requirements.

• Water makeup to the boilers is usually 5 to 10% of the steam produced.

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4- Cooling Water Systems

• An investment cost of $150.00 per gpm of total water circulation is recommended for preliminary estimates.

• This represents the total installed costs for a conventional induced-draft cooling tower, water pumps, water treating equipment, and water piping.

• Special costs for water supply and blow down disposal are not included.

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• The daily power requirements (kWh/day) for cooling water pumps and fans is estimated by multiplying the circulation rate in gpm by 0.6.

• This power requirement is usually a significant item in total plant power load and should not be ignored.

• The cooling tower makeup water is about 5% of the circulation.

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• This is also a significant item and should not be overlooked.

• An ‘‘omission factor,’’ or contingency of 15%, should be applied to the cooling water circulation requirements.

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5- Other Utility Systems

• Other utility systems required in a refinery are electric power distribution, instrument air, drinking water, fire water, sewers, waste collection, and others.

• Since these are difficult to estimate without detailed drawings, the cost is normally included in the offsite facilities.

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Offsites

• Offsites are the facilities required in a refinery which are not included in the costs of major facilities.

A typical list of offsites is: • Electric power distribution.• Fuel oil and fuel gas facilities.• Water supply, and treatment.• Air systems.• Fire protection systems.• Flare, drain and waste systems.• Plant communication systems.

• Roads and walks Railroads.• Fence.• Buildings.• Vehicles.• Product and additives.

Blending facilities.• Product loading facilities.

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Offsites

• Obviously, the offsite requirements vary widely between different refineries.

• Offsite costs for the addition of individual process units in an existing refinery can be assumed to be about 20 to 25% of the process unit costs.

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Offsites

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6- Special Costs

• Special costs include the following: land, spare parts, inspection, project management, chemicals, miscellaneous supplies, and office and laboratory furniture.

• For preliminary estimates these costs can be estimated as 4% of the cost of the process units, storage, steam systems, cooling water systems, and offsites.

• Engineering costs and contractor fees are included in the various individual cost items.

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7- Contingencies

• Most professional cost estimators recommend that a contingency of at least 15% be applied to the final total cost determined by cost-curve estimates of the type presented.

• The term contingencies covers many loopholes in cost estimates of process plants.

• The major loopholes include cost data inaccuracies when applied to specific cases and lack of complete definition of facilities required.

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Escalation

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Escalation

• All cost data presented in this book are based on U.S. Gulf Coast construction averages for the year 1999.

• Therefore, in any attempt to use the data for current estimates some form of escalation or inflation factor must be applied.

• Escalation or inflation of refinery investment costs is influenced by items which tend to increase costs as well as by items which tend to decrease costs.

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EscalationItems which increase costs include major factors: 1. Increased cost of steel, concrete, and other basic materials.

2. Increased cost of construction labor and engineering.

3. Increased costs for higher safety standards and pollution control regulations.

4. Increase in the number of reports and amount of superfluous data necessary to obtain construction permits .

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EscalationItems which tend to decrease costs are basically all related to technological improvements

• 1. Process improvements developed by the engineers in research, design, and operation.

• 2. More efficient use of engineering and construction manpower.

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Plant Location

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Plant location• Plant location has a significant influence on plant costs.

• The main factors contributing to these variations are climate and its effect on design requirements and construction conditions; local rules, regulations, codes, taxes, etc; and availability and productivity of construction labor.

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Thank you

Documents

Introduction to Petroleum Refinery Processing