PETROLEUM REFINING PROCESS
Petroleum refining begins with the distillation, or fractionation, of crude oils into separate hydrocarbon groups. The resultant products are directly related to the characteristics of the crude oil being processed. Most of these products of distillation are further converted into more useable products by changing their physical and molecular structures through cracking, reforming and other conversion processes. These products are subsequently subjected to various treatment and separation processes, such as extraction, hydrotreating and sweetening, in order to produce finished products. Whereas the simplest refineries are usually limited to atmospheric and vacuum distillation, integrated refineries incorporate fractionation, conversion, treatment and blending with lubricant, heavy fuels and asphalt manufacturing; they may also include petrochemical processing.
The first refinery, which opened in 1861, produced kerosene by simple atmospheric distillation. Its by-products included tar and naphtha. It was soon discovered that high-quality lubricating oils could be produced by distilling petroleum under vacuum. However, for the next 30 years, kerosene was the product consumers wanted most. The two most significant events which changed this situation were:
· the invention of the electric light, which decreased the demand for kerosene
· the invention of the internal-combustion engine, which created a demand for diesel fuel and gasoline (naphtha).
With the advent of mass production and the First World War, the number of gasoline-powered vehicles increased dramatically, and the demand for gasoline grew accordingly. However, only a certain amount of gasoline could be obtained from crude oil through atmospheric and vacuum distillation processes. The first thermal cracking process was developed in 1913. Thermal cracking subjected heavy fuels to both pressure and intense heat, physically breaking their large molecules into smaller ones, producing additional gasoline and distillate fuels. A sophisticated form of thermal cracking, visbreaking, was developed in the late 1930s to produce more desirable and valuable products.
As higher-compression gasoline engines were developed, there was a demand for higher-octane gasoline with better anti-knock characteristics. The introduction of catalytic cracking and poly- merization processes in the mid- to late 1930s met this demand by providing improved gasoline yields and higher octane numbers. Alkylation, another catalytic process, was developed in the early 1940s to produce more high-octane aviation gasoline and petrochemical feedstocks, the starting materials, for explosives and synthetic rubber. Subsequently, catalytic isomerization was developed to convert hydrocarbons to produce increased quantities of alkylation feedstocks.
Following the Second World War, various reforming processes were introduced which improved gasoline quality and yield, and produced higher-quality products. Some of these involved the use of catalysts and/or hydrogen to change molecules and remove sulphur. Improved catalysts, and process methods such as hydrocracking and reforming, were developed throughout the 1960s to increase gasoline yields and improve anti-knock characteristics. These catalytic processes also produced molecules with a double bond (alkenes), forming the basis of the modern petrochemical industry.
The numbers and types of different processes used in modern refineries depend primarily on the nature of the crude feedstock and finished product requirements. Processes are also affected by economic factors including crude costs, product values, availability of utilities and transportation. The chronology of the introduction of various processes is given in table 78.1 .
Table 78.1 Summary of the history of refining processing
Naphtha, tar, etc.
Cracking feedstocks (1930s)
Residual, bunker fuel
Reduce sulphur and odour
Improve octane number
Produce gasoline base stocks
Improve lubricant viscosity index
Improve pour point
Improve gasoline yield and octane number
Higher octane gasoline
Increased distillate, tar
Increase gasoline octane and yield
High-octane aviation gasoline
Produce alkylation feedstock
Fluid catalytic cracking
Increase gasoline yield and octane
Increase cracking feedstock
Convert low-quality naphtha
Convert to molecules with high octane number
Improve quality and reduce sulphur
Improve pour point
Increase gasoline yield from residual
Basic refining processes and operations
Petroleum refining processes and operations can be classified into the following basic areas: separation, conversion, treatment, formulating and blending, auxiliary refining operations and refining non-process operations. See figure 78.1 for a simplified flow chart.
Figure 78.1 Refinery process chart
Separation. Crude oil is physically separated by fractionation in atmospheric and vacuum distillation towers, into groups of hydrocarbon molecules with various boiling-point ranges, called �fractions� or �cuts�.
Conversion. Conversion processes used to change the size and/or structure of hydrocarbon molecules include:
· decomposition (dividing) by hydro-, thermal and catalytic cracking, coking and visbreaking
· unification (combining) through alkylation and polymerization
· alteration (rearranging) with isomerization and catalytic reforming
Since the beginning of refining, various treatment methods have been used to remove non-hydrocarbons, impurities and other constituents that adversely affect the performance properties of finished products or reduce the efficiency of the conversion processes. Treatment involves both chemical reactions and physical separation, such as dissolving, absorption or precipitation, using a variety and combination of processes. Treatment methods include removing or separating aromatics and naphthenes, as well as removing impurities and undesirable contaminants. Sweetening compounds and acids are used to desulphurize crude oil before processing, and to treat products during and after processing. Other treatment methods include crude desalting, chemical sweetening, acid treating, clay contacting, hydrodesulphurizing, solvent refining, caustic washing, hydrotreating, drying, solvent extraction and solvent dewaxing.
Formulating and blending is the process of mixing and combining hydrocarbon fractions, additives and other components to produce finished products with specific desired performance properties.
Auxiliary refining operations. Other refinery operations which are required to support hydrocarbon processing include light ends recovery; sour water stripping; solid waste, waste water and process water treatment and cooling; hydrogen production; sulphur recovery; and acid and tail gas treatment. Other process functions are providing catalysts, reagents, steam, air, nitrogen, oxygen, hydrogen and fuel gases.
Refinery non-process facilities. All refineries have a multitude of facilities, functions, equipment and systems which support the hydrocarbon process operations. Typical support operations are heat and power generation; product movement; tank storage; shipping and handling; flares and relief systems; furnaces and heaters; alarms and sensors; and sampling, testing and inspecting. Non-process facilities and systems include firefighting, water and protection systems, noise and pollution controls, laboratories, control rooms, warehouses, maintenance and administrative facilities.
Major Products of Crude Oil Refining
Petroleum refining has evolved continuously in response to changing consumer demand for better and different products. The original process requirement was to produce kerosene as a cheaper and better source of fuel for lighting than whale oil. The development of the internal combustion engine led to the production of benzene, gasoline and diesel fuels. The evolution of the airplane created a need for high-octane aviation gasoline and jet fuel, which is a sophisticated form of the original refinery product, kerosene. Present-day refineries produce a variety of products, including many which are used as feedstocks for cracking processes and lubricant manufacturing, and for the petrochemical industry. These products can be broadly classified as fuels, petrochemical feedstocks, solvents, process oils, lubricants and special products such as wax, asphalt and coke. (See table 78.2 .)
Table 78.2 Principal products of crude oil refining
Cooking and industrial gas
Motor fuel gas
Solvents and acetone
Resins and fibres for plastics and textiles
Paints and varnish
Chemical industry feedstock
Solvents and diluents
Chemical industry feedstocks
Aviation and motor gasoline
Military jet fuel
Jet fuel and kerosene
Heating oil and diesel fuel
Absorber oil-benzene and gasoline recovery
Medicinal oils and cosmetics
White oil-food industry
Transformer and spindle oils
Motor and engine oils
Machine and compressor oils
Turbine and hydraulic oils
Equipment and cable insulation oils
Axle, gear and steam engine oils
Metal treating, cutting and grinding oils
Quenching and rust inhibitor oils
Heat transfer oils
Lubricating greases and compounds
Printing ink oils
Pharmaceuticals and cosmetics
Food and paper industries
Candles and matches
Rust inhibitors and lubricants
Cable coating compounds
Residual fuel oil
No. 6 boiler and process fuel oil
Insulating and foundation protection
Waterproof paper products
Electrodes and fuel
A number of chemicals are used in, or formed as a result of, hydrocarbon processing. A brief description of those which are specific and pertinent to refining follows:
Flue gas from burning high-sulphur-content fuels usually contains high levels of sulphur dioxide, which usually is removed by water scrubbing.
Caustics are added to desalting water to neutralize acids and reduce corrosion. Caustics are also added to desalted crude in order to reduce the amount of corrosive chlorides in the tower overheads. They are used in refinery treating processes to remove contaminants from hydrocarbon streams.
Nitrogen oxides and carbon monoxide
Flue gas contains up to 200 ppm of nitric oxide, which reacts slowly with oxygen to form nitrogen dioxide. Nitric oxide is not removed by water scrubbing, and nitrogen dioxide can dissolve in water to form nitrous and nitric acid. Flue gas normally contains only a slight amount of carbon monoxide, unless combustion is abnormal.
Hydrogen sulphide is found naturally in most crude oils and is also formed during processing by the decomposition of unstable sulphur compounds. Hydrogen sulphide is an extremely toxic, colourless, flammable gas which is heavier than air and soluble in water. It has a rotten egg odour which is discernible at concentrations well below its very low exposure limit. This smell cannot be relied upon to provide adequate warning as the senses are almost immediately desensitized upon exposure. Special detectors are required to alert workers to the presence of hydrogen sulphide, and proper respiratory protection should be used in the presence of the gas. Exposure to low levels of hydrogen sulphide will cause irritation, dizziness and headaches, while exposure to levels in excess of the prescribed limits will cause nervous system depression and eventually death.
Sour water is process water which contains hydrogen sulphide, ammonia, phenols, hydrocarbons and low-molecular-weight sulphur compounds. Sour water is produced by steam stripping hydrocarbon fractions during distillation, regenerating catalyst, or steam stripping hydrogen sulphide during hydrotreating and hydrofinishing. Sour water is also generated by the addition of water to processes to absorb hydrogen sulphide and ammonia.
Sulphuric acid and hydrofluoric acid
Sulphuric acid and hydrofluoric acid are used as catalysts in alkylation processes. Sulphuric acid is also used in some of the treatment processes.
A number of different solid catalysts in many forms and shapes, from pellets to granular beads to dusts, made of various materials and having various compositions, are used in refining processes. Extruded pellet catalysts are used in moving and fixed bed units, while fluid bed processes use fine, spherical particulate catalysts. Catalysts used in processes which remove sulphur are impregnated with cobalt, nickel or molybdenum. Cracking units use acid-function catalysts, such as natural clay, silica alumina and synthetic zeolites. Acid-function catalysts impregnated with platinum or other noble metals are used in isomerization and reforming. Used catalysts require special handling and protection from exposures, as they may contain metals, aromatic oils, carcinogenic polycyclic aromatic compounds or other hazardous materials, and may also be pyrophoric.
The principal fuel products are liquefied petroleum gas, gasoline, kerosene, jet fuel, diesel fuel and heating oil and residual fuel oils.
Liquefied petroleum gas (LPG), which consists of mixtures of paraffinic and olefinic hydrocarbons such as propane and butane, is produced for use as a fuel, and is stored and handled as liquids under pressure. LPG has boiling points ranging from about �74 °C to +38 °C, is colourless, and the vapours are heavier than air and extremely flammable. The important qualities from an occupational health and safety perspective of LPGs are vapour pressure and control of contaminants.
Gasoline. The most important refinery product is motor gasoline, a blend of relatively low-boiling hydrocarbon fractions, including reformate, alkylate, aliphatic naphtha (light straight-run naphtha), aromatic naphtha (thermal and catalytic cracked naphtha) and additives. Gasoline blending stocks have boiling points which range from ambient temperatures to about 204 °C, and a flashpoint below �40 °C. The critical qualities for gasoline are octane number (anti-knock), volatility (starting and vapour lock) and vapour pressure (environmental control). Additives are used to enhance gasoline performance and provide protection against oxidation and rust formation. Aviation gasoline is a high-octane product, specially blended to perform well at high altitudes.
Tetra ethyl lead (TEL) and tetra methyl lead (TML) are gasoline additives which improve octane ratings and anti-knock performance. In an effort to reduce lead in automotive exhaust emissions, these additives are no longer in common use, except in aviation gasoline.
Ethyl tertiary butyl ether (ETBE), methyl tertiary butyl ether (MTBE), tertiary amyl methyl ether (TAME) and other oxygenated compounds are used in lieu of TEL and TML to improve unleaded gasoline anti-knock performance and reduce carbon monoxide emissions.
Jet fuel and kerosene. Kerosene is a mixture of paraffins and naphthenes with usually less than 20% aromatics. It has a flashpoint above 38 °C and a boiling range of 160 °C to 288 °C, and is used for lighting, heating, solvents and blending into diesel fuel. Jet fuel is a middle distillate kerosene product whose critical qualities are freezepoint, flashpoint and smokepoint. Commercial jet fuel has a boiling range of about 191 °C to 274 °C, and military jet fuel from 55 °C to 288 °C.
Distillate fuels. Diesel fuels and domestic heating oils are light-coloured mixtures of paraffins, naphthenes and aromatics, and may contain moderate quantities of olefins. Distillate fuels have flashpoints above 60 °C and boiling ranges of about 163 °C to 371 °C, and are often hydrodesulphurized for improved stability. Distillate fuels are combustible and when heated may emit vapours which can form ignitable mixtures with air. The desirable qualities required for distillate fuels include controlled flash- and pourpoints, clean burning, no deposit formation in storage tanks, and a proper diesel fuel cetane rating for good starting and combustion.
Residual fuels. Many ships and commercial and industrial facilities use residual fuels or combinations of residual and distillate fuels, for power, heat and processing. Residual fuels are dark- coloured, highly viscous liquid mixtures of large hydrocarbon molecules, with flashpoints above 121 °C and high boiling points. The critical specifications for residual fuels are viscosity and low sulphur content (for environmental control).
Health and safety considerations
The primary safety hazard of LPG and gasoline is fire. The high volatility and high flammability of the lower-boiling-point products allows vapours to evaporate readily into air and form flammable mixtures which can be easily ignited. This is a recognized hazard that requires specific storage, containment and handling precautions, and safety measures to assure that releases of vapours and sources of ignition are controlled so that fires do not occur. The less volatile fuels, such as kerosene and diesel fuel, should be handled carefully to prevent spills and possible ignition, as their vapours are also combustible when mixed with air in the flammable range. When working in atmospheres containing fuel vapours, concentrations of highly volatile, flammable product vapours in air are often restricted to no more than 10% of the lower flammable limits (LFL), and concentrations of less volatile, combustible product vapours to no more than 20% LFL, depending on applicable company and government regulations, in order to reduce the risk of ignition.
Although gasoline vapour levels in air mixtures are typically maintained below 10% of the LFL for safety purposes, this concentration is considerably above the exposure limits to be observed for health reasons. When inhaled, small amounts of gasoline vapour in air, well below the lower flammable limit, can cause irritation, headaches and dizziness, while inhalation of larger concentrations can cause loss of consciousness and eventually death. Long-term health effects may also be possible. Gasoline contains benzene, for example, a known carcinogen with allowable exposure limits of only a few parts per million. Therefore, even working in gasoline vapour atmospheres at levels below 10% LFL requires appropriate industrial hygiene precautions, such as respiratory protection or local exhaust ventilation.
In the past, many gasolines contained tetra-ethyl or tetra methyl alky lead anti-knock additives, which are toxic and present serious lead absorption hazards by skin contact or inhalation. Tanks or vessels which contained leaded gasoline at any time during their use must be vented, thoroughly cleaned, tested with a special �lead-in-air� test device and certified to be lead-free to assure that workers can enter without using self-contained or supplied breathing air equipment, even though oxygen levels are normal and the tanks now contain unleaded gasoline or other products.
Gaseous petroleum fractions and the more highly volatile fuel products have a mild anaesthetic effect, generally in inverse ratio to molecular weight. Lower-boiling-point liquid fuels, such as gasoline and kerosene, produce a severe chemical pneumonitis if inhaled, and should not be siphoned by mouth or accidentally ingested. Gases and vapours may also be present in sufficiently high concentrations to displace oxygen (in the air) below normal breathing levels. Maintaining vapour concentrations below the exposure limits and oxygen levels at normal breathing ranges, is usually accomplished by purging or ventilation.
Cracked distillates contain small amounts of carcinogenic polycyclic aromatic hydrocarbons (PAHs); therefore, exposure should be limited. Dermatitis may also develop from exposure to gasoline, kerosene and distillate fuels, as they have a tendency to defat the skin. Prevention is accomplished by use of personal protective equipment, barrier creams or reduced contact and good hygienic practices, such as washing with warm water and soap instead of cleaning hands with gasoline, kerosene or solvents. Some persons have skin sensitivity to the dyes used to colour gasoline and other distillate products.
Residual fuel oils contain traces of metals and may have entrained hydrogen sulphide, which is extremely toxic. Residual fuels which have high cracked stocks boiling above 370 °C contain carcinogenic PAHs. Repeated exposure to residual fuels without appropriate personal protection, should be avoided, especially when opening tanks and vessels, as hydrogen sulphide gas may be emitted.
Many products derived from crude-oil refining, such as ethylene, propylene and butadiene, are olefinic hydrocarbons derived from refinery cracking processes, and are intended for use in the petrochemical industry as feedstocks for the production of plastics, ammonia, synthetic rubber, glycol and so on.
A variety of pure compounds, including benzene, toluene, xylene, hexane and heptane, whose boiling points and hydrocarbon composition are closely controlled, are produced for use as solvents. Solvents may be classified as aromatic or non-aromatic, depending on their composition. Their use as paint thinners, dry-cleaning fluids, degreasers, industrial and pesticide solvents and so on, is generally determined by their flashpoints, which vary from well below �18 °C to above 60 °C.
The hazards associated with solvents are similar to those of fuels in that the lower flashpoint solvents are flammable and their vapours, when mixed with air in the flammable range, are ignitable. Aromatic solvents will usually have more toxicity than non-aromatic solvents.
Process oils include the high boiling range, straight run atmospheric or vacuum distillate streams and those which are produced by catalytic or thermal cracking. These complex mixtures, which contain large paraffinic, naphthenic and aromatic hydrocarbon molecules with more than 15 carbon atoms, are used as feedstocks for cracking or lubricant manufacturing. Process oils have fairly high viscosities, boiling points ranging from 260 °C to 538 °C, and flashpoints above 121 °C.
Process oils are irritating to the skin and contain high concentrations of PAHs as well as sulphur, nitrogen and oxygen compounds. Inhalation of vapours and mists should be avoided, and skin exposure should be controlled by the use of personal protection and good hygienic practices.
Lubricants and greases
Lubricating oil base stocks are produced by special refining processes to meet specific consumer requirements. Lubricating base stocks are light- to medium-coloured, low-volatile, medium- to high-viscous mixtures of paraffinic, naphthenic and aromatic oils, with boiling ranges from 371 °C to 538 °C. Additives, such as demulsifiers, anti-oxidants and viscosity improvers, are blended into the lubricating oil base stocks to provide the characteristics required for motor oils, turbine and hydraulic oils, industrial greases, lubricants, gear oils and cutting oils. The most critical quality for lubricating oil base stock is a high viscosity index, providing for less change in viscosity under varying temperatures. This characteristic may be present in the crude oil feed stock or attained through the use of viscosity index improver additives. Detergents are added to keep in suspension any sludge formed during the use of the oil.
Greases are mixtures of lubricating oils and metallic soaps, with the addition of special-purpose materials such as asbestos, graphite, molybdenum, silicones and talc to provide insulation or lubricity. Cutting and metal-process oils are lubricating oils with special additives such as chlorine, sulphur and fatty-acid additives which react under heat to provide lubrication and protection to the cutting tools. Emulsifiers and bacteria prevention agents are added to water-soluble cutting oils.
Although lubricating oils by themselves are non-irritating and have little toxicity, hazards may be presented by the additives. Users should consult supplier material safety data information to determine the hazards of specific additives, lubricants, cutting oils and greases. The primary lubricant hazard is dermatitis, which can usually be controlled by the use of personal protective equipment together with proper hygienic practices. Occasionally workers may develop a sensitivity to cutting oils or lubricants which will require reassignment to a job where contact cannot occur. There are some concerns about carcinogenic exposure to mists from naphthenic-based cutting and light spindle oils, which can be controlled by substitution, engineering controls or personal protection. The hazards of exposure to grease are similar to those of lubricating oil, with the addition of any hazards presented by the grease materials or additives. Most of these hazards are discussed elsewhere in this Encyclopaedia.
Wax is used for protecting food products; in coatings; as an ingredient in other products such as cosmetics and shoe polish and for candles.
Sulphur is produced as a result of petroleum refining. It is stored either as a heated, molten liquid in closed tanks or as a solid in containers or outdoors.
Coke is almost pure carbon, with a variety of uses from electrodes to charcoal briquettes, depending on its physical characteristics, which result from the coking process.
Asphalt, which is primarily used for paving roads and roofing materials, should be inert to most chemicals and weather conditions.
Waxes and asphalts are solid at ambient temperatures, and higher temperatures are needed for storage, handling and transportation, with the resulting hazard of burns. Petroleum wax is so highly refined that it usually does not present any hazards. Skin contact with wax can lead to plugging of pores, which can be controlled by proper hygienic practices. Exposure to hydrogen sulphide when asphalt and molten sulphur tanks are opened can be controlled by the use of appropriate engineering controls or respiratory protection. Sulphur is also readily ignitable at elevated temperatures. Asphalt is discussed elsewhere in the Encyclopaedia.
Petroleum Refining Processes
Hydrocarbon refining is the use of chemicals, catalysts, heat and pressure to separate and combine the basic types of hydrocarbon molecules naturally found in crude oil into groups of similar molecules. The refining process also rearranges the structures and bonding patterns of the basic molecules into different, more desirable hydrocarbon molecules and compounds. The type of hydrocarbon (paraffinic, naphthenic or aromatic) rather than the specific chemical compounds present, is the most significant factor in the refining process.
Throughout the refinery, operations procedures, safe work practices and the use of appropriate personal protective clothing and equipment, including approved respiratory protection, is needed for fire, chemical, particulate, heat and noise exposures and during process operations, sampling, inspection, turnaround and maintenance activities. As most refinery processes are continuous and the process streams are contained in enclosed vessels and piping, there is limited potential for exposure. However, the potential for fire exists because even though refinery operations are closed processes, if a leak or release of hydrocarbon liquid, vapour or gas occurs, the heaters, furnaces and heat exchangers throughout the process units are sources of ignition.
Crude oil pretreatment
Crude oil often contains water, inorganic salts, suspended solids and water-soluble trace metals. The first step in the refining process is to remove these contaminants by desalting (dehydration) in order to reduce corrosion, plugging and fouling of equipment, and to prevent poisoning the catalysts in processing units. Chemical desalting, electrostatic separation and filtering are three typical methods of crude-oil desalting. In chemical desalting, water and chemical surfactants (demulsifiers) are added to the crude oil, heated so that salts and other impurities dissolve into the water or attach to the water, and are then held in a tank where they settle out. Electrical desalting applies high-voltage electrostatic charges in order to concentrate suspended water globules in the bottom portion of the settling tank. Surfactants are added only when the crude oil has a large amount of suspended solids. A third, less common process involves filtering heated crude oil using diatomaceous earth as a filtration medium.
In chemical and electrostatic desalting, the crude feedstock is heated to between 66 °C and 177 °C, to reduce viscosity and surface tension for easier mixing and separation of the water. The temperature is limited by the vapour pressure of the crude-oil feedstock. Both methods of desalting are continuous. Caustic or acid may be added to adjust the pH of the water wash, and ammonia added to reduce corrosion. Waste water, together with contaminants, is discharged from the bottom of the settling tank to the waste water treatment facility. The desalted crude oil is continuously drawn from the top of the settling tanks and sent to an atmospheric crude distillation (fractionating) tower. (See figure 78.2.)
Figure 78.2 Desalting (pre-treatment) process
Inadequate desalting causes fouling of heater tubes and heat exchangers in all refinery process units, restricting product flow and heat transfer, and resulting in failures due to increased pressures and temperatures. Overpressuring the desalting unit will cause failure.
Corrosion, which occurs due to the presence of hydrogen sulphide, hydrogen chloride, naphthenic (organic) acids and other contaminants in the crude oil, also causes equipment failure. Corrosion occurs when neutralized salts (ammonium chlorides and sulphides) are moistened by condensed water. Because desalting is a closed process, there is little potential for exposure to crude oil or process chemicals, unless a leak or release occurs. A fire may occur as a result of a leak in the heaters, allowing a release of low-boiling-point components of crude oil.
There is the possibility of exposure to ammonia, dry chemical demulsifiers, caustics and/or acids during desalting. Where elevated operating temperatures are used when desalting sour crude oils, hydrogen sulphide will be present. Depending on the crude feedstock and the treatment chemicals used, the waste water will contain varying amounts of chlorides, sulphides, bicarbonates, ammonia, hydrocarbons, phenol and suspended solids. If diatomaceous earth is used in filtration, exposures should be minimized or controlled since diatomaceous earth can contain silica with a very fine particle size, making it a potential respiratory hazard.
Crude oil separation processes
The first step in petroleum refining is the fractionation of crude oil in atmospheric and vacuum distillation towers. Heated crude oil is physically separated into various fractions, or straight-run cuts, differentiated by specific boiling-point ranges and classified, in order of decreasing volatility, as gases, light distillates, middle distillates, gas oils and residuum. Fractionation works because the gradation in temperature from the bottom to the top of the distillation tower causes the higher-boiling-point components to condense first, while the lower-boiling-point fractions rise higher in the tower before they condense. Within the tower, the rising vapours and the descending liquids (reflux) mix at levels where they have compositions in equilibrium with each other. Special trays are located at these levels (or stages) which remove a fraction of the liquid which condenses at each level. In a typical two-stage crude unit, the atmospheric tower, producing light fractions and distillate, is immediately followed by a vacuum tower which processes the atmospheric residuals. After distillation, only a few hydrocarbons are suitable for use as finished products without further processing.
In atmospheric distillation towers, the desalted crude feedstock is preheated using recovered process heat. It then flows to a direct-fired crude charge heater, where it is fed into the vertical distillation column just above the bottom at pressures slightly above atmosphere and at temperatures from 343 °C to 371 °C, to avoid undesirable thermal cracking at higher temperatures. The lighter (lower boiling point) fractions diffuse into the upper part of the tower, and are continuously drawn off and directed to other units for further processing, treating, blending and distribution.
Fractions with the lowest boiling points, such as fuel gas and light naphtha, are removed from the top of the tower by an overhead line as vapours. Naphtha, or straight-run gasoline, is taken from the upper section of the tower as an overhead stream. These products are used as petrochemical and reformer feedstocks, gasoline blending stocks, solvents and LPGs.
Intermediate boiling range fractions, including gas oil, heavy naphtha and distillates, are removed from the middle section of the tower as side streams. These are sent to finishing operations for use as kerosene, diesel fuel, fuel oil, jet fuel, catalytic cracker feedstock and blending stocks. Some of these liquid fractions are stripped of their lighter ends, which are returned to the tower as downflowing reflux streams.
The heavier, higher-boiling-point fractions (called residuum, bottoms or topped crude) which condense or remain at the bottom of the tower, are used for fuel oil, bitumen manufacturing or cracking feedstock, or are directed to a heater and into the vacuum distillation tower for further fractionation. (See figure 78.3 and figure 78.4.)
Figure 78.3 Atmospheric distillation process
Figure 78.4 Schematic of atmospheric distrillation process
Vacuum distillation towers provide the reduced pressure required to prevent thermal cracking when distilling the residuum, or topped crude, from the atmospheric tower at higher temperatures. The internal designs of some vacuum towers are different from atmospheric towers in that random packing and demister pads are used instead of trays. Larger diameter towers may also be used to keep velocities lower. A typical first-phase vacuum tower may produce gas oils, lubricating oil base stocks and heavy residual for propane deasphalting. A second-phase tower, operating at a lower vacuum, distills surplus residuum from the atmospheric tower which is not used for lube stock processing, and surplus residuum from the first vacuum tower not used for deasphalting.
Vacuum towers are typically used to separate catalytic cracker feedstocks from surplus residuum. Vacuum tower bottoms may also be sent to a coker, used as lubricant or asphalt stock or desulphurized and blended into low-sulphur fuel oil. (See figure 78.5 and figure 78.6.)
Figure 78.5 Vacuum distillation process
Figure 78.6 Schematic of vacuum distillation process
Within refineries there are numerous other smaller distillation towers, called columns, designed to separate specific and unique products, which all work on the same principles as atmospheric towers. For example, a depropanizer is a small column designed to separate propane from isobutane and heavier components. Another larger column is used to separate ethyl benzene and xylene. Small �bubbler� towers, called strippers, use steam to remove trace amounts of light products (gasoline) from heavier product streams.
Control temperatures, pressures and reflux must be maintained within operating parameters to prevent thermal cracking from taking place within distillation towers. Relief systems are provided because excursions in pressure, temperature or liquid levels may occur if automatic control devices fail. Operations are monitored in order to prevent crude from entering the reformer charge. Crude feedstocks may contain appreciable amounts of water in suspension which separate during start-up and, along with water remaining in the tower from steam purging, settle in the bottom of the tower. This water may heat to the boiling point and create an instantaneous vaporization explosion upon contact with the oil in the unit.
The preheat exchanger, preheat furnace and bottoms exchanger, atmospheric tower and vacuum furnace, vacuum tower and overhead are susceptible to corrosion from hydrochloric acid (HCl), hydrogen sulphide (H2S), water, sulphur compounds and organic acids. When processing sour crudes, severe corrosion can occur in both atmospheric and vacuum towers where metal temperatures exceed 232 °C, and in furnace tubing. Wet H2S will also cause cracks in steel. When processing high-nitrogen crudes, nitrogen oxides, which are corrosive to steel when cooled to low temperatures in the presence of water, form in the flue gases of furnaces.
Chemicals are used to control corrosion by hydrochloric acid produced in distillation units. Ammonia may be injected into the overhead stream prior to initial condensation, and/or an alkaline solution may be carefully injected into the hot crude oil feed. If sufficient wash water is not injected, deposits of ammonium chloride can form, causing serious corrosion.
Atmospheric and vacuum distillation are closed processes, and exposures are minimal. When sour (high sulphur) crudes are processed, there may be potential exposure to hydrogen sulphide in the preheat exchanger and furnace, tower flash zone and overhead system, vacuum furnace and tower, and bottoms exchanger. Crude oils and distillation products all contain high-boiling aromatic compounds, including carcinogenic PAHs. Short-term exposure to high concentrations of naphtha vapour can result in headaches, nausea and dizziness, and long-term exposure can result in loss of consciousness. Benzene is present in aromatic naphthas, and exposure must be limited. The dehexanizer overhead may contain large amounts of normal hexane, which can affect the nervous system. Hydrogen chloride may be present in the preheat exchanger, tower top zones and overheads. Waste water may contain water-soluble sulphides in high concentrations and other water-soluble compounds, such as ammonia, chlorides, phenol and mercaptan, depending upon the crude feedstock and the treatment chemicals.
Crude oil conversion processes
Conversion processes, such as cracking, combining and rearranging, change the size and structure of hydrocarbon molecules in order to convert fractions into more desirable products. (See table 78.3.)
Table 78.3 Overview of petroleum refining processes
Desalted crude oil
Gas, gas oil, distillate, residual
Separate without cracking
Atmospheric tower residual
Gas oil, lube stock, residual
Gas oil, coke distillate
Gasoline, petrochemical feedstock
Convert vacuum residuals
Residual, heavy oil, tar
Naphtha, gas oil, coke
Convert to lighter hydrocarbons
Gas oil, cracked oil, residuals
Lighter, higher quality products
Hydrogen steam reforming
Desulphurized gas, O2 ,steam
Crack large molecules
Atmospheric tower heavy fuel/distillate
Cracked naphtha, coke, residuals
Atmospheric tower residual
Unite olefins and isoparaffins
Tower isobutane/cracker olefin
Combine soaps and oils
Lube oil, catty acid, alkymetal
Unite two or more olefins
High octane naphtha, petrochemical stocks
Upgrade low-octane naphtha
Convert straight chain to branch
Butane, centane, cexane
Remove acidic contaminants
Sour gas, cydrocarbons with CO2 and H2S
Acid-free gases and liquid hydrocarbons
Desalted crude oil
Drying and sweetening
Remove H2O and sulphur compounds
Liquid hydrocarbon, LPG, alkylated feedstock
Sweet and dry hydrocarbons
Upgrade middistillate and lubes
Cycle oils and lube feedstocks
High-quality diesel and lube oil
Remove sulphur, contaminants
High-sulphur residual/gas oil
Remove impurities/ saturate hydrocarbons
Residuals, cracked hydrocarbons
Cracker feed, cistillate, lube
Improve lube viscosity index, colour
Lube oil base stocks
High-quality lube oils
Vacuum tower residual, cropane
Heavy lube oil, csphalt
Remove wax from lube stocks
Vacuum tower lube oils
Dewaxed lube base stock
Separate unsaturated aromatics
Gas oil, ceformate, cistillate
Remove H2S, convert mercaptan
A number of hydrocarbon molecules not normally found in crude oil but important to the refining process are created as a result of conversion. Olefins (alkenes, di-olefins and alkynes) are unsaturated chain- or ring-type hydrocarbon molecules with at least one double bond. They are usually formed by thermal and catalytic cracking and rarely occur naturally in unprocessed crude oil.
Alkenes are straight-chain molecules with the formula CnHn containing at least one double bond (unsaturated) linkage in the chain. The simplest alkene molecule is the mono-olefin ethylene, with two carbon atoms, joined by a double bond, and four hydrogen atoms. Di-olefins (containing two double bonds), such as 1,2-butadiene and 1,3-butadiene, and alkynes (containing a triple bond), such as acetylene, occur in C5 and lighter fractions from cracking. Olefins are more reactive than paraffins or naphthenes, and readily combine with other elements such as hydrogen, chlorine and bromine.
Following distillation, subsequent refinery processes are used to alter the molecular structures of the fractions to create more desirable products. One of these processes, cracking, breaks (or cracks) heavier, higher-boiling-point petroleum fractions into more valuable products such as gaseous hydrocarbons, gasoline blending stocks, gas oil and fuel oil. During the process, some of the molecules combine (polymerize) to form larger molecules. The basic types of cracking are thermal cracking, catalytic cracking and hydro-cracking.
Thermal cracking processes
Thermal cracking processes, developed in 1913, heat distillate fuels and heavy oils under pressure in large drums until they crack (divide) into smaller molecules with better anti-knock characteristics. This early method, which produced large amounts of solid, unwanted coke, has evolved into modern thermal cracking processes including visbreaking, steam cracking and coking.
Visbreaking is a mild form of thermal cracking which reduces the pour point of waxy residues and significantly lowers the viscosity of feedstock without affecting its boiling-point range. Residual from the atmospheric distillation tower is mildly cracked in a heater at atmospheric pressure. It is then quenched with cool gas oil to control overcracking, and flashed in a distillation tower. The thermally cracked residue tar, which accumulates in the bottom of the fractionation tower, is vacuum flashed in a stripper and the distillate is recycled. (See figure 78.7.)
Figure 78.7 Visbreaking process
Steam cracking produces olefins by thermally cracking large hydrocarbon molecule feedstocks at pressures slightly above atmospheric and at very high temperatures. Residual from steam cracking is blended into heavy fuels. Naphtha produced from steam cracking usually contains benzene, which is extracted prior to hydrotreating.
Coking is a severe form of thermal cracking used to obtain straight-run gasoline (coker naphtha) and various middle distillate fractions used as catalytic cracking feedstocks. This process so completely reduces hydrogen from the hydrocarbon molecule, that the residue is a form of almost pure carbon called coke. The two most common coking processes are delayed coking and continuous (contact or fluid) coking, which, depending upon the reaction mechanism, time, temperature and the crude feedstock, produce three types of cokesponge, honeycomb and needle coke. (See figure 78.8.)
Figure 78.8 Coking process
· Delayed coking. In delayed coking, the feedstock is first charged to a fractionator to separate lighter hydrocarbons, and then combined with heavy recycle oil. The heavy feedstock is fed to the coker furnace and heated to high temperatures at low pressures to prevent premature coking in the heater tubes, producing partial vaporization and mild cracking. The liquid/vapour mixture is pumped from the heater to one or more coker drums, where the hot material is held approximately 24 hours (delayed) at low pressures until it cracks into lighter products. After the coke reaches a predetermined level in one drum, the flow is diverted to another drum to maintain continuous operation. Vapour from the drums is returned to the fractionator to separate out gas, naphtha and gas oils, and to recycle heavier hydrocarbons through the furnace. The full drum is steamed to strip out uncracked hydrocarbons, cooled by water injection and decoked mechanically by an auger rising from the bottom of the drum, or hydraulically by fracturing the coke bed with high-pressure water ejected from a rotating cutter.
· Continuous coking. Continuous (contact or fluid) coking is a moving bed process which operates at lower pressures and higher temperatures than delayed coking. In continuous coking, thermal cracking occurs by using heat transferred from hot recycled coke particles to feedstock in a radial mixer, called a reactor. Gases and vapours are taken from the reactor, quenched to stop further reaction and fractionated. The reacted coke enters a surge drum and is lifted to a feeder and classifier where the larger coke particles are removed. The remaining coke is dropped into the reactor preheater for recycling with feedstock. The process is automatic in that there is a continuous flow of coke and feedstock, and coking occurs both in the reactor and in the surge drum.
Health and safety considerations
In coking, temperature control should be held within a close range, as high temperatures will produce coke which is too hard to cut out of the drum. Conversely, temperatures which are too low will result in a high asphaltic content slurry. Should coking temperatures get out of control, an exothermic reaction could occur.
In thermal cracking when sour crudes are processed, corrosion can occur where metal temperatures are between 232 °C and 482 °C. It appears that coke forms a protective layer on the metal above 482 °C. However, hydrogen sulphide corrosion occurs when temperatures are not properly controlled above 482 °C. The lower part of the tower, high temperature exchangers, furnace and soaking drums are subject to corrosion. Continuous thermal changes cause coke drum shells to bulge and crack.
Water or steam injection is used to prevent buildup of coke in delayed coker furnace tubes. Water must be completely drained from the coker, so as not to cause an explosion upon recharging with hot coke. In emergencies, alternate means of egress from the working platform on top of coke drums is needed.
Burns may occur when handling hot coke, from steam in the event of a steam line leak, or from hot water, hot coke or hot slurry which may be expelled when opening cokers. The potential exists for exposure to aromatic naphthas containing benzene, hydrogen sulphide and carbon monoxide gases, and to trace amounts of carcinogenic PAHs associated with coking operations. Waste sour water may be highly alkaline, and contain oil, sulphides, ammonia and phenol. When coke is moved as a slurry, oxygen depletion may occur within confined spaces such as storage silos, because wet carbon adsorbs oxygen.
Catalytic cracking processes
Catalytic cracking breaks up complex hydrocarbons into simpler molecules in order to increase the quality and quantity of lighter, more desirable products and decrease the amount of residuals. Heavy hydrocarbons are exposed at high temperature and low pressure to catalysts which promote chemical reactions. This process rearranges the molecular structure, converting heavy hydrocarbon feedstocks into lighter fractions such as kerosene, gasoline, LPG, heating oil and petrochemical feedstocks (see figure 78.9 and figure 78.10). Selection of a catalyst depends upon a combination of the greatest possible reactivity and the best resistance to attrition. The catalysts used in refinery cracking units are typically solid materials (zeolite, aluminium hydrosilicate, treated bentonite clay, Fuller�s earth, bauxite and silica-alumina) which are in the form of powders, beads, pellets or shaped materials called extrudites.
Figure 78.9 Catalytic cracking process
Figure 78.10 Schematic of catalytic cracking process
There are three basic functions in all catalytic cracking processes:
· Reactionfeedstock reacts with catalyst and cracks into different hydrocarbons.
· Regenerationcatalyst is reactivated by burning off coke.
· Fractionationcracked hydrocarbon stream is separated into various products.
Catalytic cracking processes are very flexible and operating parameters can be adjusted to meet changing product demand. The three basic types of catalytic cracking processes are:
· fluid catalytic cracking (FCC)
· moving bed catalytic cracking
· thermofor catalytic cracking (TCC).
Fluid catalytic cracking
Fluid-bed catalytic crackers have a catalyst section (riser, reactor and regenerator) and a fractionating section, both operating together as an integrated processing unit. The FCC uses finely powdered catalyst, suspended in oil vapour or gas, which acts as a fluid. Cracking takes place in the feed pipe (riser) in which the mixture of catalyst and hydrocarbons flow through the reactor.
The FCC process mixes a preheated hydrocarbon charge with hot, regenerated catalyst as it enters the riser leading to the reactor. The charge combines with recycle oil within the riser, is vaporized and is raised to reactor temperature by the hot catalyst. As the mixture travels up the reactor, the charge is cracked at low pressure. This cracking continues until the oil vapours are separated from the catalyst in the reactor cyclones. The resultant product stream enters a column where it is separated into fractions, with some of the heavy oil directed back into the riser as recycle oil.
Spent catalyst is regenerated to remove coke which collects on the catalyst during the process. Spent catalyst flows through the catalyst stripper to the regenerator where it mixes with preheated air, burning off most of the coke deposits. Fresh catalyst is added and worn-out catalyst removed to optimize the cracking process.
Moving bed catalytic cracking
Moving-bed catalytic cracking is similar to fluid catalytic cracking; however, the catalyst is in the form of pellets instead of fine powder. The pellets move continuously by conveyor or pneumatic lift tubes to a storage hopper at the top of the unit, and then flow downward by gravity through the reactor to a regenerator. The regenerator and hopper are isolated from the reactor by steam seals. The cracked product is separated into recycle gas, oil, clarified oil, distillate, naphtha and wet gas.
Thermofor catalytic cracking
In thermofor catalytic cracking, the preheated feedstock flows by gravity through the catalytic reactor bed. Vapours are separated from the catalyst and sent to a fractionating tower. The spent catalyst is regenerated, cooled and recycled, and the flue gas from regeneration is sent to a carbon monoxide boiler for heat recovery.
Health and safety considerations
Regular sampling and testing of feedstock, product and recycle streams should be performed to assure that the cracking process is working as intended and that no contaminants have entered the process stream. Corrosives or deposits in feedstock can foul gas compressors. When processing sour crude, corrosion may be expected where temperatures are below 482 °C. Corrosion takes place where both liquid and vapour phases exist and at areas subject to local cooling, such as nozzles and platform supports. When processing high-nitrogen feedstocks, exposure to ammonia and cyanide may subject carbon steel equipment in the FCC overhead system to corrosion, cracking or hydrogen blistering, which can be minimized by water wash or by corrosion inhibitors. Water wash may be used to protect overhead condensers in the main column subjected to fouling from ammonium hydrosulphide.
Critical equipment, including pumps, compressors, furnaces and heat exchangers should be inspected. Inspections should include checking for leaks due to erosion or other malfunctions such as catalyst buildup on the expanders, coking in the overhead feeder lines from feedstock residues, and other unusual operating conditions.
Liquid hydrocarbons in the catalyst or entering the heated combustion air stream can cause exothermic reactions. In some processes, caution must be taken to assure that explosive concentrations of catalyst dust are not present during recharge or disposal. When unloading coked catalyst, the possibility of iron sulphide fires exists. Iron sulphide will ignite spontaneously when exposed to air, and therefore needs to be wetted down with water to prevent it from becoming a source of ignition for vapours. Coked catalyst may either be cooled to below 49 °C before dumping from the reactor, or first dumped into containers purged with inert nitrogen and then cooled before further handling.
The possibility of exposure to extremely hot hydrocarbon liquids or vapours is present during process sampling or if a leak or release occurs. In addition, exposure to carcinogenic PAHs, aromatic naphtha containing benzene, sour gas (fuel gas from processes such as catalytic cracking and hydrotreating, which contains hydrogen sulphide and carbon dioxide), hydrogen sulphide and/or carbon monoxide gas may occur during a release of product or vapour. Inadvertent formation of highly toxic nickel carbonyl may occur in cracking processes that use nickel catalysts with resultant potential for hazardous exposures.
Catalyst regeneration involves steam stripping and decoking, which results in potential exposure to fluid waste streams which may contain varying amounts of sour water, hydrocarbon, phenol, ammonia, hydrogen sulphide, mercaptan and other materials, depending upon the feedstocks, crudes and processes. Safe work practices and the use of appropriate personal protective equipment (PPE) are needed when handling spent catalyst, recharging catalyst, or if leaks or releases occur.
Hydrocracking is a two-stage process combining catalytic cracking and hydrogenation, wherein distillate fractions are cracked in the presence of hydrogen and special catalysts to produce more desirable products. Hydrocracking has an advantage over catalytic cracking in that high-sulphur feedstocks can be processed without previous desulphurization. In the process, heavy aromatic feedstock is converted into lighter products under very high pressures and fairly high temperatures. When the feedstock has a high paraffinic content, the hydrogen prevents the formation of PAHs, reduces tar formation and prevents build-up of coke on the catalyst. Hydrocracking produces relatively large amounts of isobutane for alkylation feedstocks and also causes isomerization for pour point control and smoke point control, both of which are important in high-quality jet fuel.
In the first stage, feedstock is mixed with recycled hydrogen, heated and sent to the primary reactor, where a large amount of the feedstock is converted to middle distillates. Sulphur and nitrogen compounds are converted by a catalyst in the primary stage reactor to hydrogen sulphide and ammonia. The residual is heated and sent to a high-pressure separator, where hydrogen-rich gases are removed and recycled. The remaining hydrocarbons are stripped or purified to remove the hydrogen sulphide, ammonia and light gases, which are collected in an accumulator, where gasoline is separated from sour gas.
The stripped liquid hydrocarbons from the primary reactor are mixed with hydrogen and sent to the second-stage reactor, where they are cracked into high-quality gasoline, jet fuel and distillate blending stocks. These products go through a series of high- and low-pressure separators to remove gases, which are recycled. The liquid hydrocarbons are stabilized, split and stripped, with the light naphtha products from the hydrocracker used to blend gasoline while the heavier naphthas are recycled or sent to a catalytic reformer unit. (See figure 78.11.)
Figure 78.11 Hydrocracking process
Health and safety considerations
Inspection and testing of safety relief devices are important due to the very high pressures in this process. Proper process control is needed to protect against plugging reactor beds. Because of the operating temperatures and presence of hydrogen, the hydrogen sulphide content of the feedstock must be strictly kept to a minimum in order to reduce the possibility of severe corrosion. Corrosion by wet carbon dioxide in areas of condensation must also be considered. When processing high-nitrogen feedstocks, the ammonia and hydrogen sulphide form ammonium hydrosulphide, which causes serious corrosion at temperatures below the water dew point. Ammonium hydrosulphide is also present in sour water stripping. Because the hydrocracker operates at very high pressures and temperatures, control of both hydrocarbon leaks and hydrogen releases is important to prevent fires.
Because this is a closed process, exposures are minimal under normal operating conditions. There is a potential for exposure to aliphatic naphtha containing benzene, carcinogenic PAHs, hydrocarbon gas and vapour emissions, hydrogen-rich gas and hydrogen sulphide gas as a result of high-pressure leaks. Large quantities of carbon monoxide may be released during catalyst regeneration and changeover. Catalyst steam stripping and regeneration creates waste streams containing sour water and ammonia. Safe work practices and appropriate personal protective equipment are needed when handling spent catalyst. In some processes, care is needed to assure that explosive concentrations of catalytic dust do not form during recharging. Unloading coked catalyst requires special precautions to prevent iron sulphideinduced fires. The coked catalyst should either be cooled to below 49 °C before dumping, or placed in nitrogen-inerted containers until cooled.
Two combining processes, polymerization and alkylation, are used to join together small hydrogen-deficient molecules, called olefins, recovered from thermal and catalytic cracking, in order to create more desirable gasoline blending stocks.
Polymerization is the process of combining two or more unsaturated organic molecules (olefins) to form a single, heavier molecule with the same elements in the same proportion as the original molecule. It converts gaseous olefins, such as ethylene, propylene and butylene converted by thermal and fluid cracking units, into heavier, more complex, higher-octane molecules, including naphtha and petrochemical feedstocks. The olefin feedstock is pretreated to remove sulphur compounds and other undesirables, and then passed over a phosphorus catalyst, usually a solid catalyst or liquid phosphoric acid, where an exothermic polymeric reaction occurs. This requires the use of cooling water and the injection of cold feedstock into the reactor to control temperatures at various pressures. Acid in the liquids is removed by caustic wash, the liquids are fractionated, and the acid catalyst is recycled. The vapour is fractionated to remove butanes and neutralized to remove traces of acid. (See figure 78.12.)
Figure 78.12 Polymerization process
Severe corrosion, leading to equipment failure, will occur should water contact the phosphoric acid, such as during water washing at shutdowns. Corrosion may also occur in piping manifolds, reboilers, exchangers and other locations where acid may settle out. There is a potential for exposure to caustic wash (sodium hydroxide), to phosphoric acid used in the process or washed out during turnarounds, and to catalyst dust. The potential for an uncontrolled exothermic reaction exists should loss of cooling water occur.
Alkylation combines the molecules of olefins produced from catalytic cracking with those of isoparaffins in order to increase the volume and octane of gasoline blends. Olefins will react with isoparaffins in the presence of a highly active catalyst, usually sulphuric acid or hydrofluoric acid (or aluminium chloride) to create a long-branched-chain paraffinic molecule, called alkylate (iso-octane), with exceptional anti-knock quality. The alkylate is then separated and fractionated. The relatively low reaction temperatures of 10°C to 16°C for sulphuric acid, 27°C to 0°C for hydrofluoric acid (HF) and 0°C for aluminium chloride, are controlled and maintained by refrigeration. (See figure 78.13.)
Figure 78.13 Alkylation process
Sulphuric acid alkylation. In cascade-type sulphuric acid alkylation units, feedstocks, including propylene, butylene, amylene and fresh isobutane, enter the reactor, where they contact the sulphuric acid catalyst. The reactor is divided into zones, with olefins fed through distributors to each zone, and the sulphuric acid and isobutanes flowing over baffles from zone to zone. Reaction heat is removed by evaporation of isobutane. The isobutane gas is removed from the top of the reactor, cooled and recycled, with a portion directed to the depropanizer tower. Residual from the reactor is settled, and the sulphuric acid is removed from the bottom of the vessel and recirculated. Caustic and/or water scrubbers are used to remove small amounts of acid from the process stream, which then goes to a de-isobutanizer tower. The debutanizer isobutane overhead is recycled, and the remaining hydrocarbons are separated in a rerun tower and/or sent to blending.
Hydrofluoric acid alkylation. There are two types of hydrofluoric acid alkylation processes: Phillips and UOP. In the Phillips process, olefin and isobutane feedstock is dried and fed to a combination reactor/settler unit. The hydrocarbon from the settling zone is charged to the main fractionator. The main fractionator overhead goes to a depropanizer. Propane, with trace amounts of hydrofluoric acid (HF), goes to an HF stripper, and is then catalytically defluorinated, treated and sent to storage. Isobutane is withdrawn from the main fractionator and recycled to the reactor/settler, and alkylate from the bottom of the main fractionator is sent to a splitter.
The UOP process uses two reactors with separate settlers. Half of the dried feedstock is charged to the first reactor, along with recycle and make-up isobutane, and then to its settler, where the acid is recycled and the hydrocarbon charged to the second reactor. The other half of the feedstock goes to the second reactor, with the settler acid being recycled and the hydrocarbons charged to the main fractionator. Subsequent processing is similar to Phillips in that the overhead from the main fractionator goes to a depropanizer, isobutane is recycled and alkylate is sent to a splitter.
Health and safety considerations
Sulphuric acid and hydrofluoric acid are dangerous chemicals, and care during delivery and unloading of acid is essential. There is a need to maintain sulphuric acid concentrations of 85 to 95% for good operation and to minimize corrosion. To prevent corrosion from hydrofluoric acid, acid concentrations inside the process unit must be maintained above 65% and moisture below 4%. Some corrosion and fouling in sulphuric acid units occurs from the breakdown of sulphuric acid esters, or where caustic is added for neutralization. These esters can be removed by fresh-acid treating and hot-water washing.
Upsets can be caused by loss of the coolant water needed to maintain process temperatures. Pressure on the cooling water and steam side of exchangers should be kept below the minimum pressure on the acid service side to prevent water contamination. Vents can be routed to soda ash scrubbers to neutralize hydrogen fluoride gas or hydrofluoric acid vapours before release. Curbs, drainage and isolation may be provided for process unit containment so that effluent can be neutralized before release to the sewer system.
Hydrofluoric acid units should be thoroughly drained and chemically cleaned prior to turnarounds and entry, to remove all traces of iron fluoride and hydrofluoric acid. Following shutdown, where water has been used, the unit should be thoroughly dried before hydrofluoric acid is introduced. Leaks, spills or releases involving hydrofluoric acid, or hydrocarbons containing hydrofluoric acid, are extremely hazardous. Precautions are necessary to assure that equipment and materials which have been in contact with acid are handled carefully and are thoroughly cleaned before they leave the process area or refinery. Immersion wash vats are often provided for neutralization of equipment which has come into contact with hydrofluoric acid.
There is a potential for serious hazardous and toxic exposures should leaks, spills or releases occur. Direct contact with sulphuric or hydrofluoric acid will cause severe skin and eye damage, and inhalation of acid mists or hydrocarbon vapours containing acid will cause severe irritation and damage to the respiratory system. Special precautionary emergency preparedness measures should be used, and protection should be provided that is appropriate to the potential hazard and areas possibly affected. Safe work practices and appropriate skin and respiratory personal protective equipment are needed where potential exposures to hydrofluoric and sulphuric acids during normal operations exist, such as reading gauges, inspecting and process sampling, as well as during emergency response, maintenance and turnaround activities. Procedures should be in place to assure that protective equipment and clothing worn in sulphuric or hydrofluoric acid activities, including chemical protective suits, head and shoe coverings, gloves, face and eye protection and respiratory protective equipment, are thoroughly cleaned and decontaminated before reissue.
Catalytic reforming and isomerization are processes which rearrange hydrocarbon molecules to produce products with different characteristics. After cracking, some gasoline streams, although of the correct molecular size, require further processing to improve their performance, because they are deficient in some qualities, such as octane number or sulphur content. Hydrogen (steam) reforming produces additional hydrogen for use in hydrogenation processing.
Catalytic reforming processes convert low-octane heavy naphthas into aromatic hydrocarbons for petrochemical feedstocks and high-octane gasoline components, called reformates, by molecular rearrangement or dehydrogenation. Depending on the feedstock and catalysts, reformates can be produced with very high concentrations of toluene, benzene, xylene and other aromatics useful in gasoline blending and petrochemical processing. Hydrogen, a significant by-product, is separated from the reformate for recycling and use in other processes. The resultant product depends on reactor temperature and pressure, the catalyst used and the hydrogen recycle rate. Some catalytic reformers operate at low pressure and others at high pressure. Some catalytic reforming systems continuously regenerate the catalyst, some facilities regenerate all of the reactors during turnarounds, and others take one reactor at a time off stream for catalyst regeneration.
In catalytic reforming, naphtha feedstock is pretreated with hydrogen to remove contaminants such as chlorine, sulphur and nitrogen compounds, which could poison the catalyst. The product is flashed and fractionated in towers where the remaining contaminants and gases are removed. The desulphurized naphtha feedstock is sent to the catalytic reformer, where it is heated to a vapour and passed through a reactor with a stationary bed of bi-metallic or metallic catalyst containing a small amount of platinum, molybdenum, rhenium or other noble metals. The two primary reactions which occur are production of high-octane aromatics by removing hydrogen from the feedstock molecules, and the conversion of normal paraffins to branched-chain or isoparaffins.
In platforming, another catalytic reforming process, feedstock which has not been hydrodesulphurized is combined with recycle gas and first passed over a less expensive catalyst. Any remaining impurities are converted to hydrogen sulphide and ammonia, and removed before the stream passes over the platinum catalyst. Hydrogen-rich vapour is recirculated to inhibit reactions which may poison the catalyst. The reactor output is separated into liquid reformate, which is sent to a stripping tower, and gas, which is compressed and recycled. (See figure 78.14.)
Figure 78.14 Catalytic reforming process
Operating procedures are needed to control hot spots during start-up. Care must be taken not to break or crush the catalyst when loading the beds, as small fines will plug up the reformer screens. Precautions against dust when regenerating or replacing catalyst are needed. Small emissions of carbon monoxide and hydrogen sulphide may occur during regeneration of catalyst.
Water wash should be considered where stabilizer fouling has occurred in reformers due to the formation of ammonium chloride and iron salts. Ammonium chloride may form in pretreater exchangers and cause corrosion and fouling. Hydrogen chloride, from the hydrogenation of chlorine compounds, may form acids or ammonium chloride salt. The potential exists for exposure to aliphatic and aromatic naphthas, hydrogen-rich process gas, hydrogen sulphide and benzene should a leak or release occur.
Isomerization converts n-butane, n-pentane and n-hexane into their respective iso-paraffins. Some of the normal straight-chain paraffin components of light straight-run naphtha are low in octane. These can be converted to high-octane, branched-chain isomers by rearranging the bonds between atoms, without changing the number or kinds of atoms. Isomerization is similar to catalytic reforming in that the hydrocarbon molecules are rearranged, but unlike catalytic reforming, isomerization just converts normal paraffins to iso-paraffins. Isomerization uses a different catalyst than catalytic reforming.
The two distinct isomerization processes are butane (C4) and pentane/hexane. (C5/C6).
Butane (C4) isomerization produces feedstock for alkylation. A lower-temperature process uses highly active aluminium chloride or hydrogen chloride catalyst without fired heaters, to isomerize n-butane. The treated and preheated feedstock is added to the recycle stream, mixed with HCl and passed through the reactor (see figure 78.15).
Figure 78.15 C4 isomerization
Pentane/hexane isomerization is used to increase the octane number by converting n-pentane and n-hexane. In a typical pentane/hexane isomerization process, dried and desulphurized feedstock is mixed with a small amount of organic chloride and recycled hydrogen, and heated to reactor temperature. It is then passed over supported-metal catalyst in the first reactor, where benzene and olefins are hydrogenated. The feed next goes to the isomerization reactor, where the paraffins are catalytically isomerized to isoparaffins, cooled and passed to a separator. Separator gas and hydrogen, with make-up hydrogen, is recycled. The liquid is neutralized with alkaline materials and sent to a stripper column, where hydrogen chloride is recovered and recycled. (See figure 78.16.)
Figure 78.16 Isomerization process
If the feedstock is not completely dried and desulphurized, the potential exists for acid formation, leading to catalyst poisoning and metal corrosion. Water or steam must not be allowed to enter areas where hydrogen chloride is present. Precautions are needed to prevent HCl from entering sewers and drains. There is a potential for exposure to isopentane and aliphatic naphtha vapours and liquid, as well as to hydrogen-rich process gas, hydrochloric acid and hydrogen chloride, and to dust when solid catalyst is used.
Hydrogen production (steam reforming)
High-purity hydrogen (95 to 99%) is needed for hydrodesulphurization, hydrogenation, hydrocracking and petrochemical processes. If not enough hydrogen is produced as by-products of refinery processes to meet the total refinery demand, the manufacture of additional hydrogen is required.
In hydrogen steam reforming, desulphurized gases are mixed with superheated steam and reformed in tubes containing a nickel base catalyst. The reformed gas, which consists of steam, hydrogen, carbon monoxide and carbon dioxide, is cooled and passed through converters where the carbon monoxide reacts with steam to form hydrogen and carbon dioxide. The carbon dioxide is scrubbed with amine solutions and vented to the atmosphere when the solutions are reactivated by heating. Any carbon monoxide remaining in the product stream is converted to methane. (See figure 78.17.)
Figure 78.17 Steam reforming process
Inspections and testing must be conducted where the possibility exists for valve failure due to contaminants in the hydrogen. Carryover from caustic scrubbers to prevent corrosion in preheaters must be controlled and chlorides from the feedstock or steam system prevented from entering reformer tubes and contaminating the catalyst. Exposures can result from contamination of condensate by process materials such as caustics and amine compounds, and from excess hydrogen, carbon monoxide and carbon dioxide. The potential exists for burns from hot gases and superheated steam should a release occur.
Miscellaneous refinery processes
Lubricant base stock and wax processes
Lubricating oils and waxes are refined from various fractions of atmospheric and vacuum distillation. With the invention of vacuum distillation, it was discovered that the waxy residuum made a better lubricant than any of the animal fats that were then in use, which was the beginning of modern hydrocarbon lubricant refining technology, whose primary objective is to remove undesirable products, such as asphalts, sulphonated aromatics and paraffinic and iso-paraffinic waxes from the residual fractions in order to produce high-quality lubricants. This is done by a series of processes including de-asphalting, solvent extraction and separation and treatment processes such as dewaxing and hydrofinishing. (See figure 78.18.)
Figure 78.18 Lubricating oil and wax manufacturing process
In extraction processing, reduced crude from the vacuum unit is propane de-asphalted and combined with straight-run lubricating-oil feedstock, preheated and solvent extracted to produce a feedstock called raffinate. In a typical extraction process which uses phenol as the solvent, the feedstock is mixed with phenol in the treating section at temperatures below 204 °C. Phenol is then separated from the raffinate and recycled. The raffinate may then be subjected to another extraction process which uses furfural to separate aromatic compounds from non-aromatic hydrocarbons, producing a lighter-coloured raffinate with improved viscosity index and oxidation and thermal stability.
|LEO: Literacy Education Online|
Writing a Process Essay
What to consider when writing a process essayA process paper either tells the reader how to do something or describes how something is done. As you write your process essay, consider the following:
- What process are you trying to explain? Why is it important?
- Who or what does the process affect?
- Are there different ways of doing the process? If so, what are they?
- Who are the readers? What knowledge do they need to understand this process?
- What skills/equipment are needed for this?
- How long does the process take? Is the outcome always the same?
- How many steps are there in the process?
- Why is each step important?
- What difficulties are involved in each step? How can they be overcome?
- Do any cautions need to be given?
- Does the process have definitions that need to be clarified?
- Are there other processes that are similar and could help illustrate the process that you are writing about?
- If needed, tell what should not be done or why something should be done.
- Process papers are often written in the second person (you), but some teacher prefer that you avoid this. Check with your teacher.
Your responses to these questions and statements should enable you to write an effective process essay.
Suggested transition words to lead readers through your essayProcess essays are generally organized according to time: that is, they begin with the first step in the process and proceed in time until the last step in the process. It's natural, then, that transition words indicate that one step has been completed and a new one will begin. Some common transitional words used in process essays are listed below:
|After a few hours,||Immediately following,|
|At last||In the end,|
|At the same time,||In the future,|
|Before||In the meantime,|
|Before this,||In the meanwhile,|
|Currently,||Last, Last but not least, Lastly,|
|Finally,||Next, Soon after,|
|First, Second, Third, etc.||Previously,|
|First of all,||Simultaneously,|
A Sample Process Essay
Kool-Aid, Oh yeah!
It has been said that Kool-Aid makes the world go 'round. Let it be advised, however, that without the proper tools and directions, the great American beverage is nothing more than an envelope of unsweetened powder. There are five simple steps to create this candy-tasting concoction.
Picking the proper packet of flavoring is the first step in making Kool-Aid. Check the grocer's shelf for a wide variety, ranging from Mountain Berry Punch to Tropical Blue Hawaiian. If it is a difficult decision for you, knock yourself out and buy two. The packets usually run under 65 cents.
After choosing the flavor that best suits your taste buds, the second step is making sure that your kitchen houses some necessary equipment for making the Kool-Aid. Find a two-quart pitcher. Plastic is nice, but glass pitchers allow the liquid to shine through and add festive coloration to any refrigerator shelf. Next, find a long-handled wooden spoon, a one-cup measuring cup, a water faucet that spouts drinkable water, usable white sugar, and an ice cube tray full of ice. Then, you are ready to mix.
Third, grab the left edge of the Kool-Aid packet between your thumb and index finger. With your other hand, begin peeling the upper-left corner until the entire top of the envelope is removed. Next, dump the contents of the envelope into the pitcher. Notice how the powder floats before settling on the bottom of the pitcher. Then, take the measuring cup and scoop two cups of sugar into the pitcher as well. At this point, adding the water is a crucial step. Place the pitcher under the water faucet and slowly turn on the cold water. If the water is turned on too quickly, powder will fly all over when the initial gusts of water hit. After the pitcher is filled within two inches of the top, turn the water off and get prepared to stir. With the wooden spoon submersed three-quarters of the way in the liquid, vigorously stir in a clockwise motion until all of the powder is dissolved. Taste it. If the Kool-Aid is not sweet enough, feel free to add more sugar.
Fourth, when you are finished seasoning the Kool-Aid to your liking, rinse off the spoon and the measuring cup. Take a glass from the cupboard. An eight-ounce glass is usually sufficient. But stronger thirsts might prefer a 32-ounce mug. Add ice and then fill the glass with Kool-Aid. Find a comfortable chair, put your feet up, and drink away. After all, Kool-Aid makes the world go 'round.
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Last update: 28 September 1997