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SECTION IV: CHAPTER 2
PETROLEUM REFINING PROCESSES

Contents:
I.
II.
III.
IV.
 
V.
VI. 		Introduction
Overview of the Petroleum Industry
Petroleum Refining Operations
Description of Petroleum Refining Processes and
Related Health and Safety Considerations
Other Refinery Operations
Bibliography


Appendix IV:2-1. Glossary

  1. INTRODUCTION.

    1. The petroleum industry began with the successful drilling of the first commercial oil well in 1859, and the opening of the first refinery two years later to process the crude into kerosene. The evolution of petroleum refining from simple distillation to today's sophisticated processes has created a need for health and safety management procedures and safe work practices. To those unfamiliar with the industry, petroleum refineries may appear to be complex and confusing places. Refining is the processing of one complex mixture of hydrocarbons into a number of other complex mixtures of hydrocarbons. The safe and orderly processing of crude oil into flammable gases and liquids at high temperatures and pressures using vessels, equipment, and piping subjected to stress and corrosion requires considerable knowledge, control, and expertise.

    2. Safety and health professionals, working with process, chemical, instrumentation, and metallurgical engineers, assure that potential physical, mechanical, chemical, and health hazards are recognized and provisions are made for safe operating practices and appropriate protective measures. These measures may include hard hats, safety glasses and goggles, safety shoes, hearing protection, respiratory protection, and protective clothing such as fire resistant clothing where required. In addition, procedures should be established to assure compliance with applicable regulations and standards such as hazard communications, confined space entry, and process safety management.

    3. This chapter of the technical manual covers the history of refinery processing, characteristics of crude oil, hydrocarbon types and chemistry, and major refinery products and by-products. It presents information on technology as normally practiced in present operations. It describes the more common refinery processes and includes relevant safety and health information. Additional information covers refinery utilities and miscellaneous supporting activities related to hydrocarbon processing. Field personnel will learn what to expect in various facilities regarding typical materials and process methods, equipment, potential hazards, and exposures.

    4. The information presented refers to fire prevention, industrial hygiene, and safe work practices, and is not intended to provide comprehensive guidelines for protective measures and/or compliance with regulatory requirements. As some of the terminology is industry-specific, a glossary is provided as an appendix. This chapter does not cover petrochemical processing.


  2. OVERVIEW OF THE PETROLEUM INDUSTRY.

    1. BASIC REFINERY PROCESS: DESCRIPTION AND HISTORY. Petroleum refining has evolved continuously in response to changing consumer demand for better and different products. The original requirement was to produce kerosene as a cheaper and better source of light than whale oil. The development of the internal combustion engine led to the production of gasoline and diesel fuels. The evolution of the airplane created a need first for high-octane aviation gasoline and then for jet fuel, a sophisticated form of the original product, kerosene. Present-day refineries produce a variety of products including many required as feedstock for the petrochemical industry.

      1. Distillation Processes. The first refinery, 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. Two significant events changed this situation: (1) invention of the electric light decreased the demand for kerosene, and (2) invention of the internal combustion engine created a demand for diesel fuel and gasoline (naphtha).

      2. Thermal Cracking Processes. With the advent of mass production and World War I, the number of gasoline-powered vehicles increased dramatically and the demand for gasoline grew accordingly. However, distillation processes produced only a certain amount of gasoline from crude oil. In 1913, the thermal cracking process was developed, which subjected heavy fuels to both pressure and intense heat, physically breaking the large molecules into smaller ones to produce additional gasoline and distillate fuels. Visbreaking, another form of thermal cracking, was developed in the late 1930's to produce more desirable and valuable products.

      3. Catalytic Processes. Higher-compression gasoline engines required higher-octane gasoline with better antiknock characteristics. The introduction of catalytic cracking and polymerization processes in the mid- to late 1930's met the demand by providing improved gasoline yields and higher octane numbers.

        Alkylation, another catalytic process developed in the early 1940's, produced more high-octane aviation gasoline and petrochemical feedstock for explosives and synthetic rubber. Subsequently, catalytic isomerization was developed to convert hydrocarbons to produce increased quantities of alkylation feedstock. Improved catalysts and process methods such as hydrocracking and reforming were developed throughout the 1960's to increase gasoline yields and improve antiknock characteristics. These catalytic processes also produced hydrocarbon molecules with a double bond (alkenes) and formed the basis of the modern petrochemical industry.

      4. Treatment Processes. Throughout the history of refining, various treatment methods have been used to remove nonhydrocarbons, impurities, and other constituents that adversely affect the properties of finished products or reduce the efficiency of the conversion processes. Treating can involve chemical reaction and/or physical separation. Typical examples of treating are chemical sweetening, acid treating, clay contacting, caustic washing, hydrotreating, drying, solvent extraction, and solvent dewaxing. Sweetening compounds and acids desulfurize crude oil before processing and treat products during and after processing.

        Following the Second World War, various reforming processes 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 sulfur. A number of the more commonly used treating and reforming processes are described in this chapter of the manual.
TABLE IV: 2-1. HISTORY OF REFINING
Year
Process name
Purpose
By-products, etc.
1862 Atmospheric distillation Produce kerosene Naphtha, tar, etc.
1870 Vacuum distillation Lubricants (original)
Cracking feedstocks (1930's)		 Asphalt, residual
coker feedstocks
1913 Thermal cracking Increase gasoline Residual, bunker fuel
1916 Sweetening reduce sulfur & odor Sulfur
1930 Thermal reforming Improve octane number Residual
1932 Hydrogenation Remove sulfur Sulfur
1932 Coking Produce gasoline basestocks Coke
1933 Solvent extraction Improve lubricant viscosity index Aromatics
1935 Solvent dewaxing Improve pour point Waxes
1935 Cat. polymerization Improve gasoline yield
& octane number		 Petrochemical
feedstocks
1937 Catalytic cracking Higher octane gasoline Petrochemical
feedstocks
1939 Visbreaking reduce viscosity Increased distillate,tar
1940 Alkylation Increase gasoline octane & yield High-octane aviation gasoline
1940 Isomerization Produce alkylation feedstock Naphtha
1942 Fluid catalytic cracking Increase gasoline yield & octane Petrochemical feedstocks
1950 Deasphalting Increase cracking feedstock Asphalt
1952 Catalytic reforming Convert low-quality naphtha Aromatics
1954 Hydrodesulfurization Remove sulfur Sulfur
1956 Inhibitor sweetening Remove mercaptan Disulfides
1957 Catalytic isomerization Convert to molecules with high octane number Alkylation feedstocks
1960 Hydrocracking Improve quality and reduce sulfur Alkylation feedstocks
1974 Catalytic dewaxing Improve pour point Wax
1975 Residual hydrocracking Increase gasoline yield from residual Heavy residuals
 
    1. BASICS OF CRUDE OIL.

      1. Crude oils are complex mixtures containing many different hydrocarbon compounds that vary in appearance and composition from one oil field to another. Crude oils range in consistency from water to tar-like solids, and in color from clear to black. An "average" crude oil contains about 84% carbon, 14% hydrogen, 1%-3% sulfur, and less than 1% each of nitrogen, oxygen, metals, and salts. Crude oils are generally classified as paraffinic, naphthenic, or aromatic, based on the predominant proportion of similar hydrocarbon molecules. Mixed-base crudes have varying amounts of each type of hydrocarbon. Refinery crude base stocks usually consist of mixtures of two or more different crude oils.

      2. Relatively simple crude oil assays are used to classify crude oils as paraffinic, naphthenic, aromatic, or mixed. One assay method (United States Bureau of Mines) is based on distillation, and another method (UOP "K" factor) is based on gravity and boiling points. More comprehensive crude assays determine the value of the crude (i.e., its yield and quality of useful products) and processing parameters. Crude oils are usually grouped according to yield structure.

      3. Crude oils are also defined in terms of API (American Petroleum Institute) gravity. The higher the API gravity, the lighter the crude. For example, light crude oils have high API gravities and low specific gravities. Crude oils with low carbon, high hydrogen, and high API gravity are usually rich in paraffins and tend to yield greater proportions of gasoline and light petroleum products; those with high carbon, low hydrogen, and low API gravities are usually rich in aromatics.

      4. Crude oils that contain appreciable quantities of hydrogen sulfide or other reactive sulfur compounds are called "sour." Those with less sulfur are called "sweet." Some exceptions to this rule are West Texas crudes, which are always considered "sour" regardless of their H2S content, and Arabian high-sulfur crudes, which are not considered "sour" because their sulfur compounds are not highly reactive.


      TABLE IV: 2-2. TYPICAL APPROXIMATE CHARACTERISTICS AND
      PROPERTIES AND GASOLINE POTENTIAL OF VARIOUS CRUDES
      (Representative average numbers)
      Crude source
      		Paraffins
      (% vol)
      		Aromatics
      (% vol)
      		Naphthenes
      (% vol)
      		Sulfur
      (% wt)
      		API gravity
      (approx.)
      		Napht. yield
      (% vol)
      		Octane no
      (typical)
      Nigerian
        -Light      		 37 9 54 0.2 36 28 60
      Saudi
        -Light      		 63 19 18 2 34 22 40
      Saudi
        -Heavy      		 60 15 25 2.1 28 23 35
      Venezuela
        -Heavy      		 35 12 53 2.3 30 2 60
      Venezuela
        -Light      		 52 14 34 1.5 24 18 50
      USA
        -Midcont. Sweet      		 - - - 0.4 40 - -
      USA
        -W. Texas Sour      		 46 22 32 1.9 32 33 55
      North Sea
        -Brent      		 50 16 34 0.4 37 31 50


    2. BASICS OF HYDROCARBON CHEMISTRY. Crude oil is a mixture of hydrocarbon molecules, which are organic compounds of carbon and hydrogen atoms that may include from one to 60 carbon atoms. The properties of hydrocarbons depend on the number and arrangement of the carbon and hydrogen atoms in the molecules. The simplest hydrocarbon molecule is one carbon atom linked with four hydrogen atoms: methane. All other variations of petroleum hydrocarbons evolve from this molecule.

      Hydrocarbons containing up to four carbon atoms are usually gases, those with 5 to 19 carbon atoms are usually liquids, and those with 20 or more are solids. The refining process uses 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 their structures and bonding patterns into different hydrocarbon molecules and compounds. Therefore it is the type of hydrocarbon (paraffinic, naphthenic, or aromatic) rather than its specific chemical compounds that is significant in the refining process.

      1. Three Principal Groups or Series of Hydrocarbon Compounds that Occur Naturally in Crude Oil.

        a.  Paraffins. The paraffinic series of hydrocarbon compounds found in crude oil have the general formula CnH2n+2 and can be either straight chains (normal) or branched chains (isomers) of carbon atoms. The lighter, straight-chain paraffin molecules are found in gases and paraffin waxes. Examples of straight-chain molecules are methane, ethane, propane, and butane (gases containing from one to four carbon atoms), and pentane and hexane (liquids with five to six carbon atoms). The branched-chain (isomer) paraffins are usually found in heavier fractions of crude oil and have higher octane numbers than normal paraffins. These compounds are saturated hydrocarbons, with all carbon bonds satisfied, that is, the hydrocarbon chain carries the full complement of hydrogen atoms.

        FIGURE IV:2-1. TYPICAL PARAFFINS.
        Example of simplest
        HC molecule (CH4):        		 Examples of straight chain paraffin molecule (Butane) and branched paraffin molecule (Isobutane) with same chemical formula (C4H10):
        METHANE (CH4) BUTANE (C4H10) ISOBUTANE (C4H10)
        molecular structure molecular structure molecular structure


        b.  Aromatics are unsaturated ring-type (cyclic) compounds which react readily because they have carbon atoms that are deficient in hydrogen. All aromatics have at least one benzene ring (a single-ring compound characterized by three double bonds alternating with three single bonds between six carbon atoms) as part of their molecular structure. Naphthalenes are fused double-ring aromatic compounds. The most complex aromatics, polynuclears (three or more fused aromatic rings), are found in heavier fractions of crude oil.

        c.  Naphthenes are saturated hydrocarbon groupings with the general formula CnH2n, arranged in the form of closed rings (cyclic) and found in all fractions of crude oil except the very lightest. Single-ring naphthenes (monocycloparaffins) with five and six carbon atoms predominate, with two-ring naphthenes (dicycloparaffins) found in the heavier ends of naphtha.

      2. Other Hydrocarbons.

        a.  Alkenes are mono-olefins with the general formula CnH2n and contain only one carbon-carbon double bond in the chain. The simplest alkene is ethylene, with two carbon atoms joined by a double bond and four hydrogen atoms. Olefins are usually formed by thermal and catalytic cracking and rarely occur naturally in unprocessed crude oil.

        FIGURE IV:2-2. TYPICAL AROMATICS.
        Example of simple aromatic compound: Examples of simple double-ring aromatic compound:
        BENZENE (C6H6) NAPTHALENE (C10H8)
        molecular structure molecular structure


        FIGURE IV:2-3. TYPICAL NAPHTHENES.
        Example of typical single-ring naphthene: Examples of naphthene with same chemical formula (C6H12) but different molecular structure:
        CYCLOHEXANE (C6H12) METHYL CYCLOPENTANE (C6H12)
        molecular structure molecular structure


        FIGURE IV:2-4. TYPICAL ALKENES.
        Simplest Alkene (C2H4): Typical Alkenes with the same chemical formula (C4H8) but different molecular structures:
        ETHYLENE (C2H4) 1-BUTENE (C4H8) ISOBUTENE (C4H8)
        molecular structure molecular structure molecular structure


        b.  Dienes and Alkynes. Dienes, also known as diolefins, have two carbon-carbon double bonds. The alkynes, another class of unsaturated hydrocarbons, have a carbon-carbon triple bond within the molecule. Both these series of hydrocarbons have the general formula CnH2n-2. Diolefins such as 1,2-butadiene and 1,3-butadiene, and alkynes such as acetylene, occur in C5 and lighter fractions from cracking. The olefins, diolefins, and alkynes are said to be unsaturated because they contain less than the amount of hydrogen necessary to saturate all the valences of the carbon atoms. These compounds are more reactive than paraffins or naphthenes and readily combine with other elements such as hydrogen, chlorine, and bromine.

        FIGURE IV:2-5. TYPICAL DIOLEFINS AND ALKYNES.
        Simplest Alkyne: (C2H2): Typical Diolefins with the same chemical formula (C4H6) but different molecular structures:
        ACETYLENE (C2H2) 1,2-BUTADIENE (C4H6) 1,3-BUTADIENE (C4H6)
        molecular structure molecular structure molecular structure


      3. Nonhydrocarbons.

        a.  Sulfur Compounds. Sulfur may be present in crude oil as hydrogen sulfide (H2S), as compounds (e.g. mercaptans, sulfides, disulfides, thiophenes, etc.) or as elemental sulfur. Each crude oil has different amounts and types of sulfur compounds, but as a rule the proportion, stability, and complexity of the compounds are greater in heavier crude-oil fractions. Hydrogen sulfide is a primary contributor to corrosion in refinery processing units. Other corrosive substances are elemental sulfur and mercaptans. Moreover, the corrosive sulfur compounds have an obnoxious odor.

        Pyrophoric iron sulfide results from the corrosive action of sulfur compounds on the iron and steel used in refinery process equipment, piping, and tanks. The combustion of petroleum products containing sulfur compounds produces undesirables such as sulfuric acid and sulfur dioxide. Catalytic hydrotreating processes such as hydrodesulfurization remove sulfur compounds from refinery product streams. Sweetening processes either remove the obnoxious sulfur compounds or convert them to odorless disulfides, as in the case of mercaptans.

        b.  Oxygen Compounds. Oxygen compounds such as phenols, ketones, and carboxylic acids occur in crude oils in varying amounts.

        c.  Nitrogen Compounds. Nitrogen is found in lighter fractions of crude oil as basic compounds, and more often in heavier fractions of crude oil as nonbasic compounds that may also include trace metals such as copper, vanadium, and/or nickel. Nitrogen oxides can form in process furnaces. The decomposition of nitrogen compounds in catalytic cracking and hydrocracking processes forms ammonia and cyanides that can cause corrosion.

        d.  Trace Metals. Metals, including nickel, iron, and vanadium are often found in crude oils in small quantities and are removed during the refining process. Burning heavy fuel oils in refinery furnaces and boilers can leave deposits of vanadium oxide and nickel oxide in furnace boxes, ducts, and tubes. It is also desirable to remove trace amounts of arsenic, vanadium, and nickel prior to processing as they can poison certain catalysts.

        e.  Salts. Crude oils often contain inorganic salts such as sodium chloride, magnesium chloride, and calcium chloride in suspension or dissolved in entrained water (brine). These salts must be removed or neutralized before processing to prevent catalyst poisoning, equipment corrosion, and fouling. Salt corrosion is caused by the hydrolysis of some metal chlorides to hydrogen chloride (HCl) and the subsequent formation of hydrochloric acid when crude is heated. Hydrogen chloride may also combine with ammonia to form ammonium chloride (NH4Cl), which causes fouling and corrosion.

        f.  Carbon Dioxide. Carbon dioxide may result from the decomposition of bicarbonates present in or added to crude, or from steam used in the distillation process.

        g.  Naphthenic Acids. Some crude oils contain naphthenic (organic) acids, which may become corrosive at temperatures above 450° F when the acid value of the crude is above a certain level.


    3. MAJOR REFINERY PRODUCTS.

      1. Gasoline. The most important refinery product is motor gasoline, a blend of hydrocarbons with boiling ranges from ambient temperatures to about 400 °F. The important qualities for gasoline are octane number (antiknock), volatility (starting and vapor lock), and vapor pressure (environmental control). Additives are often used to enhance performance and provide protection against oxidation and rust formation.

      2. Kerosene. Kerosene is a refined middle-distillate petroleum product that finds considerable use as a jet fuel and around the world in cooking and space heating. When used as a jet fuel, some of the critical qualities are freeze point, flash point, and smoke point. Commercial jet fuel has a boiling range of about 375°-525° F, and military jet fuel 130°-550° F. Kerosene, with less-critical specifications, is used for lighting, heating, solvents, and blending into diesel fuel.

      3. Liquified Petroleum Gas (LPG). LPG, which consists principally of propane and butane, is produced for use as fuel and is an intermediate material in the manufacture of petrochemicals. The important specifications for proper performance include vapor pressure and control of contaminants.

      4. Distillate Fuels. Diesel fuels and domestic heating oils have boiling ranges of about 400°-700° F. The desirable qualities required for distillate fuels include controlled flash and pour points, clean burning, no deposit formation in storage tanks, and a proper diesel fuel cetane rating for good starting and combustion.

      5. Residual Fuels. Many marine vessels, power plants, commercial buildings and industrial facilities use residual fuels or combinations of residual and distillate fuels for heating and processing. The two most critical specifications of residual fuels are viscosity and low sulfur content for environmental control.

      6. Coke and Asphalt. Coke is almost pure carbon with a variety of uses from electrodes to charcoal briquets. Asphalt, used for roads and roofing materials, must be inert to most chemicals and weather conditions.

      7. Solvents. A variety of products, whose boiling points and hydrocarbon composition are closely controlled, are produced for use as solvents. These include benzene, toluene, and xylene.

      8. Petrochemicals. Many products derived from crude oil refining, such as ethylene, propylene, butylene, and isobutylene, are primarily intended for use as petrochemical feedstock in the production of plastics, synthetic fibers, synthetic rubbers, and other products.

      9. Lubricants. Special refining processes produce lubricating oil base stocks. Additives such as demulsifiers, antioxidants, and viscosity improvers are blended into the base stocks to provide the characteristics required for motor oils, industrial greases, lubricants, and cutting oils. The most critical quality for lubricating-oil base stock is a high viscosity index, which provides for greater consistency under varying temperatures.


    4. COMMON REFINERY CHEMICALS.

      1. Leaded Gasoline Additives. Tetraethyl lead (TEL) and tetramethyl lead (TML) are additives formerly used to improve gasoline octane ratings but are no longer in common use except in aviation gasoline.

      2. Oxygenates. Ethyl tertiary butyl ether (ETBE), methyl tertiary butyl ether (MTBE), tertiary amyl methyl ether (TAME), and other oxygenates improve gasoline octane ratings and reduce carbon monoxide emissions.

      3. Caustics. Caustics are added to desalting water to neutralize acids and reduce corrosion. They are also added to desalted crude in order to reduce the amount of corrosive chlorides in the tower overheads. They are used in some refinery treating processes to remove contaminants from hydrocarbon streams.

      4. Sulfuric Acid and Hydrofluoric Acid. Sulfuric acid and hydrofluoric acid are used primarily as catalysts in alkylation processes. Sulfuric acid is also used in some treatment processes.
         
  1. PETROLEUM REFINING OPERATIONS.

    1. INTRODUCTION. 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 processed. Most distillation products are further converted into more usable products by changing the size and structure of the hydrocarbon molecules through cracking, reforming, and other conversion processes as discussed in this chapter. These converted products are then subjected to various treatment and separation processes such as extraction, hydrotreating, and sweetening to remove undesirable constituents and improve product quality. Integrated refineries incorporate fractionation, conversion, treatment, and blending operations and may also include petrochemical processing.

    2. REFINING OPERATIONS. Petroleum refining processes and operations can be separated into five basic areas:

      1. Fractionation (distillation) is the separation of crude oil in atmospheric and vacuum distillation towers into groups of hydrocarbon compounds of differing boiling-point ranges called "fractions" or "cuts."

      2. Conversion processes change the size and/or structure of hydrocarbon molecules. These processes include:

        • Decomposition (dividing) by thermal and catalytic cracking;
        • Unification (combining) through alkylation and polymerization; and
        • Alteration (rearranging) with isomerization and catalytic reforming.

      3. Treatment processes are intended to prepare hydrocarbon streams for additional processing and to prepare finished products. Treatment may include the removal or separation of aromatics and naphthenes as well as impurities and undesirable contaminants. Treatment may involve chemical or physical separation such as dissolving, absorption, or precipitation using a variety and combination of processes including desalting, drying, hydrodesulfurizing, solvent refining, sweetening, solvent extraction, and solvent dewaxing.

      4. Formulating and Blending is the process of mixing and combining hydrocarbon fractions, additives, and other components to produce finished products with specific performance properties.

      5. Other Refining Operations include: light-ends recovery; sour-water stripping; solid waste and wastewater treatment; process-water treatment and cooling; storage and handling; product movement; hydrogen production; acid and tail-gas treatment; and sulfur recovery.

        Auxiliary operations and facilities include: steam and power generation; process and fire water systems; flares and relief systems; furnaces and heaters; pumps and valves; supply of steam, air, nitrogen, and other plant gases; alarms and sensors; noise and pollution controls; sampling, testing, and inspecting; and laboratory, control room, maintenance, and administrative facilities.

    FIGURE IV:2-6. REFINERY PROCESS CHART.

    FIGURE IV:2-6. REFINERY PROCESS CHART.
TABLE IV:2-3. OVERVIEW OF PETROLEUM REFINING PROCESSES.
Process name
Action
Method
Purpose
Feedstock(s)
Product(s)
FRACTIONATION PROCESSES
Atmospheric distillation Separation Thermal Separate fractions Desalted crude oil Gas, gas oil, distillate, residual
Vacuum distillation Separation Thermal Separate w/o cracking Atmospheric tower residual Gas oil, lube stock, residual
CONVERSION PROCESSED--DECOMPOSITION
Catalytic cracking Alteration Catalytic Upgrade gasoline Gas oil, coke distillate Gasoline, petrochemical feedstock
Coking Polymerize Thermal Convert vacuum residuals Gas oil, coke distillate Gasoline, petrochemical feedstock
Hydro-cracking Hydrogenate Catalytic Convert to lighter HC's Gas oil, cracked oil, residual Lighter, higher-quality products
*Hydrogen steam reforming Decompose Thermal/ catalytic Produce hydrogen Desulfurized gas, O2, steam Hydrogen, CO, CO2
*Steam cracking Decompose Thermal Crack large molecules Atm tower hvy fuel/ distillate Cracked naphtha, coke, residual
Visbreaking Decompose Thermal reduce viscosity Atmospheric tower residual Distillate, tar
CONVERSION PROCESSES--UNIFICATION
Alkylation Combining Catalytic Unite olefins & isoparaffins Tower isobutane/ cracker olefin Iso-octane (alkylate)
Grease compounding Combining Thermal Combine soaps & oils Lube oil, fatty acid, alky metal Lubricating grease
Polymerizing Polymerize Catalytic Unite 2 or more olefins Cracker olefins High-octane naphtha, petrochemical stocks
CONVERSION PROCESSES--ALTERATION OR REARRANGEMENT
Catalytic reforming Alteration/
dehydration		 Catalytic Upgrade low-octane naphtha Coker/ hydro-cracker naphtha High oct. Reformate/ aromatic
Isomerization Rearrange Catalytic Convert straight chain to branch Butane, pentane, hexane Isobutane/ pentane/ hexane
TREATMENT PROCESSES
*Amine treating Treatment Absorption Remove acidic contaminants Sour gas, HCs w/CO2 & H2S Acid free gases & liquid HCs
Desalting Dehydration Absorption Remove contaminants Crude oil Desalted crude oil
Drying & sweetening Treatment Abspt/ therm Remove H2O & sulfur cmpds Liq Hcs, LPG, alky feedstk Sweet & dry hydrocarbons
*Furfural extraction Solvent extr. Absorption Upgrade mid distillate & lubes Cycle oils & lube feed-stocks High quality diesel & lube oil
Hydrodesulfurization Treatment Catalytic Remove sulfur, contaminants High-sulfur residual/ gas oil Desulfurized olefins
Hydrotreating Hydrogenation Catalytic Remove impurities, saturate HC's Residuals, cracked HC's Cracker feed, distillate, lube
*Phenol extraction Solvent extr. Abspt/ therm Improve visc. index, color Lube oil base stocks High quality lube oils
Solvent deasphalting Treatment Absorption Remove asphalt Vac. tower residual, propane Heavy lube oil, asphalt
Solvent dewaxing Treatment Cool/ filter Remove wax from lube stocks Vac. tower lube oils Dewaxed lube basestock
Solvent extraction Solvent extr. Abspt/ precip. Separate unsat. oils Gas oil, reformate, distillate High-octane gasoline
Sweetening Treatment Catalytic Remv H2S, convert mercaptan Untreated distillate/gasoline High-quality distillate/gasoline
* Note: These processes are not depicted in the refinery process flow chart.

  1. DESCRIPTION OF PETROLEUM REFINING PROCESSES AND RELATED HEALTH AND SAFETY CONSIDERATIONS.

    1. CRUDE OIL PRETREATMENT (DESALTING).

      1. Description.

        a.  Crude oil often contains water, inorganic salts, suspended solids, and water-soluble trace metals. As a first step in the refining process, to reduce corrosion, plugging, and fouling of equipment and to prevent poisoning the catalysts in processing units, these contaminants must be removed by desalting (dehydration).

        b.  The two most typical methods of crude-oil desalting, chemical and electrostatic separation, use hot water as the extraction agent. In chemical desalting, water and chemical surfactant (demulsifiers) are added to the crude, heated so that salts and other impurities dissolve into the water or attach to the water, and then held in a tank where they settle out. Electrical desalting is the application of high-voltage electrostatic charges to concentrate suspended water globules in the bottom of the settling tank. Surfactants are added only when the crude has a large amount of suspended solids. Both methods of desalting are continuous. A third and less-common process involves filtering heated crude using diatomaceous earth.

        c.  The feedstock crude oil is heated to between 150° and 350°F to reduce viscosity and surface tension for easier mixing and separation of the water. The temperature is limited by the vapor pressure of the crude-oil feedstock. In both methods other chemicals may be added. Ammonia is often used to reduce corrosion. Caustic or acid may be added to adjust the pH of the water wash. Wastewater and contaminants are discharged from the bottom of the settling tank to the wastewater treatment facility. The desalted crude is continuously drawn from the top of the settling tanks and sent to the crude distillation (fractionating) tower.

        TABLE IV:2-4. DESALTING PROCESS.
        Feedstock From Process Typical products . . . To
        Crude Storage Treating Desalted crude . . .  Atmospheric distillation tower
        Waste water . . . . . Treatment


        FIGURE IV:2-7. ELECTROSTAITC DESALTING.
        FIGURE IV:2-7. ELECTROSTAITC DESALTING.


      2. Health and Safety Considerations.

        a.  Fire Prevention and Protection. The potential exists for a fire due to a leak or release of crude from heaters in the crude desalting unit. Low boiling point components of crude may also be released if a leak occurs.

        b.  Safety. Inadequate desalting can cause fouling of heater tubes and heat exchangers throughout the refinery. Fouling restricts product flow and heat transfer and leads to failures due to increased pressures and temperatures. Corrosion, which occurs due to the presence of hydrogen sulfide, hydrogen chloride, naphthenic (organic) acids, and other contaminants in the crude oil, also causes equipment failure. Neutralized salts (ammonium chlorides and sulfides), when moistened by condensed water, can cause corrosion. Overpressuring the unit is another potential hazard that causes failures.

        c.  Health. Because this is a closed process, there is little potential for exposure to crude oil unless a leak or release occurs. Where elevated operating temperatures are used when desalting sour crudes, hydrogen sulfide will be present. There is the possibility of exposure to ammonia, dry chemical demulsifiers, caustics, and/or acids during this operation. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as heat, and during process sampling, inspection, maintenance, and turnaround activities.

        Depending on the crude feedstock and the treatment chemicals used, the wastewater will contain varying amounts of chlorides, sulfides, bicarbonates, ammonia, hydrocarbons, phenol, and suspended solids. If diatomaceous earth is used in filtration, exposures should be minimized or controlled. Diatomaceous earth can contain silica in very fine particle size, making this a potential respiratory hazard.


    2. CRUDE OIL DISTILLATION (FRACTIONATION).

      1. Description. The first step in the refining process is the separation of crude oil into various fractions or straight-run cuts by distillation in atmospheric and vacuum towers. The main fractions or "cuts" obtained have specific boiling-point ranges and can be classified in order of decreasing volatility into gases, light distillates, middle distillates, gas oils, and residuum.

      2. Atmospheric Distillation Tower.

        a.  At the refinery, the desalted crude feedstock is preheated using recovered process heat. The feedstock 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 atmospheric and at temperatures ranging from 650° to 700° F (heating crude oil above these temperatures may cause undesirable thermal cracking). All but the heaviest fractions flash into vapor. As the hot vapor rises in the tower, its temperature is reduced. Heavy fuel oil or asphalt residue is taken from the bottom. At successively higher points on the tower, the various major products including lubricating oil, heating oil, kerosene, gasoline, and uncondensed gases (which condense at lower temperatures) are drawn off.

        b.  The fractionating tower, a steel cylinder about 120 feet high, contains horizontal steel trays for separating and collecting the liquids. At each tray, vapors from below enter perforations and bubble caps. They permit the vapors to bubble through the liquid on the tray, causing some condensation at the temperature of that tray. An overflow pipe drains the condensed liquids from each tray back to the tray below, where the higher temperature causes re-evaporation. The evaporation, condensing, and scrubbing operation is repeated many times until the desired degree of product purity is reached. Then side streams from certain trays are taken off to obtain the desired fractions. Products ranging from uncondensed fixed gases at the top to heavy fuel oils at the bottom can be taken continuously from a fractionating tower. Steam is often used in towers to lower the vapor pressure and create a partial vacuum. The distillation process separates the major constituents of crude oil into so-called straight-run products. Sometimes crude oil is "topped" by distilling off only the lighter fractions, leaving a heavy residue that is often distilled further under high vacuum.

        TABLE IV:2-5. ATMOSPHERIC DISTILLATION PROCESS
        Feedstock From Process Typical products . . . . . . To
        Crude Desalting Separation Gases . . . . . . . . . . . Atmospheric distillation tower
              Naphthas. . . . . . . . . . . . Reforming or treating
        Kerosene or distillates . . Treating
        Gas oil . . . . . . . . . . . . . Catalytic cracking
        Residual . . . . . . . . .   Vacuum tower or visbreaker


        FIGURE IV:2-8. ATMOSPHERIC DISTILLATION.
        FIGURE IV:2-8. ATMOSPHERIC DISTILLATION.


      3. Vacuum Distillation Tower. In order to further distill the residuum or topped crude from the atmospheric tower at higher temperatures, reduced pressure is required to prevent thermal cracking. The process takes place in one or more vacuum distillation towers. The principles of vacuum distillation resemble those of fractional distillation and, except that larger-diameter columns are used to maintain comparable vapor velocities at the reduced pressures, the equipment is also similar. The internal designs of some vacuum towers are different from atmospheric towers in that random packing and demister pads are used instead of trays. 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 lower vacuum may distill 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 cracking feedstock from surplus residuum.

      4. Other Distillation Towers (Columns). Within refineries there are numerous other, smaller distillation towers called columns, designed to separate specific and unique products. Columns all work on the same principles as the towers described above. For example, a depropanizer is a small column designed to separate propane and lighter gases from butane and heavier components. Another larger column is used to separate ethyl benzene and xylene. Small "bubble" towers called strippers use steam to remove trace amounts of light products from heavier product streams.

      5. Health and Safety Considerations.

        a.  Fire Prevention and Protection. Even though these are closed processes, heaters and exchangers in the atmospheric and vacuum distillation units could provide a source of ignition, and the potential for a fire exists should a leak or release occur.

        b.  Safety. An excursion in pressure, temperature, or liquid levels may occur if automatic control devices fail. Control of temperature, pressure, and reflux within operating parameters is needed to prevent thermal cracking within the distillation towers. Relief systems should be provided for overpressure and operations monitored to prevent crude from entering the reformer charge.

        The sections of the process susceptible to corrosion include (but may not be limited to) preheat exchanger (HCl and H2S), preheat furnace and bottoms exchanger (H2S and sulfur compounds), atmospheric tower and vacuum furnace (H2S, sulfur compounds, and organic acids), vacuum tower (H2S and organic acids), and overhead (H2S, HCl, and water). Where sour crudes are processed, severe corrosion can occur in furnace tubing and in both atmospheric and vacuum towers where metal temperatures exceed 450° F. Wet H2S also will cause cracks in steel. When processing high-nitrogen crudes, nitrogen oxides can form in the flue gases of furnaces. Nitrogen oxides are corrosive to steel when cooled to low temperatures in the presence of water.

        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 and cause serious corrosion. Crude feedstock may contain appreciable amounts of water in suspension which can separate during startup and, along with water remaining in the tower from steam purging, settle in the bottom of the tower. This water can be heated to the boiling point and create an instantaneous vaporization explosion upon contact with the oil in the unit.

        c.  Health. Atmospheric and vacuum distillation are closed processes and exposures are expected to be minimal. When sour (high-sulfur) crudes are processed, there is potential for exposure to hydrogen sulfide in the preheat exchanger and furnace, tower flash zone and overhead system, vacuum furnace and tower, and bottoms exchanger. Hydrogen chloride may be present in the preheat exchanger, tower top zones, and overheads. Wastewater may contain water-soluble sulfides in high concentrations and other water-soluble compounds such as ammonia, chlorides, phenol, mercaptans, etc., depending upon the crude feedstock and the treatment chemicals. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as heat and noise, and during sampling, inspection, maintenance, and turnaround activities.

        TABLE IV:2-6. VACUUM DISTILLATION PROCESS
        Feedstock   From   Process   Typical products . . To
        Residuals Atmospheric tower Separation Gas oils . . . . . . . . Catalytic cracker
              Lubricants . . .   Hydrotreating or solvent
        Residual . . . Deasphalter, visbreaker, or coker


        FIGURE IV:2-9. VACUUM DISTILLATION.
        FIGURE IV:2-9. VACUUM DISTILLATION.



    1. SOLVENT EXTRACTION AND DEWAXING.

      1. Description. Solvent treating is a widely used method of refining lubricating oils as well as a host of other refinery stocks. Since distillation (fractionation) separates petroleum products into groups only by their boiling-point ranges, impurities may remain. These include organic compounds containing sulfur, nitrogen, and oxygen; inorganic salts and dissolved metals; and soluble salts that were present in the crude feedstock. In addition, kerosene and distillates may have trace amounts of aromatics and naphthenes, and lubricating oil base-stocks may contain wax. Solvent refining processes including solvent extraction and solvent dewaxing usually remove these undesirables at intermediate refining stages or just before sending the product to storage.

      2. Solvent Extraction.

        a.  The purpose of solvent extraction is to prevent corrosion, protect catalyst in subsequent processes, and improve finished products by removing unsaturated, aromatic hydrocarbons from lubricant and grease stocks. The solvent extraction process separates aromatics, naphthenes, and impurities from the product stream by dissolving or precipitation. The feedstock is first dried and then treated using a continuous countercurrent solvent treatment operation. In one type of process, the feedstock is washed with a liquid in which the substances to be removed are more soluble than in the desired resultant product. In another process, selected solvents are added to cause impurities to precipitate out of the product. In the adsorption process, highly porous solid materials collect liquid molecules on their surfaces.

        b.  The solvent is separated from the product stream by heating, evaporation, or fractionation, and residual trace amounts are subsequently removed from the raffinate by steam stripping or vacuum flashing. Electric precipitation may be used for separation of inorganic compounds. The solvent is then regenerated to be used again in the process.

        c.  The most widely used extraction solvents are phenol, furfural, and cresylic acid. Other solvents less frequently used are liquid sulfur dioxide, nitrobenzene, and 2,2'-dichloroethyl ether. The selection of specific processes and chemical agents depends on the nature of the feedstock being treated, the contaminants present, and the finished product requirements.

        TABLE IV:2-7. SOLVENT EXTRACTION PROCESS
        Feedstock From Process Typical products . . . To
        Naphthas, distillates, kerosene Atm. tower Treating/ blending High octane gasoline . . Storage
        Refined fuels . . . . . . . . Treating and blending
        Spent agents . . . . . . . . Treatment and blending


        FIGURE IV:2-10. AROMATICS EXTRACTION.
        FIGURE IV:2-10. AROMATICS EXTRACTION.


      3. Solvent Dewaxing. Solvent dewaxing is used to remove wax from either distillate or residual basestocks at any stage in the refining process. There are several processes in use for solvent dewaxing, but all have the same general steps, which are: (1) mixing the feedstock with a solvent, (2) precipitating the wax from the mixture by chilling, and (3) recovering the solvent from the wax and dewaxed oil for recycling by distillation and steam stripping. Usually two solvents are used: toluene, which dissolves the oil and maintains fluidity at low temperatures, and methyl ethyl ketone (MEK), which dissolves little wax at low temperatures and acts as a wax precipitating agent. Other solvents that are sometimes used include benzene, methyl isobutyl ketone, propane, petroleum naphtha, ethylene dichloride, methylene chloride, and sulfur dioxide. In addition, there is a catalytic process used as an alternate to solvent dewaxing.

TABLE IV:2-8. SOLVENT DEWAXING PROCESS
Feedstock   From   Process   Typical products . .   To
Lube basestock Vacuum tower Treating Dewaxed lubes . . . . . Hydrotreating
Wax . . . . . . . . . . . . . Hydrotreating
Spent agents . . . . . .   Treatment or recycle


FIGURE IV:2-11. SOLVENT DEWAXING.
FIGURE IV:2-11. SOLVENT DEWAXING.
Note: Diagrams in Figures IV:2-10, 11, 12, 13, 15, and 20 reproduced with permission from Shell International Petroleum Company.
 
      1. Health and Safety Considerations.

        a.  Fire Prevention and Protection. Solvent treatment is essentially a closed process and, although operating pressures are relatively low, the potential exists for fire from a leak or spill contacting a source of ignition such as the drier or extraction heater. In solvent dewaxing, disruption of the vacuum will create a potential fire hazard by allowing air to enter the unit.

        b.  Health. Because solvent extraction is a closed process, exposures are expected to be minimal under normal operating conditions. However, there is a potential for exposure to extraction solvents such as phenol, furfural, glycols, methyl ethyl ketone, amines, and other process chemicals. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as noise and heat, and during repair, inspection, maintenance, and turnaround activities.

    1. THERMAL CRACKING.

      1. Description.

        a.  Because the simple distillation of crude oil produces amounts and types of products that are not consistent with those required by the marketplace, subsequent refinery processes change the product mix by altering the molecular structure of the hydrocarbons. One of the ways of accomplishing this change is through "cracking," a process that breaks or cracks the heavier, higher boiling-point petroleum fractions into more valuable products such as gasoline, fuel oil, and gas oils. The two basic types of cracking are thermal cracking, using heat and pressure, and catalytic cracking.

        b.  The first thermal cracking process was developed around 1913. Distillate fuels and heavy oils were heated under pressure in large drums until they cracked into smaller molecules with better antiknock characteristics. However, this method produced large amounts of solid, unwanted coke. This early process has evolved into the following applications of thermal cracking: visbreaking, steam cracking, and coking.

      2. Visbreaking Process. Visbreaking, a mild form of thermal cracking, significantly lowers the viscosity of heavy crude-oil residue without affecting the boiling point range. Residual from the atmospheric distillation tower is heated (800°-950° F) at atmospheric pressure and mildly cracked in a heater. It is then quenched with cool gas oil to control overcracking, and flashed in a distillation tower. Visbreaking is used to reduce the pour point of waxy residues and reduce the viscosity of residues used for blending with lighter fuel oils. Middle distillates may also be produced, depending on product demand. The thermally cracked residue tar, which accumulates in the bottom of the fractionation tower, is vacuum flashed in a stripper and the distillate recycled.

        TABLE IV:2-9. VISBREAKING PROCESS.
        Feedstock From Process Typical products . . . . . To
        Residual Atmospheric tower & Vacuum tower Decompose Gasoline or distillate . . Hydrotreating
        Vapor . . . . . . . . . . . .  Hydrotreater
        Residue . . . . . . . . . . . Stripper or recycle
        Gases . . . . . . . . . . . . Gas plant


        FIGURE IV:2-12. VISBREAKING.
        FIGURE IV:2-12. VISBREAKING.


      3. Steam Cracking Process. Steam cracking is a petrochemical process sometimes used in refineries to produce olefinic raw materials (e.g., ethylene) from various feedstock for petrochemicals manufacture. The feedstock range from ethane to vacuum gas oil, with heavier feeds giving higher yields of by-products such as naphtha. The most common feeds are ethane, butane, and naphtha. Steam cracking is carried out at temperatures of 1,500°-1,600° F, and at pressures slightly above atmospheric. Naphtha produced from steam cracking contains benzene, which is extracted prior to hydrotreating. Residual from steam cracking is sometimes blended into heavy fuels.

      4. Coking Processes. Coking is a severe method of thermal cracking used to upgrade heavy residuals into lighter products or distillates. Coking produces straight-run gasoline (coker naphtha) and various middle-distillate fractions used as catalytic cracking feedstock. The process so completely reduces hydrogen that the residue is a form of carbon called "coke." The two most common processes are delayed coking and continuous (contact or fluid) coking. Three typical types of coke are obtained (sponge coke, honeycomb coke, and needle coke) depending upon the reaction mechanism, time, temperature, and the crude feedstock.

        a.  Delayed Coking. In delayed coking the heated charge (typically residuum from atmospheric distillation towers) is transferred to large coke drums which provide the long residence time needed to allow the cracking reactions to proceed to completion. Initially the heavy feedstock is fed to a furnace which heats the residuum to high temperatures (900°-950° F) at low pressures (25-30 psi) and is designed and controlled to prevent premature coking in the heater tubes. The mixture is passed from the heater to one or more coker drums where the hot material is held approximately 24 hours (delayed) at pressures of 25-75 psi, until it cracks into lighter products. Vapors from the drums are returned to a fractionator where gas, naphtha, and gas oils are separated out. The heavier hydrocarbons produced in the fractionator are recycled through the furnace.

        After the coke reaches a predetermined level in one drum, the flow is diverted to another drum to maintain continuous operation. The full drum is steamed to strip out uncracked hydrocarbons, cooled by water injection, and decoked by mechanical or hydraulic methods. The coke is mechanically removed by an auger rising from the bottom of the drum. Hydraulic decoking consists of fracturing the coke bed with high-pressure water ejected from a rotating cutter.

        b.  Continuous Coking. Continuous (contact or fluid) coking is a moving-bed process that operates at temperatures higher 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, at a pressure of 50 psi. Gases and vapors are taken from the reactor, quenched to stop any 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 as product. The remaining coke is dropped into the preheater for recycling with feedstock. Coking occurs both in the reactor and in the surge drum. The process is automatic in that there is a continuous flow of coke and feedstock.

      TABLE IV: 2-10. COKING PROCESSES.
      Feedstock From Process Typical products . . . To
      Residual . . . . Atmospheric & vacuum catalytic cracker Decompo-
      sition      		 Naphtha, gasoline . . Distillation column,blending
      Clarified oil . .
      Tars . . . . . .
      Wasteater
      (sour) . . . . .
      Gases . . . . .      		 Catalytic cracker
      Various units

      Treatment
      Gas plant      		   Coke . . . . . . . . . . . Shipping, recycle
      Gas oil . . . . . . . . . . Catalytic cracking


      FIGURE IV:2-13. DELAYED COKING.
      FIGURE IV:2-13. DELAYED COKING.


      1. Health and Safety Considerations.

        a.  Fire Protection and Prevention. Because thermal cracking is a closed process, the primary potential for fire is from leaks or releases of liquids, gases, or vapors reaching an ignition source such as a heater. The potential for fire is present in coking operations due to vapor or product leaks. Should coking temperatures get out of control, an exothermic reaction could occur within the coker.

        b.  Safety. In thermal cracking when sour crudes are processed, corrosion can occur where metal temperatures are between 450° and 900° F. Above 900° F coke forms a protective layer on the metal. The furnace, soaking drums, lower part of the tower, and high-temperature exchangers are usually subject to corrosion. Hydrogen sulfide corrosion in coking can also occur when temperatures are not properly controlled above 900° F.

        Continuous thermal changes can lead to bulging and cracking of coke drum shells. In coking, temperature control must often be held within a 10°-20° F range, as high temperatures will produce coke that is too hard to cut out of the drum. Conversely, temperatures that are too low will result in a high asphaltic-content slurry. Water or steam injection may be 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. Provisions for alternate means of egress from the working platform on top of coke drums are important in the event of an emergency.

        c.  Health. The potential exists for exposure to hazardous gases such as hydrogen sulfide and carbon monoxide, and trace polynuclear aromatics (PNA's) associated with coking operations. When coke is moved as a slurry, oxygen depletion may occur within confined spaces such as storage silos, since wet carbon will adsorb oxygen. Wastewater may be highly alkaline and contain oil, sulfides, ammonia, and/or phenol. The potential exists in the coking process for exposure to burns when handling hot coke or in the event of a steam-line leak, or from steam, hot water, hot coke, or hot slurry that may be expelled when opening cokers. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as heat and noise, and during process sampling, inspection, maintenance, and turnaround activities. (Note: coke produced from petroleum is a different product from that generated in the steel-industry coking process.)


    1. CATALYTIC CRACKING.

      1. Description.

        a.  Catalytic cracking breaks complex hydrocarbons into simpler molecules in order to increase the quality and quantity of lighter, more desirable products and decrease the amount of residuals. This process rearranges the molecular structure of hydrocarbon compounds to convert heavy hydrocarbon feedstock into lighter fractions such as kerosene, gasoline, LPG, heating oil, and petrochemical feedstock.

        b.  Catalytic cracking is similar to thermal cracking except that catalysts facilitate the conversion of the heavier molecules into lighter products. Use of a catalyst (a material that assists a chemical reaction but does not take part in it) in the cracking reaction increases the yield of improved-quality products under much less severe operating conditions than in thermal cracking. Typical temperatures are from 850°-950° F at much lower pressures of 10-20 psi. The catalysts used in refinery cracking units are typically solid materials (zeolite, aluminum hydrosilicate, treated bentonite clay, fuller's earth, bauxite, and silica-alumina) that come in the form of powders, beads, pellets or shaped materials called extrudites.

        c.  There are three basic functions in the catalytic cracking process:

        • Reaction:  Feedstock reacts with catalyst and cracks into different hydrocarbons;
        • Regeneration:  Catalyst is reactivated by burning off coke; and
        • Fractionation:  Cracked hydrocarbon stream is separated into various products.


        d.  The three types of catalytic cracking processes are fluid catalytic cracking (FCC), moving-bed catalytic cracking, and Thermofor catalytic cracking (TCC). The catalytic cracking process is very flexible, and operating parameters can be adjusted to meet changing product demand. In addition to cracking, catalytic activities include dehydrogenation, hydrogenation, and isomerization.

         
        TABLE IV: 2-11. CATALYTIC CRACKING PROCESS
        Feedstock From Process Typical products . . . . To
        Gas oils . . . . Towers, coker
        visbreaker        		 Decomposition, alteration Gasoline . . . . . . . . . Treater or blend
        Gases . . . . . . . . . .   Gas plant
        Deasphalted
        oils . . . . . . .        		  
        Deasphalter        		   Middle distillates . . .Hydrotreat, blend, or recycle
        Petrochem feedstock . . Petrochem or other
        Residue . . . . . . . . . . . Residual fuel blend


    1. FLUID CATALYTIC CRACKING.

      1. Description.

        a.  The most common process is FCC, in which the oil is cracked in the presence of a finely divided catalyst which is maintained in an aerated or fluidized state by the oil vapors. The fluid cracker consists of a catalyst section and a fractionating section that operate together as an integrated processing unit. The catalyst section contains the reactor and regenerator, which, with the standpipe and riser, forms the catalyst circulation unit. The fluid catalyst is continuously circulated between the reactor and the regenerator using air, oil vapors, and steam as the conveying media.

        b.  A typical FCC process involves mixing a preheated hydrocarbon charge with hot, regenerated catalyst as it enters the riser leading to the reactor. The charge is combined with a recycle stream within the riser, vaporized, and raised to reactor temperature (900°-1,000° F) by the hot catalyst. As the mixture travels up the riser, the charge is cracked at 10-30 psi. In the more modern FCC units, all cracking takes place in the riser. The "reactor" no longer functions as a reactor; it merely serves as a holding vessel for the cyclones. This cracking continues until the oil vapors are separated from the catalyst in the reactor cyclones. The resultant product stream (cracked product) is then charged to a fractionating column where it is separated into fractions, and some of the heavy oil is recycled to the riser.

        c.  Spent catalyst is regenerated to get rid of coke that collects on the catalyst during the process. Spent catalyst flows through the catalyst stripper to the regenerator, where most of the coke deposits burn off at the bottom where preheated air and spent catalyst are mixed. Fresh catalyst is added and worn-out catalyst removed to optimize the cracking process.

        FIGURE IV:2-14. FLUID CATALYTIC CRACKING. FIGURE IV:2-14. FLUID CATALYTIC CRACKING.


      2. Moving Bed Catalytic Cracking. The moving-bed catalytic cracking process is similar to the FCC process. The catalyst is in the form of pellets that are moved continuously to the top of the unit by conveyor or pneumatic lift tubes to a storage hopper, then flow downward by gravity through the reactor, and finally 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.

      3. Thermofor Catalytic Cracking. In a typical thermofor catalytic cracking unit, the preheated feedstock flows by gravity through the catalytic reactor bed. The vapors are separated from the catalyst and sent to a fractionating tower. The spent catalyst is regenerated, cooled, and recycled. The flue gas from regeneration is sent to a carbon-monoxide boiler for heat recovery.

      4. Health and Safety Considerations.

        a.  Fire Prevention and Protection. Liquid hydrocarbons in the catalyst or entering the heated combustion air stream should be controlled to avoid exothermic reactions. Because of the presence of heaters in catalytic cracking units, the possibility exists for fire due to a leak or vapor release. Fire protection including concrete or other insulation on columns and supports, or fixed water spray or fog systems where insulation is not feasible and in areas where firewater hose streams cannot reach, should be considered.

        In some processes, caution must be taken to prevent explosive concentrations of catalyst dust during recharge or disposal. When unloading any coked catalyst, the possibility exists for iron sulfide fires. Iron sulfide will ignite spontaneously when exposed to air and therefore must be wetted with water to prevent it from igniting vapors. Coked catalyst may be either cooled below 120° F before it is dumped from the reactor, or dumped into containers that have been purged and inerted with nitrogen and then cooled before further handling.

        b.  Safety. Regular sampling and testing of the 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 the feedstock can foul gas compressors. Inspections of critical equipment including pumps, compressors, furnaces, and heat exchangers should be conducted as needed. When processing sour crude, corrosion may be expected where temperatures are below 900° F. Corrosion takes place where both liquid and vapor phases exist, and at areas subject to local cooling such as nozzles and platform supports.

        When processing high-nitrogen feedstock, exposure to ammonia and cyanide may occur, subjecting carbon steel equipment in the FCC overhead system to corrosion, cracking, or hydrogen blistering. These effects may be minimized by water wash or corrosion inhibitors. Water wash may also be used to protect overhead condensers in the main column subjected to fouling from ammonium hydrosulfide. 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.

        c.  Health. Because the catalytic cracker is a closed system, there is normally little opportunity for exposure to hazardous substances during normal operations. The possibility exists of exposure to extremely hot (700° F) hydrocarbon liquids or vapors during process sampling or if a leak or release occurs. In addition, exposure to hydrogen sulfide and/or carbon monoxide gas may occur during a release of product or vapor.

        Catalyst regeneration involves steam stripping and decoking, and produces fluid waste streams that may contain varying amounts of hydrocarbon, phenol, ammonia, hydrogen sulfide, mercaptan, and other materials depending upon the feedstock, crudes, and processes. Inadvertent formation of nickel carbonyl may occur in cracking processes using nickel catalysts, with resultant potential for hazardous exposures. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as noise and heat; during process sampling, inspection, maintenance and turnaround activities; and when handling spent catalyst, recharging catalyst, or if leaks or releases occur.

      1. HYDROCRACKING.

        1. Description.

          a.  Hydrocracking is a two-stage process combining catalytic cracking and hydrogenation, wherein heavier feedstocks are cracked in the presence of hydrogen to produce more desirable products. The process employs high pressure, high temperature, a catalyst, and hydrogen. Hydrocracking is used for feedstocks that are difficult to process by either catalytic cracking or reforming, since these feedstocks are characterized usually by a high polycyclic aromatic content and/or high concentrations of the two principal catalyst poisons, sulfur and nitrogen compounds.

          b.  The hydrocracking process largely depends on the nature of the feedstock and the relative rates of the two competing reactions, hydrogenation and cracking. Heavy aromatic feedstock is converted into lighter products under a wide range of very high pressures (1,000-2,000 psi) and fairly high temperatures (750°-1,500° F), in the presence of hydrogen and special catalysts. When the feedstock has a high paraffinic content, the primary function of hydrogen is to prevent the formation of polycyclic aromatic compounds. Another important role of hydrogen in the hydrocracking process is to reduce tar formation and prevent buildup of coke on the catalyst. Hydrogenation also serves to convert sulfur and nitrogen compounds present in the feedstock to hydrogen sulfide and ammonia.

          c.  Hydrocracking produces relatively large amounts of isobutane for alkylation feedstock. Hydrocracking also performs isomerization for pour-point control and smoke-point control, both of which are important in high-quality jet fuel.

        2. Hydrocracking Process.

          a.  In the first stage, preheated feedstock is mixed with recycled hydrogen and sent to the first-stage reactor, where catalysts convert sulfur and nitrogen compounds to hydrogen sulfide and ammonia. Limited hydrocracking also occurs.

          b.  After the hydrocarbon leaves the first stage, it is cooled and liquefied and run through a hydrocarbon separator. The hydrogen is recycled to the feedstock. The liquid is charged to a fractionator. Depending on the products desired (gasoline components, jet fuel, and gas oil), the fractionator is run to cut out some portion of the first stage reactor out-turn. Kerosene-range material can be taken as a separate side-draw product or included in the fractionator bottoms with the gas oil.

          c.  The fractionator bottoms are again mixed with a hydrogen stream and charged to the second stage. Since this material has already been subjected to some hydrogenation, cracking, and reforming in the first stage, the operations of the second stage are more severe (higher temperatures and pressures). Like the outturn of the first stage, the second stage product is separated from the hydrogen and charged to the fractionator.

          TABLE IV: 2-12. HYDROCRACKING PROCESS.
          Feedstock From Process Typical products . . . . To
          High pour point Catalytic cracker, atmospheric
          & vacuum tower          		 Decomposition, hydrogenation Kerosene, jet fuel . . . .Blending
          Gas oil Vacuum tower, coker   Gasoline, distillates . . Blending
          Hydrogen Reformer   Recycle, reformer gas . . Gas plant


          FIGURE IV:2-15. TWO-STAGE HYDROCRACKING.
          FIGURE IV:2-15. TWO-STAGE HYDROCRACKING.


        3. Health and Safety Considerations.

          a.  Fire Prevention and Protection. Because this unit operates at very high pressures and temperatures, control of both hydrocarbon leaks and hydrogen releases is important to prevent fires. In some processes, care is needed to ensure that explosive concentrations of catalytic dust do not form during recharging.

          b.  Safety. Inspection and testing of safety relief devices are important due to the very high pressures in this unit. Proper process control is needed to protect against plugging reactor beds. Unloading coked catalyst requires special precautions to prevent iron sulfide-induced fires. The coked catalyst should either be cooled to below 120° F before dumping, or be placed in nitrogen-inerted containers until cooled.

          Because of the operating temperatures and presence of hydrogen, the hydrogen-sulfide content of the feedstock must be strictly controlled to a minimum to reduce the possibility of severe corrosion. Corrosion by wet carbon dioxide in areas of condensation also must be considered. When processing high-nitrogen feedstock, the ammonia and hydrogen sulfide form ammonium hydrosulfide, which causes serious corrosion at temperatures below the water dew point. Ammonium hydrosulfide is also present in sour water stripping.

          c.  Health. Because this is a closed process, exposures are expected to be minimal under normal operating conditions. There is a potential for exposure to hydrocarbon gas and vapor emissions, hydrogen and hydrogen sulfide gas due to high-pressure leaks. Large quantities of carbon monoxide may be released during catalyst regeneration and changeover. Catalyst steam stripping and regeneration create waste streams containing sour water and ammonia. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposure to chemicals and other hazards such as noise and heat, during process sampling, inspection, maintenance, and turnaround activities, and when handling spent catalyst.

      2. CATALYTIC REFORMING.

        1. Description.

          a.  Catalytic reforming is an important process used to convert low-octane naphthas into high-octane gasoline blending components called reformates. Reforming represents the total effect of numerous reactions such as cracking, polymerization, dehydrogenation, and isomerization taking place simultaneously. Depending on the properties of the naphtha feedstock (as measured by the paraffin, olefin, naphthene, and aromatic content) and catalysts used, 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.

          b.  A catalytic reformer comprises a reactor section and a product-recovery section. More or less standard is a feed preparation section in which, by combination of hydrotreatment and distillation, the feedstock is prepared to specification. Most processes use platinum as the active catalyst. Sometimes platinum is combined with a second catalyst (bimetallic catalyst) such as rhenium or another noble metal.

          c.  There are many different commercial catalytic reforming processes including platforming, powerforming, ultraforming, and Thermofor catalytic reforming. In the platforming process, the first step is preparation of the naphtha feed to remove impurities from the naphtha and reduce catalyst degradation. The naphtha feedstock is then mixed with hydrogen, vaporized, and passed through a series of alternating furnace and fixed-bed reactors containing a platinum catalyst. The effluent from the last reactor is cooled and sent to a separator to permit removal of the hydrogen-rich gas stream from the top of the separator for recycling. The liquid product from the bottom of the separator is sent to a fractionator called a stabilizer (butanizer). It makes a bottom product called reformate; butanes and lighter go overhead and are sent to the saturated gas plant.

          d.  Some catalytic reformers operate at low pressure (50-200 psi), and others operate at high pressures (up to 1,000 psi). Some catalytic reforming systems continuously regenerate the catalyst in other systems. One reactor at a time is taken off-stream for catalyst regeneration, and some facilities regenerate all of the reactors during turnarounds.

        2. Health and Safety Considerations.

          a.  Fire Prevention and Protection. This is a closed system; however, the potential for fire exists should a leak or release of reformate gas or hydrogen occur.

          b.  Safety. Operating procedures should be developed to ensure control of hot spots during start-up. Safe catalyst handling is very important. Care must be taken not to break or crush the catalyst when loading the beds, as the small fines will plug up the reformer screens. Precautions against dust when regenerating or replacing catalyst should also be considered. Also, water wash should be considered where stabilizer fouling has occurred 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 acid or ammonium chloride salt.

          c.  Health. Because this is a closed process, exposures are expected to be minimal under normal operating conditions. There is potential for exposure to hydrogen sulfide and benzene should a leak or release occur.

          Small emissions of carbon monoxide and hydrogen sulfide may occur during regeneration of catalyst. Safe work practices and/or appropriate personal protective equipment may be needed for exposures to chemicals and other hazards such as noise and heat during testing, inspecting, maintenance and turnaround activities, and when handling regenerated or spent catalyst.

          TABLE IV: 2-13. CATALYTIC REFORMING PROCESS
          Feedstock From Process Typical products . . . . To
          Desulfurized naphtha Coker Rearrange, dehydrogenate High octane gasoline . . Blending
          Aromatics . . . . Petrochemical
          Naphthene-rich fractions hydrocracker, hydrodesulfur   Hydrogen . . . . Recycle, hydrotreat, etc.
          Straight-run naphtha Atmospheric fractionator   Gas . . . . . . . . Gas plant


          FIGURE IV:2-16. PLATFORMING PROCESS.
          FIGURE IV:2-16. PLATFORMING PROCESS.




      3. CATALYTIC HYDROTREATING.

        1. Description. Catalytic hydrotreating is a hydrogenation process used to remove about 90% of contaminants such as nitrogen, sulfur, oxygen, and metals from liquid petroleum fractions. These contaminants, if not removed from the petroleum fractions as they travel through the refinery processing units, can have detrimental effects on the equipment, the catalysts, and the quality of the finished product. Typically, hydrotreating is done prior to processes such as catalytic reforming so that the catalyst is not contaminated by untrea