Fuel Gas Refinery Fuel/Fuel GasSr Units Name 1 AGS- Air Generation System 3 ARU- Amine Recovery Unit 4 ATF Merox- Aviation Turbine Fuel Merox 5 ATF-HDT- Aviation Turbine Fuel Hydrotreate
Trang 1Refinery Process
Executive Summary
The refining process depends on the chemical processes of distillation (separating liquids
by their different boiling points) and catalysis (which speeds up reaction rates), and uses
the principles of chemical equilibria Chemical equilibrium exists when the reactants in a
reaction are producing products, but those products are being recombined again into
reactants By altering the reaction conditions the amount of either products or reactants
can be increased.
Refining is carried out in three main steps.
Step 1 - Separation
The oil is separated into its constituents by distillation, and some of these components
(such as the refinery gas) are further separated with chemical reactions and by using
solvents which dissolve one component of a mixture significantly better than another.
Step 2 - Conversion
The various hydrocarbons produced are then chemically altered to make them more
suitable for their intended purpose For example, naphthas are "reformed" from paraffins
and naphthenes into aromatics These reactions often use catalysis, and so sulfur is
removed from the hydrocarbons before they are reacted, as it would 'poison' the catalysts
used The chemical equilibria are also manipulated to ensure a maximum yield of the
desired product.
Step3 - Purification
The hydrogen sulfide gas which was extracted from the refinery gas in Step 1 is converted
to sulfur, which is sold in liquid form to fertiliser manufacturers.
The refinery produces a range of petroleum products.
Petrol
Petrol (motor gasoline) is made of cyclic compounds known as naphthas It is made in two
grades: Regular (91 octane) and Super or Premium (96 octane), both for spark ignition
engines These are later blended with other additives by the respective petrol companies.
Jet fuel/Dual purpose kerosene
The bulk of the refinery produced kerosene is high quality aviation turbine fuel (Avtur) used
by the jet engines of the domestic and international airlines Some kerosene is used for
heating and cooking.
Diesel Oil
This is less volatile than gasoline and is used mainly in compression ignition engines, in road
vehicles, agricultural tractors, locomotives, small boats and stationary engines Some diesel
oil (also known as gas oil) is used for domestic heating.
Fuel Oils
A number of grades of fuel oil are produced from blending Lighter grades are used for the
larger, lower speed compression engines (marine types) and heavier grades are for boilers
and as power station fuel.
Trang 2Fuel Gas Refinery Fuel/Fuel Gas
Sr Units Name
1 AGS- Air Generation System
3 ARU- Amine Recovery Unit
4 ATF Merox- Aviation Turbine Fuel Merox
5 ATF-HDT- Aviation Turbine Fuel Hydrotreater
6 CCR- Continuous Catalytic Reformer
7 CDU- Crude Distillation Unit
8 DCU-Delayed Crocker Unit
9 Desal/Demin Plant
10 DHDT- Diesel Hydrotreating
11 ETP- Effluent Treatment Plant
12 FCCU- Fluid Catalytic Cracker Unit
14 HMU- Hydrogen Manufacturing Unit
18 PRU- Propylene Recovery Unit
19 SGU-Saturated Gas Unit
20 SRU- Sulphur Recoveru Unit
21 SS&H- Sulphur Storage & Handling
22 SWS- Sour Water Stripper
23 UGS- Unsaturated Gas Seperation Unit
24 VBS- Visbreaker Unit
25 VDU- Vaccume Distillation Unit
Naptha
Desalted
FCCu, Etc)
Diesel
Stripped Water Gas Oil
Propane Reduced
CO2 Propylene
Light Vaccume
To Hydrocracker
& H2 Hydrotreater Natural Gas Diesel
Premier Coke
ESSAR CONSTRUCTIONS INDIA LTD.
KURLA, MUMBAI BITUMEN
(Road, Roofing, waterproofing)
ATF MEROX Aviation Turbine Fuel Merox
Jet Fuel/
Kerosene
CCR Continuos Catalytic Reformer
Gasolines Blending Super Premium Unleaded Premiun unleaded Unleaded
(FCCU) Fluid Catalytic Cracking Units
VGO-HDT Vaccume Gas Oil Hydotreater
Sulphur
Alkylation Unit Poly Unit
PRU
Supporting Units
Bitumen Blowing
Crude Oil Storage
ISOM Light Naptha Isomerisation
Naptha
NHTU Naptha Hydrotreate Unit
DHDT Diesel Hydrotreater
Gas Processing
Amine Recovery Unit
Merox Unit
SRU Sulphur Recover Unit
Heating
Desalter
ATF ATF Hydrotreater
HDT-ETP
Trang 3Crude Oil Storage
Crude Oil Storage
In almost all cases, crude oils have no inherent value without petroleum refining processes to convert them into marketable products Crude oil is a complex mixture of hydrocarbons that also contains sulfur, nitrogen, heavy metals and salts Most of these contaminants must be removed in part or total during the refining process The hydrocarbons that make up crude oil have boiling points from less than 60˚F to greater than 1200˚F (60-650˚C).
Crude oil varies in sulfur content Higher sulfur crude oil is more corrosive than lower sulfur crude oils
In order to process higher sulfur crude oils, equipment must be built from more expensive alloys to provide higher corrosion resistance Many refineries are not able to process crude oils with high sulfur
The American Petroleum Institute (API) has developed a characterization for the density of crude oils:
˚API = (141.5/Specific Gravity@60˚F) -131.5
When comparing crude oils, the crude oil with the higher API will be easier to refine than one with a lower API.
Crude oil is delivered to a refinery by marine tanker, barge, pipeline, trucks and rail The level of BS&W (bituminous sediment and water) is monitored to avoid high levels of water and solids Water separates from crude oil as it sits in tanks waiting to be refined This water is generally drained to waste water treatment just prior to processing.
Process Chart
Trang 4All crude oil contains salt, predominantly chlorides Chloride salts can combine with water to form
hydrochloric acid in atmospheric distillation unit overhead systems causing significant equipment
damage and processing upsets Chlorides and other salts will also deposit on heat exchanger surfaces reducing energy efficiency and increasing equipment repairs and cleaning.
Salt must be removed from crude oil prior to processing Crude oil is pumped from storage tanks and preheated by exchanging heat with atmospheric distillation product streams to approximately 250˚F (120˚C) Inorganic salts are removed by emulsifying crude oil with water and separating them in a desalter Salts are dissolved in water and brine is removed using an electrostatic field and sent to the waste water treatment.
Process Chart
Trang 5Atmosheric Distillation Unit/ Crude Distillation Unit
Distillation concentrates lower boiling point material in the top of the distillation tower and higher boiling point material in the bottom Progressively higher boiling point material is present between the top and bottom of the tower Heat is added to the bottom of the tower using a reboiler that vaporizes part of the tower bottom liquid and returns it to the tower Heat is removed from the top of the tower through an overhead condenser A portion of the condensed liquid is returned to the tower as reflux The continuous vaporization and condensation of material on each tray of the fractionation tower is what creates the separation of petroleum products within the tower.
The most common products of atmospheric distillation are fuel gas, naphtha, kerosene (including jet fuel), diesel fuel, gas oil and resid Atmospheric distillation units run at a pressure slightly above atmospheric in the overhead accumulator Temperatures above approximately 750˚F (400˚C) are avoided to prevent thermal cracking of crude oil into light gases and coke With the exception of Coker units, the presence of coke in process units is undesirable because coke deposit fouls refining equipment and severely reduces process performance.
Trang 6Vaccum Distillation Units
Atmospheric resid is further fractionated in a Vacuum Distillation tower Products that exist as a liquid at atmospheric pressure will boil at a lower temperature when pressure is significantly reduced Absolute operating pressure in a Vacuum Tower can be reduced to 20 mm of mercury or less (atmospheric
pressure is 760 mm Hg) In addition, superheated steam is injected with the feed and in the tower bottom
to reduce hydrocarbon partial pressure to 10 mm of mercury or less.
Atmospheric resid is heated to approximately 750˚F (400˚C) in a fired heater and fed to the Vacuum Distillation tower where it is fractionated into light gas oil, heavy gas oil and vacuum resid.
Typical products and their true boiling points (TBP) from crude oil distillation (i.e., both atmospheric and vacuum tower products) are:
Trang 7Naptha HDS/ Hydrotreater
Most catalytic reforming catalysts contain platinum as the active material Sulfur and nitrogen
compounds will deactivate the catalyst and must be removed prior to catalytic reforming The Naphtha HDS unit uses a cobalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed with unreacted hydrogen.
Reactor conditions are relatively mild for Naphtha HDS at 400-500˚F (205-260˚C) and relatively moderate pressure 350-650 psi (25-45 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.
If required, the boiling range of the Catalytic Reforming charge stock can be changed by redistilling in the Naphtha HDS Often pentanes, hexanes and light naphtha are removed and sent directly to gasoline blending or pretreated in an Isomerization Unit prior to gasoline blending.
Trang 8Kerosene HDS/ Hydrotreater
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements like sulfur, nitrogen and aromatics by reacting them with hydrogen Cobalt-molybdenum catalysts are used for desulphurization When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used In some instances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance.
Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-100 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst
Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil in a product separator.
Hydrogen sulfide and light ends are stripped from the desulfurized product Hydrogen sulfide
is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to use as desalter water or discharge.
Trang 9Diesel HDS/Hydrotreater
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements like sulfur, nitrogen and aromatics by reacting them with hydrogen Cobalt-molybdenum catalysts are used for desulphurization When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used In some instances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance.
Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-100 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst
Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil in a product separator.
Hydrogen sulfide and light ends are stripped from the desulfurized product Hydrogen sulfide
is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to use as desalter water or discharge.
Trang 10Gas Oil HDS
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements, particularly sulfur and nitrogen, by reacting them with hydrogen prior to feed to the FCC Unit Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at relatively high pressures up to 2000 psi (138 bar) depending on the level of reaction severity needed to meet product specification and the composition of the feedstock.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst For desulphurization, the most common catalysts are
cobalt-molybdenum When hydrodenitrofication (HDN) is desired in addition to desulfurization, molybdenum catalysts are recommended.
nickel-Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil and hydrogen sulfide and light end are stripped from the desulfurized product.
Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent
to sour water stripping prior to use as desalter water or discharge.
Trang 11Fluid Catalytic Cracker (FCC)
The FCC is considered by many as the heart of a modern petroleum refinery FCC is the tool refiners use to correct the imbalance between the market demand for lighter petroleum products and crude oil distillation that produces an excess of heavy, high boiling range products The FCC unit converts heavy gas oil into gasoline and diesel.
The FCC process cracks heavy gas oils by breaking the carbon bonds in large molecules into multiple smaller molecules that boil in a much lower temperature range The FCC can achieve conversions of 70-80% of heavy gas oil into products boiling in the heavy gasoline range The reduction in density across the FCC also has the benefit of producing a volume gain (i.e., combined product volumes are greater than the feed volume) Since most
petroleum products are sold on a volume basis, this gain has a significant effect on refinery profitability.
FCC reactions are promoted at high temperatures 950-1020˚F (510-550˚C) but relatively low pressures of 10-30 psi (1-2 bar) At these temperatures, coke formation deactivates the catalyst by blocking reaction sites on the solid catalyst The FCC unit utilizes a very fine powdery catalyst know as a zeolite catalyst that is able to flow like a liquid in a fluidized bed - hence the name "Fluid Cat Cracker" Catalyst is continually circulated from the reactor to a regenerator where coke is burned off in controlled combustion with air creating carbon monoxide, carbon dioxide, sulfur oxides (SOX) and nitrous oxides (NOX) as well as some other combustion products.
Feedstock gas oil is preheated and mixed with hot catalyst coming from the regenerator at 1200-1350˚F (650-735˚C) The hot catalyst vaporizes the feedstock and heats it to reaction temperature To avoid overcracking, which reduces yield at the expense of gasoline, reaction time is minimized The primary reaction occurs in the transfer line (or riser) going to the reactor The primary purpose of the reactor is to separate catalyst from reaction products FCC products are more highly unsaturated than distillation products Naphtha in the
gasoline range has good octane Distillate range products have low pour points but poorer combustion qualities Light end products are highly olefinic (unsaturated) and are used as feedstock for further upgrading processes like alkylation With sulfur concentration of gasoline reducing, FCC products (gasoline and distillates) may require desulfurization through a HDS Unit prior to blending.
Air emissions are a growing concern for FCC units Emissions include catalyst fines, SOX and NOX components Electrostatic precipitators and scrubbers are used to reduce air emissions As air quality concerns grow, more equipment to reduce SOX and NOX are expected.
Trang 12The Hydrocracker is similar to the FCC in that it is a catalytic process that cracks long chain gas oil molecules into smaller molecules that boil in the gasoline, jet fuel and diesel fuel range The fundamental difference is that cracking reactions take place in an extremely
hydrogen rich atmosphere Two reactions occur First carbon bonds are broken followed by attachment of hydrogen Hydrocracker products are sulfur free and saturated.
Another difference is operating conditions Hydrocrackers run at high temperature 650-800˚F (345-425˚C) and very high pressures of 1500-3000 psi (105-210 bar) Hydrocracker reactors contain multiple fixed beds of catalyst typically containing palladium, platinum, or nickel These catalysts are poisoned by sulfur and organic nitrogen, so a high-severity HDS/HDN reactor pretreats feedstock prior to the hydrocracking reactors Hydrocracker units may be configured in single stage or two stage reactor systems that enable a higher conversion of gas oil into lower boiling point material.
Typical feedstock to a Hydrocracker includes FCC cycle oil, coker gas oil and gas oil from crude distillation Heavy naphtha from the Hydrocracker makes excellent Catalytic Reformer feedstock Distillates from Hydrocracking make excellent jet fuel blend stocks Light ends are highly saturated and a good source of iso-butane for alkylation The yield across a
Hydrocracker may exhibit volumetric gains as high as 20-25% making it a substantial
contributor to refinery profitability.
Trang 13A major ancillary facility of the expanded refinery is the effluent water treatment plant.
The treatment of effluent water is as follows Process water is deodorised in sour-water strippers where the gas (H2S and NH3) is stripped off The stripped water has oil removed in the gravity separators and then, together with some rainwater, is homogenised in a buffer tank From this tank, the effluent water is piped to a flocculation/flotation unit where air and polyelectrolytes are injected in small concentrations to make the suspended oil and solids separate from the water The latter are skimmed off and piped to a separate sludge
handling/disposal unit The remaining watery effluent from the flotation unit is passed to adjoining biotreater where the last of the dissolved organic impurities are removed by the action of micro-organisms in the presence of oxygen (biodegradation) On a continual basis, sludge containg micro-organisms is removed to the sludge handling/disposal unit
Trang 14The most common form of the coking process in today's refineries is Delayed Coking where vacuum resid is thermally cracked into smaller molecules that boil at lower temperatures
Products include naphtha, gas oils and coke Light product yield varies by feedstock but is generally around 75% conversion Coke is sold as a fuel or specialty product into the steel and aluminum industry after calcining to remove impurities.
Vacuum resid is fed to the coker fractionator to remove as much light material as possible Bottoms from the fractionator are heated in a direct fired furnace to more than 900˚F (480˚C) and discharged into a coke drum where thermal cracking is completed High velocity and stream injection are used to minimize coke formation in furnace tubes Coke deposits in the drum and cracked products are sent to the fractionator for recovery Coke drums typically operate in the 25-50 psi (2-4 bar) range while the fractionator operates at a pressure slightly above atmospheric in the overhead accumulator Fractionator bottoms are recycled through the furnace to extinction.
Multiple coke drums are used As one drum is being filled with coke, others are offline for coke removal Coke removal involves steaming, quenching, hydraulic cutting to remove solid coke from the drum and vessel preparation for return to service.
Coker light products are highly unsaturated Coker light ends are recovered as an olefin feed source for alkylation Coker naphtha requires desulfurization before upgrade in the Catalytic Reforming Unit Coker gas oils are generally sent to the Hydrocracker for upgrade.
Visbreaking is a milder form of thermal cracking often used to reduce the viscosity and pour point of vacuum resid in order to meet specification for heavy fuel oil Visbreaking helps avoid the use of expensive cutter stock required for dilution The process is carefully controlled to predominantly crack long paraffin chains off aromatic compounds while avoiding coking reactions.
There is a tradeoff between furnace temperature and residence time for visbreaking
operations Longer residence time leads to lower furnace outlet temperatures In general, operations are conducted between 800-930˚F (425-500˚C) Material is quenched with cold gas oil to stop the cracking process Pressure is important to unit design and ranges between 300-
750 psi (20-50 bar).
Trang 15The Amine Treating Unit removes CO2 and H2S from sour gas and hydrocarbon
streams in the Amine Contactor The Amine (MDEA) is regenerated in the Amine Regenerator, and recycled to the Amine Contactor.
The sour gas streams enter the bottom of the Amine Contactor The cooled lean amine is trim cooled and enters the top of the contactor column The sour gas flows upward counter-current to the lean amine solution An acid-gas-rich-amine solution leaves the bottom of the column at an elevated temperature, due to the exothermic absorption reaction The sweet gas, after absorption of H2S by the amine solution, flows overhead from the Amine Contactor
The Rich Amine Surge Drum allows separation of hydrocarbon from the amine
solution Condensed hydrocarbons flow over a weir and are pumped to the drain The rich amine from the surge drum is pumped to the Lean/Rich Amine Exchanger
The stripping of H2S and CO2 in the Amine Regenerator regenerates the rich amine solution The Amine Regenerator Reboiler supplies the necessary heat to strip H2S and CO2 from the rich amine, using steam as the heating medium
Acid gas, primarily H2S and water vapor from the regenerator is cooled in the Amine Regenerator Overhead Condenser The mixture of gas and condensed liquid is
collected in the Amine Regenerator Overhead Accumulator The uncondensed gas is sent to Sulfur Recovery.
The Amine Regenerator Reflux Pump, pumps the condensate in the Regenerator Accumulator, mainly water, to the top tray of the Amine Regenerator A portion of the pump discharge is sent to the sour water tank.
Lean amine solution from the Amine Regenerator is cooled in the Lean/Rich
Exchanger A slipstream of rich amine solution passes through a filter to remove particulates and hydrocarbons, and is returned to the suction of the pump The lean amine is further cooled in the Lean Amine Air Cooler, before entering the Amine Contactor.
Trang 16Needle Coke Unit
Needle Coke is a premium grade, high value petroleum coke, used in the
manufacturing of graphite electrodes for the arc furnaces in the metallurgy industry Its hardness is due to the dense mass formed with a structure of carbon threads or needles oriented in a single direction Needle coke is highly crystalline and can provide the properties needed for manufacturing graphite electrode It can withstand temperatures as high as 28000C.
The technology is primarily focused on production of needle coke in any existing delayed coker unit using heavier hydrocarbon streams without any costly pre-
treatment Formation of needle coke requires specific feedstocks, special coking and also special calcination conditions If feedstocks are suitable for needle coke, process conditions for coking and calcination are selected to improve the properties and yield of the needle coke Typical yield of needle coke is 18-30 wt% of fresh feed.
The maximum limits of sulfur and ash in calcined needle coke are 0.6 and 0.3 wt% respectively Higher sulfur content of coke can cause the puffing of electrode High ash content can increase the resistivity and decrease electrode strength The
calcined coke with higher sulfur and ash content is not considered suitable for manufacturing of graphite electrode even if other properties meet the quality of premium grade coke Thus, the quality and price of needle coke are highly
dependent on the properties of feedstock used for coking.
Refineries having delayed coker unit either processing low sulfur crude and/or having a residue hydrotreater unit and/or having RFCC/ FCC unit processing low sulfur feed are suitable for considering this technology.