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OIL REFINING PROCESSES Advanced course Assoc.Prof. Pham Huyen [email protected]
References • Chang Samuel Hsu and Paul R. Robinson, Practical Advances in Petroleum Processing, Vol 1, Springer, 2006 • Mohamed A. Fahim, Taher A. Alsahhaf and Amal Elkilani, Fundamentals of Petroleum Refining, Elsevier, 2010
Outline Unit 1. Introduction Unit 2. Refinery Feedstocks and Products Unit 3. Modern Petroleum Processing Unit 4. Auxiliary Processes & Utilities
Unit 1. Introduction Largest Worldwide Refineries Approximately 650 Refineries in the world
Source: Oil & Gas Journal
Unit 1. Introduction • High sulfur, heavy crude is lowest cost. àRequires extremely complex refinery to convert into high value products. • Low sulfur, light crude is highest cost. à Simple refining yields high value products. • a function of location of crude supply versus refining centers. à Refiners close to crude production enjoy advantage over refineries distant from supply
Unit 1. Introduction
Unit 1. Introduction
Note: product blending and sulfur recovery units are not shown, but these are almost always present
Unit 1. Introduction • DQR Introduction • NSRP Introduction
Unit 2. Refinery Feedstocks and Products 2.1. Composition of Crude Oils 2.2. Products Composition 2.3. Physical Property Characterization Data 2.4. Chemical Analysis Data
2.1. Composition of Crude Oils Impurities (sulphur, nitrogen, oxygen and metals): -‐ low concentrations -‐ undesirable -‐ affect the quality of the produced products -‐ Catalyst poisoning and corrosion
2.1. Composition of Crude Oils Hydrogen to carbon ratios affect the physical properties of crude oil. -‐ As the hydrogen to carbon ratio decreases, the gravity and boiling point of the hydrocarbon compounds increases. -‐ the higher the hydrogen to carbon ratio of the feedstock, the higher its value is to a refinery because less hydrogen is required.
2.1. Composition of Crude Oils
2.1. Composition of Crude Oils Hydrocarbons: -‐ Paraffins -‐ Olefins are not naturally present in crude oils but they are formed during the conversion processes -‐ Naphthenes (cycloalkanes): Mutli-‐ring naphthenes are present in the heavier parts of the crude oil -‐ Aromatics Polynuclear aromatic compounds are found in the heavy petroleum cuts à cause catalyst deactivation and coke deposition during processing à environmental problems
2.1. Composition of Crude Oils
2.1. Composition of Crude Oils -‐ Sulphur Compounds
• varies from less than 0.05 to more than 10 wt% (but generally falls in the range 1–4 wt%). • Crude oil with less than 1 wt% sulphur is referred to as low sulphur or sweet, and that with more than 1 wt% sulphur is referred to as high sulphur or sour. • Sulphur heteroatoms • inorganic forms: elemental sulphur S, dissolved hydrogen sulphide H2S, carbonyl sulphide COS • organic forms: mercaptans and sulphides, Sulphides and disulphides, Thiophenes
2.1. Composition of Crude Oils -‐ Oxygen Compounds • less than 2 wt%. • include alcohols, ethers, carboxylic acids, phenolic compounds, ketones, esters and anhydrides. • causes the crude to be acidic with consequent processing problems such as corrosion.
2.1. Composition of Crude Oils -‐ Nitrogen Compounds
• Crude oils contain very low amounts of nitrogen compounds. • the more asphaltic the oil, the higher its nitrogen content. • more stable than sulphur compounds à harder to remove. • be responsible for the poisoning of a cracking catalyst, and contribute to gum formation in finished products. • The nitrogen compounds in crude oils may be classified as basic or non-‐basic. • Basic nitrogen compounds: pyridines. • Non-‐basic nitrogen compounds: pyrrole types.
2.1. Composition of Crude Oils -‐ Metallic Compounds • • • • • • • •
exist in all crude oil types in very small amounts cause operational problems and contaminate the products, affect upgrading processes cause poisoning to the catalysts used for hydroprocessing and cracking. small amounts of metals (iron, nickel and vanadium) in the feedstock to the catalytic cracker affect the activity of the catalyst à increased gas and coke formation and reduced gasoline yields. For high-‐temperature power generators, the presence of vanadium in the fuel may lead to ash deposits on turbine blades and cause severe corrosion, and the deterioration of refractory furnace linings. inorganic water-‐soluble salts, mainly as chlorides and sulphates of sodium, potassium, magnesium and calcium à removed in desalting operations. oil-‐soluble organometallic compounds: Zinc, titanium, calcium and magnesium appear in the form of organometallic soaps. oil-‐soluble compounds: vanadium, nickel, copper and iron àcomplexing with pyrrole compounds.
2.1. Composition of Crude Oils -‐ Asphaltenes: -‐ condensed polynuclear aromatic layers linked by saturated links, -‐ lead to coke formation and metal deposition on the catalyst surface causing catalyst deactivation. -‐ Resins -‐ polar molecules in the molecular weight range of 500–1000, -‐ insoluble in liquid propane but soluble in n-‐heptane. -‐ responsible for dissolving and stabilizing the solid asphaltene molecules in petroleum. The resin molecules surround the asphaltene clusters (micelles) and suspend them in liquid oil. Because each asphaltene is surrounded by a number of resin molecules, the content of resins in crude oils is higher than that of the asphaltenes.
2.2. Products Composition -‐ Liquefied Petroleum Gas (LPG) -‐ Gasoline -‐ Kerosene -‐ Jet Fuel -‐ Diesel Fuel -‐ Fuel Oil (Residual Fuel Oil) -‐ Lube Oil -‐ Asphalt -‐ Petroleum Coke
2.2. Products Composition
2.2. Products Composition
2.2. Products Composition
2.2. Products Composition Major quality aspects of main petroleum products
2.2. Products Composition
2.3. Physical Property Characterization Data 2.3.1. Fractionation
2.3.10. Aniline Point
2.3.2. True Boiling Point Distillation
2.3.11. Flash Point
2.3.3. ASTM Distillation
2.3.12. Octane Number
2.3.4. Simulated Distillation by Gas Chromatography
2.3.13. Cetane Number 2.3.14. Smoke Point
2.3.5. API Gravity 2.3.6. Pour Point 2.3.7. Viscosity 2.3.8. Refractive Index 2.3.9. Freezing Point
2.3.15. Reid Vapour Pressure 2.3.16. Water, Salt and Sediment 2.3.17. Molecular Weight
2.4. Chemical Analysis Data 2.4.1. Elemental Analysis 2.4.2. Carbon Residue 2.4.3. Detailed Hydrocarbon Analysis 2.4.4. Hydrocarbon Family Analysis 2.4.5. Aromatic Carbon Content 2.4.6. SARA Analysis
ASTM testing grid for crude oil and petroleum fractions
Unit 3. Modern Petroleum Processing
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.1.1. Distillation • the biggest unit in most plants • Many downstream conversion units also use distillation for production separation • To reduce corrosion, plugging, and fouling in crude heaters and towers, and to prevent the poisoning of catalysts in downstream units, these contaminants are removed by a process called desalting
3.1.1. Distillation
Atmospheric distillation • At the bottom of the stripping section, steam is injected into the column • to strip the atmospheric residue of any light hydrocarbon and • To lower the partial pressure of the hydrocarbon vapours in the flash zone. àlowering the boiling point of the hydrocarbons àcausing more hydrocarbons to boil and go up the column to be eventually condensed and withdrawn as side streams.
Vacuum Distillation -‐ residue from an atmospheric distillation tower -‐ The vacuum, which is created by a vacuum pump or steam ejector, is pulled from the top of the tower. -‐ vacuum columns have larger diameters and their internals are simpler (random packing and demister pads are used) -‐ The overhead stream à lube base stock, heavy fuel oil, or as feed to a conversion unit -‐ The vacuum residue à asphalt, or feedstock for coker or visbreaker unit
3.1.2. Solvent Refining a. Solvent Deasphalting b. Solvent Extraction c. Solvent Dewaxing, Wax Deoiling
a. Solvent Deasphalting (SDA) • Solvent deasphalting takes advantage of the fact that aromatic compounds are insoluble in paraffins. • Propane deasphalting is commonly used to precipitate asphaltenes from residual oils. • Deasphalted oil (DAO) is sent to hydrotreaters, FCC units, hydrocrackers, or fuel-‐oil blending. In hydrocrackers and FCC units, DAO is easier to process than straight-‐run residual oils. This is because asphaltenes easily form coke and often contain catalyst poisons such as nickel and vanadium, and the asphaltene content of DAO is (by definition) almost zero.
a. Solvent Deasphalting (SDA) • An advanced version of solvent deasphalting is “residuum oil supercritical extraction,” or ROSE. • In this process, the oil and solvent are mixed and heated to above the critical temperature of the solvent, where the oil is almost totally insoluble • Advantages include higher recovery of deasphalted liquids, lower operating costs due to improved solvent recovery, and improved energy efficiency. • The ROSE process can employ three different solvents, -‐ Propane: Preparation of lube base stocks -‐ Butane : Asphalt production -‐ Pentane: Maximum recovery of liquid
Schematic of the ROSE process
Refinery with solvent deasphalting, Rose-‐residue oil supercritical extraction unit
b. Solvent Extraction • to remove aromatics and other impurities from lube and grease stocks. • The solvent is separated from the product stream by heating, evaporation, or fractionation. • Remaining traces of solvent are removed from the raffinate by steam stripping or flashing. • NMP, phenol, furfural, and cresylic acid are widely used as solvents.
c. Solvent Dewaxing, Wax Deoiling • Solvent dewaxing removes wax (normal paraffins) from deasphalted lube base stocks. • The main process steps include mixing the feedstock with the solvent, chilling the mixture to crystallize wax, and recovering the solvent. • Commonly used solvents include toluene and methyl ethyl ketone (MEK). • Methyl isobutyl ketone (MIBK) is used in a wax deoiling process to prepare food-‐grade wax.
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.2.1. Thermal cracking • Visbreaking • Delayed Coking • Fluid Coking
3.2.1. Thermal cracking Visbreaking • Feed: AR or VR • Mild heating 471–493 C (880–920 F) at 50–200 psig • Reduce viscosity of fuel oil • Low conversion (10%) at 221oC (430F) • Heated coil or soaking drum • Products: gases, naphtha, gas oil, reridue or tar
Delayed coking • Feed: VR, FCC slurry, visbreaking tar • Moderate heating 482–516oC (900–960F) at 90 psig • Soak drums 452–482oC (845– 900F)
Fluid coking and flexicoking • Feed: VR • Severe heating 482–566oC (900–1050F) at 10 psig • Fluidized bed with steam • Higher yields of light ends
• Less coke yield (20% for • Residence time: until they are fluid coking and 2% for full of coke flexicoking) • Coke is removed hydraulically • Products: gas, naphtha, • Coke yield 30 wt%, unsaturated gases, LN, HN, LCO, HCO
LCO, HCO, coke
Visbreaking
(A) Coil type visbreaker. • •
more stable visbreaker products more flexible and allows the production of heavy cuts, boiling in the vacuum gas oil range
(B) Soaker type visbreaker • less capital investment, • consumes less fuel • longer on-‐stream times
Delayed coking
3.2.2. Fluid Catalytic Cracking • A typical FCC unit comprises three major sections • riser/reactor, • Regenerator • fractionation.
• Purpose • Convert heavy oils into gasoline and/or light olefins
• Licensors • Axens (IFP) • KBR • UOP
ExxonMobil Stone & Webster
3.2.2. Fluid Catalytic Cracking • Catalysts and Additives • • • • •
Zeolite (highly acidic, catalyzes cracking) Rare-‐earth oxide (increases catalyst stability) ZSM-‐5 (increases octane and production of light olefins) Pt (promotes combustion of CO to CO in regenerator) Desox (transfers SOx from regenerator to riser/reactor) .
• Feeds • Atmospheric gas oil • Coker gas oil • Lube extracts
Vacuum gas oil Deasphalted oil Vacuum resid (up to 20 vol%)
3.2.2. Fluid Catalytic Cracking • Typical Feed Properties • • • •
Nitrogen Carbon residue Nickel + Vanadium 90% boiling point
<3000 wppm <5.0 wt% <50 wppm <1300°F (704°C)
• Typical Process Conditions • • • • •
Feed temperature Reactor temperature Regenerator temperature Catalyst/Oil ratio Reactor pressure
300 – 700°F (150 – 370°C) 920 – 1020°F (493 – 550°C) 1200 – 1350°F (650 – 732°C) 4.0 – 10.0 10 – 35 psig (170 – 343 kPa)
3.2.2. Fluid Catalytic Cracking • Typical Product Yields • • • • • • • • •
Conversion H2, H2S, methane, ethane Propane and propylene Butanes and butenes Gasoline LCO Slurry oil Coke Total C3-‐ plus
70 – 84 vol% 3.0 – 3.5 wt% 4.5 – 6.5 wt% 9.0 – 12.0 wt% 44 – 56 wt% 13 – 20 wt% 4 – 12 wt% 5 – 6 wt% 106 – 112 vol%
3.2.3. Hydrotreating and hydrocacking
LGO = Light Gas Oil HCO = FCC Heavy Cycle Oil
HGO = heavy Gas Oil VGO = Vacuum Gas Oil
LCO = FCC Light Cycle Oil VBGO = Visbreaker Gas Oil
CGO = Coker Gas Oil
3.2.3. Hydrotreating and hydrocacking
3.2.3. Hydrotreating and hydrocacking
Role of hydrotreating (HT) in the refinery 1. Meeting finished product specification. • Kerosene, gas oil and lube oil desulphurization. • Olefin saturation for stability improvement. • Nitrogen removal. • De-‐aromatization for kerosene to improve cetane number, 2. Feed preparation for downstream units: • Naphtha is hydrotreated for removal of metal and sulphur. • Sulphur, metal, polyaromatics and Conradson carbon removal from vacuum gas oil (VGO) to be used as FCC feed. • Pretreatment of hydrocracking feed to reduce sulphur, nitrogen and aromatics.
Naphtha hydrotreating unit
Diesel fuel hydrotreating unit
Atmosphere residue desulphurization process
3.2.3. Hydrotreating and hydrocacking
3.2.3. Hydrotreating and hydrocacking
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.3.1. Catalytic Reforming
3.3.1. Catalytic Reforming
3.3.2. Isomerization
3.3.2. Isomerization
Sơ đồ công nghệ Penex
Sơ đồ quá trình Penex kết hợp với Deisohexane
3.3.3. Catalytic Oligomerization ΔH < 0
• Catalysts: • Sulfuric acid, phosphoric acid, and solid phosphoric acid on kieselguhr pellets (SPA) are used as catalysts. • The SPA catalyst is non-‐corrosive, so it can be used in less-‐expensive carbon-‐steel reactors.
• Temperatures: 300 to 450°F (150 to 230°F) • Pressures: 200 to 1,200 psig (1480 to 8375 kPa).
3.3.3. Catalytic Oligomerization
UOP’s indirect Alkylation (LnAlk) process
SPA: solid phosphoric acid
3.3.4. Alkylation
(H2SO4, HF)
3.3.4. Alkylation • • • •
Zeolite catalyst Liquid phase 50 – 90oC uncommercialized
Unit 4. Auxiliary Processes & Utilities • Steam Methane Reformer (hydrogen production) • Light Ends Recovery Units • Lube Oil Units • Amine Treater • Caustic and Merox Treaters • Sulfur Recovery, Tail Gas Treating, NaHS Units • Sour Water Strippers • Water Treating (de-‐ionization) • Steam Production
Waste Water Processing Relief Systems and Flares Plant and Instrument Air Flare Gas Recovery Units MSAT Benzene Reduction Units (similar to ISOM unit) • Nitrogen Systems • Electrical Systems • • • • •
Energetic issues in an oil refinery Energy by source in an oil refinery Other 7% Electricity 5% Natural gas 25% Petroleum coke 17%
• Refinery gas + petroleum coke + other oil-‐based by-‐products accounts for 65% of the energy sources in an oil refinery.
Refinery gas 46%
• 38% of the energy sources in an oil refinery are used to produce non-‐fuel products like lubricant oils, wax, asphalt, and petrochemical feedstocks. • Oil refineries generate large amounts of electricity on-‐site. • The cost of energy for heat and power accounts for c.a. 40% of the operating costs in a refinery!!!
Energetic issues in an oil refinery [Worrell 2005]
Sulfur Recovery • Purpose Converts H2S gas into elemental sulfur, “Claus” Unit • 1/3 of H2S burned in Reaction Furnace to produce SO2 (sulfur dioxide) 1.5 O2 + H2S àSO2 + H2O • Zinc Oxide catalyst beds convert SO2 and H2S into elemental sulfur and water SO2 + 2H2S à3S + 2H2O • Sulfur is collected in pit or tank and trucked / railed. Used in chemical manufacture. • Process is about 96% efficient, so Tail Gas Treating (SCOT Unit or other) required to purify off gas
Steam Production
• Purpose Provide steam for process heating, steam stripping in distillation, and steam turbine drivers • Multiple Boilers at various steam pressure levels • Certain Process Units are net producers of steam from waste heat
Waste Water Treatment • Purpose Remove Oil, Grease and other contaminants from Refinery Waste Water to meet discharge permit requirements • Many processes combined to meet specific refinery waste characteristics and discharge requirements • Oil removal and biological treatment are 1st step • Can be re-‐used, injected underground or sent to waterrway
Waste Water Treatment
A refinery typically uses more water than crude oil!
Particulate Emission Control • Wet gas scrubbing (WGS) is very efficient (>90%) for removal of particulates (4–10 mm) from the FCC regenerator exit. Cyclones could be the first choice clean-‐up device for particulates. • Electrostatic precipitators (ESP) employ an electrostatic field to apply a charge to particulate emissions and then collect them on grounded metal plates. ESP units are very efficient (99.8%) for removing finer (4–10 mm) particulates from FCC regenerator gas.
Treatment of FCCflue gases byWGS
Treatment of FCC flue gases by ESP
Exercise 1. Calculating Properties Utilizing UNISIM Software Process simulators are used to characterize crude oil and determine the thermophysical properties of crude oil and fractions. UNISIM simulator can be utilized in defining pseudo-‐components of a crude oil, given its crude assay. It provides the option of selecting the thermodynamic model for vapour–liquid equilibrium and thermodynamic properties calculations. It is recommended to use Peng–Robinson equation of state to model hydrocarbon and petroleum mixtures in UNISIM. Detailed
Consider the following crude assay which has API = 29 à Use UNISIM to divide the crude into 10 pseudo-‐components and calculate all cut properties.
Solution: • The crude assay (vol% versus TBP) is entered the oil environment and oil manager data entry of UNISIM, and the number of pseudo-‐components (10 cuts) is entered in the Blend calculation. The properties calculated by UNISIM are listed in Table .1.
Exercise 2: Design of Crude Distillation Units Using Process Simulators The simulation or design of the distillation columns involves dividing the crude oil into pseudo-‐components (Exercise 1). Then a thermodynamic model is chosen for vapour liquid equilibrium and thermodynamic properties calculations. A good model is the cubic equations of state, and the Peng–Robinson equation is one of the most widely used models for hydrocarbon and petroleum mixtures. Next, the unit operations stage-‐wise or ‘‘tray to tray’’ distillation calculations are performed. The mass, energy balance and vapour liquid equilibrium relations for each tray are written and solved together, subject to certain specification for the products. Computer simulation programs such as UNISIM are used for quick simulation of CDU units.
Perform a material balance for a CDU using UNISIM for 100,000 BPCD of 29 API crude with the following assay. • The crude is fed to a pre-‐flash separator operating at 450 F and 75 psia. The vapour from this separator bypasses the crude furnace and is remixed with the hot (650F) liquid leaving the furnace. • The combined stream is then fed to the distillation column (Figure 1). The column operates with a total condenser, three side strippers and three pumparounds (Figure 2).
Figure 1
Figure 2
Solution: In the oil environment and oil manager data entry of the UNISIM software, the crude assay is entered as vol% and TBP. The yield distribution of the products is shown in Figure 3. The distillation column has three inlet steam streams, with pressures and flow rates listed in Table 1. The main distillation column contains 29 stages (see Figure 2). The overhead condenser operates at 19.7 psia and the bottoms at 32.7 psia. The side stripper connections are also shown in Figure 2.
Figure 3.
Exercise 3: Simulation of ARDS Unit • A heavy residue stream that contains mostly n-‐C30 (990 lb mol/h) and some amount of thiophene (10 lb mol/h) is prepared to enter an ARDS process to crack the heavy component n-‐C30 to more lighter components such as n-‐C20, n-‐C10 and n-‐C4. In addition, thiophenes should be completely removed. The feed stream is initially at 100F and 120 psia. This feed needs to be mixed with hydrogen stream (1250 lb mol/h) available at 150F and 200 psia. The mixed feed should be heated and compressed to 700F and 1500 psia before entering the reactor. The reactions are shown in Table. • The reactor products are cooled to 200F before entering a gas–liquid separator. 300 lb mol/h of the hydrogen coming from this separator is recycled back with the feed. The rest is vented to the atmosphere. The liquid stream coming out from the separator is then expanded by a valve to reduce the pressure to 250 psia. This makes it ready to enter a distillation column in order to separate the extra hydrogen left with the hydrocarbons. A typical flowsheet of the ARDS process is shown in Figure. Perform a material and energy balance for the ARDS process using UNISIM simulator.
Solution: 1. Enter the simulation basis environment in UNISIM. 2. Add the components as follows: Thiophene, n-‐C30, n-‐C20, n-‐C10 , n-‐C4, H2 and H2S. 3. Select Peng–Robinson as the fluid package. 4. Insert Reaction-‐1 stoichiometry and conversion and do the same for Reaction-‐2. 5. Enter simulation environment. 6. Insert the first unit for the oil feed as shown in the flow chart with compositions, temperature and pressure as given in Table 2. 7. Continue inserting units as shown in the flowsheet. 8. The reactor is a conversion reactor. 9. The distillation column is 15 trays with reflux ratio equal to 1.0 and full reflux. The active specification to run the distillation column is a hydrogen recovery of 100% and an n-‐decane recovery of 90%. 10. Finally, add the recycle control unit to optimize the connections.
UNISIM results
References • Chang Samuel Hsu and Paul R. Robinson, Practical Advances in Petroleum Processing, Vol 1, Springer, 2006 • Mohamed A. Fahim, Taher A. Alsahhaf and Amal Elkilani, Fundamentals of Petroleum Refining, Elsevier, 2010
Outline Unit 1. Introduction Unit 2. Refinery Feedstocks and Products Unit 3. Modern Petroleum Processing Unit 4. Auxiliary Processes & Utilities
Unit 1. Introduction Largest Worldwide Refineries Approximately 650 Refineries in the world
Source: Oil & Gas Journal
Unit 1. Introduction • High sulfur, heavy crude is lowest cost. àRequires extremely complex refinery to convert into high value products. • Low sulfur, light crude is highest cost. à Simple refining yields high value products. • a function of location of crude supply versus refining centers. à Refiners close to crude production enjoy advantage over refineries distant from supply
Unit 1. Introduction
Unit 1. Introduction
Note: product blending and sulfur recovery units are not shown, but these are almost always present
Unit 1. Introduction • DQR Introduction • NSRP Introduction
Unit 2. Refinery Feedstocks and Products 2.1. Composition of Crude Oils 2.2. Products Composition 2.3. Physical Property Characterization Data 2.4. Chemical Analysis Data
2.1. Composition of Crude Oils Impurities (sulphur, nitrogen, oxygen and metals): -‐ low concentrations -‐ undesirable -‐ affect the quality of the produced products -‐ Catalyst poisoning and corrosion
2.1. Composition of Crude Oils Hydrogen to carbon ratios affect the physical properties of crude oil. -‐ As the hydrogen to carbon ratio decreases, the gravity and boiling point of the hydrocarbon compounds increases. -‐ the higher the hydrogen to carbon ratio of the feedstock, the higher its value is to a refinery because less hydrogen is required.
2.1. Composition of Crude Oils
2.1. Composition of Crude Oils Hydrocarbons: -‐ Paraffins -‐ Olefins are not naturally present in crude oils but they are formed during the conversion processes -‐ Naphthenes (cycloalkanes): Mutli-‐ring naphthenes are present in the heavier parts of the crude oil -‐ Aromatics Polynuclear aromatic compounds are found in the heavy petroleum cuts à cause catalyst deactivation and coke deposition during processing à environmental problems
2.1. Composition of Crude Oils
2.1. Composition of Crude Oils -‐ Sulphur Compounds
• varies from less than 0.05 to more than 10 wt% (but generally falls in the range 1–4 wt%). • Crude oil with less than 1 wt% sulphur is referred to as low sulphur or sweet, and that with more than 1 wt% sulphur is referred to as high sulphur or sour. • Sulphur heteroatoms • inorganic forms: elemental sulphur S, dissolved hydrogen sulphide H2S, carbonyl sulphide COS • organic forms: mercaptans and sulphides, Sulphides and disulphides, Thiophenes
2.1. Composition of Crude Oils -‐ Oxygen Compounds • less than 2 wt%. • include alcohols, ethers, carboxylic acids, phenolic compounds, ketones, esters and anhydrides. • causes the crude to be acidic with consequent processing problems such as corrosion.
2.1. Composition of Crude Oils -‐ Nitrogen Compounds
• Crude oils contain very low amounts of nitrogen compounds. • the more asphaltic the oil, the higher its nitrogen content. • more stable than sulphur compounds à harder to remove. • be responsible for the poisoning of a cracking catalyst, and contribute to gum formation in finished products. • The nitrogen compounds in crude oils may be classified as basic or non-‐basic. • Basic nitrogen compounds: pyridines. • Non-‐basic nitrogen compounds: pyrrole types.
2.1. Composition of Crude Oils -‐ Metallic Compounds • • • • • • • •
exist in all crude oil types in very small amounts cause operational problems and contaminate the products, affect upgrading processes cause poisoning to the catalysts used for hydroprocessing and cracking. small amounts of metals (iron, nickel and vanadium) in the feedstock to the catalytic cracker affect the activity of the catalyst à increased gas and coke formation and reduced gasoline yields. For high-‐temperature power generators, the presence of vanadium in the fuel may lead to ash deposits on turbine blades and cause severe corrosion, and the deterioration of refractory furnace linings. inorganic water-‐soluble salts, mainly as chlorides and sulphates of sodium, potassium, magnesium and calcium à removed in desalting operations. oil-‐soluble organometallic compounds: Zinc, titanium, calcium and magnesium appear in the form of organometallic soaps. oil-‐soluble compounds: vanadium, nickel, copper and iron àcomplexing with pyrrole compounds.
2.1. Composition of Crude Oils -‐ Asphaltenes: -‐ condensed polynuclear aromatic layers linked by saturated links, -‐ lead to coke formation and metal deposition on the catalyst surface causing catalyst deactivation. -‐ Resins -‐ polar molecules in the molecular weight range of 500–1000, -‐ insoluble in liquid propane but soluble in n-‐heptane. -‐ responsible for dissolving and stabilizing the solid asphaltene molecules in petroleum. The resin molecules surround the asphaltene clusters (micelles) and suspend them in liquid oil. Because each asphaltene is surrounded by a number of resin molecules, the content of resins in crude oils is higher than that of the asphaltenes.
2.2. Products Composition -‐ Liquefied Petroleum Gas (LPG) -‐ Gasoline -‐ Kerosene -‐ Jet Fuel -‐ Diesel Fuel -‐ Fuel Oil (Residual Fuel Oil) -‐ Lube Oil -‐ Asphalt -‐ Petroleum Coke
2.2. Products Composition
2.2. Products Composition
2.2. Products Composition
2.2. Products Composition Major quality aspects of main petroleum products
2.2. Products Composition
2.3. Physical Property Characterization Data 2.3.1. Fractionation
2.3.10. Aniline Point
2.3.2. True Boiling Point Distillation
2.3.11. Flash Point
2.3.3. ASTM Distillation
2.3.12. Octane Number
2.3.4. Simulated Distillation by Gas Chromatography
2.3.13. Cetane Number 2.3.14. Smoke Point
2.3.5. API Gravity 2.3.6. Pour Point 2.3.7. Viscosity 2.3.8. Refractive Index 2.3.9. Freezing Point
2.3.15. Reid Vapour Pressure 2.3.16. Water, Salt and Sediment 2.3.17. Molecular Weight
2.4. Chemical Analysis Data 2.4.1. Elemental Analysis 2.4.2. Carbon Residue 2.4.3. Detailed Hydrocarbon Analysis 2.4.4. Hydrocarbon Family Analysis 2.4.5. Aromatic Carbon Content 2.4.6. SARA Analysis
ASTM testing grid for crude oil and petroleum fractions
Unit 3. Modern Petroleum Processing
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.1.1. Distillation • the biggest unit in most plants • Many downstream conversion units also use distillation for production separation • To reduce corrosion, plugging, and fouling in crude heaters and towers, and to prevent the poisoning of catalysts in downstream units, these contaminants are removed by a process called desalting
3.1.1. Distillation
Atmospheric distillation • At the bottom of the stripping section, steam is injected into the column • to strip the atmospheric residue of any light hydrocarbon and • To lower the partial pressure of the hydrocarbon vapours in the flash zone. àlowering the boiling point of the hydrocarbons àcausing more hydrocarbons to boil and go up the column to be eventually condensed and withdrawn as side streams.
Vacuum Distillation -‐ residue from an atmospheric distillation tower -‐ The vacuum, which is created by a vacuum pump or steam ejector, is pulled from the top of the tower. -‐ vacuum columns have larger diameters and their internals are simpler (random packing and demister pads are used) -‐ The overhead stream à lube base stock, heavy fuel oil, or as feed to a conversion unit -‐ The vacuum residue à asphalt, or feedstock for coker or visbreaker unit
3.1.2. Solvent Refining a. Solvent Deasphalting b. Solvent Extraction c. Solvent Dewaxing, Wax Deoiling
a. Solvent Deasphalting (SDA) • Solvent deasphalting takes advantage of the fact that aromatic compounds are insoluble in paraffins. • Propane deasphalting is commonly used to precipitate asphaltenes from residual oils. • Deasphalted oil (DAO) is sent to hydrotreaters, FCC units, hydrocrackers, or fuel-‐oil blending. In hydrocrackers and FCC units, DAO is easier to process than straight-‐run residual oils. This is because asphaltenes easily form coke and often contain catalyst poisons such as nickel and vanadium, and the asphaltene content of DAO is (by definition) almost zero.
a. Solvent Deasphalting (SDA) • An advanced version of solvent deasphalting is “residuum oil supercritical extraction,” or ROSE. • In this process, the oil and solvent are mixed and heated to above the critical temperature of the solvent, where the oil is almost totally insoluble • Advantages include higher recovery of deasphalted liquids, lower operating costs due to improved solvent recovery, and improved energy efficiency. • The ROSE process can employ three different solvents, -‐ Propane: Preparation of lube base stocks -‐ Butane : Asphalt production -‐ Pentane: Maximum recovery of liquid
Schematic of the ROSE process
Refinery with solvent deasphalting, Rose-‐residue oil supercritical extraction unit
b. Solvent Extraction • to remove aromatics and other impurities from lube and grease stocks. • The solvent is separated from the product stream by heating, evaporation, or fractionation. • Remaining traces of solvent are removed from the raffinate by steam stripping or flashing. • NMP, phenol, furfural, and cresylic acid are widely used as solvents.
c. Solvent Dewaxing, Wax Deoiling • Solvent dewaxing removes wax (normal paraffins) from deasphalted lube base stocks. • The main process steps include mixing the feedstock with the solvent, chilling the mixture to crystallize wax, and recovering the solvent. • Commonly used solvents include toluene and methyl ethyl ketone (MEK). • Methyl isobutyl ketone (MIBK) is used in a wax deoiling process to prepare food-‐grade wax.
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.2.1. Thermal cracking • Visbreaking • Delayed Coking • Fluid Coking
3.2.1. Thermal cracking Visbreaking • Feed: AR or VR • Mild heating 471–493 C (880–920 F) at 50–200 psig • Reduce viscosity of fuel oil • Low conversion (10%) at 221oC (430F) • Heated coil or soaking drum • Products: gases, naphtha, gas oil, reridue or tar
Delayed coking • Feed: VR, FCC slurry, visbreaking tar • Moderate heating 482–516oC (900–960F) at 90 psig • Soak drums 452–482oC (845– 900F)
Fluid coking and flexicoking • Feed: VR • Severe heating 482–566oC (900–1050F) at 10 psig • Fluidized bed with steam • Higher yields of light ends
• Less coke yield (20% for • Residence time: until they are fluid coking and 2% for full of coke flexicoking) • Coke is removed hydraulically • Products: gas, naphtha, • Coke yield 30 wt%, unsaturated gases, LN, HN, LCO, HCO
LCO, HCO, coke
Visbreaking
(A) Coil type visbreaker. • •
more stable visbreaker products more flexible and allows the production of heavy cuts, boiling in the vacuum gas oil range
(B) Soaker type visbreaker • less capital investment, • consumes less fuel • longer on-‐stream times
Delayed coking
3.2.2. Fluid Catalytic Cracking • A typical FCC unit comprises three major sections • riser/reactor, • Regenerator • fractionation.
• Purpose • Convert heavy oils into gasoline and/or light olefins
• Licensors • Axens (IFP) • KBR • UOP
ExxonMobil Stone & Webster
3.2.2. Fluid Catalytic Cracking • Catalysts and Additives • • • • •
Zeolite (highly acidic, catalyzes cracking) Rare-‐earth oxide (increases catalyst stability) ZSM-‐5 (increases octane and production of light olefins) Pt (promotes combustion of CO to CO in regenerator) Desox (transfers SOx from regenerator to riser/reactor) .
• Feeds • Atmospheric gas oil • Coker gas oil • Lube extracts
Vacuum gas oil Deasphalted oil Vacuum resid (up to 20 vol%)
3.2.2. Fluid Catalytic Cracking • Typical Feed Properties • • • •
Nitrogen Carbon residue Nickel + Vanadium 90% boiling point
<3000 wppm <5.0 wt% <50 wppm <1300°F (704°C)
• Typical Process Conditions • • • • •
Feed temperature Reactor temperature Regenerator temperature Catalyst/Oil ratio Reactor pressure
300 – 700°F (150 – 370°C) 920 – 1020°F (493 – 550°C) 1200 – 1350°F (650 – 732°C) 4.0 – 10.0 10 – 35 psig (170 – 343 kPa)
3.2.2. Fluid Catalytic Cracking • Typical Product Yields • • • • • • • • •
Conversion H2, H2S, methane, ethane Propane and propylene Butanes and butenes Gasoline LCO Slurry oil Coke Total C3-‐ plus
70 – 84 vol% 3.0 – 3.5 wt% 4.5 – 6.5 wt% 9.0 – 12.0 wt% 44 – 56 wt% 13 – 20 wt% 4 – 12 wt% 5 – 6 wt% 106 – 112 vol%
3.2.3. Hydrotreating and hydrocacking
LGO = Light Gas Oil HCO = FCC Heavy Cycle Oil
HGO = heavy Gas Oil VGO = Vacuum Gas Oil
LCO = FCC Light Cycle Oil VBGO = Visbreaker Gas Oil
CGO = Coker Gas Oil
3.2.3. Hydrotreating and hydrocacking
3.2.3. Hydrotreating and hydrocacking
Role of hydrotreating (HT) in the refinery 1. Meeting finished product specification. • Kerosene, gas oil and lube oil desulphurization. • Olefin saturation for stability improvement. • Nitrogen removal. • De-‐aromatization for kerosene to improve cetane number, 2. Feed preparation for downstream units: • Naphtha is hydrotreated for removal of metal and sulphur. • Sulphur, metal, polyaromatics and Conradson carbon removal from vacuum gas oil (VGO) to be used as FCC feed. • Pretreatment of hydrocracking feed to reduce sulphur, nitrogen and aromatics.
Naphtha hydrotreating unit
Diesel fuel hydrotreating unit
Atmosphere residue desulphurization process
3.2.3. Hydrotreating and hydrocacking
3.2.3. Hydrotreating and hydrocacking
Unit 3. Modern Petroleum Processing 3.1. SEPARATION 3.1.1. Distillation 3.1.2. Solvent Refining 3.2. CONVERSION 3.2.1. Thermal cracking 3.2.2. FCC 3.2.3. Hydrotreating and hydrocracking 3.3. UPGRADING NAPHTHA 3.3.1. Catalytic Reforming 3.3.2. Isomerization 3.3.3. Catalytic Oligomerization 3.3.4. Alkylation
3.3.1. Catalytic Reforming
3.3.1. Catalytic Reforming
3.3.2. Isomerization
3.3.2. Isomerization
Sơ đồ công nghệ Penex
Sơ đồ quá trình Penex kết hợp với Deisohexane
3.3.3. Catalytic Oligomerization ΔH < 0
• Catalysts: • Sulfuric acid, phosphoric acid, and solid phosphoric acid on kieselguhr pellets (SPA) are used as catalysts. • The SPA catalyst is non-‐corrosive, so it can be used in less-‐expensive carbon-‐steel reactors.
• Temperatures: 300 to 450°F (150 to 230°F) • Pressures: 200 to 1,200 psig (1480 to 8375 kPa).
3.3.3. Catalytic Oligomerization
UOP’s indirect Alkylation (LnAlk) process
SPA: solid phosphoric acid
3.3.4. Alkylation
(H2SO4, HF)
3.3.4. Alkylation • • • •
Zeolite catalyst Liquid phase 50 – 90oC uncommercialized
Unit 4. Auxiliary Processes & Utilities • Steam Methane Reformer (hydrogen production) • Light Ends Recovery Units • Lube Oil Units • Amine Treater • Caustic and Merox Treaters • Sulfur Recovery, Tail Gas Treating, NaHS Units • Sour Water Strippers • Water Treating (de-‐ionization) • Steam Production
Waste Water Processing Relief Systems and Flares Plant and Instrument Air Flare Gas Recovery Units MSAT Benzene Reduction Units (similar to ISOM unit) • Nitrogen Systems • Electrical Systems • • • • •
Energetic issues in an oil refinery Energy by source in an oil refinery Other 7% Electricity 5% Natural gas 25% Petroleum coke 17%
• Refinery gas + petroleum coke + other oil-‐based by-‐products accounts for 65% of the energy sources in an oil refinery.
Refinery gas 46%
• 38% of the energy sources in an oil refinery are used to produce non-‐fuel products like lubricant oils, wax, asphalt, and petrochemical feedstocks. • Oil refineries generate large amounts of electricity on-‐site. • The cost of energy for heat and power accounts for c.a. 40% of the operating costs in a refinery!!!
Energetic issues in an oil refinery [Worrell 2005]
Sulfur Recovery • Purpose Converts H2S gas into elemental sulfur, “Claus” Unit • 1/3 of H2S burned in Reaction Furnace to produce SO2 (sulfur dioxide) 1.5 O2 + H2S àSO2 + H2O • Zinc Oxide catalyst beds convert SO2 and H2S into elemental sulfur and water SO2 + 2H2S à3S + 2H2O • Sulfur is collected in pit or tank and trucked / railed. Used in chemical manufacture. • Process is about 96% efficient, so Tail Gas Treating (SCOT Unit or other) required to purify off gas
Steam Production
• Purpose Provide steam for process heating, steam stripping in distillation, and steam turbine drivers • Multiple Boilers at various steam pressure levels • Certain Process Units are net producers of steam from waste heat
Waste Water Treatment • Purpose Remove Oil, Grease and other contaminants from Refinery Waste Water to meet discharge permit requirements • Many processes combined to meet specific refinery waste characteristics and discharge requirements • Oil removal and biological treatment are 1st step • Can be re-‐used, injected underground or sent to waterrway
Waste Water Treatment
A refinery typically uses more water than crude oil!
Particulate Emission Control • Wet gas scrubbing (WGS) is very efficient (>90%) for removal of particulates (4–10 mm) from the FCC regenerator exit. Cyclones could be the first choice clean-‐up device for particulates. • Electrostatic precipitators (ESP) employ an electrostatic field to apply a charge to particulate emissions and then collect them on grounded metal plates. ESP units are very efficient (99.8%) for removing finer (4–10 mm) particulates from FCC regenerator gas.
Treatment of FCCflue gases byWGS
Treatment of FCC flue gases by ESP
Exercise 1. Calculating Properties Utilizing UNISIM Software Process simulators are used to characterize crude oil and determine the thermophysical properties of crude oil and fractions. UNISIM simulator can be utilized in defining pseudo-‐components of a crude oil, given its crude assay. It provides the option of selecting the thermodynamic model for vapour–liquid equilibrium and thermodynamic properties calculations. It is recommended to use Peng–Robinson equation of state to model hydrocarbon and petroleum mixtures in UNISIM. Detailed
Consider the following crude assay which has API = 29 à Use UNISIM to divide the crude into 10 pseudo-‐components and calculate all cut properties.
Solution: • The crude assay (vol% versus TBP) is entered the oil environment and oil manager data entry of UNISIM, and the number of pseudo-‐components (10 cuts) is entered in the Blend calculation. The properties calculated by UNISIM are listed in Table .1.
Exercise 2: Design of Crude Distillation Units Using Process Simulators The simulation or design of the distillation columns involves dividing the crude oil into pseudo-‐components (Exercise 1). Then a thermodynamic model is chosen for vapour liquid equilibrium and thermodynamic properties calculations. A good model is the cubic equations of state, and the Peng–Robinson equation is one of the most widely used models for hydrocarbon and petroleum mixtures. Next, the unit operations stage-‐wise or ‘‘tray to tray’’ distillation calculations are performed. The mass, energy balance and vapour liquid equilibrium relations for each tray are written and solved together, subject to certain specification for the products. Computer simulation programs such as UNISIM are used for quick simulation of CDU units.
Perform a material balance for a CDU using UNISIM for 100,000 BPCD of 29 API crude with the following assay. • The crude is fed to a pre-‐flash separator operating at 450 F and 75 psia. The vapour from this separator bypasses the crude furnace and is remixed with the hot (650F) liquid leaving the furnace. • The combined stream is then fed to the distillation column (Figure 1). The column operates with a total condenser, three side strippers and three pumparounds (Figure 2).
Figure 1
Figure 2
Solution: In the oil environment and oil manager data entry of the UNISIM software, the crude assay is entered as vol% and TBP. The yield distribution of the products is shown in Figure 3. The distillation column has three inlet steam streams, with pressures and flow rates listed in Table 1. The main distillation column contains 29 stages (see Figure 2). The overhead condenser operates at 19.7 psia and the bottoms at 32.7 psia. The side stripper connections are also shown in Figure 2.
Figure 3.
Exercise 3: Simulation of ARDS Unit • A heavy residue stream that contains mostly n-‐C30 (990 lb mol/h) and some amount of thiophene (10 lb mol/h) is prepared to enter an ARDS process to crack the heavy component n-‐C30 to more lighter components such as n-‐C20, n-‐C10 and n-‐C4. In addition, thiophenes should be completely removed. The feed stream is initially at 100F and 120 psia. This feed needs to be mixed with hydrogen stream (1250 lb mol/h) available at 150F and 200 psia. The mixed feed should be heated and compressed to 700F and 1500 psia before entering the reactor. The reactions are shown in Table. • The reactor products are cooled to 200F before entering a gas–liquid separator. 300 lb mol/h of the hydrogen coming from this separator is recycled back with the feed. The rest is vented to the atmosphere. The liquid stream coming out from the separator is then expanded by a valve to reduce the pressure to 250 psia. This makes it ready to enter a distillation column in order to separate the extra hydrogen left with the hydrocarbons. A typical flowsheet of the ARDS process is shown in Figure. Perform a material and energy balance for the ARDS process using UNISIM simulator.
Solution: 1. Enter the simulation basis environment in UNISIM. 2. Add the components as follows: Thiophene, n-‐C30, n-‐C20, n-‐C10 , n-‐C4, H2 and H2S. 3. Select Peng–Robinson as the fluid package. 4. Insert Reaction-‐1 stoichiometry and conversion and do the same for Reaction-‐2. 5. Enter simulation environment. 6. Insert the first unit for the oil feed as shown in the flow chart with compositions, temperature and pressure as given in Table 2. 7. Continue inserting units as shown in the flowsheet. 8. The reactor is a conversion reactor. 9. The distillation column is 15 trays with reflux ratio equal to 1.0 and full reflux. The active specification to run the distillation column is a hydrogen recovery of 100% and an n-‐decane recovery of 90%. 10. Finally, add the recycle control unit to optimize the connections.
UNISIM results
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