Icarus-ORM Academy Oil & Gas Industry Process Hazards Guidebook 2021 PDF

THE OIL AND GAS INDUSTRY PROCESS B Y : I C A R U S - O R M A C A D E M Y  4 PRODUCTI...

THE OIL AND GAS INDUSTRY PROCESS B Y : I C A R U S - O R M A C A D E M Y  4 PRODUCTI 1 WHAT IS A WELLHEAD? A wellhead is the structure at the surface of a well that comprises of valves, spools and adapters. The main function of a wellhead is to control the pressure from the well to ensure safe operation and to manage the fl ow from the well. In An overvieW ON later stages of the life of a well, the wellhead can also provide a means of gas injection or attaching a p u m p to increase production. This is the start of the oil and gas value stream. Oil and gas wells are installed after drilling is complete. Oil and gas wells typically produce a mixture of hydrocarbon gases, liquids 2 Relie and water. In order to obtain the gas- liquid mixture from the well, a Emulsion from the well can f wellhead is implemented at the surface. The mixture is then sent to a fl ow to one of two separator and metered for accounting before being processed. headers, the group separator header or the test separator. Ga s 1 Pressures in the well can exceed 20, 0 0 0 kPag and requires pressure control to bring the pressure d o w n to a more manageable range. Condensa te Wate r HOW DOES A A separator takes SEPARATOR the gas liquid mixture WORK? - from the wellheads and divides it into three components - water, condensate, and gas. This is achieved by moving the mixture slowly through the separator. Due to the varying fl uid densities, the different components will stratify. The water will settle at the bottom , while the condensate floats on top , separating by overflowing to the other side of the weir. The gas fills the space above the liquid interface. The group separator takes fl ow from all the wells and separates the phases into produced gas, produced condensate, and produced water, Emulsio which is metered for accounting purposes before being recombined and sent to a gas processing facility. The test separator header takes fl ow from one well, and separates the phases into produced gas, produced condensate, and produced water n for well monitoring and production accounting. PRODUCTION Important process parameters  4 GAS 8 Compressor stages typically have a compression ratio between 2.5 and 3.5, meaning that if a system needs to increase pressure from 1000 to 9000 kPag , it would require 2 stages, with an approximate compression ratio An COMPRESSION of 3.0. Across the first stage the pressure increases from 1000 to 3000 kPag , and across the second stage the overvieW pressure would increase from 3000 to 9000 kPag. A compressor is a mechanical piece of equipment that is used to increase the pressure and reduce the volume of a gas stream. It is critical Flar in natural gas processing , transportation , and delivery of natural gas to our PS e homes. V Most types of compressors require a suction scrubber to remove any liquids in the stream prior to compressing the gas. Liquids are not compressible and can cause catastrophic damage in the compressor. Demister r Coole Pad Inlet Separat Gas Compress or or The recycle line maintains suction Liquid During compression , the temperature can pressure and allows s increase significantly. The outlet of most the compressor to compressors is around 140-160C. It's operate even when important to cool the stream after there is no supply of compression so downstream equipment gas coming into Drain does not need to be designed for the the compressor. System higher temperature. Outlet Gas During compression , significant energy is put into the system. Any area where energy is being put into a system is important to evaluate in a PHA , as there are usually several hazards associated with the process. When evaluating a compressor in a PHA , it is important to know what type of compressor it is and to have a general understanding of how it functions. The type of compressor can significantly impact the consequences of different scenarios. Two of the common types of compressors are reciprocating and centrifugal.  5 GAS 0 COMPRESSION PROCESS Important ProcessIMPORTANCE PARAMETERS Parameters Understand normal operating and ma incoming pressure to determine if there is a source of overpressure from blocked flow PRESSURE Understand max compressor discharge pressure and determine if it can overpressure discharge pressure Determine equilibrium pressure of the compressor on shutdown and determine if settle-out overpressure is credible Understand normal operating and max incoming temperature to determine if there is a source of over TEMPERATURE temperature Determine if there is a concern for hydrate formation based on operating temperatures and potential pressure drops in the system LEVEL Understand response time available to liquids accumulating in the scrubber FLOW RATE Understand compressor size and PSV sizing requirements COMPOSITION Understand flammability / toxicity to determine consequences of a gas release Hydrates Hydrates form in solutions that contain water and gas, like emulsion. Under high pressures and low temperatures, the water/gas structure will form a crystalline solid that can block fl ow in pipe. Hydrates can be a concern in compressors due to changing pressures from compressing and recycling gas, as well as the wide temperature operating range due to heating from compression and then after-cooling.  5 TANK 7 FARMS A tank farm may contain one type of product or a variety. Common products stored in tank farms An Tanks farms , also called oil terminals , are storage facilities for hydrocarbon liquids. Products supplied from upstream or midstream include : diesel , gasoline , NGLs , crude , waste water , etc. The type overvieW facilities are transported via pipeline , truck , train or boat and loaded into tanks. There it can be stored until it is required for further and material of a tank depend on the stored product properties. processing or to be used downstream. The storage capacity of a tank farm manages fluctuations in supply upstream and demand downstream to prevent costly delays in distribution.  5 TANK FARMS 9 Important process parameters PROCESS IMPORTANCE PARAMETERS T E M P E R AT U R E Temperature monitoring and control is important for maintaining temperature within tank rated limits P R E SS U R E Important for understanding potential blocked flow and reverse flow overpressure Level control is important for understanding high leveling/filling and low leveling/draining LEVEL thresholds Tank level is important for preventing a floating roof from sinking or reaching the top Controlling fill rate is important in preventing static ignition of product F LO W RATE Flow rate is also important for determining the response time required to prevent overfilling a tank Maximum roof speed is important in determining maximum flow rate of product in or out of the tank Vapourization of a product is important in understanding how much vapour is expected to be released from the COMPOSITION tank H2S concentration is important in understanding dispersion from tank vents and potential flammability of any releases Tank elevation is important in determining if equalization/draining is possible between two connected tanks or E L E VAT I O N from a tank back to another flowpath  6 TANK 0 Tank features FARMS There are two main categories of tank roofs: fixed and floating. Fixed roofs are solidly connected to the top of the tank wall and are either welded or bolted to remain stationary during the operation of the tank. They can be flat cylinders , cones , or domed shaped. Floating roofs can be internal or external. Both have a roof that floats on the liquid level in the tank that can move up or down as the product level rises and falls. An internal floating roof has an additional fixed roof at the top of the tank , while an external floating roof tank only uses the floating roof to separate tank contents from the environment. Tanks can have many other components like coatings , insulation , mixers , etc. depending on the products that are stored , the size of the tank , the temperature limitations and other factors. Some common tank features including those used as safeguards are shown in the tanks below. Vent PSV Thief Hatch Fixed Roof Fixed Roof Pressure Vacuum Internal Floating Valve Roof Seal Coating Vapour Space Floating Roof Insulation Level Overflow Floating Roof Gauge Line Level Radar Floating Roof Support Legs Mixer External Floating Internal Floating Fixed Roof Roof Roof  6 RAIL 6 An overvieW TERMINAL Transportation of hydrocarbons can be performed by pipeline trucking or rail , , available infrastructure all play a role in deciding if rail is a practical solution.. The volume to be transported , geography , and 1 The product is brought into the terminal by tank cars. The tank cars contain hydrocarbon liquids and fl ammable vapours. 4 Product from the tank car is stored in tanks. Multiple tanks may be used for diff erent products. 2 3 Hoses with A p um p is used to special couplings can be p um p liquid product to the tank from the bottom of attached remove the the tank car to the cars to In many product storage tank at the. cases facility ,. product can be removed from tank cars at multiple once.  67 W H A T T Y P E S O F PRO D U C T S C A N B E TRA N S P ORT E D B Y RA I L ? Rail cars can be used to transport liquid hydrocarbons and pressurized gases. The design of the tank car, including the pressure rating and material, dictates which type of product it can carry. Common commodities include crude oil, ethanol, diesel, etc. 40,0 0 0 30,0 T O T A L CRU D E 0 0 TRA N S P ORT E 20,0 D B Y RA I L ( T H 0 0 O U S A N D B A RR 10,0 0 ELS) IN UNIT 0 ED STATES 0 0 5 S1 - S1 - 20 - S1 - S1 - S1 - S1 - S1 - S1 - S1 - S1 - - - - - - - - - - - 20 7n- 20 8n- 20 9n- 20 3n- 20 4n- 20 5n- 20 6n- 20 0n- 20 1n- 20 2n- 20 n- 20 a8y 20 a9y 20 a0y 20 a6y 20 a7y 20 a2y 20 a3y 20 a4y 20 a1y 20 a5y 20 a0y 20 e7p 20 e8p 20 e3p 20 e4p 20 ep 20 e6p 20 e9p 20 ep 20 e1p 20 e2p J1a M1 J1a M1 J1a M2 J1a M1 J1a M1 J1a M1 J1a M1 J1a M1 J1a M1 J1a M1 Ja M1 MONTH - YEAR RA I L V S. P I P E L I N E S TRU C T UR AL While rail transportation can be two to three times more costly than transportation by pipeline, rail networks can respond quickly to new C O N S I D ER production One of A theT biggest IONS concerns in different oil fields. Rail transportation is also a good alternative when there is for rail transportation is no pipeline infrastructure in place. For example, exports of crude oil by rail in derailment. Tank cars can Canada more than doubled in 2018, from 146 million barrels per day in January rupture on impact if they to 354 million barrels per day in December. This occured as production are not designed increased more than pipeline capacity. properly. Topfittings, heat shields, and valves can all Another situation where rail may be used instead of pipelines is for heavy be weak points. Using crude or bitumen, where diluent is required when transporting product by the correct couplings pipelines. on cars However, pipelines are generally considered a safer alternative, with a lower and ordering based cars and train on weight likelihood of a spill. While historically, between 1996 and 2007, there was less length correctly the decreases spilled crude oil from railroads than trucks or pipelines on a per ton - mile basis, likelihood of a derailment. in the year 2013 alone, the total volume of crude spilled from railways was greater than all spills from 1975 to 2012.  6 RAIL TERMINAL 9 Important process parameters PROCESS IMPORTANCE PARAMETERS It is important to understand the temperature of the product and the temperature rating of all equipment and TEMPERATURE piping It is important to understand any areas where trapped fluid could cause a thermal overpressure High temperature product going into the storage tank could cause vaporization It is important to understand potential blocked flow and reverse flow overpressure from pressure sources PRESSURE such as pumps Pressure rating of tanks is important to determine if overpressure or pulling a vacuum are credible scenarios Level in the rail car is important to prevent cavitating the pumps LEVEL Level in the spit tank and product storage tank are important to prevent overfilling and loss of containment Filling the tank too quickly could lead to tank roof damage FLOW RATE If there is a flow meter on the system, overspinning the meter may cause meter damage Product can come from a variety of courses, so contamination of the product storage tank can be a COMPOSITION concern Precautions should be taken against impurities which could cause increased corrosion  7 SOUR GAS 4 7 Acid gas can either be sent to a Claus reaction process to produce elemental sulphur , or to an acid gas injection An TREATING compressor. 9 overvieW 3 Lean amine is p u m p e d from the regenerator Coole r Acid Gas Sweet tower back into the Gas contactor tower. Ami n e is Sw e e t e ne d gas stripped of cooled to be t w e e n 40 - H2S and CO2 exits the top 60 ° C. 2 of the contactor Refl u x Lean amine enters the top of the contactor tower Coole and fl ows r e Temperatur d o w n w a rd through 6 the trays towerof. The Acid gas off the top of the amine absorbs H2S re Temperatu regeneration tower is sent S H2 and CO2 from the to a condenser to recover 5 S H2 gas. water and ami ne w h i c h is Rich amine enters the sent back to the tower. regeneration tower and H2S and CO2 flashes off from the tower heat and drop in pressure as it fl ows d o w n the tower. Sour Gas Sour Lean Rich Gas Amine Amine 1 Heat Sour gas enters the input bottom of the tower , Rich contacting ami ne as it Amine rises up. 4 8 Ric h amine exits the The ami ne from the bottom of the tower and fl ows to bottom of the tower is sent to the flash dru m w h i c h Amine is used to " sweeten " natural gas, or a heater to flash off the operates at a m u c h lower remove H2S and CO2. Amine reacts with remaining H2S and CO2 pressure , flashing off some in the ami ne before it is of the absorbed gases. and binds H2S and CO2 into the liquid sent back to the phase to remove it from the gas stream. contactor. The terms rich and lean amine refer to the level of H2S and CO2 absorbed into the amine.  7 SOUR GAS 6 TREATING PROCESS Important processIMPORTANCE PARAMETERS parameters Temperature monitoring and control is important for maintaining adequate temperatures in the gas and amine systems to ensure proper H2S and CO2 removal T E M P E R AT U R E Temperature of the lean amine leaving the regenerator is important for ensuring amine is properly regenerated Also important for effective absorption and removal of H2S and CO2 from the amine Pressure is important for maintaining amine circulation in the system P R E SS U R E It is important for understanding potential blocked flow and reverse flow overpressure Also important for effective absorption and removal of H2S and CO2 from the amine Amine contactor tower level is important for preventing gas blowthrough to the LEVEL flash drum Flash drum level is important for preventing gas blowthrough to the regenerator Regenerator level is imporant for providing head pressure for amine flowing out the regenerator Controlling gas and amine flow rate is important for maintaining the correct ratio of gas / H2S for F LO W RATE adequate removal Reflux flow is important for maintaining the top temperature of the regenerator and preventing excess water / amine losses in the acid gas system H2S monitoring on the outlet gas is important to prevent sending H2S into the downstream sweet COMPOSITION gas system and ensuring the amine package is operating properly  8 GAS 1 Natural gas produced from wells usually has a high water content. This can cause several issues for natural gas operations including freezing and hydrate formation, as well as corrosion. It is important to remove An overvieW DEHYDRATION the water in order for the gas to meet sales specification requirements. 8 5 Lean glycol is pu mpe d into the top of the Rich glycol enters the stripping contactor and cooled prior to entering the tower and water begins to flash tower. The fl ow of glycol is controlled to ensure 2 out of the glycol from the Water an adequate gas to glycol fl ow ratio in the tower. pressure drop and increased Vapour Dry gas exits temperature. tower. the top of the 6 Dry Water vapour exits the top of the tower Gas with potential for some contaminants Cooler like benzene / toluene / ethyl- benzene / xylene (BTEX). Glycol Glycol Strippin Contactor g Tower 4 A heat exchanger Wet recovers heat from the Gas lean glycol which helps to preheat the rich Flash glycol before it enters Rich Gas the stripping tower. Glycol Glycol Flash Drum Hea 1 t Inpu Wet gas enters the glycol Heat t contactor and mixes Exchanger with glycol. Glycol exits Glycol the bottom of the 3 7 Reboiler contactor with water The glycol flash drum drops the pressure of stripped the gas from the glycol and allows any initial water vapour rich remaining Glycol is excess heatedwater content to remove stream. and trapped hydrocarbons to separate from to complete the regeneration. the liquid prior to the stripping tower.  8 GAS 3 DEHYDRATION PROCESS Important ProcessIMPORTANCE PARAMETERS Parameters Temperature monitoring and control is important for maintaining adequate temperatures in the gas and T E M P E R AT U R E glycol to maintain proper water removal from the gas stream Temperature of glycol leaving the regenerator is important for ensuring glycol is properly regenerated Pressure is important for maintaining amine circulation in the system P R E SS U R E Pressure is important for understanding potential blocked flow and reverse flow overpressure Pressure is important for effective absorption and removal of water from the glycol Glycol contactor tower level is important for preventing gas blowthrough to the flash LEVEL drum Flash drum level is important for preventing gas blowthrough to the stripping tower Regenerator level is important for maintaining flow of glycol out of the tower Controlling gas and glycol flow rate is important for maintaining the correct ratio of gas / H2S for adequate F LO W RATE removal Reflux flow is important for maintaining the top temperature of the regenerator and preventing excess glycol losses to downstream system Dewpoint / water content monitoring is important for ensuring gas leaving system meets proper COMPOSITION specifications / requirements  8 CONDENSATE 8 An STABILIZATION overvieW process to reduce the vapour pressure of Off Gas hydrocarbon liquids Stabilization is to make midstream an important them safer 6 and easier to transport. The gas off the top of the stabilizer and surge drum are sent downstream to a compressor to recover the flashed gases back into the gas Condensat Condensate Stabilized process. e Product Stabilizatio Cooler Condensat n Tower e 4 Gases flash out of 7 the condensate e Temperatur Stabilized condensate is sent downstream for stream due to the storage or to a p u m p skid for transportation. heat input into the tower, w hi ch causes lighter end Condensat hydrocarbons to e vapourize. 1 Condensate from an Inlet Surge upstream process enters Drum the inlet surge drum, off Condensat Condensat Condensat gas begins to flash off, and e e e water separates into the water boot. Reboiler Wate r Condensate Heat input Boot Heat Wate r Exchanger 3 2 5 Heat is recovered from the hot Water off the bottom of the surge The reboiler maintains a constant stabilized condensate to preheat drum is temperature at the bottom of the unstabilized condensate treatment and / or sent downstream for the tower to ensure any hydrocarbons before the stabilization disposal. tower. with a low boiling point are vapourized.  9 CONDENSATE 0 STABILIZATION PROCESS Important processIMPORTANCE PARAMETERS parameters Temperature of condensate is important for process control and ensuring that condensate meets requirements for vapour pressure specifications TEMPERATURE Water temperature is important incase there are concerns about freezing in low points during low ambient temperature conditions Important to know maximum incoming pressures and design pressures to understand potential sources of overpressure PRESSURE Pressure control is important for maintain flow into and out of the surge drum and stabilization tower Level control is important for preventing liquid carryover from either the surge drum or the stabilization tower to prevent liquid carryover to the compressor LEVEL Level control is important for preventing gas blowthrough to condensate storage tanks Water level control is important to prevent carrying water over into the stabilization tower, causing potential contamination and fouling issues (also important to prevent condensate losses into drain system) FLOW RATE Flow rate into the process is important for controlling required heat input and level control of process  9 NATURAL GAS L IQUI DS 5 An RECOVERY Natural gas liquids (NGLs) recovery is an important process for 1 removing more valuable hydrocarbons such as ethane, propane, overvieW Gas enters the process and flows through a series of heat exchangers butane. This process typically operates at high pressure and low temperatures to cause those hydrocarbons to condense. to drop the temperature. 2 Off Inlet Glycol is injected into the stream to prevent any water in the system Gas Gas from freezing when the Glyco temperature goes below 0°C. 6 l Stripped gas is sent downstream typically to a compressor to increase the pressure and is re- Stripped injected to the stripped gas stream Gas or for further treating / processing. e Temperatur Refrigera nt Propane 7 3 The reboiler maintains temperature at the Refrigerant propane is used to drop bottom of the tower to the temperature of the gas further, boil off any remaining causing propane and butane and light end products. other NGLs to condense in the gas NGL Condensa stream. Natural Gas Liquids s te Reboiler Glyc Heat ol input NGLs to Glyco Boot Bullet l 5 8 4 Recovered NGLs are sent to a NGLs are sent downstream to a The injected glycol is recovered and stabilzation tower to remove some storage bullet w hi ch is separated from the NGLs in the boot lighter end products and reduce a ressurized vessel designed to p of the low temperature separator. the vapour pressure. store the NGLs at a pressure high Glycol is sent downstream to be enough to prevent regenerated. vapourization.  9 NATURAL GAS L IQUIDS 7 Important process RECOVERY parameters PROCESS IMPORTANCE PARAMETERS Temperature of gas into the process, and the temperature after cooling, are important parameters for maintaining NGL recovery from the gas stream T E M P E R AT U R E Temperature of the stabilization tower is important for maintaining the desired product vapour pressure of the NGL stream Inlet pressures and design pressures are important to understand if there is any concern for P R E SS U R E blocked flow overpressure NGL level in the separator is important for preventing gas blowthrough to stabilization tower or liquid carryover to the gas system downstream LEVEL Glycol level in the separator boot is important for preventing gas blowthrough to glycol system or having glycol carryover into the stabilization tower Reboiler NGL level is important for preventing liquid carryover out the top of the tower or having gas blowthrough to the NGL storage downstream Glycol flow rate is important to ensure there is enough glycol in the process to prevent any water in F LO W RATE the system from freezing Inlet gas composition is important to know the fraction of NGLs in the system to determine the COMPOSITION required cooling and heat input for the process  11 FLA 0 An overvieW RE WHAT IS A FLARE? 6 Pilot fuel gas is continuously burned at order the to flare stack maintain tip in a constant source of ignition Flares play an important role in the safety of hydrocarbon facilities. They at the stack. An provide a controlled means of releasing product pressure, volume and energy emergency blowdown can which can be very hazardous if contained in the wrong situation. The three occur at any time. main components of a flare system are flare header piping, a flare knockout Therefore, the stack must drum and a flare stack. The flare header piping is a network of piping be ready to combust the throughout a facility that collects relief fl owpaths and directs them to the release. flare knockout. The flare knockout drum or FKOD is a vessel that captures liquids from a blowdown or relief event. A blowdown is a release of gas and/or liquid product and pressure from the process piping and equipment. The flare stack is a tall cylindrical structure that releases fl ammable, toxic or corrosive waste vapours high into the air where they are then combusted into products that are less harmful to the environment. Flare stack emissions are tightly monitored and regulated. 2 A continuous purge of fuel gas keeps a 1 positive pressure slightly above Blowdown from other systems combine in a relief header and 4 5 system. atmospheric Pressure in the are directed to the flare knockout A flow meter Pilot fuel gas, is controlled relief with pressure a regulator drum. Gas is separated from upstream of typically natural valve. hydrocarbon liquids and water. the stack gas, is tracks the controlled with l l l l l Purge emission rate. a pressure Gas 241 regulating valve. l l l l l Relie Fuel f Gas Liquid s 3 The separated water and liquids are drained from the knockout drum either by a manual operation and truck out procedure or with automated logic to start a drain pump when the liquid level reaches a certain height in the drum.  11 FLARE 3 Important process parameters SECTION PROCESS IMPORTANCE PARAMETERS Understand normal operating and max incoming pressure to determine if FUEL GAS L INES P R E SS U R E there is a source of over pressure due to a blocked flow Understand normal operating and max incoming pressure to determine if P R E SS U R E there is a source of over pressure in the event of a blowby to the flare knockout drum FLARE KNOCKOUT Understand normal operating and max temperature to determine if DRUM T E M P E R AT U R E there is a source of over temperature Relief products can reach extremely hot or cold temperatures Understand the time available to respond to liquids accumulating in the LIQUID DROPOUT knockout drum and prevent liquid carryover to the flare stack RATE Determine how much liquid is expected in the FKOD and if there is a L IQUID TRUCK M A N UA L / AU T O M AT I C concern for pulling back the flare during removal of liquids OUT FLARE STACK G OV E R N I N G CASE Determine if the flare is capable of handling the greatest expected release  11 HYDROCRACKING 8 An overvieW UNIT Hydrocracking units are used to convert heavy oil products into lighter products such as diesel gasoline and naphtha This is achieved , by cracking the longer heavier hydrocarbon molecule chains into shorter chains in a reactor then saturating these shorter chains with , ,. hydrogen. 1 The feed surge drum dampens any surges coming from the inlet and allows for appropriate control of the feed to the unit. Feed Oil 2 The feed p u m p is used to feed the heavy oil into the unit at the Feed desired rate. Surge Drum Charg e Heate 4 r Appropriate temperature Reacto Fee control is critical in the r profile Temperature d Pump hydrocracking # unit. Product from the 1 bottom of the reactor is cooled and this heat is 5 used to preheat the The feedstock to the Makeup feed oil going to the reactor. reactors consists of the feed oil and hydrogen. Hydroge This mixture is preheated in a charge n heater to bring it up to Makeup the required temperature for the reaction. Compress Hydroge or n 3 Hydrogen is critical for the hydrocracking reaction for temperature control and saturating the hydrocarbons.A hydrogen compressor is used to provide this feedstock to the process.  11 9 WHAT IS THE FEED? W H A T A RE T H E PRO The feed for this unit can come from other units such as a fluidized catalytic cracking DUCTS? unit a coker unit or an atmospheric or vacuum distillation tower including kerosene , , , The amount of each product gas oil light cycle oil , and heavy cycle oil , Hydrocracking units can handle. produced depends on operating feeds with more aromatic oils better than catalytic cracking processes. conditions and feedstock used but , common products include light naphtha heavy naphtha diesel and , , , distillates Hydrocracking is commonly used in. the place of a fluidized catalytic 8 cracking unit for jet fuel and diesel production due to the low aromatic Cool hydrogen quench gas is recycled back to the and sulphur and high Recycle hydrogen reactors to control the content of the products The. temperature in the reactors. process can yield high quality fuels Compress Hydroge and more environmentally friendly or n fuels compared to 6 cracking unita fluidized. The reactors contain catalytic catalysts w h i c h help convert long heavy chain molecules into shorter chain 7 saturated A high pressure separator is 10 hydrocarbons. used to separate the Off gas from the hydrocracker Reacto Sulfur are also and nitrogen hydrogen rich gas , can be further processed in an removed impurities the r ami ne unit to remove hydrogen. hydrocarbon liquids and sulfide and carbon dioxide profile Temperature ,. #2 water. High Pressure Separator Off Gas Low 11 Pressure Separato r Hydrocarbon liquids are sent for further processing in another 9 unit such as a fractionation The low pressure separator tower. separates the off gas from the hydrocarbon liquid in order to get the desired products. Hydrocarbo n Liquids  12 0 1 CATALY TRA Y S 2 ST BED 4 Quench hydrogen ring 1 Wire mesh 2 Non reactive ceramic 5 Liquid collection 3 balls tray 3 Catalyst pellets 6 Distribution tray W H A T H A P P E N S I N S I D E T H E RE A C T OR S? Hydrotreating is performed to remove impurities such as sulfur and nitrogen. These impurities are converted to ammonia and hydrogen sulfide. Other impurities removed during this stage of the process include nickel, silicon, alkali metals, iron, arsenic, and vanadium. Hydrodenitrogenation and hydrodesulfurization need to occur prior to 4 the feed interacting with the hydrocracking catalyst, since the impurities can reduce the catalyst activity. Often the feed is pretreated to remove impurities. In some cases, hydrotreating occurs in the first reactor, then ammonia is separated out prior to the product entering the second hydrocracking reactor. Common hydrotreating catalysts include cobalt- molybdenum and silica- alumina. 5 Hydrocracking consists of two main reactions. Catalytic cracking uses heat to break longer heavier molecules into shorter chains with the use of a catalyst. These shorter chains are then saturated by adding hydrogen in a hydrogenation reaction. The hydrogenation reaction creates more heat than is used in the cracking reaction, so the overall hydrocracking reaction is exothermic. Due to the catalytic cracking occuring in the presence of hydrogen, the hydrocracking reaction does not produce coke like in a pure catalytic cracking reaction. 6 Catalyst activity decreases over time due to fouling and coking. A shutdown is required to regenerate or replace the catalyst. Multiple catalyst beds are used to allow for injection of quench hydrogen for temperature control and more uniform mixing.  12 HYDROCRACKING 3 UNIT PROCESS Important process IMPORTANCE PARAMETERS parameters Temperature control in the reactors is critical to ensure proper conversion and prevent a runaway reaction Since there are high temperatures in some sections of the process, understanding the temperature rating and T E M P E R AT U R E metallurgy of different section of piping is important (special attention should be paid to sections where reverse or misdirected flow of a higher temperature stream is possible) It is important to understand inlet and outlet temperatures for the different exchangers to manage temperature ratings of different vessels The BMS in the charge heater controls feed inlet temperature to the reactors, which can impact conversion and potential for a runaway reaction Pressure interfaces are important, especially at high/low pressure interfaces such as between the high and low pressure separators Pressure control on the discharge of pumps and compressors are critical to prevent overpressure (the potential of running multiple pieces of equipment at once or overspeed is also important) P R E SS U R E Understanding how quickly the system can depressure in the event of a runaway reaction is important when evaluating safeguards Reactor pressure impacts conversion. Increased hydrogen partial pressure increases conversion and increased ammonia partial pressure decreases conversion, however, the impact of the hydrogen is greater, so increase in reactor pressure will increase conversion Level is important in the separators to prevent a gas blowby LEVEL Level is important in the knockout drums to prevent sending liquid into the compressors Feed ratios to the reactors impact conversion and potential for a runaway reaction, it is important to F LO W RATE understand feed rates of hydrocarbon and hydrogen The amount of product recycled impacts the efficiency of the process The feed to hydrogen ratio to the reactors is important to ensure proper conversion and has COMPOSITION an impact on temperature control  13 FLUIDIZED CATALYTIC CRACKING 2 Reacto r Product UNIT An overvieW The Fluidized Catalytic Cracking or FCC unit, is a core component in a modern refinery s and processes about one third of the crude oil produced worldwide. It is particularly Reacto common in North America due to its high yield of gasoline over diesel/kerosene. r WHAT IS FLUIDIZED CATAL YTIC CRACKING? Spent Flue Slide The FCC unit produces a combination of olefin rich Gas Valve hydrocarbon vapours, gasoline, diesel and heavy fuel oil from a feed of atmospheric / vacuum gas oil from the crude Regenerat distillation unit. The feed to the FCC is high molecular or weight, long chain hydrocarbons, w ith boiling points above The֯ process 340 C. utilizes a powdered zeolite catalyst which lowers the temperature that the long chain hydrocarbons will crack at. The catalyst circulates through the system, behaving as a fluid w h e n aerated where it is constantly being regenerated. It then is mixed with the hydrocarbon stream where it is quickly deactivated by the reaction depositing coke on the surface of the catalyst. Finally, it is returned to be regenerated by combusting the deposited coke off the surface with air. Combustio n Air Regen Slide SLIDE VALVES Valve The regen and spent slide valves play an important role in the control of the FCC operation. They maintain a catalyst barrier between the regenerator and reactor, preventing the mixing of the hydrocarbon atmosphere in the reactor and the oxygen rich atmosphere in the regenerator. They are large hydraulically operated valves designed for the severe conditions of the FCC unit. Fee d  13 Reacto 3 HOW DOES r Product s 6 A stream of cracked IT WORK? hydrocarbon vapours exits 7 Reacto the The regenerator operates at fines are removed Catalyst r 9 top of the reactor. extremely high temperatures downstrea Flue and collects 5 between 1000-1400 m heat is recovered above the Cyclones in the °F (~540- 760 °C) so that the carbon on gas before it is vented to spent slide valve and reactor the surface of the catalyst will auto- atmosphere. flows to the exits disengage the ignite. The only heat input into the regenerator. catalyst from the process during normal operation is the hydrocarbon from this combustion heating the reactor. FlueAny carryover vapour stream. surface of the catalyst. Gas The catalyst is then fed to the reactor Regenerat standpipe where it mixes with the or 4 feed stream of heavy gas oils and lift The endothermic gas. The heat and activity of the 1 0 reaction cools the catalyst causes the long cha