Attachment REPORT

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CHAPTER 1 INTRODUCTION HISTORICAL BACKGROUND The Tema Oil Refinery, formerly known as Ghana Italian Petroleum (GHAIP) Company limited, was incorporated under the laws of Ghana in 1960 as part of the Ghana Government Industrialization program. The Ghanaian Italian Petroleum Company limited was formed by the Government of Ghana in conjunction with the National Hydrocarbon Trust of Italy (Entre Nationale Idrocarburi-ENT) to construct a refinery for crude Oil processing in the country. In December 1961, GHAIP entrusted a consortium of firms, consisting of SNAM progetti, NUOVO PIGNONE and SAIPEM (companies of ENI group) with the construction of a refinery at Tema, capable of processing the most varied types of crude. The construction of the refinery with a design capacity of 1,250,000 metric tons of crude per year, an equivalent of 28,000 barrels per stream Day (BPSD) was completed by the middle of 1963.The refinery was formally opened by Osagyefo Dr. Kwame Nrumah, President of the Republic of Ghana on 28th September, 1963. The refinery covering a total area of 440,000 square meters is linked to an Oil jetty at the Tema Harbor by pipelines of various diameters for the transportation of crude Oil, fuel Oil, white products, (Gasoline, kerosene and gas oil) and LPG. On arrival at the harbor, the ship s with crude oil of petroleum product are inspected and certified for quality and quantity before it is pumped through the appropriate pipeline into storage tank at the refinery. After processing of the crude, the residue was exported and sold to other countries which had the facility (eg. Fluid Catalytic Cracking, FCC) to further process into useful products. This facility is now available to the refinery and they have seized the export of this residue known as atmospheric residue. The unit is known as Residue Fluid Catalytic Cracking, RFCC. The generic name for RFCC is FCC which is fluid catalytic cracking. The details of the whole project of building the unit is as shown below: • MILESTONE; Dec., 1998 Project Contract May, 1999 Project Commencement May, 2000 Sod Cutting Project Nov., 2001 Mechanical Completion Apr., 2002 Completion and Taking Over Oct., 2002 Commercial Operation The Unit (RFCC) was commissioned on 13th November 2002 by the sitting president of the Republic of Ghana, John Agyekum Kuffour. The unit was named RFCC because it processes atmospheric residue, but elsewhere in the world some go by its generic name. The plant processes atmospheric residue (AR) from the CDU into useful products such as Clarified Oil (CLO), Liquefied Petroleum Gas (LPG), Heavy Cycle Oil (HCO), Light Cycle Oil (LCO) and gasoline. The capacity of the plant is 14000 bpsd The former unit is known as Crude Distillation Unit, CDU. It was revamped to increase its capacity from 28000 BPSD to 45000BPSD. LPG, Kerosene, Heavy Gas Oil (HGO),

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Light Gas Oil (LGO), Light Naphtha, Heavy Naphtha and Atmospheric Residue are products of the unit. Objectives of the Refinery To ensure a continuous and adequate supply of petroleum products primarily in Ghana, mainly through the refining of crude oil, in a safe, healthy, cost effective, efficient and environmentally friendly manner to increase shareholder value. Vision of the Refinery To be the premier refinery counted among the very best in Africa. Departments at Tema Oil Refinery Tema Oil Refinery (TOR) has the various departments. • Production • Maintenance • Administration • Fire and Safety • Inspection and monitoring • Procurement • Quality control

Sections under Production • Residue fluid catalytic cracking (RFCC) • Crude distillation unit (CDU) • Waste water treatment unit (WWT) • Movement of product (MOP) • Utilities (Power house)

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CHAPTER 2 UTILITIES (POWER HOUSE) FUCTIONS • Steam generation and supply • Power generation and supply • Compressed air system 1. Instrument air 2. Process air • Water system 1. Municipal water filtration and supply 2. Boiler feed water system a. Demineralised water production b. Deaeration c. Addition of oxygen scavengers and phosphate d. Process cooling water system GENERAL OVERVIEW OF BOILERS Boilers are designed to allow the entire requirement for the production of steam and for combustion to come together. With fire tube boilers the shell contains the water that is needed to produce steam. The pipes provide a continuous supply fuel to the area directly beneath the shell. This is referred to as combustion area, which is the area in which combustion takes place. inside the shell. When the water absorbs enough heat to reach its boiling point, it boils, producing steam. PRINCIPLES OF OPERATION In simple terms, four basic requirements must be met in order for combustion to occur. There are many kinds of fuel available for use in boilers. Oil, natural gas, coal, wood, and waste material are just a few examples. Air contains the oxygen that is necessary for combustion. Heat is required to raise the temperature of the fuel/air mixture to the point where the chemical reaction occurs. This is the point at which ignition takes place. Combustion can only occur when fuel, air, heat, and chemical reaction are all present. If any one of the four requirements is not present, combustion does not occur. Boilers are designed to allow all of the requirements for the production of steam and for combustion to come together.

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TYPES OF BOILER FIRE TUBE BOILER Fire tube boilers are named for the way that they are constructed. Basically, a fire tube boiler uses a group of steel tubes to route the hot gases created by combustion through a shell filled with water. It consists of a steel cylindrical shell that houses a tubular combustion area, a series of fire tubes, and a feedwater inlet line (some fire tube boilers have more than one combustion area). Fuel and air enter the boiler through the fuel air inlet. The horizontal fire tubes route combustion gases through the boiler. Each time that gases are routed through the boiler shell is called a pass. WATER TUBE BOILERS In water tube boilers, the tubes are used to transport water and steam. The combustion gases flow past the outside surfaces of water tubes. Although water tubes boilers vary in design, their basic principles of operation are similar. The water tube boiler consists of two drums and a series of water tubes. Boiler drums are basically shells that distribute water to the water tubes. The water tubes connect the two drums and form a wall around the combustion area. Water enters the upper drum through the feedwater inlet line. During normal operation, the water tubes and the lower drum are completely filled with water. The upper drum is only filled to certain level to provide space for steam to collect and build up pressure. As fuel is burned in the combustion area of the boiler, heat is transferred to the adjacent water tubes. The hot combustion gases flow past the water tubes and out of the boiler through the combustion gas outlet. Water circulates from the upper drum, through the water tubes, and into the lower drum. From the lower drum, the water is distributed to the water tubes surrounding the combustion area. As the water in these tubes is heated, a steam/water mixture is produced. The steam /water mixture flows into the upper drum, where the steam and water are separated. This saturated steam is then routed to the superheater and then leaves the boiler at a temperature of about 390oC and pressure of about 42 bar through the steam outlet. The steam is finally routed into the plant as may be required. TOR utilizes water tube boilers. FUEL SYSTEMS Introduction The fuel gas and the fuel oil are burnt in the boilers for producing steam and the furnaces of the process plant.

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The fuel gas is a by product of the various working cycles of the crude, and in general is made of incondensable products which do not make it very useful commercially. The fuel oil, generally come from the distillation plants and is mainly stored in the tank farm and is a commercial product. It consumption therefore must be reduced to the indispensable and must be used only when there is shortage of fuel gas. FUEL OIL SYSTEM Two tanks store the product. Normally one tank is in service while the other is in stand by. Each tank is provided with low pressure steam heating coils so as to decrease the viscosity of the product and render it pumpable. The fuel oil is sucked by two pumps one driven by electric and the other by steam turbine. On the suction of the pumps two interchangeable filters are installed which serve to keep back the impurities which may clog burners. The delivery pipe line of the pumps is connected to the suction one by means of an automatic valve which is controlled by the network pressure constant. On delivery pipeline of the pump there is also a heating coil which increase the temperature of the fuel so as to decrease the viscosity of the fuel. This makes it suitable for atomization. FUEL GAS SYSTEM The process plants usually produce fuel gas both at high and low pressures. The pressures are conveyed to an accumulator. The high pressure accumulator discharges into the low pressure one by means of an automatic valve which is controlled by pressure existing in the accumulator itself. The low pressure is the one which distributes the fuel gas to the burner and pilot the networks. PROCESS CONTROL AND INSTRUMENTATION SYSTEM All boilers in the Utilities Department are water tube boilers. Boiler 1 i.e. H1 is controlled by an analog control system while boilers 4, 5 and 6 i.e. H4, H5 and H6 are run by a digital control system. H1 and H4 have 25 and 30 tonnes of steam producing capacity respectively while H5 and H6 produce 70 tonnes of steam each. Note: H = Boiler

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HP STEAM

BOILER

Air Feedwater

Fuel oil

In the boiler; air, fuel and a heat source are needed for combustion to take place for the generation of steam. The amounts of air and fuel needed in the boiler system depends on the rate of combustion for steam generation or simply put it depends on the load. An actuator in conjunction with an air register is used to regulate the amount of air entering for combustion. Boiler operations are undertaken at about 42 bar. This implies that the steam header pressure should be just about the same as the boiler pressure. This further implies that feedwater entering the boiler must be pumped to about a pressure of 52 bar to introduce it into the system. The level of feedwater in the upper drum should be half-way filled to allow for steam generation. The deaerator level should not exceed 90% of its capacity. This, if allowed, causes overflow of water which is not rid of oxygen into the boiler. Normal operations, here, may range between 40-70% (water level). Return lines as well as control valves are used to control the flow of feedwater in and out of the boiler. Feedwater coming into the boiler from the deaerator should be about 100 deg. celcius thereby increasing the boiler efficiency. In the boiler system, manually operated valves, control valves and return lines are used in the process control. in the digital system, control may be undertaken manually, automatically or in cascade. A set point, say, of incoming feedwater, fuel oil or combustion air levels are done to control the amounts for either increase or decrease in steam generation. The set point affects the process value as well as the output of the particular system. Ideally, about 25m3 of water should yield about 25 tonnes of steam. In cascade, a target is set and the system communicates with other auxiliary systems to attain the required parameters. This type of operation allows optimum use of fuel oil, combustion air, main steam pressure etc. depending on the set point

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SAFETY CONCERNS • Water level in the boiler should be maintained at the appropriate level to prevent overheating of tubes or rupture/warping. • Boiler efficiency should be at optimum to prevent wet steam output as this causes corrosion in the turbine system. • Feedwater into the boiler should completely be devoid of air. • The boiler should not be overloaded or exceed its capacity. • A white smoke from the overhead indicates too much combustion air allowed into the system whereas a black smoke indicates too much fuel in the system resulting from incomplete combustion. • Set points should be such that there is no overpressure in the boiler as steam pressure should be at the required operating value. • Fuel introduced must be regulated corresponding to an increase or decrease in load. • Purity of feedwater into the boiler must be controlled to prevent scale formation in the boiler which in turn restricts heat transfer. • Soot build up reduces the efficiency of boilers(by causing insulation) • During boiler start –up, heat must be applied gradually to all metal components for even expansion rate. If not “cracking” occurs.(warming up and cooling down curve) • Build-up of unburned fuels in boiler could also produce an explosion, if ignited. • Never re-admit feedwater to the boiler if the water has been out of the glass for more than 3 minutes. BOILER FEED WATER SYSTEM Water entering the boiler for steam generation has to be PURE thus; to be free from dissolved substances (ions), mechanical dirt and oxygen. This is to avoid damage to the plant equipment (water tubes). Thus the water is treated from impurities that can cause three major problems; • Corrosion • Fouling and Scale formation • Carryover (process in which impurities in the boiler water are picked up in steam and deposited elsewhere in the steam cycle). The feed water system consist of the; • Filter • Vask(storage facility) • Demineralizer • De-aerator Eliminox/Oxygen scavenger injection point

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Municipal water

Sand filter

Vask

Demineralizer

Storage tank

Steam Deaerator Boiler WATER TRATMENT FILTRATION Filtration is necessary to remove the impurities in the water which may otherwise be trapped in the resin and eventually accumulate to the point where it could restrict the easy flow of water through the bed. In this way, the efficiency of the ion-exchanger reduces. In the refinery (TOR), water from Ghana water and sewage limited is filtered by passing it through sand and gravel beds or media. The smallest grade of gravels is at the top of the bed, and layers of progressively larger grades of gravels are beneath it with the sand on the very top of both the larger and smaller gravel grades. This is to prevent the fine sand particles from getting along with the filtered water. The filtered water is then pumped to the demineralization unit for the removal of dissolved substances (ions). DEMINERALIZATION Demineralizers also referred to as ion-exchangers are used to remove dissolved substances (ions) which remain in the filtered water. This process is called DEMINERALIZATION. The function of the ion-exchange process is mainly to exchange ions, thus the ions are removed from the water while H+ and OH- are released into the water. The H+ and OH- ions released from the resin surface combine to form pure water (H2O). RESINS The actual exchange of ions takes place in small beads of plastic materials called RESINS TYPES Each ion exchange resin bead contains numerous charged areas, called sites. Depending on the type of resin bead, the charges on the sites will be either positive or negative. The resin beads with positively charged sites are used to remove negatively charged ions; they are

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called anion resin. The beads with negatively charged sites are used to remove positively charged ions; they are called cation resin. Properties The two main properties of the resin beads which enhance the ion exchange process are porosity and selectivity. Resin beads are actually made up of very small plastic strands. It is this composition that makes the beads porous, and thus allows water to flow through them. EXCHANGE MECHANISM The filtered water enters the Cation Exchanger first and then through the Anion Exchanger. Both the cation and anion exchangers have a diffuser which spreads the water over the resin bed. As the water flows through the cation exchanger, the cation resin beads which are negatively charged, attracts the positively charged ions in the water (Ca2+, Mg2+, etc…) due to the selectivity of the resin beads. The attracted positively charged ions which have the same charges as the hydrogen ion (H+) which is on the site of the resin beads tend to repel one another. Since the attracted positively charged ions are much stronger than the hydrogen ion (H+), it forces the hydrogen ion off the active sites of the ion into the water. Because the process is an exchange of ions, the attracted positively charged ions take over the active sites on the resin beads. In this way, the positively charged ions are removed from the water and hydrogen ions are released into the water. At the anion resin beads, the same phenomenon occurs except that the dissolved anions (Cl-, etc…) become attracted to the anion resin sites displacing OH- ions into the water. The displaced OH- ions combine with the already released H+ ions to form water. The water leaving the anion resin beads is therefore neutral and contains only hydrogen and oxygen. This water is called demineralized water. Cation Exchange X-H2+ + M2+ XM + 2H+

Where X- is the cation resin M2+ refers to Ca2+, Mg2+ etc. (cations in water) Anion Exchange A+ (OH)-2 + IOVERALL EQUATION 2H+ +2OH2H2O (DEMINERALISEDWATER) AI + 2OH-

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REGENERATION (Charging of the resin) After the resin has been in use for sometime, its ability to exchange ions decreases and becomes exhausted. Regeneration is the process of correcting resin exhaustion. The cation resin is regenerated by using sulphuric acid (H2SO4) whiles the anion resin is regenerated by using sodium hydroxide (NaOH). The 2H+ from the H2SO4 is released to the site of the cation resin bead to make it active. On the other hand, the OH- from the NaOH is released to the site of the anion resin bead to make it active. The sulphuric acid and the sodium hydroxide are diluted with water before they are charged into the cationic and anionic to reduce their concentration and to prevent them from destroying the resins. After the regeneration, the resins are washed and rinsed with water to remove excess H2SO4 and NaOH as well as SO4- and Na+. DE-AERATION Small concentrations of gas in water can cause serious corrosion problems. De- aeration is the process where by steam is used to strip off the dissolved oxygen in the demineralised water. The process takes place in a de-aerator. The steam and the demineralised water flow in a counter-current manner with the water flowing from the top and the steam from the bottom of the de-aerated. De-aeration, coupled with other aspects of external treatment, provides the best and highest quality feed water for boiler use. The purposes of de-aeration are; 1. To remove oxygen, carbon dioxide and other noncondensable gases from feed water 2. To heat the incoming makeup water and return condensate to an optimum temperature for: a. Minimizing solubility of the undesirable gases b. Providing the highest temperature water for injection to the boiler De-aerators are typically elevated in boiler rooms to help create head pressure on pumps located lower. This allows hotter water to be pumped without vapor lock should some steam get into the pump In the de-aerator are packings which reduce the flow-rate (speed) of the water to give it more contact time with the steam. There spring-loaded nozzles in the de-aerator which sprays the water onto the packings. The spring-loaded nozzles located in the top of the deaerator spray the water into a steam atmosphere that heats it The steam heats the water, and at the elevated temperature the solubility of oxygen is extremely low and most of the dissolved gases are removed from the system by venting. The spray will reduce the dissolved oxygen content in the demineralised water. The effluent is then stored in a tank right under the de-aerator called the de-aerator storage tank. From the de-aerator storage tank, the water is pumped to the upper drum of the boiler. Since the stripping cannot remove all the oxygen in the demineralised water, oxygen scavengers such as hydrazine or eliminox is used to remove the remaining oxygen.

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The addition of eliminox (oxygen scavenger used at TOR since hydrazine is no longer in use) during the suction of the demineralised water from the de-aerator storage tank removes all the remaining oxygen in the mineralized water. DE-AERATOR PLANT

Compressed Air System
The purpose of a typical compressed air system is to supply • Oil free, dry compressed air (instrument air) for pneumatic instruments of all process and utility units. • Oil free, compressed air (process air) for air powered tools and various other purposes and utility units and off sites. The system includes • Air compression section • A drying section The compressor is an electric motor/ turbine driven by a reciprocating oil free two stage type. In normal operation, two compressors will run and the third will be on standby. 11

COMPRESSED AIR PRODUCTION OPERATION Process air Atmospheric air is sucked by first stage of the compressors through the suction filter that prevents solid particles from entering the compressor casing. After the first stage, the air is cooled by the compressor’s intercoolers and condensed vapours are removed in moisture separators. Air is sucked by the second stage cylinders and compressed to the final required pressure. Air is again cooled in the compressors after-coolers and condensed water vapour is removed in the after-coolers moisture separators. The discharge header feeds the plant air receiver. From plant air receiver, process air is distributed to the plant. A part of which is sent to the driers. Instrument air The compressed air leaving the condensate separator after the final cooler still contains moisture which could be damaging to the pneumatic instrumentation. There is therefore the need for a drying section. The plant air receiver feeds the drying system composed of 2 air driers having the following characteristics: • Alumina absorbers (activated) • Double tower (one in operation and one in regeneration) • Automated cyclic switching The high surface area of the activated alumina aids in the selective adsorption of water vapor molecules. During absorption, the air flow is from top to bottom and in regeneration; the flow is from the bottom to the top. Cyclic switching of phases and towers is automatic. At the outlet of each of drier, a dust filter is provided to retain the particles of alumina that could damage the instruments. A hygrometer (AI) installed on the line at the outlet of the air-drying system, measures the residual water vapour content in the dried air to check the effective operation of the driers. The dried air feeds the instrument air receiver and then the instrument air is distributed.

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Plant air to network

Atmospheric air Air compressors (2- stage)

After-coolers Driers Instrument air to network

Air receiver

Instrument air receiver

Block diagram of compressed air system

Power Generation and Distribution Equipment such as pumps, compressors and fans is essential to the operation of an industrial facility. Before this equipment can operate, it must be supplied with power. Although electric motors are among the most common means of supplying the power necessary to drive equipment. Other drivers such as internal combustion engines, gas turbines and steam turbines are also used. Steam Turbines Principles of Operation Steam turbine function and basic operation Essentially, a steam turbine converts the energy in steam into mechanical energy that can be used to drive rotating equipment. In the turbine, steam first passes through a restriction called a nozzle. The nozzle converts the steam’s pressure into velocity, so as the steam passes through the nozzle, its speed increases. The faster moving steam then strikes a set of blades, causing them to turn. The turning blades produce mechanical energy that can be used to drive rotating equipment. Turbine blading Steam turbines generally use a series of fixed blades and moving blades to make the most effective use of the steam’s energy and cause rotary motion. Normally, the blades are designed for what is called impulse movement. Basically, impulse means that the high

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velocity steam pushes on the blades, causing the blades and the shaft on which they are mounted to rotate. However, the blading arrangement will tell of the type of steam turbine in use. When a series of fixed blades are used together with two sets of moving blades we have a single stage turbine. Also when we have one set of fixed blades together with one set of moving blades we have a multistage turbine. Power Plant Principles of operation Power generation In the turbine, steam passes through a restriction called nozzle. At the nozzle, there is an admission valve which admits the steam into an actuator which is automatically controlled by a governor. The governor sensitizes the actuator as to the amount of steam that is needed to drive the turbine blades depending on the amount of load on the generator. The admitting steam should correspond to a temperature of 392°C and a pressure of 42 bar. This is to avoid damaging the turbine. When this high-pressure steam turns the blades, with time the pressure decreases. This steam is now called medium pressure steam ( about 15 bar). This steam can be used in other areas and later ends up as condense which is later sent as make up boiler feed water. The turning blades produce mechanical energy that is used to drive the shaft of the generator. The generator then converts this energy into electromotive force (voltage). Power house has two main generators; generator3 and generator 4. Generator 3 produces a power of 6500KW and generator 4 a power of 5500KW. Power Distribution The generated electrical power is distributed to the various sections in the refinery such as RFCC, CDU, administration etc. Two sources of power are available at utilities; one internal and the other external. The internal power generated is 6000V and the external is step-down from 11000V to 6000V to suite their requirement by using a transformer. This voltage is stepped down to about 380V. In some cases, the refinery the internal power is used to drive essential equipment while the external power is used at areas not directly linked to the plant.

CHAPTER 3

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CDU (HYDROSKIMMING) The CDU (Crude Distillation Unit) is the main refining plant in the TOR. It processes raw crude into various products namely; • Fuel Gas • Virgin Naphtha • Kerosene • Light Gas Oil (LAGO) • Heavy Gas Oil (HAGO) • Atmospheric Residue PROCESS DESCRIPTION Crude oil from storage (tank farm) flow by gravity to the battery limit of the CDU, where it is pumped by the steam turbine pumps, to the first preheat train consisting of two sets of parallel heat exchangers. In this first preheat train, the crude (at a temperature of about 30oC exchanges heat with the cold residue (from the second train) and side stream products from stripper (01-C-02) going to storage; i.e. Kerosene, Light Gas oil and Heavy Gas oil) The preheated crude, now at about 110-130oC, enters the desalter. The desalted crude then flows to the second preheat train, also consisting of two sets of parallel heat exchangers for further heating by the lower and upper pump around and hot residue to a temperature of about 210 – 240oC . The crude is then routed to parallel furnaces, 01-F-61(40% of crude) and 01-F-01(60%) to a temperature between 345 – 355oC, depending on the type of crude. The heated crude streams from the furnaces them combine and enters the flash zone of the main column tangentially, to create a whirling movement leading to separation due to boiling point difference of crude components. The main column overhead vapor products, comprising off gases, full range naphtha and water, is air-cooled in and sent to the main column overhead receiver, equipped with a boot to collect the aqueous phase; which is then pumped as sour water to the wash water vessel. The off gases are collected in the off gas receiver, and sent to the compressor, and cooled through a heat exchanger with water and sent to the fuel gas knock out drum where the condensate is removed. The overhead from the knock out drum is then sent as fuel gas for the purpose of heating in the refinery. The full-range naphtha is pumped to the Stabilizer after exchanging heat with heavy naphtha in and low pressure steam where LPG (Liquefied Petroleum Gas) is recovered at the overhead receiver, then pumped to storage. The stabilizer reboiler reheats the stabilizer bottoms product and the vapours sent back to stabilizer to be collected as overhead product, LPG. The stabilized naphtha from the reboiler, 01-E-19 enters the Splitter Column, (by pressure gradient) which splits the light and the heavy naphtha components as overhead and bottom products respectively. The splitter bottom product is reheated with steam in the splitter reboiler to recover any light naphtha vapours, which is sent back to the splitter. The splitter overhead product (light naphtha) is cooled in air cooler, then water cooled and sent to splitter overhead receiver from where it is pumped to the Merox unit for treatment, then to storage. The bottom product (heavy naphtha) is pumped through exchangers, for cooling then to storage. 15

The main column middle distillates; kerosene, light gas oil and heavy gas oil are drawn from various points up the column and stripped to improve upon the product quality. The stripped products are cooled by exchanging heat with crude oil in the first preheat train. The light and the heavy gas oil are further air cooled respectively before being sent to storage. Kerosene is further cooled with water and sent to storage. The atmospheric residue is pumped through exchangers 01-E-06AR/BR, 01-E-66A/B then through 01-E-03R/01-E-63 to exchange heat with crude. It is then further air cooled and sent to storage. PRINCIPLE OF OPERATION OF EQUIPMENTS FURNACE (01-F-01, 01-F-61) The furnaces are equipments used for heating crude. Desalted preheated crude from the second set of heat exchangers (Train B) enters the furnaces at 210-240ºC through the conventional zone. 01-F-01, which is the bigger of the two furnaces, takes 60% of the desalted crude while the other (F-61) takes 40%. The maximum pressure and the minimum amount of crude allowed for circulation in the furnaces is 15bar and 20 ton/ hour respectively. A slam shut valve, which is part of the interlock system, automatically put the burners off when the required conditions in the furnace are not met, for example inadequate distribution of crude in the left and right coils. The furnace is equipped with three shutters, primary, secondary and tertiary to control the amount of air, size of flame and the height of flame respectively, to check tube rapture as a result of direct firing of tubes. Both furnaces use either fuel gas or fuel oil (black oil) which is atomized by steam, the pressure difference between the atomizing steam and the fuel oil being about 2.5bar. Fuel gas is however preferred as it is a by-product in the refinery process and therefore a cheaper source of fuel. The furnaces also heat low pressure steam to super heated steam to be used in a main column for stripping. Crude leaving the furnace is about 345 to 355ºC depending on the density of the crude being processed. The crude leaves through the radiant zone. DESALTER (01-V-51) Desalting is a single stage process that removes salts, water and other sediments from the crude. The crude entering the desalter is often preheated in the first set of the heat exchangers to a temperature of about 110 – 120ºC Water (fresh water and sour water) is added upstream of the desalter. The water and crude pass through a mixing valve and a mixer to create a water-in-oil emulsion. This is to provide an intimate contact between the oil-impurities and the wash water, thereby dissolving the salts of sodium, calcium and others and wetting the suspended solids. It then enters the desalter through the bottom where it is sprinkled out in the desalter to give out a large surface area. This enable the water being introduced from the top of the desalter to dissolve the salt solution from the sprinklers as polar solvents dissolves like. This then falls as water droplets and a transformer at the outside the desalter creates a high voltage electrostatic field within the desalter causing the droplets to coalesce and settle at

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the bottom of the desalter. The impurity containing water is then continuously withdrawn as underflow through a pipeline to the waste water treatment. The overflow which is desalted crude flows to the second set of heat exchangers (Train B) for further heating. The water leaving the desalter is 0.3% by volume and the maximum salt content of the crude leaving the desalter is 0.5 PTB (pound per thousand barrels). By desalting the crude, we prevent the hydrolysis at temperatures above 150oC into fouling precipitates and corrosive acidic compounds as captured below: CaCl2 + H2O = Ca (OH) 2 + HCl

MAIN COLUMN (01-C-01) The crude column has 42 fractionating trays and 1 chimney tray. Hot partially vapourized crude at 345-355ºC from the furnaces enters the flash zone of the column tangentially. This is to allow swirling and easy separation of the crude into the various fractions in the column. The heavier fractions condense and settle at the bottom as residue oil and the lighter fractions move upwards. The separation is due to the temperature and slight pressure gradients in the columns. Both parameters have their highest and lowest values at the bottom and top respectively. The fractions having carbon compositions from C1 to C 8 are the lightest hence exit from the top of the column and are condensed at the air coolers. The middle distillate products mainly kerosene (kero), light gas oil (LAGO) and heavy gas oil (HAGO) are drawn from intermediate points up the column into a side stripper (01-C02) to improve upon their qualities. Ammonia is added at the top of the column to neutralize any acid that may have been formed from the desalter. Kontol, a corrosion inhibitor is also added to the column to form a protective film on the inside walls. This prevents the salts from reacting with the inner part of the vessel, resulting in corrosion. The residue is pumped through a system of heat exchangers then air cooled and sent to storage. MIDDLE DISTILATE SIDE STRIPPERS After distillation in the main column, the middle distillates thus kerosene, light atmospheric gas oil (LAGO) and heavy atmospheric gas oil (HAGO) are drawn at various temperatures by the middle distillate side strippers. Kerosene, the lightest of the middle distillates is drawn from a partial draw-off recessed sump below tray 15 at a temperature of 200ºC and sent to tray 1 of the kerosene stripper. Superheated L.P.S from the furnace is fed below the bottom tray of the 6-tray kerosene stripper to remove traces of lighter products in the kerosene back to the main column. The kerosene is then pumped by the kerosene rundown pump, to the exchanger 01-E-01R to be cooled by exchanging heat with crude; it is further cooled with fresh water before it goes to storage at 40ºC.

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The light gas oil (LGO) is drawn from a partial draw-off recessed sump below tray 27 of the main column at about 265ºC and sent to the first tray of the LGO stripper. Stripping steam is used to remove lighter products from the LGO back to the column. The stripping steam reduces the pressure in the stripper by creating a partial pressure thereby increasing the boiling rate returning lighter ends back to the main column. The LGO is then pumped by the LGO rundown pump, to exchanger01- E-61 to exchange heat with crude; it is further cooled by the air coolers before it goes to storage at 50ºC. The heavy gas oil (HGO) is drawn from a partial draw-off recessed sump below tray 33 at 300 and sent to tray 1 of the HAGO stripper. Lighter products are stripped off the HGO by superheated steam from the furnace. The HGO is then pumped to exchangers E-62 and E-02R to be cooled by exchanging heat with the crude. The HGO is further cooled by the air cooler to about 60ºC before it goes to storage. GASOLINE STABILIZATION The full- range naphtha from the main column overhead receiver is heated by exchanging heat with heavy naphtha in exchanger E-69A/B and with low pressure steam (L.P.S) in exchanger E-73 before it enters the stabilizer. The stabilizer has 35trays, 21-tray rectifying section of 1,270mm diameter and 14-tray stripping section of 2,130mm diameter. Full-range naphtha enters the stabilizer on tray 22 at a temperature of 100ºC. Transfer of products from column C-03 to C-04 is made possible by pressure difference in the columns. The debutanizer stabilizes the full-range naphtha by stripping off the lighter products. The overhead vapour from the stabilizer, LPG is condensed in exchanger 01-E- 67A/B before it goes into the overhead receiver V-02 whiles the off-gases are sent to the Fuel gas receiver and excess to the blow down line to be flared. There is also a pressure control valve on a vent line to the fuel gas header which helps to maintain the pressure in the column. The LPG is then pumped from the overhead receiver by the LPG pumps, to the LPG treatment plant. There is a return line of the LPG to the stabilizer to help maintain the temperature gradient (reflux). The stabilizer bottom product which is stabilized naphtha goes into a reboiler which uses medium pressure steam (M.P.S) as heating medium to strip off traces of LPG back into the stabilizer. GASOLINE SPLITTER (01-C-04) The hot feed from the stabilizer reboiler enters the splitter, on tray 16 at about 128ºC. The splitter separates the stabilized naphtha into heavy and light naphtha with light naphtha as the overhead products which is condensed by the air cooler and further cooled in the trim condenser using fresh water before it goes into the overhead receiver V-03. A portion of the light naphtha is returned to the column as a reflux whiles the rest pumped from the overhead receiver by the naphtha pumps to the merox unit for treatment. The splitter bottom products goes into a kettle shaped reboiler which uses M.P.S as the heating medium to strip off traces of light naphtha back to the splitter.

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The heavy naphtha is then pumped from the splitter reboiler to exchanger 01-E69A/B to be cooled by exchanging heat with full-range naphtha; it then goes through the trim condenser for further cooling before it goes to storage. MEROX UNIT Mercaptans are undesirable in petroleum products since they contain sulphur which has corrosive effects and objectionable smell. As a result, the mercaptans are converted into disulphide, which are less objectionable The reaction takes place in an alkali medium in the presence of the merox plus catalyst. A compressor injects oxygen into the naphtha before it enters the merox gas reactor; also there is introduction of caustic solution from a caustic tank into the reactor to create an alkaline medium for the oxidation of mercaptans into disulphides. CORROSION Corrosion is the gradual wearing away of a particular plant part in an industrial set-up. The reduction of metal thickness can simply be described as corrosion Due to the nature of products at the refinery and the vast network of pipes that convey them; measures have been put in place to minimize their effect greatly. CORROSION CONTROL MEASURE Desalting Crude oil in its untreated form contains a lot of impurities. The impurities mostly consist of salts, water, sediment and mechanical suspensions such as silt and iron oxides. The presence of salts in the crude poses a corrosion threat. The salts, which are mostly chlorides of metals, tend to be acidic and are thus removed from the crude by mixing the crude oil with water to dissolve the salts in the oil. The dissolved salts in the water are then extracted from the bottom of the vessel known as the Desalter, in which the mixture after separation is contained. Addition of Ammonia Due to the chemical reaction in the desalter, the crude oil entering the column is slightly acidic. Acids have the tendency to corrode materials even metals. To neutralize the acidity, ammonia which is a base is added to the crude oil. The chemical reaction of the process is given by: NH3 + HCl→NH4Cl + H2O Application of Corrosion Inhibitors Kontol, a chemical corrosion inhibitor is pumped by a motor pump to the Atmospheric Distillation Column. This chemical forms a film coating along the inner walls of the upper part column preventing some of the salts that may still find their way into the column from reacting with the inner plates of the column to corrode it.

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PUMPS AND DRIVERS Components of a Pump A pump is a mechanical device used to transfer a product from one point to another by discharging at high flows and pressure. A typical centrifugal pump consists of the following: Pump Casing – There are two types  Top Casing  Bottom Casing Mechanical Seal – This generally prevents leakage of fluid from the pump. There are three types:  Primary Seal – This prevents leakage from rotating surface.  Secondary Seal – This prevents leakage along the shaft.  Tertiary Seal – When the primary and secondary seals have failed, it serves as a standby seal preventing fluid from the mechanical seal. Impellers – This controls the flow rate of the fluid in the pump thus providing liquid velocity. Plain Bearings – This prevents wear between the shaft and the casing and also serves as a support for the shaft. Coupling – It serves as a link between the motor and the pump. Volute-this forces the liquid to discharge out of the pump converting velocity to pressure. This is accomplished by offsetting the impeller in the volute and by maintaining a close clearance between the impeller and the volute at the cut-water. Membrane – It serves as an alignment material between the motor and the pump. Auxiliaries of a Pump The axillaries of a pump are the parts that facilitate and support the whole process of pumping. They aid the whole process. They include: Auxiliary valves –the drain valve for instance regulate the amount of condensate that should be emptied from the casing of the steam turbine pumps to prevent the blades in it from chipping or pitting. Some regulate amount of the oil and water for the cooling of pumping system. The auxiliary system normally deals with the lubrication system and seal systems.

SAFETY MEASURES • Fire extinguishers are placed at vantage points and used in the occasion of a fire. • Safety or pressure release valves are placed on all columns and pressurized vessels to maintain the set pressure by popping-up to release the excess pressure.

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• • • • • •

Lubricating oil levels are checked before start-up and periodically to avoid the wearing of moving metallic components, especially ball bearings within pumps. To facilitate the communication of instructions, two-way radio phones set at specific channels have been provided to workers working in the plant. To avoid leakages and explosion due to pressure build-up, the thickness of metals forming the walls of vessels are routinely checked for signs of corrosion and the appropriate actions taken based on the results. To avoid cavitations and the loss of suction in the pumps used, there are minimum by-pass lines on most pumps to maintain a constant level in their respective storage vessels. To ensure personnel safety, ladders are attached to all columns and vessels for support in the event of maintenance to facilitate climbing. Warning signs are placed at specific areas to maintain safety consciousness

CHAPTER 4 RESIDUAL FLUID CATALYTIC CRACKING UNIT (RFCC)

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The residue fluid catalytic cracking unit was developed based on the basis that the residue produced after crude distillation could further be cracked using a catalyst to obtain more desirable products. One of the important advantages of fluid catalytic cracking is the ability of the catalyst to flow easily between the Reactor and the Regenerator when fluidized with an appropriate vapor phase. The operation of RFCC is a continuous process. The products at RFCC are as follows; LPG (liquefied petroleum gas), Gasoline, Light Cycle Oil (LCO), Heavy Cycle Oil (HCO) and Clarified Oil (CLO). PRODUCTS LPG Gasoline LCO HCO CLO B/D 3510 7460 2050 700 1390 AMOUNT Kg/hr 13039 37771 13000 4700 10085

B/D= Barrel per Stream day REACTOR-REGENERATOR (Unit 11) Process Description The Residue Fluid Catalytic Cracking (RFCC) process converts heavy crude oil fractions into lighter, more valuable hydrocarbon products at high temperature and moderate pressure in the presence of finely divided silica / alumina based catalyst. In the course of cracking large hydrocarbon molecules into smaller molecules, a nonvolatile carbonaceous material, commonly referred to as coke, is deposited on the catalyst. The coke laid down on the catalyst acts to deactivate the catalyst by blocking access to the active catalytic sites. In order to regenerate the catalytic activity of the catalyst, the coke deposited on the catalyst is burned off with air in the Regenerator vessel.

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Process Flow and Control The pumped raw oil charge is preheated by a series of cycle oil and main column bottoms heat exchangers. The preheated raw oil and steam are introduced into the reactor riser at the bottom of the riser. Here the feed is contacted with a controlled amount of regenerated catalyst, lift steam and lift gas. The catalyst flow is controlled to maintain a desired reactor temperature. The hot regenerated catalyst vaporizes the feed and the resultant vapors carry the catalyst upward through the riser with a minimum of back mixing. Cracking occurs as the hydrocarbon vapors and catalyst travel up the riser. At the top of the riser the desired cracking reactions have been completed and the catalyst is quickly separated from the hydrocarbon vapors to minimize further cracking reactions. The reactor product vapors flow through the reactor vapor line to the main column where they are condensed and fractionated into gaseous co-products, FCC gasoline, cycle oil products, and a heavy residual bottoms material. During the cracking reaction, a carbonaceous by-product called coke is deposited on the circulating catalyst. This catalyst referred to as spent catalyst, drops from the reactor chamber into the stripping section where a countercurrent flow of steam removes both interstitial and some adsorbed hydrocarbon vapors. The stripped catalyst flows from the reactor stripper through the reactor standpipe to the regenerator where the coke is continuously burned off. The catalyst flow through the reactor standpipe is controlled to balance the circulating catalyst flow by maintaining a constant reactor catalyst level. In the regenerator, the heat of combustion raises the catalyst temperature to the 648 oC -746oC range. The purpose of this regeneration is to reactivate the spent catalyst so that when catalyst is returned to the reactor riser it is in the optimum condition to perform its cracking function. The regenerator serves to burn the coke from the catalyst particles and transfer heat to the circulating catalyst. The energy carried by the hot regenerated catalyst is used to vaporize and heat up the oil vapor to the desired reaction temperature in the riser. It also provides the heat of reaction necessary to crack the feedstock to the desired conversion level. Hot regenerated catalyst is pre-accelerated with lift steam and lift gas, dry gas from the gas concentration unit absorber section, at the bottom of the reactor riser prior to contacting the hydrocarbon feed stream further up the riser. The regenerator is normally operated at conditions that achieve complete combustion of CO to CO2. However, the combustion temperature can be varied for partial CO

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combustion, if processing conditions allow a lower level of heat generation. The regenerator is equipped with a catalyst recirculation standpipe, which supplies hot regenerated catalyst from the upper to the lower regenerator to provide additional heat for combustion. The recirculation catalyst flow is normally controlled to maintain the target combustor temperature. The regenerator is also provided with a Direct Fired Air Heater that is used on startup to supply heat to the system until the catalyst temperature is raised sufficiently for auto-regeneration. Flue gas exits through cyclone separators to minimize catalyst entrainment prior to discharge from the regenerator. The sensible heat of the hot flue gas is recovered in a Flue Gas Steam Generator. In order to maintain the activity of the working catalyst inventory at the desired level, and to make up for any catalyst lost from the system, fresh catalyst is introduced into the circulating catalyst system from a Fresh Catalyst Storage Hopper. An Equilibrium Catalyst Storage Hopper is provided to hold regenerated catalyst withdrawn from the circulating system a necessary to maintain the desired working activity and to provide catalyst for startup. MAIN COLUMN CIRCUIT (UNIT 12) Process description The Main Column is the first step in the product separation sequence. The superheated reactor vapors need to be cooled so that fractionation can be conducted. In large measure, operation of the Main Column becomes an exercise in controlled heat removal coupled with sufficient liquid-vapor contacting to effect the desired degree of fractionation into desired product streams, namely main column bottoms (MCB), heavy cycle oil (HCO), light cycle oil (LCO), heavy naphtha (HCN), unstabilized gasoline and wet gas. MCB, HCO and HCN are taken as products directly from the main column, although on many FCC units HCO and HCN are not removed from the unit as discreet net product streams. Main column sidestream products are often steam-stripped in sidestream strippers for flash point adjustment. The unstabilized gasoline and wet gas are subjected to further separation in the gas concentration section. Process flow and control The raw oil is pumped on flow control through a series of heat exchangers, called the feed

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preheat train, prior to entering the reactor riser through the feed nozzles. The raw oil is heated by exchanging with the circulating Heavy Naphtha, net MCB, and circulating MCB. Usually all streams except the circulating main column bottoms are flow controlled by the operator. The final raw oil temperature is controlled by passing some oil around the circulating main column bottoms exchanger. Reactor product vapors contain large quantities of light gas and gasoline vapors, which pass through the entire main column as saturated gases. These products are condensed in the Main Column Condenser, the Main Column Trim Condenser and separated in the Main Column Receiver. A quantity of the condensed hydrocarbon liquid (unstabilized gasoline) is pumped to the main column as reflux. Reflux to the main column controls the overhead vapor temperature. This temperature determines the endpoint of the gasoline product. The reflux also heat balances the column. The unstabilized gasoline liquid in the receiver not used as reflux is pumped to the gas concentration unit on receiver level control. Gas flows to the suction drum of the wet gas compressor in the gas concentration unit. Water from the overhead receiver is pumped to the sour water treating unit. Naphtha product is pumped and used for heat exchange with the feed coming in from the Raw Oil Feed Surge Drum on flow control and returned to the main column as internal reflux for the main column naphtha section. Circulating LCO provides heat to Stripper Reboiler and Debutanizer Feed Exchanger. Flow to the exchanger is regulated by a flow controller that is set according to process requirements. A stream of LCO, after heat exchange at the circulating Stripper Reboiler is sent to the Sponge Absorber as “lean” oil to absorb light gasoline range components from the light gas in the gas concentration section. The “rich” oil from the sponge absorber is returned to the main column with the cooled LCO circulation stream, providing internal reflux for the main column LCO section. HCO is withdrawn from the column and used to provide heat to the Debutanizer Reboiler. HCO flow to this exchanger is regulated by a flow controller. The controller is set by the operator to achieve desired product or process specification. The HCO circulation rates also provide proper reflux in the HCO section of the column. The HCO circuit also provides flush oil to the Main Column Bottoms Pumps. A spillback to the main column is provided for control of internal reflux. The spillback operates off a level controller on the HCO drawoff tray. 25

The main column bottoms system is designed to de-superheat the reactor vapors, condense the bottoms product and scrub entrained catalyst particle fines from the reactor product gases. Main column bottoms (MCB) is removed from the bottom of the main column and sent to a circulating bottom/raw oil exchanger and two steam generators. The vapors are de-superheated by circulating a large stream of cooled column bottoms over the disk and donut trays where it acts to de-superheat the reactor vapors as well as flush catalyst fines out of the column. GAS CONCENTRATION UNIT (Unit 13) General Process & Process Description A Gas Concentration Unit receives gasoline and all lighter products from a Fluid Catalytic Cracking Unit (FCC) and separates this mixture into stabilized gasoline, a liquefied petroleum gases (LPG) stream, and a non-condensable lean gas stream. The gasoline stream may be processed further, into heavy and light gasoline streams. The LPG stream is sent to an LPG treating unit for treating. After treating, the LPG stream may further be separated into mixed C3 and mixed C4 streams. Gas streams and/or gasoline streams from other units may also be charged to the Gas Concentration Unit.

The first step in the Gas Concentration process is the separation of the non-condensable lean gas from the heavier components. The lean gas cannot be separated in conventional fractionation equipment unless refrigeration is used (even though the equipment may be operated at high pressure). A stripper- absorber system must therefore be used for this primary separation. Net gas from the FCC unit must first be compressed and cooled before entering the stripper-absorber system. A two-stage, Wet Gas Compressor is used for this purpose. The compressor raises the gas pressure and moves the net gas stream forward for processing in the stripper-absorber system. A spillback from the compressor is provided to prevent the compressor from surging during turndown operation. The compressor speed is varied to control the Main Column Receiver pressure. The heart of a stripper-absorber configuration is the high pressure cooler and receiver. The High Pressure Receiver serves as both a surge vessel to dampen process upsets and as a water settler. All internal streams and all charge streams pass through the cooler/receiver except for the unstabilized cracked gasoline. Gas from the Wet Gas Compressor joins the 26

Primary Absorber bottoms stream, the Stripper overhead vapor stream, and the liquid from the Compressor Interstage suction Drum to enter the High Pressure Condenser, High Pressure Trim Condenser and then the High Pressure Receiver. Gas from the High Pressure Receiver (referred to as rich gas) contains valuable products in the propane-butane range. The gas is washed with cracked gasoline from the Main Column Receiver to recover these products in the Primary Absorber. Stabilized gasoline can also be injected at the top of the Primary Absorber to increase the C 3/C4 recovery. Heat is generated as the liquid streams flow down the column absorbing the lighter material from the rising gas stream. This heat is removed via intercoolers to increase absorption efficiency. The liquid hydrocarbon from the bottom of the Primary Absorber is pumped to the High Pressure Condenser.

The gas stream from the Primary Absorber exits from the top and flows to the bottom of the Sponge Absorber. The Sponge Absorber is a packed tower where any remaining C5+ material is removed by countercurrent contact with lean oil, normally Light Cycle Oil (LCO) from the FCC unit. The lean gas from the top of the Sponge Absorber is then sent to a Fuel Gas Absorber through Lean Gas Knockout Drum for H2S removal. A portion of the untreated lean gas may be recycled to the Reactor riser in the FCC unit as lift media. The LCO (Rich Oil) is pumped back to the Main Column. Unfortunately, absorption is not as selective an operation as fractionation. As such, the rich oil contains not only the desired C3s and C4s, but also a considerable quantity of the unwanted ethane (C2), methane (C1) and hydrogen sulfide (H2S). These components are removed by charging the High Pressure Receiver liquid to the Stripper. Stripper Reboilers heat is used to strip out the correct quantity of material from the Stripper charge by having the stripper overhead vapor flow reset the reboilers heat input. The stripper overhead vapor returns to the High Pressure Receiver and High Pressure Condensers from which the lighter gases again enter the bottom of the Primary Absorber. The Stripper bottoms contain a reduced concentration of H2S and C2- material that permits handling this stream in conventional fractionation equipment. The Stripper bottoms material is separated in the Debutanizer into LPG and gasoline. The Debutanizer is operated to control the Reid Vapor Pressure (RVP) of the gasoline product. Heat to the Debutanizer Reboiler is supplied from circulating FCC heavy cycle oil. The LPG 27

stream is generally sent to a LPG Merox Unit to remove sulfur compounds prior to further processing. The Debutanizer bottoms are removed to either net gasoline, to treating, or recycle gasoline to the Primary Absorber.

LPG EXTRACTION UNIT (UNIT 14) Process Principles Low molecular weight mercaptans are soluble in caustic soda solution. Therefore, when treating LPG, the Merox process can be used to extract mercaptans, thus reducing the sulfur content of the treated product. In the extraction unit, sulfur reduction is directly related to the extractable mercaptan content of the fresh charge. The LPG Merox process utilizes liquid-liquid contacting to extract the mercaptans from the LPG with a strong aqueous alkali solvent. The mercaptan-rich slovent, which also contains the dispersed Merox catalyst, is sent to a regeneration section where air is injected and mercaptans are oxidized to disulfides. The disulfides are subsequently separated from the solvent by coalescing, gravity settling, and decanting; the regenerated lean solvent is recycled back to Extractor. Thus, the process consists of two steps; mercaptan extraction and solvent regeneration. The remainder of this section discusses the reaction chemistry involved in the LPG Extraction process Process Variables The following represent the five primary process variables. C atalyst O xygen A akalinity C ontact H eat Process Flow and Control Virtually, all extraction unit feedstreams need pretreatment before entering the Merox unit proper. The purpose of pretreatment is to remove acidic impurities such as H 2S, and/or CO2. The quantity of impurities or contaminants in feedstock will determine which type pretreatment equipment is required. An LPG Amine Absorber is provided on feedstocks containing relatively high concentration of acid gases (H2S and CO2). An aqueous solution of a diethanolamine (DEA), is utilized in a countercurrent contact to extract the acid gas. This equipment is

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provided upstream of extractive LPG Merox unit. A LPG Amine Absorber will remove acid gases to an equilibrium level dependent on amine regeneration; however, this level is not low enough to send amine treated feed directly to Merox unit. Further treatment in the form of a caustic prewash is required to remove the last trace of acid gases present. In mercaptan extraction unit, fresh feed is charged to an Extractor column, in which mercaptans are countercurrently extracted by a caustic stream containing Merox catalyst. The treated material passes overhead to a Caustic Knockout Drum in which any entrained caustic solution is separated and returned to the circulation systems. The product then passes through a sand filter to coalesce any entrained caustic solution before going to storage. The mercaptan-rich caustic solution from the bottom of the Extractor column flows to the regeneration section where air is injected into this stream and the mercaptans are converted to disulfides. The Oxidizer effluent flows into the Disulfide Separator where spent air, disulfide oil and the caustic solution are separated. Spent air is vented to a safe place while disulfide oil is decanted and sent to FCC unit. The regenerated caustic stream is returned to the Extractor column. Merox catalyst is added periodically to maintain required activity.

UOP Merox Process Extraction GASOLINE TREATING UNIT (UNIT 15)

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The Merox Unit has been designed to convert the mercaptans in the feed directly to disulfides, which remains in the product. There is no reduction in total sulfur content. Because the vapor pressure of disulfides is so low relatively to those of mercaptans, their presence is much less objectionable. The unit is a sweetening process. Gasoline from the gas concentration unit goes to the reactor, packed with merox catalyst. The function of the catalyst is to accelerate the oxidation without allowing side reactions to occur. Caustic and air are injected into the gasoline before it enters the reactor. Reaction takes place in the reactor where mercaptans are converted to disulfides. The disulfide stays with the gasoline to storage. Reaction chemistry The merox process in all of its applications is based on the ability of an organometallic catalyst to accelerate the oxidation of mercaptans to disulfides at or near the ambient temperature and pressures. The overall reaction can be written as RSH+1/4O2 1/2RSSH+1/2H2O. ……………………(1) Where R is the hydrocarbon chain, which may be branched or cyclic. This chain may be saturated or unsaturated. Hence, in most petroleum fractions, there is usually a mixture of mercaptan to an extent that the R column might have 1,2,3…………10 or more carbon atoms.Due to this, there may be different alkyl chains in the reaction. 2R`SH+2RSH+O2 2R`SSR+2H2O………………………..(2)

This reaction occurs spontaneously but at a very slow rate, whenever any sour mercaptan bearing distillate is exposed to the atmospheric oxygen.

AMINE TREATMENT UNIT (UNIT 16) The amine treatment unit is designed to remove hydrogen sulfide H2S, sulfur Dioxide (SO2) and carbon dioxide (CO2) from the sour fuel gas feed stream with Diethanolamine (DEA), through absorption. This unit consists of regenerator, which strips the rich (DEA) solution of the absorbed H2S and CO2 from the LPG Extraction unit and the fuel Gas absorber and returns the lean solution to the same units. During this process, rich amine from the LPG amine absorber and fuel gas absorber enters the flash drum of which it separate into two phases; vapor and liquid. The vapor phase constituted by light hydrocarbons is scrubbed using lean DEA and sent to the acid Gas Flare by means of split range control of pressure with fuel gas. The liquid phase constituted by two immiscible liquids (heavy hydrocarbon and solution of rich DEA) is separated by means of internal box in separator. The hydrocarbon overflows to the internal

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box by the difference of density and it is drained to the Slope Oil Header. The rich amine is then pumped to the lean/rich amine heat exchanger for it to be preheated. The rich amine flows on the tube side whiles the lean amine flows on the shell side in order to minimize corrosion problem from temperatures of 59oC to 100oC before entering the amine regenerator. It then enters the amine regenerator from the top .The CO2 and H2S are stripped from the rich DEA solution by cascading the rich DEA solution counter current with steam from the Reboiler. After the stripping, the regenerated amine (lean amine) produced comes back to an exchanger then it goes to an air cooler to be cooled before it enters the carbon filters for it to be filtered. Anti foam agent is also added to prevent the foaming of the lean amine before it enters the amine absorber for the absorption of H2S. THEORY AND PRINCIPLES OF PROCESS The Chemistry of the Reaction of H2S and CO2 with Diethanolamine The Diethanolamine is the most generally accepted and widely used of the many available solvent for removal of H2S and CO2 from natural gas stream. Because of its reactivity and availability at low cost, Diethanolamine has achieved a position of prominence in the gas treating and sweetening industry. The reactivity and absorption properties of the Diethanolamine in solution are based on the reactivity of the amino nitrogen with the acidic components of CO2 and H2S. The primary function of the Ethanol groups is to raise the molecular weight and hence lower the vapor pressure of the amine. The primary reactions of Diethanolamine with H2S and CO2 are: Diethanolamine H2S 2R2NH + H2S  ( R2NH2)2S ( R2NH2 )2S + H2S  2R2NH2HS CO2 2R2NH + H2O + CO2  ( R2NH2 ) 2CO3 ( R2NH2 ) 2CO3 + H2O + CO2  2R2NH2HCO3 or 2R2NH + CO2  R2NCOONH2R2 COS

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2R2NH + COS  R2NCOSNH2R2 Where: R = C2H4OH It is important to note that the presence of water appears on the left-hand side of both the carbon dioxide reactions. This presence of water undoubtedly accounts for the fact that carbon dioxide is much more difficult to strip from alkanolamine solutions than is H2S. The reaction shown above proceeds to the right at low temperatures and high pressure, and to the left at higher temperatures and lower pressures. These reactions govern the absorption of hydrogen sulfide and carbon dioxide by alkanolamine solutions at ambient temperatures. At elevated temperatures (that exist in the stripper column) the reactions are reversed. The typical explanation for the formation of Heat Stable Salts (HSS) in an amine system is that the normal absorption mechanism involving amine and H2S is ; R2HN or R3N (amine) + H2S (weak acid) = R2HNH (+) or R3NH (+) + HS (-) This reaction is easily reversed in the regenerator at higher temperatures. However, if a stronger acid enters the system, the reaction is the same. For example, Formic Acid; R2HN or R3N (amine) + HCOOH = R2HNH (+) or R3NH (+) + HCOO (-) Increasing the temperature in the Regenerator can not reverse this reaction. That is why they are called Heat Stable Salts (HSS). The amine-cation pair remains in the solution. Therefore, the molecule of amine is no longer able to absorb H2S. Additionally the anions compete for the Fe(++) cations in the protective FeS coating, producing corrosion.

SOUR WATER TREATMENT UNIT (UNIT 18) The purpose of the sour water treatment unit is to remove hydrogen sulfide H2S and ammonia (NH3) from a combined sour water stream coming from the main column overhead receiver and amine treatment unit. Sour water from the bottom of the main column overhead is pumped to the sour water flash drum. The drum is separated into three sections. The sour water enters the middle of the drum where any hydrocarbon liquid present forms a layer on the top of the sour water. Sour water entering the drum is reduced in pressure to flash off light hydrocarbons, which are sent to the flare. Hydrocarbons that separate from the sour water as liquid are skimmed over wire into the hydrocarbon section of the drum. Skimmed hydrocarbon is drained to the

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slop oil drum using the pressure in the sour water flash drum. The sour water is pumped into the sour water storage tank of which any oil and undissolved gases are flashed and any oil and solids are separated from the water. It is then pumped through an exchanger to exchange heat with the stripped water before it enters the sour water stripper from the top. As the sour water enters the stripper, caustic is fed into the stripper and LP steam is used in an exchanger which heats the sour water to strip off hydrogen sulfide and ammonia in the sour water. The oil portion of the water is also removed as slop oil. The stripped water is then move to exchange heat with the fresh water in an exchanger to reduce the temperature before it goes to waste water treatment unit (WWT) for treatment.

PROCESS PRINCIPLES (ON CATALYST) The RFCC catalysts in use today, referred to as zeolites, have a framework structure that acts as a molecular sieve. These have become the industry standard RFCC catalysts due to their high activity, stability, and superior catalytic properties. They are very resistant to breakage and thermal deactivation. They yield a product distribution containing more gasoline, less dry gas, and produce less coke than previously used catalyst types. The catalytic activity occurs at what are termed acid sites, where the catalyst cracks gas oil molecules selectively to gasoline and lighter materials without significant coke formation. The characteristics of the zeolite type of FCC catalysts are: • Apparent Bulk Density (ABD) • Attrition Resistance • Catalyst Poisons Iron, vanadium, nickel, sodium and copper in the feed cause undesirable reactions when they deposit on the catalyst. Nickel and copper are more effective in promoting these side reactions so their presence in the feed is more serious. Deposited metals tend to drive the cracking reaction to completion forming coke, hydrogen, and light hydrocarbon gases. However, the alternating reduction and oxidation of the metals as the catalyst circulates does reduce their dehydrogenation effectiveness. Another factor, which reduces the effect of metal poisoning, is the short contact time in riser cracking, which reduces the extent of the coke and light gas production. Sodium, lithium, calcium or potassium contamination of the catalyst can be due to the presence of salts in the charge. Sodium salts affect the catalyst structure and permit sintering at lower temperatures. Proper feed desalting will reduce these contaminants. 33

Coke is a temporary poison that can block acid sites from reaction. Sulfur and nitrogen could also fall in this category. EQUILBRIUM CATALYST MICRO ACTIVITY TEST (MAT) The catalyst’s conversion ability at given conditions is determined by the Micro Activity Test (MAT) which measures the equilibrium catalyst’s activity and selectivity. In the MAT, a decoked catalyst sample is used to crack a typical FCC feedstock under controlled conditions in a laboratory reactor. The resulting catalyst, liquid and vapor products are analyzed and the results compared to a laboratory standard. The catalyst’s activity is reported as conversion, while the selectivity values relate to the catalyst’s undesirable characteristics of producing coke, light hydrocarbon gases, and hydrogen. Other catalyst properties analysed are as follows: • Particle Size Distribution • Pore Volume • Sintering Index • Structure • Surface Area PROCESS EQUIPMENT DIRECT FIRED AIR HEATER (DFAH) The figure below shows a drawing of a direct fired air heater, present on all FCC units between the blower and the combustion air inlet to the regenerator. The air heater is used for refractory curing and dryout following repair or renewal of regenerator linings, as well as during normal startup to heat the regenerator catalyst inventory. The DFAH outlet temperature is controlled by the fuel gas rate. Because air heater disoperation can cause damage to regenerator internals, a high temperature shutdown has been installed. For additional safety, the air heater will also shut down on low air flow and loss of flame detection from a flame sensor.

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AUX: • • • •

Pilot lines Flame Sensor High Energy Ignitor Sight Port

WET GAS COMPRESSOR (WGC)

The Wet Gas Compressor separates the relatively low pressure of the FCC Main Column from the high pressure gas concentration unit. A centrifugal compressor is used for this service. Centrifugal Wet Gas Compressors are multi-stage machines, contained within two external stages. Each of the two stages is protected by an anti-surge device that will override normal controls to protect the compressor. Gas leakage out of the casing is prevented by suction and discharge end labyrinth seals. These seals are backed by either buffer gas. The seal system must be kept in operation while the casing is under pressure or gas will leak out.

Centrifugal Compressor

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AUX: • • • •

Turbine driven Vacuum and condenser system Lube oil system Control oil system

MAIN AIR BLOWER The Main air Blower has a conventional control scheme for a turbine driven blower. Flow is measured by the venturi in the discharge line. This FRC (flow recording controller) controls the speed of the turbine, which regulates airflow. A vent line, called a snort, is located on the air blower discharge and is used to prevent air blower surge. The snort valve is controlled by the anti-surge system. The check valve in the air blower discharge line isolates the blower from the regenerator if the blower trips, or if the regenerator over pressures. This closing action is assisted by a spring-loaded air cylinder, which operates when regenerator pressure falls to a certain predetermined pressure differential with the air blower discharge. The main purpose of the MAB is to supply air for the combustion of coke in the regenerator. 36

AUX: • • • • •

Lube oil and Governor Control oil system Surface condenser Gland condenser Governor Sealing system

REACTOR The lift media (gas or steam) transports regenerated catalyst up into the riser to the feed injection point. The combined feed is mixed with atomizing steam at each of the feed distributors. This mixture is then injected into the riser where it meets the hot regenerated catalyst. The oil is immediately vaporized with the resulting volumetric expansion forcing the catalyst/vapor mixture up the riser to the riser to the reactor vessel. Cracking reactions take place in the 23 seconds required for the catalyst and hydrocarbon vapors to reach the top of the riser. Catalyst is quickly separated from hydrocarbon in the reactor VSS enclosure to reduce over cracking. Cyclones further remove entrained catalyst particles from the hydrocarbon vapors. Recovered spent catalyst flows down the VSS (vortex separation system) enclosure and the cyclone diplegs to the reactor stripper section. Steam displaces any remaining hydrocarbon vapors from the catalyst in the reactor stripper. Catalyst flows down over perforated baffle plates and steam flows upward through the perforations in a counter current arrangement. Form the stripper, spent catalyst flows out of the reactor into the reactor standpipe. Catalyst flow to the combustor is regulated by the spent catalyst slide valve that maintains the reactor catalyst bed level AUX: • • • • •

Slide valve Cyclones Lift gas system Optimix Feed Nozzle Stripping Steam system

REGENERATOR The high efficiency regenerator is divided into two sections. The lower section is called the combustor where the spent, recirculated and cooled catalysts are mixed with air and coke combustion occurs. The combustor operates in the fast fluidized regime of fluidization. All the catalyst entering the combustor is transported up the combustor riser into the upper regenerator where the regenerated catalyst disengages from the flue gas and catalyst returns to the riser. The upper regenerator holds the cyclones, provides volume for the regenerated

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catalyst to disengage from the flue gas and provides the surge capacity for catalyst in the system. This catalyst flow is regulated by the regenerated catalyst slide valve. AUX: • Cat-Cooler; The Catalyst Cooler provides very important FCC operating flexibility, permitting direct control over the regenerated catalyst temperature. • Cyclones • Catalyst hoppers • Flue Gas System; This system is comprised of double disc slide valves, an Orifice Chamber, a Flue Gas Steam Generator and an Electrostatic Precipitator. Some installations use a wet gas scrubber in place of the electrostatic precipitator. • Slide valve SLIDE VALVES AND HYDRAULIC SYSTEM The operation of slide valves is based on a hydraulic system, which consists of arrangement of pumps, oil and piping lines. The oil is discharged at a high pressure to either open the slide valves or close it, thus regulating the amount of catalyst admitted into or discharged from the system. There are five slide valves; SLV- 101, SLV- 102, SLV-103, SLV-104 and SLV-105 SLV- 101 allows spent catalyst into the regenerator for regeneration. SLV- 102 also allows regenerated catalyst into the reactor for cracking. SLV-103 circulates catalyst between the dense phase and the combustor of the regenerator. SLV-104 sends cooled catalyst from the catalyst cooler to the combustor. SLV-105 controls the flow of flue gas leaving the regenerator through the orifice chamber to the flue gas steam generator.

CONCLUSION After a week of safety training we learnt about the causes, effects and prevention of fire in the refinery. Two weeks each at Utilities, CDU and RFCC introduced us to the various utilities needed for the refining of crude oil and the processes undertaken in the operation

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of both CDU and RFCC. A few days of lectures on the operations of WWT and MOP enlightened us on the products obtained, how they are stored and transported and how waste water from the plants are treated. Overall, we studied various equipment and the chemical engineering principles employed in their operations and coupled with adjusting to working conditions, abiding by company rules and regulations and observing good working relations with our superiors and colleagues. After two and a half months of industrial attachment in TOR, we can confidently say we left with more knowledge than we brought.

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