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NOMENCLATURE

DL: Density of liquid

DN: Nozzle diameter

dv: Density of vapor

I-1: Total height

Rd: Disengagement height

RH: Hold-up height

Hu: Higher of liquid level

HmE: Height from mist eliminator

LLL: Least liquid level

Nu Normal liquid level

Pressure

QL Liquid volume flow rate

QM Quantity of mixture entering separator

Qv Vapor volumetric flow rate

Temperature

TH Hold-up time

Ts Surge time.

Velocity

VH Hold-up volume

Vs Surge volume

WI, Mass of liquid entering separator

Wv Mass of vapor entering separator

X Dryness fraction

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CHAPTER -I

INTRODUCTION

M/S Nagarjuna Fertilizers and Chemicals Limited - Kakinada is the flag ship company of the Nagarjuna group Founded by Mr K.V.K.Raju. It is the first has based fertilizer plant in south india. It covers 1130 acres, of which two third is occupied by green belt. The main product of the company is urea.

The mission of the company is to "Serve Society through Industry" and its vision is to become leader in core sectors of the industry. It has adopted a policy of quality management system ISO 9002, Environment Management System (ISO 14001) and OHSAS (ISO 18001) series of standards.

The technology for the fertilizers plant is provided by Snamprogetti for Ammonia production and Haldor Topsoe for Urea production.

Urea is a white crystalline solid with a nitrogen content of 46%. It is widely used as a fertilizer around the world owing to the fact that it is many ways the most convenient form of fixed nitrogen. Urea leaves no residues in the soil, is highly soluble enabling easy handling, is resistant towards bleaching and has the highest percentage of fixed nitrogen among solid fertilizers. When it is dissolved in water it hydrolyses very slowly to form ammonia carbonate and wentually decomposes to ammonia and CO2. This is the basic reason of use of urea as a fertilizer.

Urea manufacture is a historical significance. When Wholer in the year 1828 synthesized ea in the laboratory from ammonia cyanate, he shattered then prevalent belief that organic aterial cannot be prepared from inorganic chemicals. Urea was the first organic material to be nthesized from an inorganic source.

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Commercial urea production was started by IC Fabes of Germany in the year 1920 based on anunonia carbonate process. Since then considerable ingenuity was used to overcome process difficulties such as corrosion problems, recovery of unused gases andeconomic which led to present day developments. A mojor part of chemical fertilizer is produced in India in the form of urea.

The main process involves production of ammonia and carbon dioxide from the natural gas, using this ammonia and carbon dioxide for the production of urea. Many of the process producers involved lot of heat exchangers and separators for the recovery of heat generated and for separating the liquid from vapor respectively. The process abovementioned reason we have selected the design of separator as our project.

In NFCL, Kakinada several types of separators are installed both in process plant and also in offsites.

Our project includes the design of a vertical separator (Syn Gas First Stage Separator) in ammonia plant.

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PROCESSES AND PLANT DESCRIPTION

The feed stock natural gas, is desulphurised. The desulphurised natural gas is mixed with super heated steam to give steam to Carbon ratio of 3.3:1, preheated and fed to the catalyst tubes Reformer and sent to the Secondary Reformer. The exit gas from Secondary Reformer in primal)' is cooled to out 380 deg. C in the Waste Heat Boiler where high-pressure steam is generated. The carbonmonoxide formed in the reforming step is converted to CO2 high temperature shift conversion and low temperature shift conversion. The CO2 present in the process gas is removed in the CO2 removal section using Giammarco Vetrocoke process. The CO2 gas stripped from the solution in the regenerators is cooled and sent to Urea plant.

The condensed ammonia is separated and the uncondensed gases are recirculated back to the converter via the recirculation compressor. The product ammonia is cooled to a temperature of _33 deg. C by means of ammonia refrigeration system. The inerts level in the synthesis loop is kept low by taking an inerts purge and sending the same to the purge gas recovery unit where ammonia and Hydrogen are recovered and the remaining off gas is used as fuel. The product ammonia is pumped to the ammonia storage tanks or directly to Urea Plant.

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Interduction of SEPARATOR :

PURPOSE OF SEPARATOR The first step in the ammonia synthesis section is the compression of process gas out Jetting rnethariator because of conversion of nitrogen and hydrogen to ammonia is favored at high pressure and low temperature, the compressor system for this purpose is called synthesis gas compressor. And has four stages within it.

Between every stage of this compressor, the synthesis gas will be cooled to maintain the required temperature as the compression simultaneously results in temperature rise. Thus while getting cooled in the interstage cooler, the water vapor present in the synthesis gas will be condensed to liquid water.

This liquid water should not be allowed to entrain in the synthesis gas as it causes erosion on the walls on the subsequent compressor stages and also has unwanted side effects. So interstage separators are provided immediately after a cooler to separate and drain out liquid water.

This condensed water should not be allowed to be entrained in the gas. Therefore the gas is passed through the separator to separate water from gas. This separation is needed to

i. Prevent corrosionii. Prevent equipment damage

The general various separations are:

i. Liquid part from vapor / gasii. Liquid particles from immiscible liquidiii. Dust (or) solid particles from vapor or gasiv. Solid particles from liquid v. Solid particles from other liquid

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What is separator:

A  separator is a device used in several industrial applications to separate a vapor–liquid mixture.

For the common variety, gravity is utilized in a vertical vessel to cause the liquid to settle to the bottom of the vessel, where it is withdrawn.

In low gravity environments such as a space station, a common liquid separator will not function because gravity is not usable as a separation mechanism. In this case, centrifugal force needs to be utilized in a spinning centrifugal separator to drive liquid towards the outer edge of the chamber for removal. Gaseous components migrate towards the center. The gas outlet may itself be surrounding by a spinning mesh screen or grating, so that any liquid that does approach the outlet strikes the grating, is accelerated, and thrown away from the outlet

A typical vapor–liquid separator including commonly a de-entrainment pad and sometimes an inlet distributor

Functions of separator:

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separator has two types of functions

1.primary functions

2.secondary functions

primary functions:

Separation of oil from gas may begin as the fluid flows through the producing formation into the well bore and may progressively increase through the tubing, flow lines, and surface handling equipment. Under certain conditions, the fluid may be completely separated into liquid and gas before it reaches the oil and gas separator. In such cases, the separator vessel affords only an "enlargement" to permit gas to ascend to one outlet and liquid to descend to another.

1.Removal of liquid From Gas:

Difference in density of the liquid and gaseous hydrocarbons may accomplish acceptable separation in an oil and gas separator. However, in some instances, it is necessary to use mechanical devices commonly referred to as "mist extractors" to remove liquid mist from the gas before it is discharged from the separator. Also, it may be desirable or necessary to use some means to remove nonsolution gas from the oil before the oil is discharged from the separator.

2.Removal of Gas From liquid:

The physical and chemical characteristics of the oil and its conditions of pressure and temperature determine the amount of gas it will contain in solution. The rate at which the gas is liberated from a given oil is a function of change in pressure and temperature. The volume of gas that an oil and gas separator will remove from crude oil is dependent on (1) physical and chemical characteristics of the crude, (2) operating pressure, (3) operating temperature, (4) rate of throughput, (5) size and configuration of the separator, and (6) other factors.

Agitation, heat, special baffling, coalescing packs, and filtering materials can assist in the removal of nonsolution gas that otherwise may be retained in the oil because of the viscosity and surface tension of the oil. Gas can be removed from the top of the drum by virtue of being gas. Oil and water are separated by a baffle at the end of the separator, which is set at a height close to the oil-water contact, allowing oil to spill over onto the other side, while trapping water on the near side. The two fluids can then be piped out of the separator from their respective sides of the baffle. The produced water is then either injected back into the oil reservoir, disposed of or treated. The bulk level (gas - liquid interface) and the oil water interfaced are determined using instrumentation fixed to the vessel. Valves on the oil and water outlets are controlled to ensure the interfaces are kept at their optimum levels for separation to occur. The Separator will only achieve bulk separation. The smaller droplets of water will not settle by gravity

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and will remain in the oil stream. Normally the oil from the separator is routed to a coalescer to further reduce the water content.

3.Separation of Water From Oil:

The production of water with oil continues to be a problem for engineers and the oil producers. Since 1865 when water was coproduced with hydrocarbons, it has challenged and frustrated the industry on how to separate the valuable from the disposable. According to Rehm et al (1983),[4] innovation over the years has led from the skim pit to installation of the stock tank, to the gunbarrel, to the freewater knockout, to the hay-packed coalescer and most recently to the Performax Matrix Plate Coalescer, an enhanced gravity settling separator. The history of water treating for the most part has been sketchy and spartan. There is little economic value to the produced water, and it represents an extra cost for the producer to arrange for its disposal. Today oil fields produce greater quantities of water than they produce oil. Along with greater water production are emulsions and dispersions which are more difficult to treat. The separation process becomes interlocked with a myriad of contaminants as the last drop of oil is being recovered from the reservoir. In some instances it is preferable to separate and to remove water from the well fluid before it flows through pressure reductions, such as those caused by chokes and valves. Such water removal may prevent difficulties that could be caused downstream by the water, such as corrosionwhich can be referred to as being a chemical reactions that occurs whenever a gas or liquid chemically attacks an exposed metallic surface. [5] Corrosion is usually accelerated by warm temperatures and likewise by the presence of acids and salts. Other factors that affect the removal of water from oil include hydrate formation and the formation of tight emulsion that may be difficult to resolve into oil and water. The water can be separated from the oil in a three-phase separator by use of chemicals and gravity separation. If the three-phase separator is not large enough to separate the water adequately, it can be separated in a free-water knockout vessel installed upstream or downstream of the separators.

secondary functions:

1.Maintenance of Optimum Pressure on Separator:

For an oil and gas separator to accomplish its primary functions, pressure must be maintained in the separator so that the liquid and gas can be discharged into their respective processing or gathering systems. Pressure is maintained on the separator by use of a gas backpressure valve on each separator or with one master backpressure valve that controls the pressure on a battery of two or more separators. The optimum

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pressure to maintain on a separator is the pressure that will result in the highest economic yield from the sale of the liquid and gaseous hydrocarbons.

2.Maintenance of Liquid Seal in Separator

To maintain pressure on a separator, a liquid seal must be effected in the lower portion of the vessel. This liquid seal prevents loss of gas with the oil and requires the use of a liquid-level controller and a valve.

Methods Used To Remove liquid From Gas in Separators:

Effective oil-gas separation is important not only to ensure that the required export quality is achieved but also to prevent problems in downstream process equipment and compressors. Once the bulk liquid has been knocked out, which can be achieved in many ways, the remaining liquid droplets are separated from by a demisting device. Until recently the main technologies used for this application were reverse-flow cyclones, mesh pads and vane packs. More recently new devices with higher gas-handling have been developed which have enabled potential reduction in the scrubber vessel size. There are several new concepts currently under development in which the fluids are degassed upstream of the primary separator. These systems are based on centrifugal and turbine technology and have additional advantages in that they are compact and motion insensitive, hence ideal for floating production facilities.[6] Below are some of the ways in which oil is separated from gas in separators.

1.Density Difference (Gravity Separation)

Natural gas is lighter than liquid hydrocarbon. Minute particles of liquid hydrocarbon that are temporarily suspended in a stream of natural gas will, by density difference or force of gravity, settle out of the stream of gas if the velocity of the gas is sufficiently slow. The larger droplets of hydrocarbon will quickly settle out of the gas, but the smaller ones will take longer. At standard conditions of pressure and temperature, the droplets of liquid hydrocarbon may have a density 400 to 1,600 times that of natural gas. However, as the operating pressure and temperature increase, the difference in density decreases. At an operating pressure of 800 psig, the liquid hydrocarbon may be only 6 to 10 times as dense as the gas. Thus, operating pressure materially affects the size of the separator and the size and type of mist extractor required to separate adequately the liquid and gas. The fact that the liquid droplets may have a density 6 to 10 times that of the gas may indicate that droplets of liquid would quickly settle out of and separate from the gas. However, this may not occur because the particles of liquid may be so small that they tend to "float" in the gas and may not settle out of the gas stream in the short period of time the gas is in the oil and gas separator. As the operating pressure on a separator increases, the density difference between the liquid and gas decreases. For this reason, it is desirable to operate oil and gas separators at as

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low a pressure as is consistent with other process variables, conditions, and requirements.

2.Impingement

If a flowing stream of gas containing liquid, mist is impinged against a surface, the liquid mist may adhere to and coalesce on the surface. After the mist coalesces into larger droplets, the droplets will gravitate to the liquid section of the vessel. If the liquid content of the gas is high, or if the mist particles are extremely fine, several successive impingement surfaces may be required to effect satisfactory removal of the mist.

3.Change of Flow Direction

When the direction of flow of a gas stream containing liquid mist is changed abruptly, inertia causes the liquid to continue in the original direction of flow. Separation of liquid mist from the gas thus can be effected because the gas will more readily assume the change of flow direction and will flow away from the liquid mist particles. The liquid thus removed may coalesce on a surface or fall to the liquid section below.

4.Change of Flow Velocity

Separation of liquid and gas can be effected with either a sudden increase or decrease in gas velocity. Both conditions use the difference in inertia of gas and liquid. With a decrease in velocity, the higher inertia of the liquid mist carries it forward and away from the gas.[7] The liquid may then coalesce on some surface and gravitate to the liquid section of the separator. With an increase in gas velocity, the higher inertia of the liquid causes the gas to move away from the liquid, and the liquid may fall to the liquid section of the vessel.

5.Centrifugal Force

If a gas stream carrying liquid mist flows in a circular motion at sufficiently high velocity, centrifugal force throws the liquid mist outward against the walls of the container. Here the liquid coalesces into progressively larger droplets and finally gravitates to the liquid section below. Centrifugal force is one of the most effective methods of separating liquid mist from gas. However, according to Keplinger (1931),some separator designers have pointed out a disadvantage in that a liquid with a free surface rotating as a whole will have its surface curved around its lowest point lying on the axis of rotation. This created false level may cause difficulty in regulating the fluid level control on the separator. This is largely overcome by placing vertical quieting baffles which should extend from the bottom of the separator to above the outlet. Efficiency of this type of mist extractor increases as the velocity of the gas stream increases. Thus for a given rate of throughput, a smaller centrifugal separator will suffice.

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Where vapor–liquid separators are used

Vapor–liquid separators are very widely used in a great many industries and applications, such as:

Oil refineries Natural-gas processing plants Petrochemical  and chemical plants Refrigeration systems Air conditioning Compressor systems Gas pipelines Steam condensate flash drums Geothermal power plants Combined cycle power plants Flare stacks Soil vapor extraction Paper mills

Safety Features for liquid and Gas Separators:

liquid and gas separators should be installed at a safe distance from other lease equipment. Where they are installed on offshore platforms or in close proximity to other equipment, precautions should be taken to prevent injury to personnel and damage to surrounding equipment in case the separator or its controls or accessories fail. The following safety features are recommended for most oil and gas separators.

High- and Low-Liquid-Level Controls:

High- and low liquid-level controls normally are float-operated pilots that actuate a valve on the inlet to the separator, open a bypass around the separator, sound a warning alarm, or perform some other pertinent function to prevent damage that might result from high or low liquid levels in the separator.

High- and Low-Pressure Controls:

High- and low pressure controls are installed on separators to prevent excessively high or low pressures from interfering with normal operations. These high- and low-pressure controls can be mechanical, pneumatic, or electric and can sound a warning, actuate a shut-in valve, open a bypass, or perform other pertinent functions to protect personnel, the separator, and surrounding equipment.

High- and Low-Temperature Controls:

Temperature controls may be installed on separators to shut in the unit, to open or to close a bypass to a heater, or to sound a warning should the temperature in the separator become too high or too low. Such temperature controls are not normally used on separators, but they may be appropriate in special cases. According to Francis (1951), low-temperature controls in separators is another tools used by gas producers

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which finds its application in the high-pressure gas fields, usually referred to as "vapour-phase" reservoirs. Low temperatures obtainable from the expansion of these high-pressure gas streams are utilized to a profitable advantage. A more efficient recovery of the hydrocarbon condensate and a greater degree of dehydration of the gas as compared to the conventional heater and separator installation is a major advantage of low-temperature controls in oil and gas separators.

Safety Relief Valves:

A spring-loaded safety relief valve is usually installed on all oil and gas separators. These valves normally are set at the design pressure of the vessel. Safety relief valves serve primarily as a warning, and in most instances are too small to handle the full rated fluid capacity of the separator. Full-capacity safety relief valves can be used and are particularly recommended when no safety head (rupture disk) is used on the separator.

Safety Heads or Rupture Disks:

A safety head or rupture disk is a device containing a thin metal membrane that is designed to rupture when the pressure in the separator exceeds a predetermined value. This is usually from 1 1/4 to 1% times the design pressure of the separator vessel. The safety head disk is usually selected so that it will not rupture until the safety relief valve has opened and is incapable of preventing excessive pressure buildup in the separator.

Operation and Maintenance of separators:

Over the life of a production system, the separator is expected to process a wide range of produced fluids. With break through from water flood and expanded gas lift circulation, the produced fluid water cut and gas-oil ratio is ever changing. In many instances, the separator fluid loading may exceed the original design capacity of the vessel. As a result, many operators find their separator no longer able to meet the required oil and water effluent standards, or experience high liquid carry-over in the gas according to Power et al (1990). Some operational maintenance and considerations are discussed below:

1.Periodic Inspection

In refineries and processing plants, it is normal practice to inspect all pressure vessels and piping periodically for corrosion and erosion. In the oil fields, this practice is not generally followed (they are inspected at a predetermined frequency, normally decided by an RBI assessment) and equipment is replaced only after actual failure. This policy may create hazardous conditions for operating personnel and surrounding equipment. It is recommended that periodic inspection schedules for all pressure equipment be established and followed to protect against undue failures.

2.Installation of Safety Devices

All safety relief devices should be installed as close to the vessel as possible and in such manner that the reaction force from exhausting fluids will not break off, unscrew, or

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otherwise dislodge the safety device. The discharge from safety devices should not endanger personnel or other equipment.

3.Low Temperature

Separators should be operated above hydrate-formation temperature. Otherwise hydrates may form in the vessel and partially or completely plug it thereby reducing the capacity of the separator. In some instances when the liquid or gas outlet is plugged or restricted, this causes the safety valve to open or the safety head to rupture. Steam coils can be installed in the liquid section of oil and gas separators to melt hydrates that may form there. This is especially appropriate on low-temperature separators.

Types of separators:

1. Filter Vane Separators.

2.Gravity Separators.

3.Centrifugal Separators.

4. Mist eliminator pads.

5.Liquid/gas coalescers.

1.Filter Vane Separators:

Vane separators are simply a series of baffles or plates within a vessel. The mechanism controlling separation again is inertial impaction. Vane separators are sensitive to mass velocity for removal efficiency, but generally can operate at higher velocities than mist eliminators, mainly because a more effective liquid drainage reduces liquid reentrainment. However, because of the relatively large paths between the plates constituting the tortuous network, vane separator can only remove relatively large droplet sizes (10 microns and above). Often, vane separators are used to retrofit mist eliminator pad vessels when gas velocity exceeds design velocity.7 

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The vane’s unique geometry channels the collected liquid away from the gas, minimizing re-entrainment. The blade geometry also allows for more efficient mist removal. New vessels can be designed much smaller saving cost and weight.

Benefits

Increase capacity up to 100% Reduce vessel size and weight Increased efficiency Maintains efficiency at higher pressures De-bottleneck existing equipment

2.GravitySeparator:

In a gravity separator or knock-out drum, gravitational forces control separation. The lower the gas velocity and the larger the vessel size, the more efficient the liquid/gas separation. Because of the large vessel size required to achieve settling, gravity separators are rarely designed to remove droplets smaller than 300 microns.4 A knock-out drum is typically used for bulk separation or as a first stage scrubber. A knock-out drum is also useful when vessel internals are required to be kept to a minimum as in a relief system or in fouling service.5 Gravity separators are not recommended as the soul source of removal if high separation efficiency is required.

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In a vertical separator fluids enter the vessel through an inlet device whose primary objectives are to achieve efficient bulk separation of liquid from he gas and to improve flow distribution of both phases through the separator.Liquid removed by the inlet device is diverted to the bottom of the vessel while the gas moves upward, usually passes through the mist extractor to remove small droplet of entrained liquid, and then the vapour phase flows out of vessel.As a general rule a vertical separator is chosen when the ratio of vapour to liquid volume is large i.e. 750 or more.The various type internal available for vertical separator, these are:1. Demister Mats(Mist Extractor)2. Vane Packs3. Mutilcyclone or Swirl Decks.4. Filter Separators5. CyclonesThere are separator where inlet diverter is can also be used(As Per GPSA).

Sizing of Vertical Separator without Mist Extractor(Demister):An empty knock-out drum is suitable for bulk separation of gas and liquid especially when the liquid volume fraction is high stratified or plug flow in the inlet pipe It should also be used when internals are to be kept to a minimum eg. Fouling servics (wax, coke, scale etc..)The design margin of 10-25% should be applied to the normal operating gas flow to calculate the free cross section area above the high level trip.Determination of Separator Diameter:·  Based on K-Value (Using Souder – Brown Equation):The Design of separator is based on Souders-Brown Equation:

Vmax = Maximum velocity (Terminal Velocity) gas velocity allowable for particles of size Dp to drop or settle out of gas , m/s?L = Vapor Density, kg/m3 ,V = Liquid Density, kg/m3K = Empirical Constant for Sizing of Separator, m/s

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3.Centrifugal Separator :

In centrifugal or cyclone separators, centrifugal forces can act on an aerosol at a force several times greater than gravity. Generally, cyclonic separators are used for removing aerosols greater than 100 µm in diameter and a properly sized cyclone can have a reasonable removal efficiency of aerosols as low as 10 µm. A cyclone’s removal efficiency is very low on mist particles smaller than 10µm.6 Both cyclones and knock-out drums are recommended for waxy or coking materials.

Bulk water, which exists in air or compressed gas systems, causes corrosion of piping, damage to valves, cylinders, pneumatic tools and machinery, and reduces the effectiveness of aftercoolers/heat exchangers. Over 99% of bulk water can be easily and economically removed by installing a type XWS Water Separator. Your compressed air and gas system will operate much more efficiently with reduced downtime and maintenance costs. This upgrade will also improve the effectiveness of aftercoolers, refrigerant dryers, filters and other downstream equipment.

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We offer Centrifugal Type Moisture Separators those are specifically designed for the extraction of liquid particles from air/ gas flow. Owing to its finish standards.  

A rotary motion is imparted to the air/gas flow by means of a guiding device with a high circulatory velocity.

The particles, water droplets contained in the air/gas are flung on to the separator wall bycentrifugal force and are collected at the bottom.

Cleaned dry air/gas leaves the separator through a central dip tube. Collected moisture at the bottom of separator casing is automatically drained by

BEP Auto drain trap Collecting chamber is fitted with a cover plate which prevents the separated,

moisture being picked up again and carried forward Moisture separator cannot become clogged and its performance remains constant

with a uniformly/low pressure drop.

4.Mist eliminator pads:

Beginning about 1947, special devices were developed to remove mist fromgas streams. Now known as mist eliminators, or demister pads (Demister is a registered trademark of koch-Glitsch) these devices provide a large surface area in a small volume to collect liquid without substantially impeding gas flow. Unlike filters, which hold particles indefinitely, mist eliminators coalesce (merge) fine droplets and allow the liquid to drain away. Gas typically flows upward through a horizontal mist eliminator.

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The separation mechanism for mist eliminator pads is inertial impaction. Typically, mist eliminator pads, consisting of fibers or knitted meshes, can remove droplets down to 1-5 microns but the vessel containing them is relatively large because they must be operated at low velocities to prevent liquid reentrainment

Advanteges:

•Increasingthroughput•Downsizingnew vessels• Improving product purity• Cutting operating costs• Reducing environmental pollution• Reducing downstream corrosion• Increasing recovery of valuable liquids

5.Liquid/Gas Coalescers:

Liquid/gas coalescer cartridges combine features of both mist eliminator pads and vane separators, but are usually not specified for removing bulk liquids. In bulk liquid systems, a high efficiency coalescer is generally placed downstream of a knock-out drum or impingement separator. Gas flows through a very fine pack of bound fibrous material with a wrap on the outer surface to promote liquid drainage (See Figure 2 below). A coalescer cartridge can trap droplets down to 0.1 micron. When properly designed and sized, drainage of the coalesced droplets from the fibrous pack allows gas

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velocities much higher than in the case of mist eliminator pads and vane separators with no liquid reentrainment or increase in pressure drop across the assembly.

Material construction

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The following materials are used to construct the separator, based on the separation of liquid and gas composition.

1.carbon steels

2.stain less steels

1.Carbon steel:

Carbon steel, also called  plain-carbon steel, is a metal alloy, a combination of two elements, iron and carbon, where other elements are present in quantities too small to affect the properties. The only other alloying elements allowed in plain-carbon steel are:  carbon (0.12-2%)manganese (1.65% max), silicon (0.60% max), and copper (0.60% max). Steel with a low carbon content has the same properties as iron, soft but easily formed. As carbon content rises the metal becomes harder and stronger but less ductile and more difficult to weld. Higher carbon content lowers steel's melting point and its temperature resistance in gener

Propartis :

1. Great heardness and malleability2. Low tensile strength3. good wear resistance4. low cost of material5. good impact resisance

Types :

There rar four types of carbon steels classifed based on amount of carbon in the alloy

1.low carbon steel

2.medium carbon steel

3.high carbon steel

4.very high carbon steel

1.low carbon steel:

approximately 0.05% to 0.25% carbon content with up to 0.4% manganese content (e.g. AISI 1018 steel). Less strong but cheap and easy to shape; surface hardness can be increased through carburizing.

It is often used when large quantities of steel are needed, for example as structural steel. The density of mild steel is approximately 7.85 g/cm3 (7850 kg/m3 or 0.284 lb/in3)/4 and the Young's modulus, like all steels, is 210 GPa (30,000,000 psi).

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Low-carbon steels suffer from yield-point runout where the material has two yield points. The first yield point (or upper yield point) is higher than the second and the yield drops dramatically after the upper yield point. If a low-carbon steel is only stressed to some point between the upper and lower yield point then the surface may develop Lüder bands. Low-carbon steels contain less carbon than other steels and are easier to cold-form, making them easier to handle.

.

2.medium carbon steel:

approximately 0.29% to 0.54% carbon content with 0.60 to 1.65% manganese content (e.g. AISI 1040 steel). Balances ductility and strength and has good wear resistance; used for large parts, forging and car parts.

3.high carbon steel:

Carbon steels which can successfully undergo heat-treatment have a carbon content in the range of (0.30–1.70%) by weight. Trace impurities of various other e lements  can have a significant effect on the quality of the resulting steel. Trace amounts of sulfur in particular make the steel red-short, that is, brittle and crumbly at working temperatures. Low-alloy carbon steel, such as A36 grade, contains about 0.05% sulfur and melts around 1,426–1,538 °C (2,599–2,800 °F). Manganese is often added to improve the hardenability of low-carbon steels. These additions turn the material into a low-alloy steel  by some definitions, but AISI's definition of carbon steel allows up to 1.65% manganese by weight.

4.very high carbon steel:

 approximately 0.96% to 2.1% carbon content, specially processed to produce specific atomic and molecular microstructure

heat treatment process of carbon steel:

The purpose of heat treating carbon steel is to change the mechanical properties of steel, usually ductility, hardness, yield strength, or impact resistance. Note that the electrical and thermal conductivity are only slightly altered. As with most strengthening techniques for steel, Young's modulus(elasticity) is unaffected. All treatments of steel trade ductility for increased strength and vice versa. Iron has a higher solubility for carbon in theaustenite phase; therefore all heat treatments, except spheroidizing and process annealing, start by heating the steel to a temperature at which the austenitic phase can exist. The steel is then quenched (heat drawn out) at a high rate causing cementite to precipitate and finally the remaining pure iron to solidify. The rate at which the steel is cooled through the eutectoid temperature affects the rate at which carbon diffuses out of austenite and forms cementite. Generally speaking, cooling swiftly will leave iron carbide finely dispersed and produce a fine

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grained pearlite (until the martensitecritical temperature is reached) and cooling slowly will give a coarser pearlite. Cooling a hypoeutectoid steel (less than 0.77 wt% C) results in a lamellar-pearlitic structure of iron carbide layers with -α ferrite (pure iron) between. If it is hypereutectoid steel (more than 0.77 wt% C) then the structure is full pearlite with small grains (larger than the pearlite lamella) of cementite scattered throughout. The relative amounts of constituents are found using the lever rule. The following is a list of the types of heat treatments possible:

Spheroidizing: Spheroidite forms when carbon steel is heated to approximately 700 °C for over 30 hours. Spheroidite can form at lower temperatures but the time needed drastically increases, as this is a diffusion-controlled process. The result is a structure of rods or spheres of cementite within primary structure (ferrite or pearlite, depending on which side of the eutectoid you are on). The purpose is to soften higher carbon steels and allow more formability. This is the softest and most ductile form of steel. The image to the right shows where spheroidizing usually occurs.

Full annealing : Carbon steel is heated to approximately 40 °C above Ac3 or Ac1 for 1 hour; this ensures all the ferrite transforms into austenite (although cementite might still exist if the carbon content is greater than the eutectoid). The steel must then be cooled slowly, in the realm of 20 °C (68 °F) per hour. Usually it is just furnace cooled, where the furnace is turned off with the steel still inside. This results in a coarse pearlitic structure, which means the "bands" of pearlite are thick. Fully annealed steel is soft and ductile, with no internal stresses, which is often necessary for cost-effective forming. Only spheroidized steel is softer and more ductile.

Process annealing: A process used to relieve stress in a cold-worked carbon steel with less than 0.3 wt% C. The steel is usually heated up to 550–650 °C for 1 hour, but sometimes temperatures as high as 700 °C. The image rightward shows the area where process annealing occurs.

Isothermal annealing: It is a process in which hypoeutectoid steel is heated above the upper critical temperature and this temperature is maintained for a time and then the temperature is brought down below lower critical temperature and is again maintained. Then finally it is cooled at room temperature. This method rids any temperature gradient.

Normalizing: Carbon steel is heated to approximately 55 °C above Ac3 or Acm for 1

hour; this ensures the steel completely transforms to austenite. The steel is then air-cooled, which is a cooling rate of approximately 38 °C (100 °F) per minute. This results in a fine pearlitic structure, and a more-uniform structure. Normalized steel

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has a higher strength than annealed steel; it has a relatively high strength and ductility.

Quenching: Carbon steel with at least 0.4 wt% C is heated to normalizing temperatures and then rapidly cooled (quenched) in water, brine, or oil to the critical temperature. The critical temperature is dependent on the carbon content, but as a general rule is lower as the carbon content increases. This results in a martensitic structure; a form of steel that possesses a super-saturated carbon

content in a deformed body-centered cubic (BCC) crystalline structure, properly termed body-centered tetragonal (BCT), with much internal stress. Thus quenched steel is extremely hard but brittle, usually too brittle for practical purposes. These internal stresses cause stress cracks on the surface. Quenched steel is approximately three to four (with more carbon) fold harder than normalized steel

Martempering  (Marquenching): Martempering is not actually a tempering

procedure, hence the term "marquenching". It is a form of isothermal heat treatment applied after an initial quench of typically in a molten salt bath at a temperature right above the "martensite start temperature". At this temperature, residual stresses within the material are relieved and some bainite may be formed from the retained austenite which did not have time to transform into anything else. In industry, this is a process used to control the ductility and hardness of a material. With longer marquenching, the ductility increases with a minimal loss in strength; the steel is held in this solution until the inner and outer temperatures equalize. Then the steel is cooled at a moderate speed to keep the temperature gradient minimal. Not only does this process reduce internal stresses and stress cracks, but it also increases the impact resistance.

Quench and tempering: This is the most common heat treatment encountered, because the final properties can be precisely determined by the temperature and time of the tempering. Tempering involves reheating quenched steel to a temperature below the eutectoid temperature then cooling. The elevated temperature allows very small amounts of spheroidite to form, which restores ductility, but reduces hardness. Actual temperatures and times are carefully chosen for each composition.

Austempering : The austempering process is the same as martempering, except the steel is held in the molten salt bath through the bainite transformation temperatures, and then moderately cooled. The resulting bainite steel has a greater ductility, higher impact resistance, and less distortion. The disadvantage of austempering is it can only be used on a few steels, and it requires a special salt bath.

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Stainless steel:

Stainless steel is a generic term for a family of corrosion resistant alloy steels containing (10.5% or more )chromium.

All stainless steels have a high resistance to corrosion. This resistance to attack is due to the naturally occurring chromium-rich oxide film formed on the surface of the steel. Although extremely thin, this invisible, inert film is tightly adherent to the metal and extremely protective in a wide range of corrosive media. The film is rapidly self repairing in the presence of oxygen, and damage by abrasion, cutting or machining is quickly repaired.

Proparties:

1.high ductality and formability

2.goodmechanical proparties

3.good weldability

4.high corrosive resistance

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Clasifficication of stainless steels:

1.Group A

2.Group B

3.Group C

4.Precipitation hardenable stainless steels.

1.Group A:

This group includes plain Fe-Cr alloys and the amount of solid solution

is less than 13%. Cr-(17*%C)<13

2.Group B:

This group includes plain Fe-Cr alloys and the amount of solid solution is

exceeds than 13%. Cr-(17*%C)>13

3.Group C:

This group include those alloys which contain at least 24% of the total of Cr, Ni

and Mn. The amount of Cr in these alloys is at least 18% with carbon content

between 0.03 and 0.25%.

4.Precipition Hardenable Stainless Steels :

They contain element such as Mo,Cb,Ti,Al,Cu, or N in addtion to the basic

element Cr and Ni . Higher strenth is developed due to the precipition of

certain compounds.

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DESIGN PROCEDURE

4.1 PRINCIPLE O'F GRAVITY FLOW SEPARATOR

Gas liquid separators is often based on the principle of gravity settling, when liquid droplets suspended in rising gas vapors settle down at the bottom of the separation vessel and are eventually taken out through the bottom. Gas stream separated from liquid is taken out from the top of the separation vessel. The separation of liquid droplets from vapor phase can be explained with the equation for terminal velocity of liquid droplets. Two phase separators may be oriented vertically or horizontally. Vertical gas liquid separations are preferred for separating liquid from mixtures with high gas / liquid ratios.

Gas liquid separation is usually accomplished in three stages.

STAGE 1

This is primary separation, which uses an inlet diverter so that the momentum of the liquid particles entrained in the vapor causes the largest droplets to impinge on the diverter and drop by gravity.

STAGE 2

This is gravity separation of smaller droplets as the vapor flows through disenlargemeni area. Disenlargement area is the area between the inlet diverter and the bottom of the mis eliminator pad. This is called secondary separation.

STAGE 3

The final stage is mist eliminator where the smallest droplets are coalesced so that larger droplets are formed which will separate by gravity

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4.2 REASONS FOR DESIGN

In revamp process some of the equipments are newly erected for the increase of ammonia production. So, in that process the new synthesis gas compressor is erected. For this synthesis gas compressor the vertical separator is designed depending up on the flow conditions of that compressor.

4.3 DESIGN CONCEPTS

4.3.1 HOLD-UP TIME

It is defined as the time it takes to reduce the normal liquid level from (NLL) to least liquid level (LLL) while maintaining a normal outlet flow with feed making.

4.3.2 SURGE TIME

It is defined as the time it takes to rise from normal liquid level (NLL) to higher liquid level (HLL) without any outlet flow.

4.3.3 TERMINAL SETTING VELOCITY

When a particle falls under the influence of gravity, it will accelerate until the frictional drag in the fluid balances the gravitational forces. At this point it will continue to fall at constant velocity which is called terminal velocity or setting velocity or critical velocity.

4.4 DESIGN STEPS

STEP 1

UT = k [(di,- dv) / dv]

Where,

Ut=Terminal velocity.

dL = density of liquid.

dv = density of vapor.

k -- 0.43-0.023 in p.

p = pressure (pound /inch^2)

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conservative design(Uu):

Uu=0.75*Ut

STEP 2

The vapor volumetric flow rate (Qv) is calculated as

Qv = Wv / (3600 x dv)

Wv = mass of vapor entering separator.

STEP 3

The vessel inside diameter is calculated by

DVD=[4XQ/nXUU]1/2

If there is a mist eliminator, 3 to 6 inches are added to DVD to accommodate ring and rounded to next 6 inches increment to obtain D.

If there is no mist eliminator, D = DVD, where D is vessel diameter.

STEP 4

The liquid volume flow rate (QL) is calculated as

QL = WL / (60 x (dL)

WL = mass of liquid entering separator

STEP 5

The hold-up volume is calculated as

VH = TH x QL

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TH = hold-up time.

STEP 6

The vs is calculated as

Vs = Ts x Qi

Ts = surge time

STEP 7

Determination of hold up height (RH)

VH= (I1 / 4) x D2 X HH

Then, HH ( PAI/4) x D2

HH should be a minimum of 1 foot (0.3048).

So if HH comes out less than 0.3408 m then consider HH as 0.3048 m.

STEP 8

Surge height is calculated as

Vs =(PAI/ 4) x D2 x Hs

Then, Hs = Vs / (PAI /4) x D2

Hs should be a minimum of 6 inches (0.1524 m).

So if Hs comes out less than 0.1524 m, then consider Hs as 0.1524m

STEP 9:

the lower liquid level(hLL) is considered as 6 inches(0.1524m).

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STEP 10

Nozzlediameter (DN) calculation involves following sequence

QM = QL + Qv

QM = quantity of mixture entering separator

f = QL (QL + Qv)

dm= f* dL + (1-f) dv

dm = density of mixture

DN = [4x QM x dm / (II x 60)]

Then HLIN is calculated as 12+DN

STEP 11

Disengagement height is calculated as

Ha = max [0.5 x D, 24 + 0.5 x DN]

STEP12

If there is a mist eliminator 6 inches and for the mist eliminator pad 1 feet (0.3048) from

mist eliminator to the tangent line of the vessel is provided.

HME = Height from mist eliminator to top tank height

HME = 0.3048 + 0.1524

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= 0.4572 m

STEP 13

H = HLLL + HH + Hs + HLIN + HD + HME

SYNTHASISGAS COMPRESSOR

STAGE1 STAGE 2Suction Discharge Suction Discharge

Pressure 24.6 47.5 46.81 70.32Temperture 41 130.33 42 97.97

STAGE SUCTION DRY GAS FLOW RATE(NM3/HR) 1 121860 2 115724

DENSITY TABLE

SEPARATOR PR(KG/CM2) TEMPERTURE(C) DL DV1 46.81 42 991.38 16.3831

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DESIGN CALCULATIONS

5.1 CALCULATION OF MASS OF WATER VAPOR ENTERING THE COMPRESSOR STAGE 1 SUCTION

The weight of the gas:

=(0.733 \ 2) + (0.2(,17 28) + (0.0032 40) + (0.0121 x 10) = 9.046 kg. i.e. 22.4 m3 volume of gas weighs P.0426 kg. Therefore 1 m3 of gas weighs 9.0426 22.4 Li

STAGE 1 SUCTION CONDITION

T =41°C

P = 24.6 atm

Since gas is saturated with water vapor the saturated pressure at these conditions will be equal to partial pressure of water vapor.

(FROM THE REFRENCE OF STEAM TABLE)

At T = 41°C and Ps = 0.07931 atm

now calcuiating the mole fraction(X):

Xwater = Ps / P

= 0.007931 /24.6

= 0.003223

Xdry gas=1- Xwater

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= 1- 0.003223

= 0.9967

Total flow (dry gas + water vapor) = dry gas flow / Xdry gas

=121860 /0.9967

= 122254.14 (NM3 / hr).

Water vapor flow rate = total flow — flow of dry gas

= 122254.14 — 121860

= 394.14 (Nm3 / hr).

Mass of water entering compressor stage 1 suction = 394.14 x 18 / 22.414

= 316.526 kg / hr

Similarity second stage

p =46.81 kg / cm2

T = 42 °C

Since gas is saturated with water vapor the saturated pressure at these conditions will be equal to partial pressure of water vapor.

At T = 42°C and

P = 0.0836 atom (FROM STEAM TABLE)

Xwater = Ps / P

= 0.0836 /46.81

= 0.001785.

Xdry gas = 1 - Xwater

= 1-0.001785

= 0.9982

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Total flow (dry gas + water) = dry gas flow / Xdry gas

= 115724 / 0.9982

= 115932.67 Nm3 / hr

Water vapor flow rate =total flow — flow of dry gas

= 115932.67- 115724

= 208.6 Nm3 / hr

Mass of water entering compressor stage 2 suction

= 208.6 x (18 / 22.414)

= 167.58 Kg/hr

Mass of water vapor condensed between stage 1 and stage 2

= 316.526 - 167.58

= 148.946 Kg/hr

Total mass of vapor passing through step1:

w = [(121860 / 22.414) x 9.04] + 167.58

= 49330.2121 Kg/hr

5.2 CALCULATIONS OF TERMINAL VELOCITY:

STEP 1

UT = K [(di, - dv)/ dv]1/2

K = 0.43 — 0.023 ln p

P = 46.81 atm i.e. 688.107 psia

Then K = 0.2797 ft/sec.

Therefore UT= 0.2797 x [(991.38 - 16.3831) / 16.3831] ½

= 2.157 ft/sec

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= 0.657 m/sec.

For a conservative design

Uu = 0.75 UT

= 0.75 *0.657

= 0.4927 m/sec.

STEP 2

The vapor volumetric flow rate(Qv) is calculated as

Qv = Wv / (3600 x dv)

= 49330.2121 / (3600 x 16.3831)

= 0.8356 m3/sec.

STEP 3

The vessel inside diameter is calculated by

DVD= (4 xQ/I1xUu)1/2

=[(4 x 0.8356) / (3.14 x 0.4927)]

= 1.470 m.

If there is a mist eliminator, 3 to 6 inches are added to DvD to accommodate a support rii and rounded to next 6 inches increment to obtain D.

Therefore D = 1.6986 m.

5.3 CALCULATION OF HEIGHT OF VERTICAL SEPARATOR

STEP 4

The liquid volume flow rate (QL) is calculated as

QL = / (60 x (dL)

WL = mass of water entering separator.

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=148.496 / (60 x 991.38)

= 0.00250 m3/min.

STEP 5

Hold-up volume is calculated as

VH = TH X QL

TH = 10 min

= 10 x 0.00250

= 0.0250 m3/min.

STEP 6

Surge volume is calculated as

V5 = Ts x QL

Ts = 3 min

= 3 x 0.00250

= 0.00750 m3/min.

STEP 7

Determination of hold up height (HH)

VH = (II / 4) x D2 X HH

Then HH = VH (11/4) x D2

= 0.025 / (0.785 x 1.698^2)

= 0.0187 m.

HH should be minimum of 1 feet (0.3048m)

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So if HH comes out less than 0.3048m then consider HH as 0.3048m

Therefore HH = 0.3048m.

STEP 8

Surge height is calculated as

Vs = (II / 4) x D^2 x Hs

Then Hs = Vs / (pai / 4) x D2

= 0.0075 / (0.785 x 1.6986)

=0.003311 m

Hs should be a minimum of 6 inches (0.1524 m)

So if Hs comes out less than 0.1524 m, then consider Hs as 0.1524 m

Therefore Hs = 0.1524 m.

STEP 9

The lower liquid level (HLLL) is considered as 6 inches (0.1524 m).

Therefore HLLL = 0.1524 m.

STEP 10

Calculation of nozzle diameter (DN)

Qm = QL ± Qv

Where, QM = Quantity of mixture entering separator.

= (0.00250 / 60) + 0.836

= 0.8364 M3/ sec

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= 29.5018 ft3 / sec

f= QL (QL + Qv) = 0.0000498

dm = density of mixture

= (f x dL) + (1 - f) Dv

= (0.0000498 x 991.38) + (1 - 0.0000498) x 16.3831

= 16.4316 kg / m3

= 1.026 lb / ft3

DN = [4 X Qm dm / (H x 60)]

= [4 x 29.5018 x 1.026 /(Hx 60)]

=0.801 ft

=9.617 inch

Then HL IN is calculated as 12 + DN

Therefore HLIN = 12 + 9.617

= 21.617 inches

= 0.549 m.

STEP 11

Disengagement height is calculated as

Hd = max (0.5 D, (24 + 0.5 DN))

max [0.5 x 1.6986, (24 + 0.5 x 9.67)]

= max [0.8493, 0.7312]

= 0.8493 m.

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STEP 12

If there is a mist eliminator 6 inches, and for the mist eliminator pad 1 feet (0.3048 m) from the mist eliminator to the tangent line of the vessel is provided.

HME = height from mist eliminator to top tank height.

HME = 0.3048 + 0.1524

= 0.4572 m.

STEP 13

H = HLLL + HH + Hs + HLIN + HD + HME

= 0.1524 + 0.3048 + 0.1524 + 0.549 + 0.8493+ 0.4572

=2.4651 m.

Aspect Ratio

H/D = 2.4651 / 1.6986 = 1.45.

DM HM ASPECT RATIO MASS OF LIQUID CONDENSED(KG/HR)

1.698 2.465 1.45 148.94

CONCLUSION

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At present in M/S NAGA1RJUNA FERTILIZERS AND CHEMICALS LIMITED- KAK1NADA, the source that is being used for separating the condensate in the outlet of synthesis gas compressor first stage is vertical separator of adequate size suit to the pre revamping. From the study, it was observed that the size of the separator designed for replacing to the revamping capacity is suitable to cater the plant loads successfully.

Under the conditions considered in the above work the following conclusions can bemade.

The efficiency of separator largely depends on the extent to which the velocity of incoming gas is brought to below the terminal setting velocity. This reduction in velocity is made possible by increasing diameter. Diameter is the main parameter determining the efficiency of the separator.

The present work is aimed at designing a vertical separator with best functional characteristics. The objective of the present work has been successfully achieved. From this analysis it has been identified that the operational benefit has been achieved by replacing the existing vertical separator with the higher capacity one.

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BIBLIOGRAPHY

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