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2.2 CRUDE DISTILLATION
Regular laboratory analyses will monitor the desalter performance, and the desalted crude should normally not contain more than one kilogram of salt per, 1,000 harrels of feed.
2.2 CRUDE DISTILLATION
The purpose of crude oil distillation is primarily to split the crude into several distillate fractions of a certain boiling range. Sharpness of fractionation is of secondary importance. The number of trays used for crude distillation is very small compared to most other distillations. A crude distillation tower, producing 6 fractions has only 40 to 50 trays.
Crude can be separated into gasoline, naphtha, kerosene, diesel oil, gas oil, and other products, by distillation Figure 4.10 at atmospheric pressure. Distillation is an operation in which vapors rising through fractionating decks in a tower are intimately contacted with liquid descending across the decks so that higher boiling components are condensed, and concentrate at the bottom of the tower while the lighter ones are concentrated at the top or pass overhead. Crude is generally pumped to the unit directly from a storage tank, and it is important that charge tanks be drained completely free from water before charging to the unit. If water is entrained in the charge, it will vaporize in the exchangers and in the heater, and cause a high pressure drop through that equipment. If a slug of water should be charged to the unit, the quantity of steam generated by its vaporization is so much greater than the quantity of vapor obtained from the same volume of oil, that the decks in the fractionating column could be damaged. Water expands in volume 1600 times upon vaporization at 100ºC at atmospheric pressure.
2.2.1 Process Description (Figure 2.10)
A. Heat Exchange
In order to reduce the cost of operating a crude unit as much heat as possible is recovered from the hot streams by heat exchanging them with the cold crude charge. The number of heat exchangers within the crude unit and cross heat exchange with other units will vary with unit design. A record should be kept of heat exchanger outlet temperatures so that fouling can be detected and possibly corrected before the capacity of the unit is affected.
B. Crude Flashing
Desalted crude is heat exchanged against what ever other heat sources are available to recover maximum heat before crude is charged to the heater, which ultimately supplies all the heat required for operation of the crude unit.
The heat input is controlled by having the heater transfer temperature reset flow of fuel to the burners. The heater transfer temperature is merely a convenient control, and the actual temperature, which has no great significance, will vary from 325ºC to as high as 430ºC, depending on the type of crude and the pressure at the bottom of the fractionating tower. It is noteworthy that if the quantity of gasoline and kerosene in crude is reduced, the transfer temperature required for the same operation will be increased, even through the “lift” is less.
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Crude entering the flash zone of the fractionating column flashes into the vapor which rises up the column and the liquid residue which drops downwards. This flash is a very rough separation; the vapors contain appreciable quantities of heavy ends, which must be rejected downwards into reduced crude, while the liquid contains lighter products, which must be stripped out.
C. Fractionation
Flashed vapors rise up the fractionating column Figure 2.11 counter – current to the internal reflux flowing down the column. The lightest product, which is generally gasoline passes overhead and is condensed in the overhead receiver. (Should the crude contain any non-condensable gas, it will leave the receiver as a gas, and can be recovered by other equipment, which should be operated to obtain the minimum flash zone pressure.) The temperature at the top of the fractionators is a good measure of the endpoint of the gasoline and this temperature is controlled by returning some of the condensed gasoline as reflux to the top of the column. Increasing the reflux rate lowers the top temperature and results in the net overhead product having a lower endpoint. The loss in net overhead product must be removed on the next lower draw try. This will decrease the initial boiling point of material from this tray. Increasing the heater transfer temperature increases the heat input and demands more reflux to maintain the same top temperature.
External reflux which is returned to the top of the fractionators passes downwards against the rising vapors. Lighter components of the reflux are revaporized and return to the top of the column while the heavier components in the rising vapors are condensed and return down the column. We have then an internal reflux stream flowing from, the top of the fractionators all the way back to the flash zone and becoming progressively heaver as it descends.
The products heaver than the net overhead are obtained by withdrawing portions of the internal reflux stream. The endpoint of a sidecut will depend on the quantity withdrawn. If the sidecut withdrawal rate is increased, the extra product is material which was formerly flowing down the fractionators as internal reflex. Since the internal reflux below the draw off is reduced, heavier vapors can now rise to that point and result in a heavier product. Changing the drawoff rate is the manner in which sidecuts are kept on end point specifications.
Temperature of the drawoff decks is a fair indication of the endpoint of the product drawn at that point and an experienced operator may vary his drawoff rate to hold a constant deck temperature and therefore a specification product.
The degree of fractionation between cuts is generally judged by measuring the number of degrees centigrade between the 95% point of the lighter product and the 5% point of the heaving product. (Some people use IBP and FBP but the IBP varies with stripping). The gap between gasoline and kerosene should be about 5ºC while between kerosene and light gas oil 3ºC is normal. Fractionation can be improved by increasing the reflux in the fractionators, which is done by raising the transfer temperature. There may be occasions when the internal reflux necessary to achieve satisfactory fractionation between the heaver products is so great that if it was supplied from the top of the fractionators the upper decks would flood. An “Intermediate Circulating Reflux” solves this problem. Some internal reflux is withdrawn, pumped through a cooler, or exchanger, and returned colder a few decks higher in the column. This cold oil return condenses extra vapors to liquid and increases the internal reflux below that point. If we wish to improve fractionation between the light and heavy gas oil, we would increases the heater transfer temperature, which would cause the top reflux to increases, then restore the top reflux to its former rate by increasing the circulating reflux rate. It is to be noted that even through the heater transfer temperature is increased, the extra heat is recovered by exchanger with crude, and as a result the heater duty will only increases slightly.
Sometimes fractionators will be “pulled dry”. That is to say, the rate at which a product is being withdrawn is greater than the quantity of internal reflux in the fractionators. All the internal reflux then flows to the stripper, the decks below the drawoff run dry, and therefore no fractionation takes place, while at the same time there is insufficient material to maintain the level in the stripper, and the product pump will tend to lose suction. It is necessary then to either lower the product withdrawal rate or to increases the internal reflux in the tower by raising the transfer temperature or by reducing the rate at which the next lightest product is being withdrawn.
D. Product Stripping
The flashed residue in the bottom of the fractionators and the sidecut products have been in contact with lighter boiling vapors. These vapors must be removed to meet flash point specifications and to drive the light ends into lighter and more valuable products.
Steam, usually superheated steam, is used to strip these light ends. Generally only enough steam is used to meet a flash point specification. While further increases in the quantity of steam may raise the IBP of the product slightly, the only way to substantially increase the IBP of one product is to increases the yield of the next light product. (Provided, of course, the fractionators has enough internal reflux to make a good separation).
All the stripping steam is condensed in the overhead receiver and must be drained off. Refluxing water will upset the fractionators. If the endpoint of the overhead product is very low, water may not pass overhead, and will accumulate on the upper decks and cause the tower to flood.
The effect of steam
Steam is frequently used in fractionating columns, strippers and sometimes in furnaces. If the quantity and temperature of the steam are known, its effect can be determined by calculating the partial pressure exerted by the steam. This partial pressure is then subtracted from the total system pressure (according to Dalton
Example
Let it be required to calculate the top temperature of a fractionating column when the top product, of which the composition is given below, contains in addition 4% by wt of steam. Total pressure at the top of the column is 20 psia.
Consequently the steam partial pressure amounts to 19.0% of 20 psia = 3.80 psia and the hydrocarbon partial pressure equals, therefore, 20-3.80 = 16.20 psia. The conventional dew point calculation as described before is now carried out at a pressure of 16.20 psia, disregarding the steam.
When liquid water is present on the top tray of the column, its vapour pressure must be subtracted from the total pressure. In this case, however, the temperature must be known, and this has to be determined by trial and error.
Example 2
Data given: Total pressure and temperature of a flashing system and the amount of hydrocarbon vapour to be flashed off per hour;
Required; Amount of steam needed for this operation.
By trial and error the pressure at which the amount of vapour flashed off at the given temperature is found from the flash equation.
From the relation:
The moles of steam can be found and consequently the required weight of steam determined.
E. Desalting
Most crude contain traces of salt which can decompose in the heater to from hydrochloric acid and cause corrosion of the fractionator's overhead equipment. In order to remove the salt water is injected into the partially preheated crude and the stream is thoroughly mixed so that the water extracts practically all the salt from the oil. The mixture of oil and water is separated in a desalter, which is a large vessel in which may be accelerated by the addition of chemicals or by electrical devices. The salt laden water is automatically drained from the bottom of the desalter.
If the oil entering the desalter is not enough, it may be too viscous to permit proper mixing and complete separation of the water and the oil, and some of the water may be carried into the fractionators. If, on the other hand, the oil is too hot, some vaporization may occur, and the resulting turbulence can result in improper separation of oil and water. The desalter temperature is therefore quite critical, and normally a bypass is provided around at least one of the exchangers so that the temperature can be controlled. The optimum temperature depends upon the desalter pressure and the quantity of light material in the crude, but is normally about 120ºC +or- 10ºC being lower for low pressure and light crudes. The average water injection rate is 5% of the charge.
Good desalter control is indicated by the chloride content of the overhead receiver water. This should be in the order of 10-30 ppm chlorides. If the desalter operation appears to be satisfactory but the chloride content in the overhead receiver water is greater than 30 ppm, then caustic should be injected at the rate of 1 to 3 lbs. per 1000 barrels of charge to reduce the chloride content to the range of 10-30 ppm. Salting out will occur below 10 and severe corrosion above 30 ppm.
Another controlling factor on the overhead receiver water is pH. Thus should be controlled between pH 5 and 6.5. Ammonia injection into the tower top section can be used as a control for this.
F. Product Disposal
All products are cooled before being sent to storage. Light products should be below 60ºC to reduce vapor losses in storage, but heavier products need not be as cold. If a product is being charged to another unit, there may be an advantage in sending it out hot.
A product must never leave a unit at over 100ºC if there is any possibility of it entering a tank with water bottoms. The hot oil could readily boil the water and blow the roof off.
2.2.2 Product Specifications
The composition of a distillation product is determined by performing laboratory tests on samples of that product. These test results are then compared with product specifications or standards that have been set for the product. If the product is meeting specifications, column operations do not have to be adjusted. But, if the products are off-specification, a change in column operations must be made.
One can see that the control of the tower is a rather complicated simultaneous solution of material and heat balances. At each draw we must draw the quantity of material in the crude that boils within the specified boiling range. If we draw too much, or too little, the product above or below will have to shift by that amount, thereby possibly putting it off specification. To stay on specifications the material balance must be maintained; the quantity of each product in the crude must be withdrawn at that particular draw tray.
The second problem, the heat balance, must be solved so that the right product appears at the right tray with the proper degree of fractionation. The tower designers help with this problem by locating the draw trays according to the design crude and product slate. However, cruder vary, product requirements vary, and the refinery must manipulate the heat and material balance to draw the right amount of product, with the proper distillation range or other product specifications.
Specifications for typical products boiling ranges are shown in Figure 2.12. These products would come out of crude that has a crude assay TBP as shown in Figure 2.13.
A. Initial Boiling Point (IBP)
The initial boiling point (IBP) of a petroleum product is that temperature at which the first drop of condensate is collected during a laboratory distillation test. In a mixture of hydrocarbons, the first molecules to vaporize are the light ones. So, the initial boiling-point test is used to check for light hydrocarbons that are present in a product. Suppose specifications on the bottom product call for an initial boiling point between 100-110°F. Lab tests show an IBP of 95°F. You know that light material boils at lower temperatures than heavy material. So, the bottom product in this example contains material that is too light.
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Figure 2.12 Acceptable Products / |
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Figure 2.13 Typical Crude Oil |
In order to raise the IBP of a product, we must make the product heavier. One way to raise the IBP of the bottom product is to strip some light components off with steam. Another way to raise the IBP is to increase the temperature of the feed or the reboiler temperature so more light components are vaporized.
B. End Boiling Point (EP)
The end boiling point (EP) of a petroleum product is the highest temperature reached during a laboratory distillation test, or the temperature at which the last drop of liquid vaporizes during the test. In a mixture of hydrocarbons, the last molecules to vaporize are the heavy ones. So, the end boiling point or end point test is used to check for heavy hydrocarbons that are present in a product.
Specifications call for an overhead product with an EP between 150-160° F. Lab results indicate an EP of 170° F. You know that heavy material boils at higher temperatures than light material. So, the top product does not meet specifications because it contains material that is too heavy. In order to lower the EP of a product, we must make the product lighter. One way to reduce the EP of the top product is to decrease the feed or reboiler temperature so that fewer heavy components vaporize.
Another way to bring EP on-specification is to lower the top temperature by increasing the reflux rate.
C. Flash Point
The temperature at which a petroleum product generates ignitable vapors is called the flash point. Light hydrocarbons tend to flash more easily than heavy hydrocarbons. A sample that contains traces of light hydrocarbons flashes at a lower temperature than a sample without these traces.
A side draw product carries flash point specifications of 125-130° F. The lab test shows a flash point of 110° F. The sample contains material that is too light. We can bring the product back to specification by decreasing the reflux rate, or by using more stripping steam, or by increasing the reboiler temperature.
D. API Gravity
Another specification for petroleum products is API gravity. API gravity is used to designate the "heaviness" or "lightness" of products based on a scale in which 10° API gravity is the same weight as water. An oil that is exactly the same weight as water would be measured at 10 ° API. Kerosine is measured at about 42° API. Gasoline, which is lighter than kerosene, is measured at about 60° API. The lighter the oil, the higher API gravity.
Suppose specifications call for a product with an API gravity of 30-35°. The product sample tests 28°. The product is too heavy.
E. Colour
Petroleum products are often color tested in the lab. Light hydrocarbons are light colored while heavy hydrocarbons are dark in color. A light hydrocarbon product that is dark colored probably contains too many heavy molecules. Excessive vapor rates can cause small drops of liquid to become entrained in the vapor and be carried up the tower. Entrainment of heavy materials may contaminate the overhead product and make it too dark in color. Hydrocarbons will decompose and change color at very high temperatures. So, an off-color product may indicate that a tower is operating at too high a temperature.
2.3 CRUDE DISTILLATION OPERATION
Figure 2.10 shows a diagram of a crude distillation column. Before the feed enters this column, it is heated by a series of heat exchangers and a furnace. Next, the feed is introduced into the column on the feed tray. Most of the lighter fractions immediately vaporize, or flash and start rising up the tower. The heavier fractions remain in a liquid state and work their way to the bottom of the column. Any light components that remain in the liquid are removed with stripping steam.
In addition to overhead and bottom products, three other fractions are drawn from the side of the tower. Each of these fractions passes through a stripping column that uses steam to remove light components. Vapors from the stripping columns are reintroduced to the tower at a point above the draw-off tray.
2.3.1 Reflux Rate Changing
Vapors at the top of the tower are cooled and condensed to liquid. Part of this liquid is returned to the tower as cooling reflux. Let's consider the effect of making cut point changes in a crude unit by varying the reflux rate. Reflux as a "coolant" that removes heavy fractions by condensing them.
Suppose the reflux rate is increased from 1,000 to 1,200 barrels per hour, and the other tower operating conditions are held constant. This extra reflux flowing down the tower causes the temperature on each tray to decrease. Some of the heavier hydrocarbons in the upward flowing vapors will now condense and fall back down the tower. The heaviest components are condensed out of the vapors on each tray in the column. As a result, the fraction formed on each tray will be lighter. The extra reflux flowing down the tower reduces the temperature of the liquid at the bottom of the column. When the bottom temperature decreases, the amount of light material vaporized out of the liquid at the bottom of the tower is decreased. So the liquid at the bottom of the column becomes lighter. Since the amount of product drawn to the stripper columns remains constant, increasing the reflux rate causes more bottom product to be formed. Because fewer vapors are now going overhead, the amount of top product formed is decreased, or less. Lighter overhead, bottom, and side draw products are produced by increasing the reflux rate.
If we decrease the reflux rate from 1,000 barrels to 800 barrels, the cut point changes are reversed. The temperature on each of the trays increases, and a higher tower temperature mean heavier products. So overhead, bottom, and side draw products become heavier. The amount of overhead product produced increases and the amount of bottom product formed decreases.
2.3.2 Feed Temperature Changing
Now let's consider how changing the temperature of the feed affects cut point changes in the crude unit. Suppose we raise the temperature of the feed and hold the reflux rate and other tower variables constant. As the crude enters the column more of the feed is vaporized because of the higher temperature. Some of the heavy material that previously fell to the bottom of the tower is contained in these vapors. So the products formed above the feed tray become heavier. The increase in temperature causes the lightest materials in the liquid at the bottom of the tower to boil out, so the bottom product becomes heavier. Since more vapor goes overhead when the temperature of the feed is increased, the amount of top product formed increases. Because less liquid falls to the bottom of the column when the feed temperature increases, the amount of bottom product formed decreases. So heavier overhead, bottom, and side draw products produced by increasing the feed temperature.
If we reduce the temperature of the feed, the cut point changes will again reverse. Less heavy material is vaporized when the crude enters the column, so the top and side draw products become lighter. The material that no longer vaporizes is actually lighter than the liquid at the bottom of the column. When this material falls to the bottom of the column, the bottom product gets lighter. Lighter overhead, bottom, and side draw products are produced by decreasing the temperature of the feed. When the feed temperature is reduced, the amount of top product produced decreases and the amount of bottom product formed increases.
2.3.3 Side Product (Draw off) Rate Changing
Another way to change the cut point in a crude column is to vary the amount of liquid that is drawn to the stripper columns. Suppose we increase the kerosene draw by 100 barrels. When we open a stripper draw on the side of a crude unit less reflux flows to the trays below the draw-off tray. Reducing the amount of reflux going to the trays below the kerosene draw causes these trays to heat up. As the temperature on these trays increases more heavy material begins rising up the tower. Because the temperature of the vapors rising to the kerosene draw is higher, the draw-off tray temperature will also be higher. High temperatures produce heavy products, so increasing the kerosene draw makes this product heavier. The products formed below the kerosene draw also become heavier.
Now suppose we want to make the kerosene product heavier without changing the composition of the gas oil and reduced crude products. To do this we must increase the kerosene draw and at the same time not change the amount of reflux, or liquid on the gas oil tray and the trays below this point. We can do this by decreasing the gas oil draw at the same time the kerosene draw is increased. We draw less gas oil product to keep the same amount of reflux on the gas oil tray and the trays below this point. With the same amount of reflux on these trays, the temperature profile in this part of the tower does not change and the gas oil and reduced crude products do not change composition. So to make the kerosene product heavier without changing the composition of the gas oil and reduced crude products, the gas oil draw is decreased and the kerosene draw is increased.
Let’s reverse the situation and look at what happens when the kerosene draw is decreased. Now the amount of reflux flowing to trays below the kerosene draw increases. An increase in reflux causes more heavy components to condense out of the rising vapors because the temperature on the trays falls. Low temperatures produce light products, so reducing the kerosene draw results in a lighter kerosene product. The products formed below the kerosene draw also become lighter.
Suppose we want a lighter kerosene product but do not want to change the composition of the gas oil and reduced crude products. Since there is more reflux flowing down to the gas oil tray, we will have to increase the gas oil draw. In this situation we are drawing more gas oil product to keep the same amount of reflux on the gas oil tray and the trays below this point. So to make the kerosene product lighter without changing the composition of the gas oil and reduced crude products, the gas oil draw is increased and the kerosene draw is decreased.
The composition of crude distillation products can be changed by changing, or varying the amount of liquid that is drawn to a stripping column. Opening a stripper draw makes this product and products formed below this point heavier. Closing a stripper draw makes this product and products below this tray lighter. To change the composition of a side draw product without affecting the composition of products below this point, you must adjust two stripper draws. The first stripper draw adjustment is made to change the composition of the product. The second adjustment keeps the composition of the other products from changing by maintaining the same amount of reflux, or liquid on these trays.
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