Crude Oil Stabilization and Sweetening - Chapter 6
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Chapter 6 193
Crude Oil Stabilization and Sweetening 193
6.1: Introduction 193
6-1-1: Crude oil treatment steps 193
6.2: Process Schemes 194
6.2.1: Multi-Stage Separation 194
6.2.2: Oil Heater-Treaters 194
6.2.3: Liquid Hydrocarbon Stabilizer 195
6.2.4: Cold-Feed Stabilizer 197
6.2.5: Stabilizer with Reflux 197
6.3: Stabilization Equipment 199
6.3.1: Stabilizer Tower 199
6.4: Stabilizer Design 205
6.5: Crude Oil Sweetening 206
6.6.1: Stage vaporization with stripping gas. 206
6.6.2: Trayed stabilization with stripping gas. 207
6.6.3: Reboiled trayed stabilization. 208
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Chapter 6
Crude Oil Stabilization and Sweetening
6.1: Introduction
Once degassed and dehydrated–desalted, crude oil is pumped to gathering facilities to be stored in storage tanks.
These liquids contain a large percentage of methane and ethane, which will flash to gas in the tank. This lowers the partial pressure of all other components in the tank and increases their tendency to flash to vapors. Stabilization is the process of increasing the amount of intermediate (C3 to C5) and heavy (C6+) components in the liquid phase. In an oil field this process is called crude stabilization and in a gas field it is called condensate stabilization.
In stabilization, adjusting the pentanes and lighter fractions retained in the stock tank liquid can change the crude oil gravity. The economic value of the crude oil is accordingly influenced by stabilization because of the following reasons:
1- Liquids can be stored and transported to the market more profitably than gas.
2- It is advantageous to minimize gas losses from light crude oil when stored.
This chapter deals with methods for stabilizing the crude oil to maximize the volume of production as well as its API gravity, against two important constraints imposed by its vapor pressure and the allowable hydrogen sulfide content.
In addition, the requirement to treat the oil at high temperature is more important than stabilizing the liquid and may require the flashing of both intermediate and heavy components to the gas stream.
Gas condensate, on the other hand, may contain a relatively high percentage of intermediate components. Thus, some sort of condensate stabilization should be considered for each gas well production facility.
The most common method used to remove the light components from hydrocarbon liquids before the liquid enters a stock tank or a pipeline is stage separation.
Crude oil is considered ‘‘sweet’’ if the dangerous acidic gases are removed from it. On the other hand, it is classified as ‘‘sour’’ if it contains as much as 0.05 ft3 of dissolved H2S in 100 gal of oil. Hydrogen sulfide gas is a poison hazard because 0.1% in air is toxically fatal in 30 min.
Additional processing is mandatory—via this dual operation—in order to release any residual associated gases along with H2S present in the crude.
A stabilizer can achieve a stable specification product with a higher liquid recovery, but usually results in higher capital expenditures’ (CAPEX) and operating expenses (OPEX). The addition of a stabilizer requires additional space which is normally not a factor for onshore applications, but may be a major consideration for an offshore installation.
6-1-1: Crude oil treatment steps
Produced hydrocarbons from wells normally flow to a separator for removal of the hydrocarbon gas. The hydrocarbon crude or condensate oil outflow from the separator usually goes through additional stages of separation or treatment before reaching the sales point. In each of these stages the liquid reaches near equilibrium at a different condition of pressure and temperature thus to some extent “stabilizing” the crude or condensate.
The following methods of crude stabilization are normally used:
• Multi-stage separation
• Weathering in a stock tank
• Heater-treater after separation
• Stabilizer.
The method one selects for stabilization depends primarily on contract specifications and economics. Factors that favor the installation of a stabilization unit include:
• An oil contract specification that requires a low crude vapor pressure that cannot easily be obtained by stage separation.
• A sour crude with a contract specification that limits the H2S content to less than 60 ppm.
• Condensate production with 500API or higher and flow rates in excess of 5,000 bpd.
6.2: Process Schemes
6.2.1: Multi-Stage Separation
Figure 6-1 shows a multi-stage separation system. This is the most common method of separating oil and gas. This system typically requires from two to four separation stages, each occurring in a separator vessel.
Figure 6-1. Schematic of a three-stage separation system.
6.2.2: Oil Heater-Treaters
Three-phase separators, which utilize gravity separation, often are not adequate to separate the water from the oil. Heating the emulsion is commonly used to break the emulsion. Heater treaters not only improve the oil-water separation process, but also stabilize the crude by vaporizing the light hydrocarbons prior to the crude flowing to an atmosphere pressure storage tank. Utilizing heater-treaters alone often results in higher than desired losses of intermediate components to the vapor phase when the hot crude is flashed entering the storage tank.
The crude departing the treater can be cooled before going to the storage tank by exchanging heat with the colder emulsion upstream of the treater. This will lead to fewer vapor losses and will help stabilize the intermediate components when the crude is flashed at storage tank conditions. For small flow rates, the oil-treating temperature is kept as low as possible to prevent stock tank losses, since the treated oil will normally go directly to the stock tank without cooling.
6.2.3: Liquid Hydrocarbon Stabilizer
It is possible to stabilize a hydrocarbon liquid at constant pressure by successively flashing the hydrocarbon liquid at increasing temperatures as shown in Figure 6-2. At each successive stage the partial pressure of the intermediate components is higher than it could have been at that temperature if some of the lighter components had not been removed by the previous stage. It would be very costly to arrange a process as shown in Figure 6-2 and thus never done. Instead, the same effect can be obtained in a tall, vertical pressure vessel with a cold temperature at the top and a hot temperature at the bottom. This unit is called a “stabilizer.”
Figure 6-2. Multiple flashes at constant pressure and increasing temperature.
A stabilizer applies the same principles as multi-stage separation except that the flashes take place in a stabilizer tower operating at a constant pressure, but with varying temperatures. The stabilizer tower is normally a trayed vertical pressure vessel; however, structured packing may also be used. As heat is added to the bottom of the stabilizer tower, vapors are generated on the bottom tray. The hot vapors rise to the tray above, where they bubble through the liquid. The liquid is heated by the hot vapors, which vaporize some of the hydrocarbon liquid. The vapors, in turn, are cooled by the liquid, and a portion of the vapor is condensed.
This process of vaporization and condensation is repeated on each tray in the stabilizer tower. As the liquids fall down the stabilizer tower, the heavier hydrocarbons are condensed so that the hydrocarbon liquids leaving the stabilizer tower contain almost none of the light hydrocarbon components, and the vapor leaving the top of the stabilizer tower contains almost none of the heavier components.
The vapor pressure of the liquid hydrocarbon leaving the bottom of the tower is controlled by controlling the stabilizer tower pressure and bottom temperature. At a constant pressure, the liquid hydrocarbon product’s vapor pressure can be increased by lowering the bottom temperature, or decreased by increasing the bottom temperature.
Figure 6-3 illustrates a liquid hydrocarbon stabilizer system. The well stream flows to a high pressure, three-phase separator. Liquids containing a high fraction of light ends are cooled and enter the stabilizer tower at a pressure between 100 to 200 psi.
Figure 6-3. Cold-feed stabilization system.
As the hydrocarbon liquid falls from tray to tray in the stabilizer tower, it is heated by the hot gases bubbling through the liquid. On each tray some of the liquids are vaporized and some of the hot gases are condensed. The liquids falling down the stabilizer tower become richer and richer in heavy hydrocarbon components and leaner and leaner in light hydrocarbons. At the bottom of the stabilizer tower, some of the liquids are cycled to a reboiler where they receive heat to provide the necessary bottom temperature which is normally in the range of 2000 to 4000F. The reboiler could be a direct-fired bath, an indirect-fired bath, or a heating media exchanger. For a specific bottom product’s vapor pressure, a lower stabilizer tower operating pressure requires a lower bottom temperature, but more compression is required for the overhead vapors.
The hydrocarbon liquid leaving the stabilizer tower at the bottom tray temperature is in equilibrium with the vapors and is at its bubble point.
The liquid leaving the stabilizer tower is cooled before going to storage or pipeline. The hydrocarbon vapors leaving the top of the stabilizer tower are in equilibrium with the liquids on the top tray and are at their dew point.
One design consideration that needs to be addressed in the design of a stabilizer system is whether to use a cold feed or reflux. A cold-feed stabilizer without reflux such as that shown in Figure 6-3 does not achieve as good a split between the light and heavy components as a column with reflux (see Figure 6-4 and the following discussion); thus, recoveries are not as high. However, a stabilizer with reflux requires additional equipment, higher CAPEX, and higher OPEX, but achieves a higher recovery. Descriptions of both a cold-feed stabilizer and a stabilizer with reflux follow.
6.2.4: Cold-Feed Stabilizer
A conventional stabilizer tower is a distillation column with a reboiler, but no overhead condenser (refer to Figure 6-3). The lack of an overhead condenser means that there is no liquid reflux from the overhead stream.
Thus, the feed is introduced on the top tray and must provide all the cold liquid for the stabilization tower. Since the feed is introduced on the top tray, it is important to minimize the flashing of the feed so that intermediate components are not lost overhead. To lower the feed stream temperature and reduce flashing, a cooler is sometimes added on the inlet feed stream.
Adding a cooler on the inlet feed stream lowers the temperature of the inlet hydrocarbon liquid, lowers the fraction of intermediate components that flash to vapor on the top tray and increases the recovery of these components in the liquid bottoms. However, the colder the feed, the more heat is required from the reboiler to remove light components from the liquid bottoms. If too many light components remain in the liquid, the vapor pressure limitations for the liquid may be exceeded. Light components may also encourage flashing of intermediate components (by lowering their partial pressure) in the storage tank. There is a balance between the amount of inlet cooling and the amount of reboiling required.
The hydrocarbon liquid out the bottom of the stabilizer tower must meet a specified vapor pressure. The stabilizer tower is designed to maximize the molecules of intermediate components in the liquid without exceeding the vapor pressure specification. This is accomplished by driving the maximum number of molecules of methane and ethane out of the liquid and keeping as much of the heavier ends as possible from going out with the gas. The hot liquid from the stabilizer is at its bubble point at the pressure and temperature in the stabilizer. It must be cooled sufficiently to avoid flashing when it enters the atmospheric storage tank.
The overhead gas can be used as fuel, or compressed and included with the sales gas. Any water that enters the column in the feed stream will collect in the middle of the column due to the range of temperatures involved. This water cannot leave with the bottom product or with the overhead stream; therefore, provisions should be made to remove this water from a tray near the middle of the column. The heating of the liquid hydrocarbon in the stabilizer tower acts as a demulsifier to remove water from hydrocarbon liquid. The excellent water-separating ability of the stabilizer usually eliminates the need for a hydrocarbon liquid dehydration system.
6.2.5: Stabilizer with Reflux
Figure 6-4 shows a typical stabilizer system with reflux and a feed/bottom heat exchanger. In this configuration, the well fluid is heated by the bottom product and injected into the stabilizer tower, below the top, where the temperature in the stabilizer tower is equal to the temperature of the feed. The stabilizer tower’s top temperature is controlled by cooling and condensing part of the hydrocarbon vapors leaving the stabilizer and pumping the resulting hydrocarbon liquids back to the tower. This replaces the cold feed configuration and allows better control of the overhead product and, consequently, slightly higher recovery of the heavier components. This configuration minimizes the amount of flashing.
The principles of this configuration are the same as in a cold-feed stabilizer or any other stabilizer tower. As the liquid falls through the tower, it goes from tray to tray, and gets increasingly richer in the heavier components and increasingly leaner in the lighter components. The stabilized hydrocarbon liquid is cooled in the heat exchanger by the feed stream before flowing to the stock tank or pipeline.
At the top of the stabilizer tower intermediate components going out with the gas are condensed, separated, pumped back to the stabilizer tower, and sprayed down on the top tray. This liquid is called “reflux,” and the two-phase separator that separates it from the hydrocarbon liquid from the gas is called a “reflux tank” or “reflux drum.” The reflux performs the same function as the cold feed in a cold feed stabilizer. Cold liquid hydrocarbons strip out the intermediate components from the gas as the gas rises.
The heat required at the reboiler depends upon the amount of cooling done in the condenser. The colder the condenser, the purer the product, and the larger the percentage of the intermediate components that will be recovered in the separator and kept from going out with the gas.
The hotter the bottom temperature, the greater the percentage of light components boiled out of the bottoms. The greater the percentage of light components boiled out of the bottoms liquid, the lower the vapor pressure of the bottoms liquid.
A heat balance around the stabilizer tower is part of the design. The heat leaves the stabilizer tower in the form of vapors out the top, and the liquid bottom product has to be balanced by the heat entering in the feed and the reboiler. If the stabilizer tower has a reflux, this amount of heat has to be added to the column balance.
A stabilizer tower with reflux will recover more intermediate components from the gas than a cold-feed stabilizer tower. However, it requires more equipment to purchase, install, and operate. This additional cost must be justified by the net benefit of the incremental hydrocarbon liquid recovery, less the cost of natural gas shrinkage and loss of heating value, over that obtained from a cold-feed stabilizer.
Figure 6-4. Schematic of a typical crude stabilization with reflux and feed/bottom heat exchanger.
6.3: Stabilization Equipment
6.3.1: Stabilizer Tower
The stabilizer tower is a fractionation tower using trays or packing.
Figure 6-5 shows a stabilizer tower with bubble cap trays.
Trays, structured packing, or random packing are used in the tower to promote intimate contact between the vapor and liquid phases, thereby permitting the transfer of mass and heat from one phase to the other. The feed to the stabilizer tower normally enters near the top of a cold-feed stabilizer, and at or near the tray where the stabilizer tower conditions and feed composition most nearly match the inlet feed conditions, in stabilizer towers with reflux. The liquids in the stabilizer tower fall down through the downcomer, across the tray, over the weir and into the down-comer to the next tray. The temperature on each tray increases as the liquids drop from tray to tray. Hot gases come up the stabilizer tower and bubble through the liquid on the tray above, where some of the heavier components in the gas are condensed and some of the lighter components in the liquid are vaporized. The gas gets leaner and leaner in heavy hydrocarbons as it travels up the stabilizer tower; the falling liquids get richer and richer in the heavier hydrocarbon components. The vapors leaving the top of the stabilizer tower contain a minimum amount of heavy hydrocarbons, and the liquid leaving the bottom of the tower contains a minimum of light hydrocarbons. Stabilizer columns commonly operate at pressures between 100 to 200 psig.
6.3.1.1: Trays and Packing
The more stages, the more complete the split, but the taller and more costly the tower. Most stabilizers will normally contain approximately five theoretical stages. In a refluxed tower, the section above the feed is known as the rectification section, while the section below the feed is known as the stripping section. The rectification section normally contains about two equilibrium stages above the feed, and the stripping section normally contains three equilibrium stages.
Trays
For most trays, liquid flows across an “active area” of the tray and then into a “down-comer” to the next tray below, etc. Inlet and/or outlet weirs control the liquid distribution across the tray. Vapor flows up the stabilizer tower and passes through the tray active area, bubbling up through (and thus contacting) the liquid flowing across the tray. The vapor distribution is controlled by:
• Perforations in the tray deck (sieve trays),
• Bubble caps (bubble cap trays), or
• Valves (valve trays).
Trays are generally divided into four categories:
• Sieve trays,
• Valve trays,
• Bubble cap trays, and
• High capacity/high efficiency trays.
Sieve Trays
Sieve trays are the least expensive tray option. In sieve trays, vapor flowing up through the tower contacts the liquid by passing through small perforations in the tray floor (Figure 6-6). Sieve trays rely on vapor velocity to exclude liquid from falling through the perforations in the tray floor. If the vapor velocity is much lower than design, liquid will begin to flow through the perforations rather than into the downcomer.
This condition is known as weeping. Where weeping is severe, the equilibrium efficiency will be very low. For this reason, sieve trays have a very small turndown ratio.
Figure 6-5. Schematic of a stabilizer tower.
Figure 6-6. Vapor flow through a sieve tray.
Valve Trays
Valve trays are essentially modified sieve trays. Like sieve trays, holes are punched in the tray floor. However, these holes are much larger than those in sieve trays. Each of these holes is fitted with a device called a “valve.” Vapor flowing up through the tower contacts the liquid by passing through valves in the tray floor (Figure 6-7). Valves can be fixed or moving. Fixed valves are permanently open and operate as deflector plates for the vapor coming up through the tray floor. For moving valves, vapor passing through the tray floor lifts the valves and contacts the liquid. Moving valves come in a variety of designs, depending on the manufacturer and the application. At low vapor rates, valves will close, helping to keep liquid from falling through the holes in the deck.
At sufficiently low vapor rates, a valve tray will begin to weep. That is, some liquid will leak through the valves rather than flowing to the tray down-comers. At very low vapor rates, it is possible that all the liquid will fall through the valves and no liquid will reach the down-comers.
This severe weeping is known as “dumping.” At this point, the efficiency of the tray is nearly zero.
Figure 6-7. Vapor flow through valve tray
Bubble Cap Trays
In bubble cap trays, vapor flowing up through the tower contacts the liquid by passing through bubble caps (Figure 6-8).
Each bubble cap assembly consists of a riser and a cap. The vapor rising through the tower passes up through the riser in the tray floor and then is turned downward to bubble into the liquid surrounding the cap. Because of their design, bubble cap trays cannot weep. However, bubble cap trays are also more expensive and have a lower vapor capacity/higher pressure drop than valve trays or sieve trays.
Figure 6-8. Vapor flow through bubble cap tray
High Capacity/High Efficiency Trays
High capacity/high efficiency trays have valves or sieve holes or both. They typically achieve higher efficiencies and capacities by taking advantage of the active area under the down-comer. At this time, each of the major vendors have their own version of these trays, and the designs are proprietary.
Bubble Cap Trays vs. Valve Trays
At low vapor rates, valve trays will weep. Bubble cap trays cannot weep (unless they are damaged). For this reason, it is generally assumed that bubble cap trays have nearly an infinite turndown ratio. This is true in absorption processes (e.g., glycol dehydration), in which it is more important to contact the vapor with liquid than the liquid with vapor. However, this is not true of distillation processes (e.g., stabilization), in which it is more important to contact the liquid with the vapor. As vapor rates decrease, the tray activity also decreases. There eventually comes a point at which some of the active devices (valves or bubble caps) become inactive. Liquid passing these inactive devices gets very little contact with vapor. At this point, it is possible that liquid may flow across the entire active area without ever contacting a significant amount of vapor. This will result in very low efficiencies for a distillation process.
Nothing can be done with a bubble cap tray to compensate for this.
However, a valve tray can be designed with heavy valves and light valves. At high vapor rates, all the valves will be open. As the vapor rate decreases, the valves will begin to close. With light and heavy valves on the tray, the heavy valves will close first, and some or all of the light valves will remain open. If the light valves are properly distributed over the active area, even though the tray activity is diminished at low vapor rates, what activity remains will be distributed across the tray. All liquid flowing across the tray will contact some vapor, and mass transfer will continue. Of course, even with weighted valves, if the vapor rate is reduced enough, the tray will weep and eventually become inoperable.
However, with a properly designed valve tray this point may be reached after the loss in efficiency of a comparable bubble cap tray. So, in distillation applications, valve trays can have a greater vapor turndown ratio than bubble cap trays.
Tray Efficiency and Stabilizer Height
In general, stabilizer trays generally have a 70% equilibrium stage efficiency. That is, 1.4 actual trays are required to provide one theoretical stage. The spacing between trays is a function of the spray height and the down-comer backup (the height of clear liquid established in the down-comer). The tray spacing will typically range from 20 to 30 inches (with 24 inches being the most common), depending on the specific design and the internal vapor and liquid traffic. The tray spacing may increase at higher operating pressures (greater than 165 psia) because of the difficulty in disengaging vapor from liquid in the active areas of the tray.
Packing
Packing typically comes in two types: random and structured. Liquid distribution in a packed bed is a function of the internal vapor/liquid traffic, the type of packing employed, and the quality of the liquid distributors mounted above the packed bed. Packing material can be plastic, metal, or ceramic. Packing efficiencies can be expressed as height equivalent to a theoretical plate (HETP).
Random Packing
A bed of random packing typically consists of a bed support (typically a gas injection support plate) upon which pieces of packing material are randomly arranged (they are usually poured or dumped onto this support plate). Bed limiters, or hold-downs, are sometimes set above random beds to prevent the pieces of packing from migrating or entraining upward. Random packing comes in a variety of shapes and sizes. For a given shape (design) of packing, small sizes have higher efficiencies and lower capacities than large sizes.
Figure 6-9 shows a variety of random packing designs. An early design is known as a Rasching ring. Rasching rings are short sections of tubing and are low-capacity, low-efficiency, high-pressure drop devices. Today’s industry standard is the slotted metal (Pall) ring. A packed bed made of 1-inch slotted metal rings will have a higher mass transfer efficiency and a higher capacity than will a bed of 1-inch Rasching rings. The HETP for a 2-inch slotted metal ring in a stabilizer is about 36 inches. This is slightly more than a typical tray design, which would require 34 inches (1.4 trays × 24-inch tray spacing) for one theoretical plate or stage.
Structured Packing
A bed of structured packing consists of a bed support upon which elements of structured packing are placed. Beds of structured packing typically have lower pressure drops than beds of random packing of comparable mass transfer efficiency. Structured packing elements are composed of grids (metal or plastic) or woven (metal or plastic) or of thin vertical crimped sheets (metal, plastic, or ceramic) stacked parallel to each other. Figure 6-10 shows examples of the vertical crimped sheet style of structured packing.
The grid types of structured packing have very high capacities and very low efficiencies, and are typically used for heat transfer or for vapor scrubbing. The wire mesh and the crimped sheet types of structured packing typically have lower capacities and higher efficiencies than the grid type.
Trays or Packing ?
There is no umbrella answer. The choice is dictated by project scope (new tower or retrofit), current economics, operating pressures, anticipated operating flexibility, and physical properties.
Distillation Service
For distillation services, as in hydrocarbon stabilization, tray design is well understood, and many engineers are more comfortable with trays than with packing. In the past, bubble cap trays were the standard. However, they are not commonly used in this service anymore. Sieve trays are inexpensive but offer a very narrow operating range when compared with valve trays. Although valve trays offer wider operating range than sieve trays, they have moving parts and so may require more maintenance. High capacity/high efficiency trays can be more expensive than standard valve trays. However, high capacity/high efficiency trays require smaller diameter stabilization towers, so they can offer significant savings in the overall cost of the distillation tower. Random packing has traditionally been used in small diameter (<20 inches) towers. This is because it is easier and less expensive to pack these small diameter towers. However, random packed beds are prone to channeling and have poor turndown characteristics when compared with trays. For these reasons, trays were preferred for tower diameters greater than 20 inches.
Stripping Service
For stripping service, as in a glycol or amine contactor, bubble cap trays are the most common. In recent years, there has been a growing movement toward crimped sheet structured packing. Improved vapor and liquid distributor design in conjunction with structured packing can lead to smaller-diameter and shorter stripping towers than can be obtained with trays.
6.3.1.2: Stabilizer Reboiler
The stabilizer reboiler boils the bottom product from the stabilizer tower.
The source of all heat used to generate vapor in a stabilizer is the reboiler. The boiling point of the bottom product is controlled by controlling the heat input of the reboiler together with the stabilizer operating pressure, this actions control the vapor pressure of the bottom product.
Reboiler temperatures typically range from 2000 to 4000F (900 to 2000C) depending on operating pressure, bottom product composition, and vapor pressure requirements. It’s important to note that reboiler temperatures should be kept to a minimum to decrease the heat requirements, limit salt buildup, and prevent corrosion problems.
Maintaining stabilizer operating pressures below 200 psig will result in reboiler temperatures below 3000F. A water-glycol heating medium can then be used to provide heat. Higher stabilizer pressures require the use of steam or hydrocarbon-based heating mediums.
However, operating at high pressures decreases the flashing of the feed when entering the stabilizer tower and decreases the amount of feed cooling required. In general, a liquid hydrocarbon stabilizer should be designed to operate between 100 to 200 psig.
Selection of a stabilizer heat source depends on the medium and tower operating pressure. The source of reboiler heat should be considered when a crude stabilizer is being evaluated. If turbine generators or compressors are installed nearby, then waste heat recovery should be considered.
Figure 6-9. Various types of random packing.
Figure 6-10. Structured packing can offer better mass transfer than trays.
6.3.1.3: Stabilizer Cooler
The stabilizer cooler is used to cool the bottom product leaving the tower before it goes to a tank or pipeline. The temperature of the bottom product may be dictated by contract specification or by efforts to prevent loss of vapors from an atmospheric storage tank.
For a stabilizer with a reflux system, the bottom product may be cooled by exchanging heat with the feed to the stabilizer.
6.3.1.4: Stabilizer Reflux System
The stabilizer reflux system consists of a reflux condenser, reflux accumulator, and reflux pumps. The system is designed to operate at a temperature required to condense a portion of the vapors leaving the top of the stabilizer.
The temperature range is determined by calculating the overhead vapor’s dew point temperature. The heat duty required is determined by the amount of reflux required.
The type of exchanger selected for the reflux depends on the design temperature required to condense the reflux. The lower the operating pressure of the stabilizer, the lower the temperature required for condensing the reflux. In most installations, air-cooled exchangers may be used. Some installations may require refrigeration and a shell-and-tube exchanger configuration.
The reflux accumulator consists of a two-phase separator with several minutes of retention time to allow separation of the vapors and liquids.
The reflux accumulator is normally located below the reflux condenser, with the line sloped from the condenser to the accumulator. The size of the reflux accumulator depends on the amount of reflux required and the total amount of vapors leaving the stabilization tower.
Reflux pumps are sized to pump the required reflux from the reflux accumulator back to the top of the stabilizer tower. Depending upon the reflux circulation rate, two 100 percent pumps or three 50 percent pumps may be installed. This allows either a 100 percent spare or a 50 percent spare pump.
6.3.1.5: Stabilizer Feed Cooler
An inlet feed cooler may be required if a cold feed stabilizer tower is used. Calculations are required to determine the design feed temperature and the heat duty exchanger. This exchanger is usually a shell-and-tube type with some type of refrigerant required to cool the feed sufficiently.
6.3.1.6: Stabilizer-Heater
A feed heater may be required for stabilizers with a reflux system. If a feed heater is used, it is normally a shell-and-tube type exchanger that exchanges heat between the cold feed and the hot bottom product, which is then cooled before going to storage or pipeline.
The selection of equipment and the decision whether to use cold-feed or a reflux system depends on a number of factors. The availability of heat sources for reboiler and streams for cooling the system influence the final decision. Economics of product recovery, CAPEX, and OPEX are major considerations.
6.4: Stabilizer Design
It can be seen from the previous description that the design of both a cold-feed stabilizer and a stabilizer with a reflux is a rather complex and involved procedure. Distillation computer simulations are available that can be used to optimize the design of any stabilizer if the properties of the feed stream and desired vapor pressure of the bottom product are known. Cases should be run of both a cold-feed stabilizer and one with reflux before a selection is made. Because of the large number of calculations required, it is not advisable to use hand calculation techniques to design a distillation process. There is too much opportunity for computational error.
Normally, the contract specification will specify a maximum Reid Vapor Pressure (RVP). This pressure is measured according to a specific American Society of Testing Materials (ASTM) testing procedure.
A sample is placed in an evacuated container such that the ratio of the vapor volume to the liquid volume is 4 to 1. The sample is then immersed in a 1000F liquid bath. The absolute pressure then measured is the RVP of the mixture.
The vapor pressures of various hydrocarbon components at 1000F are given in Table 6-1.
The vapor pressure of a mixture is given by:
VP = ∑ [ VPn x MFn ] Eq. 6-1
Where
Where VP = vapor pressure of mixture, psia
VPn = vapor pressure of component n, psia
MFn = mole fraction of component n in liquid
Table 6-1, Vapor pressure of relative light components.
6.5: Crude Oil Sweetening
Apart from stabilization problems of ‘‘sweet’’ crude oil, ‘‘sour’’ crude oils containing hydrogen sulfide, mercaptans, and other sulfur compounds present unusual processing problems in oil field production facilities. The presence of hydrogen sulfide and other sulfur compounds in the well stream impose many constraints. Most important are the following:
* Personnel safety and corrosion considerations require that H2S concentration be lowered to a safe level.
* Brass and copper materials are particularly reactive with sulfur compounds; their use should be prohibited.
* Sulfide stress *****ing problems occur in steel structures.
* Mercaptans compounds have an objectionable odor.
Along with stabilization, crude oil sweetening brings in what is called a ‘‘dual operation,’’ which permits easier and safe downstream handling and improves and upgrades the crude marketability.
Three general schemes are used to sweeten crude oil at the production facilities:
6.6.1: Stage vaporization with stripping gas.
This process—as its name implies—utilizes stage separation along with a stripping agent.
Hydrogen sulfide is normally the major sour component having a vapor pressure greater than propane but less than ethane.
Normal stage separation will, therefore, liberate ethane and propane from the stock tank liquid along with hydrogen sulfide. Stripping efficiency of the system can be improved by mixing a lean (sweet) stripping gas along with the separator liquid between each separation stage. Figure 6-11, represents typical stage vaporization with stripping gas for crude oil sweetening/stabilization. The effectiveness of this process depends on the pressure available at the first-stage separator (as a driving force), well stream composition, and the final specifications set for the sweet oil.
Figure 6-11. Crude sweetening by stage vaporization with stripping gas.
6.6.2: Trayed stabilization with stripping gas.
In this process, a tray stabilizer (nonreflux) with sweet gas as a stripping agent is used as shown in Figure 6-12. Oil leaving a primary separator is fed to the top tray of the column countercurrent to the stripping sweet gas. The tower bottom is flashed in a low-pressure stripper. Sweetened crude is sent to stock tanks, whereas vapors collected from the top of the gas separator and the tank are normally incinerated. These vapors cannot be vented to the atmosphere because of safety considerations. Hydrogen sulfide is hazardous and slightly heavier than air; it can collect in sumps or terrain depressions.
This process is more efficient than the previous one.
Figure 6-12. Crude sweetening by trayed stabilization with stripping gas.
6.6.3: Reboiled trayed stabilization.
The reboiled trayed stabilizer is the most effective means to sweeten sour crude oils. A typical reboiled trayed stabilizer is shown in Figure 6-13. Its operation is similar to a stabilizer with stripping gas, except that a reboiler generates the stripping vapors flowing up the column rather than using a stripping gas. These vapors are more effective because they possess energy momentum due to elevated temperature.
Because hydrogen sulfide has a vapor pressure higher than propane, it is relatively easy to drive hydrogen sulfide from the oil.
Figure 6-13. Crude sweetening by reboiled trayed stabilization.
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