Similar to crude oil, natural gas is a mixture of hydrocarbons, water, and inorganic components, but in a gaseous state. Typically, unwanted components are removed upstream to prevent operational or corrosion problems. Often the processes used to remove these impurities are called gas treating or gas conditioning, as further explained here.
The mixture or allocation of various components in a natural gas stream can vary significantly by location. The gas is often classified based on its component make-up. For example, natural gas containing sulfur compounds, such as hydrogen sulfide (H2S) or mercaptans, is termed “sour gas.” Likewise, when natural gas is absent any significant amount of sulfur compounds, it is termed “sweet gas.” If water is present along with H2S or carbon dioxide (CO2), the gas is said to be acidic. According to this article from the Society of Professional Engineers, even with ample supplies of natural gas in the world, nearly one in three sources contains acid gas.
Thus, natural gas with appreciable amounts of undesirable components must be further treated or conditioned before being transported by a midstream company or accepted by a downstream gas processor.
Gas Sweetening & Amine Regeneration
Natural gas containing high quantities of H2S and CO2 is considered toxic. If H2S and CO2 volumes are appreciable, this lowers the heating value of the sales gas. Thus, sour gas or acid gas must be treated to remove these toxic components. The processes used for removal of acid gas are referred to as sour gas sweetening, amine gas sweetening, gas conditioning or gas treatment.
If water is present in the natural gas along with acid gas components, the combination can be highly corrosive. Therefore, some processes require that the water be removed from the natural gas (dehydration) prior to any other downstream gas treatment. Buyers and transporters of natural gas often establish product specifications for the sales gas. Specifications for sales gas often limit H2S to less than 4ppm and CO2 to less than 3 or 4 mole percent.
If water is present in the natural gas along with acid gas components, the combination can be highly corrosive.Click to tweet
Gas sweetening is achieved by contacting the primary gas stream with a solvent solution, usually amine. Alkanolamines are the most widely used solvents for removal of acid gas components. There are several commercial amines available including triethanolamine (TEA), diethanolamine (DEA), monoethanolamine (MEA), diglycolamine (DGA) and methyldiethanolamine (MDEA). Some chemical manufacturers have their own proprietary solvents for gas sweetening. For more detail, read this article from the GSPA Engineering Data Book.
Many of the gas sweetening processes are similar. For a general process description, we will use the term MDEA, or more generally, amine. MDEA is a tertiary amine which can be regenerated and can be used to selectively remove H2S and slip CO2. Slip CO2 is the CO2 that passes through the process along with the treated gas. In this process, MDEA contacts and absorbs the acidic gases. The lean aqueous amine concentration, generally in the range of 40 to 50% by weight, flows counter current to the gas stream in an Absorber/Contactor column.
Detailed Description of Typical Amine Unit Process
The inlet stream to the Gas Treatment Unit (GTU) typically arrives at a temperature of 30 to 45 degrees C. To remove free water and liquid hydrocarbons, an inlet filter separator is used to reduce the likelihood of foaming. If foaming does occur it can result in high amine losses, off-spec gas and a high pressure differential across the Absorber column.
After the free liquid scrubbing, the wet gas enters the Absorber at the bottom and contacts a momentum breaker, such as a Multi Vane Inlet Device, for proper gas distribution. The wet acid gas flows upward through the chimney trays and through the contact section before exiting the Absorber. The contact section can be either trays or structured packing. At this point the sour gas flowing upwards comes in contact with the counter-current lean amine bring fed at the top of the packing. Here in the contact section the amine absorbs the H2S and CO2 in an exothermic reaction.
To minimize amine losses, a water wash section is installed above the contact section, which consists of three to four trays known as the structured packing. It is here that the wash water contacts and removes residual amine from the treated gas. The aqueous solution containing amine is then routed to the regeneration system where make-up water is added to the amine. The treated gas exits the contact section and continues to flow upward to the high efficiency vane-type mist extractor to remove any entrained amine before leaving the Absorber. The sweet gas exiting the Absorber then goes through downstream processing systems, such as Gas Dehydration Systems and Dew Point Control Units, to meet the sales gas specifications.
A sharp increase in Absorber differential pressure is an excellent indication that foaming is occurring.Click to tweet
The rich amine is collected at the bottom of the Absorber where it flows to the regeneration system under level control. A differential pressure instrument on the Absorber monitors the differential pressure across the structured packing. A sharp increase in Absorber differential pressure is an excellent indication that foaming is occurring.
After pressure reduction, the rich amine from the Absorber is then sent to an Amine Flash Drum. Here the hydrocarbons are separated from the amine and a small amount of acid gas is flashed. This flashed gas can be sent to flare or be used as fuel gas. Should the flashed gas be used as fuel gas, it is then routed to the stripping section of the Amine Flash Drum and hydrocarbons are sent to the closed drain system. The Amine Flash Drum is a horizontal 3-phase separator designed to operate when 50 to 60% full.
The flashed gas from Amine Flash Drum enters the stripping section and flows upward through the structured packing. Here in the trays it comes in contact with either downward-flowing lean amine or water wash to reduce the acid gas content in the flashed gas.
Amine Regeneration Process
The rich amine from the Amine Flash Drum is heated in the Lean/Rich Amine Exchanger, typically a plate and frame type exchanger. Rich amine is preheated and lean amine is cooled to about 95 to 100 degrees Celsius before entering the Regenerator. The Amine Flash Drum level is removed on level-control. The level control valve is located downstream of the Lean/Rich Exchanger to minimize two-phase flow through the exchanger.
The preheated rich amine enters the Regenerator through a liquid deflector and flows down to the chimney tray and into the Reboiler. The kettle-type reboiler heats the rich amine solution and produces sufficient steam required to strip the acid gases. Separated acid gases from the Reboiler flow to the Regenerator. Lean amine from the Reboiler overflows the weir and passes through the Lean/Rich Amine Exchanger to heat the incoming rich amine and, in the process, cool the lean amine.
Steam from the Reboiler flows up through the trays and provides the heat required to regenerate the amine. The gas flowing up the column becomes more enriched with acid as it rises in the Regenerator. Just above the rich amine feed is a water wash section to minimize amine losses. This section of trays uses reflux water to extract amine from the steam and send it back down the column. The relatively wet acid gas then exits the top of the Regenerator and enters the Regenerator Condenser where the wet gas stream is cooled using a suitable heat exchanger, such as plate and frame exchanger.
The 2-phase stream then enters the Regenerator Reflux Drum where the water and sour gas are separated. The sour gas is then pressure-controlled to disposal by flare, injection or sulfur recovery unit (SRU). The water is pumped back to the top feed point of the Regenerator as reflux by the Regenerator Reflux pumps.
Lean Amine from the Reboiler overflows the weir and passes through the Lean/Rich Amine Exchanger where it is cooled by preheating the incoming rich amine. The partially-cooled lean amine is then further cooled to a temperature 5 to 10 degrees celsius higher than the acid gas coming into the amine contactor/absorber. A higher lean amine temperature can result in excessive amine losses. A lower lean amine temperature can result in hydrocarbon condensation in the absorber, resulting in operational problems. Depending on the operating pressure of the absorber a lean amine booster pump may be required. The amine then enters the Absorber through GTU Lean Amine Main Pumps. Flow to the Absorber is controlled by a flow control valve.
A slip stream of lean amine (10-20%) from the Lean Amine Cooler goes through a series of filters. The first is a Lean Amine Filter which protects the downstream carbon bed from fouling. The slip stream then goes through a Lean Amine Carbon Bed that removes impurities which may promote foaming in the towers. The last filter, a Lean Amine After Filter, removes any remaining carbon fines. The slipstream then is returned to the GTU Lean Amine Booster pumps suction.
Anti-foam chemical is injected at the lean amine circulation pump suction to prevent foaming. The Anti-foam Injection System is comprised of both an anti-foam chemical storage tank and anti-foam chemical injection pumps.
Gas Dehydration & TEG Regeneration
Dehydration is the process by which water vapor is removed from natural gas. Natural gas is required to be dehydrated to meet sales gas specifications, to reduce the dew point temperature, to reduce corrosion in gas transmission pipelines, and to prevent excess accumulation of liquid slugs in pipelines. For an exhaustive study on the formation of hydrates, we recommend Natural Gas Hydrates: A Guide for Engineers, by John J. Carroll, available here.
There are several commercial methods for dehydrating natural gas. The most common are glycol dehydration, using a liquid desiccant, and molecular sieve dehydration, using a solid adsorbent. The most commonly used glycols for dehydration applications are:
- Monoethylene glycol (MEG also known as ethylene glycol)
- Diethylene glycol (DEG),
- Triethylene glycol (TEG),
- Tetraethylene glycol (TREG)
Glycol Dehydration and Glycol Regeneration
TEG dehydration is widely used for drying the gas because vapor losses are low, cost is nominal, boiling point is higher than water, and TEG has an affinity toward water.
Higher inlet gas temperatures require higher glycol circulation rates because hotter natural gas has a higher soluble water content in the TEG process. Gas temperatures should be higher than 20 degrees C as lower temperatures are likely to cause the formation of hydrates and unnecessarily increase viscosity of the glycol. If inlet temperatures are too high, then an inlet cooler is recommended.
Higher operating pressure is not a major concern for gas dehydration with glycol, but glycol losses do increase along with an increase in pressure. Low operating pressure increases the volumetric flow which requires a larger contactor. Low pressure increases the water content in the gas which requires a larger regeneration system with more stages.
Water-saturated gas, from either separators or compressors, flows to the glycol contactor. Glycol contactors are designed with either an internal scrubber or an external scrubber. It is important to have an inlet scrubber or filter separator when an integral scrubber-contactor is not used. The inlet scrubber will remove any free water and hydrocarbons. The presence of hydrocarbons can result in foaming, while the presence of water can increase the reboiler duty and cause salt precipitation or fouling.
The wet gas enters the contactor through a multi-vane inlet device, then flows upward through a section of structured packing in a counter-current direction where it is is contacted by lean TEG that is flowing downward. Prior to the structured packing, lean TEG enters the contactor at the top of the column and cascades in a downward direction after passing through a liquid distributor, tower packing and chimney tray. Rich TEG is routed to a TEG Regeneration System via a level control valve.
TEG dehydration is widely used for drying the gas because vapor losses are low, cost is nominal, boiling point is higher than water, and TEG has an affinity toward water.Click to tweet
In a vertically-oriented flash vessel, a bucket enables skimming and removal of hydrocarbons. If the vessel is horizontal, the Glycol Flash Drum design uses a bucket and weir.Click to tweet
The Glycol Reflux Coil operates at low pressure, ranging from 4.5 to 5.5 barg, and is designed for the same pressure as the glycol contactor. The lower pressure prevents gas blow-by through the level control valve to the glycol flash drum. The vapors leaving through the overhead line of the still column are typically sent to a low-pressure flare.
Rich Glycol from the Glycol Reflux Coil enters the tube side of the Cold Lean/Rich Heat Exchanger where it is warmed to approximately 80 to 90 degrees C by a counter-current flow of lean Glycol prior to entering the Glycol Flash Drum. The Glycol Flash Drum is designed as either a vertical or horizontal type. In a vertically-oriented flash vessel, a bucket enables skimming and removal of hydrocarbons. If the vessel is horizontal, the Glycol Flash Drum design uses a bucket and weir.
The Glycol Flash Drum is used to remove dissolved gas and liquid hydrocarbons because any residual amounts can cause foaming. Liberated gases exit the vessel from the gas outlet nozzle to an LP flare header under pressure control. A Fuel Gas Blanket in the Glycol Flash Drum maintains the pressure on the vessel. Liquid hydrocarbons that accumulate in the vessel are skimmed into the bucket and subsequently drained. Skimming operations can be done either manually or automatically by using a level control valve.
Rich Glycol from the Glycol Flash Drum flows to one of the two Glycol Sock Filters, each sized for 100% flow. The Cartridge Filter is sized to collect solids from 5 to 10-micron in size and larger. The rich Glycol then flows to the Activated Carbon Filter to adsorb dissolved hydrocarbons, thereby mitigating the effects of foaming.
The filtered rich Glycol is preheated to approximately 150 to 165 degrees C in the Hot Lean/Rich Heat Exchanger by way of heat transfer with the outgoing lean glycol. The hot rich Glycol from the Heat Exchanger flows across the Flash Tank Level Control Valve into the TEG Still Column. The Flash Tank Level Control Valve is located downstream of the Hot Lean/Rich Glycol Heat Exchanger in order to maintain back pressure on the exchanger and minimize vapor generation within the tubes.
The TEG Still Column operates at atmospheric pressure, or at low pressure back pressure, and is filled with Random Packing. The rich Glycol enters the TEG Still Column through an internal pipe distributor. The Glycol flows downward across the packing and is partly regenerated in the column through contact with rising vapors from by the TEG Reboiler. The Glycol vapor is partially condensed by the TEG Reflux Condenser as it rises through the TEG Still Column.
Chemicals for either pH-adjustment or prevention of foam generation are used intermittently based on requirements at site. These chemicals prevent foaming in the columns and maintain the quality of the glycol.Click to tweet
Because TEG is highly hygroscopic, the intimate contact between wet gas and lean TEG on the surface of structured packing allows absorption of water vapor from the gas stream. A detailed discussion of the absorption process can be found here in the book Gas Treating: Absorption Theory and Practice, by Dag Eimer, copyright 2014.
A large amount of water is removed at the bottom of the packing where the gas holds most of the water. As the gas flows upward, it is stripped of water and becomes dry. The remaining water vapor in the gas is removed toward the top of the contactor where the TEG is at its highest concentration.
It is important that the TEG entering the top of the contactor be cooled to 5-8 degrees C above the inlet gas temperature in the lean TEG cooler. This is necessary because equilibrium between the TEG and the water vapor in the gas is affected by temperature. After contacting the gas, the water-rich TEG is regenerated by heating it at near atmospheric pressure to a temperature high enough to remove virtually all the absorbed water. The regenerated TEG is then cooled and re-circulated back to the contactor. The dry gas exits the contactor via a high efficiency mist eliminator and sent for further processing.
Lean glycol enters the top of the glycol contactor. The glycol is distributed evenly across the packing with a liquid distributor. It is important that the distributor be designed and fabricated to an acceptable tolerance to avoid channeling. As the glycol flows down the surface of the structured packing, it absorbs water from the natural gas and becomes rich in water. Rich glycol is discharged under level control from the contactor and flows to the Glycol Reflux Coil of the TEG Reflux Condenser in the Glycol Regeneration Package.
The TEG Reflux Condenser at the top of the Glycol Still Column maintains the temperature of the steam leaving the overhead line at about 100 degrees C. This limits glycol vaporization losses. Rich glycol flowing through the Glycol Reflux Coil is warmed by the hot water and the glycol vapors from the reboiler. The overhead temperature is controlled by regulating the amount of rich glycol flow through the reflux coil with a manual bypass valve or a temperature control valve.
The partially-regenerated Glycol leaving the bottom of the TEG Still Column now enters the front end of the TEG Reboiler for regeneration. The Reboiler can contain an electric heater, or, if it is a kettle-type reboiler, heat is provided by steam. Gravity causes the regenerated glycol to flow across the length of the Reboiler and enter the adjacent Stripping Column. The TEG Reboiler and Stripping Column operate at atmospheric pressure at 204 degrees C.
The Stripping Column enhances the lean TEG concentration in order to meet the gas dew point. Stripping Gas is superheated by passing the gas through a stripping coil in the reboiler before being sent to the Stripping Column where it flows upward to come in contact with the lean TEG. The column is designed with random packing which provides adequate surface area for stripping the residual water content from the lean glycol. The steam, or heating medium, in a kettle-type reboiler is regulated to automatically control the TEG Reboiler temperature. If an electric heating bundle is used, the TEG Reboiler temperature is controlled by a Thyristor Control Panel.
In the glycol regeneration process, gravity causes 204 degree C glycol to flow from the bottom of the Stripping column into the shell side of both the hot and cold Lean/Rich Glycol Heat Exchangers. Here the glycol is cooled to less than 93 degrees C to prevent seal damage to the pumps.
Lean Glycol from the shell side of the cold lean/rich side of the exchanger flows into the TEG Surge Drum. The TEG Surge Drum is sized for a maximum of 20 minutes residence time at maximum pump capacity. It can also be sized to allow 14 to 21 days of glycol losses or to allow sufficient capacity to drain the reboiler to the surge drum when an electric heater bundle is used.
The Glycol Circulation Pumps are positive displacement-type pumps and can be either rotary gear-type or plunger-type reciprocating pumps. These pumps are an important part of the Glycol Regeneration Unit. The pumps transfer the lean TEG from the surge drum to the TEG contactor via a lean TEG cooler. The lean TEG cooler is designed to cool down the incoming lean TEG to a temperature within 5 to 8 degrees C of the inlet wet gas to the contactor. The Lean TEG cooler is designed as either a Gas/Gas Exchanger, which uses dehydrated gas from the glycol contactor to cool the incoming lean TEG, or a normal shell and tube exchanger, which uses a cooling medium.
Chemicals for either pH-adjustment or prevention of foam generation are used intermittently based on requirements at site. These chemicals prevent foaming in the columns and maintain the quality of the glycol.
The MEG regeneration process is similar process but is not detailed herein. We would be glad to provide more detail about this process. Simply click the button below to talk to a VME Product Manager or Engineer.
To achieve the required mercury content of LNG pipeline feed gas, mercury removal is necessary as mercury will attack aluminum in the heat exchangers at low temperatures. Mercury removal beds are normally located downstream of the dehydration systems as it removes any free liquid and water. This also increases the efficiency of mercury removal. The beds can be installed at different locations in the plant depending on the process and metallurgy.
Chemical adsorption technology is utilized to remove mercury from natural gas. Before entering a mercury adsorption tower, feed gas goes through an inlet coalescence separator to first remove free water and other impurities such as dust. Gas enters the mercury removal tower which utilizes a sulphur-impregnated, carbon-based trapping material. The sulphur reacts with the mercury to form mercury sulphide which then adheres to the bed. The outlet gas from the mercury removal unit is then sent to the downstream process.
Molecular Sieve Dehydration & CO2 Gas Removal via Membrane
Molecular sieve dehydration is used when natural gas is to be used for NGL recovery plants, LNG plants, or when very low water dew point is required. Dehydration of natural gas using molecular sieve can achieve outlet water content of less than 0.1 parts per million (ppm).
Molecular Sieve dehydration uses solid-bed desiccant adsorption for the removal of water vapor. There are several commercially available solid-bed desiccant suppliers that can be used for such purpose. The mole sieve design usually consists of 2 or more units based on client preference and process requirements. The most simplest and most common design is the 2-unit design where one is under adsorption while the other is handles regeneration and cooling.
Molecular sieve dehydration is used when natural gas is to be used for NGL recovery plants, LNG plants, or when very low water dew point is required.Click to tweet
The regeneration process can use either the wet gas or dry gas. Using dry gas for regeneration is preferred and is common when high operating pressures are required. However, this requires a compressor to re-inject the gas back into the process. When higher pressure drops are acceptable to the process, a slip stream of wet gas can be used for regeneration. Using wet gas for the process does not require a compressor. Wet gas is passed through the inlet separation to remove any hydrocarbons and solid particles prior to entering the solid bed desiccant tower. The gas then flows downward through the tower, entering at the top and exiting at the bottom of the tower. As the gas flow downward through the bed, the water gets adsorbed onto the solid bed surface. Over a period of time, the solid bed surface will become saturated with water and needs to be regenerated.
The gas exiting the tower at the bottom is dry and is sent to a particulate filter before it is sent downstream for further processing. While one tower is adsorbing the other tower is regenerating and cooling. At any point in time one tower is always adsorbing, ensuring a continuous flow of gas. Switching between regeneration and adsorbing is done with the use of switching valves. The switching sequence is generally based on a fixed-time cycle. Depending on the type of desiccant selected, switching logic can also be based on the dew point requirement.
A slip stream of the dehydrated gas is used for regeneration and is heated up to 285 – 315 degrees C before being used as regeneration gas. Regeneration gas flows upward through the tower to ensure any contaminants that may be collected at the top of the bed are removed. Any residual water is left at the top of the desiccant bed so as to not affect the dew point of the gas during the adsorption process. For the cooling period, the regeneration gas flow through the tower can be downward or upward depending on the use of wet or dry gas. When using dry gas, the flow will be upward, and when using wet gas, the flow will be downward to ensure that any water is adsorbed and collected at the top of the tower.
Acid Gas Removal using Membrane Unit
Membrane units can be used to remove CO2 from natural gas. Membranes can be used only when high feed gas pressure is available. Due to high pressure drop across the membranes, the permeate exits the membrane at low pressure. Also, membranes are generally not suitable for high H2S partial pressure or bulk H2S removal. Acid gas removal using Membranes have several advantages over conventional amine systems. Advantages include lower capital cost, much smaller foot print (and significant weight reduction), no moving parts, and no solvent requirement.
Advantages of acid gas removal using membranes include lower capital cost, much smaller foot print (and significant weight reduction), no moving parts, and no solvent requirement.Click to tweet
Process gas from the Membrane pre-heater enters the Membrane skids for acid gas removal. Membranes are thin polymer-based, hollow fibers that allow for preferential passage for certain gas components (CO2, H2S etc.) over the rest (Methane, Ethane, C6+, etc.). Membranes work on the difference between the component gas permeability and the gas partial pressure through the hollow fiber. Each membrane unit normally consists of a few hollow membrane tubes.
High CO2 permeate gas is sent to the permeate flare system. A gas composition analyzer is provided at the permeate gas outlet to permeate flare header.
Crude Oil Stabilization
Crude Oil Stabilizers are used to sweeten natural gas by removing H2S and stripping out the light hydrocarbons. This reduces the vapor pressure of the gas to stabilize the crude for storage and shipment. As the crude flows downwards in the column through trays / packing, it is heated by the incoming hot lighter hydrocarbon gas and strips the lighter ends in the process. When the crude reaches the reboiler, it is hot, with the lighter ends stripped and the crude stabilized. The reboiler is generally a kettle type and uses either saturated steam or other heating medium available. The flashed gas can be used for a variety of downstream processes (such as power generators) or can be sent to an incinerator. The stabilized crude is sent to storage.
Condensate liquid at saturated condition is pumped under flow control through a feed/bottom exchanger where it is heated by the incoming hot stabilized crude. Once heated, it then flows to the condensate stabilizer column via the VME Multi Vane Inlet distributor, equipped with trays. The main feed generally enters the column top between trays 3 and 4. Alternate feed locations are provided with one above (between tray 2 and 3) and one below (between tray 4 and 5) the main feed. Water draw-off is located on trays 2, 3 and 5. As the unstablized condensate flows down the trays it comes in contact with the hot hydrocarbon vapors while stripping the light components from the condensate. The column sump is partitioned into two parts. A 20mm weep hole is provided on the bottom of the weir to enable start-up of the reboiler pump during commissioning and plant start-up. The partially stabilized crude from the trays is collected in the unstabilized section of the column sump.
It is essential to maintain the temperature of the stabilizer. The lower the temperature, the higher the vapor pressure of condensate at 38 degrees C, resulting in off-spec condensate.Click to tweet
Liquid from the unstabilized section of the sump is pumped via the reboiler recirculation pumps to the stabilizer reboiler which is a shell and tube heat exchanger. The reboiler recirculation pumps are centrifugal type which is under direct flow control cascaded with the level of the unstabilized section of the column sump. This allows for a constant flow through the stabilizer reboiler. The reboiler uses hot oil as the heating medium which flows through the tube side of the exchanger. The unstabilized condensate is partially vaporized and exits the reboiler as two-phase fluid. The vaporized hot condensate flows back to the condensate stabilizer and enters the stabilized side of the column sump below the bottom tray. The temperature of the condensate exiting the reboiler and entering the stabilizer column is controlled by the hot oil flow to the stabilizer reboiler exchanger. The hot oil flow is under direct flow control cascaded with the temperature controller located on the outlet of the stabilizer reboiler. It is essential to maintain the temperature of the stabilizer, which has a direct impact on the stabilization requirements. The lower the temperature, the higher the vapor pressure of condensate at 38 degrees C resulting in off-spec condensate.
The hot vaporized stabilized crude enters the stabilized section of the condensate stabilizer sump below the bottom tray. Liquid and vapor disengage as they enter the column. Vapor rises up the column as boil-up for distillation and the stabilized liquid is collected in the bottom sump of the column. The stabilized condensate is then drawn out from the column under level control.
Hot vapors exit from the top of the condensate stabilizer and are cooled by the overhead condenser. The overhead condenser is designed to be an air cooler, but may also be water cooled. The cooled and condensed hydrocarbon vapors flow to the overhead reflux separator. The overhead reflux separator is a three-phase separator with boot designed to separate water and gas from the condensate. Separated water is collected in the boot of the separator and discharged to the closed drain header by an on-off level control valve. The condensate is pumped back to the top tray of the condensate stabilizer column as reflux. The reflux pumps are centrifugal type and on direct flow-control cascaded with the condensate level of the reflux separator. This maintains a constant reflux flow to the stabilizer column. The pressure controllers located on the gas outlet line of the overhead reflux separator control and maintain the operating pressure of the stabilizer column. The hydrocarbon gas from the reflux separator is sent to the vapor recovery suction scrubber via pressure control and any excess gas is vented to the HP flare by the pressure control valve.
The hot stabilized condensate from the column sump passes through the Feed/Bottom exchanger providing heat to the incoming unstabilized feed stream and is further cooled by the bottoms cooler before being pumped. The Feed/Bottom exchanger is designed as a shell and tube type heat exchanger. The unstabilized crude from the separator is pumped through the tube side of the Feed/Bottom exchanger and is heated by the hot stabilized crude flowing on the shell side. The temperature of the unstabilized fluid exiting the tube side of the exchanger and feeding the condensate stabilizer column is controlled by a direct acting temperature controller. This controller is located on the inlet to the column. It controls the stabilized condensate flow through the exchanger and by passes the rest. The partially-cooled stabilized condensate flows to the bottoms cooler. It is designed as an air cooler and cools the stabilized condensate to about 45 degrees C before being sent to the condensate transfer pumps.