Glycol dehydrationis a liquiddesiccantsystem for the removal of water fromnatural gasandnatural gas liquids(NGL). It is the most common and economical means of water removal from these streams. TEG is the most commonly used glycol in industry.Purpose of removing waterThis water can cause several problems for downstream processes and equipment. 1. At low temperatures the water can either freeze in piping or, as is more commonly the case, formhydrateswith CO2and hydrocarbons (mainly methane hydrates). Depending on composition, these hydrates can form at relatively high temperatures plugging equipment and piping.[1]Glycol dehydration units depress the hydrate formation point of the gas through water removal.2. Without dehydration, a free water phase (liquid water) could also drop out of the natural gas as it is either cooled or the pressure is lowered through equipment and piping. This free water phase will often contain some portions of acid gas (such as H2S and CO2) and can causecorrosion.[1]For the above two reasons theGas Processors Associationsets out a pipeline quality specification for gas that the water content should not exceed 7 pounds per million standard cubic feet.Glycol dehydration units must typically meet this specification at a minimum, although further removal may be required if additional hydrate formation temperature depression is required, such as upstream of acryogenicprocess orgas plant.ProcessLean, water-free glycol (purity >99%) is fed to the top of an absorber (also known as a "glycol contactor") where it is contacted with the wet natural gas stream. The glycol removes water from the natural gas by physical absorption and is carried out the bottom of the column. Upon exiting the absorber the glycol stream is often referred to as "rich glycol". The dry natural gas leaves the top of the absorption column and is fed either to a pipeline system or to a gas plant. Glycol absorbers can be either tray columns or packed columns.After leaving the absorber, the rich glycol is fed to aflash vesselwhere hydrocarbon vapors are removed and any liquid hydrocarbons are skimmed from the glycol. This step is necessary as the absorber is typically operated at high pressure and the pressure must be reduced before the regeneration step. Due to the composition of the rich glycol, a vapor phase having a high hydrocarbon content will form when the pressure is lowered.After leaving the flash vessel, the rich glycol is heated in a cross-exchanger and fed to the stripper (also known as a regenerator). The glycol stripper consists of a column, an overhead condenser, and a reboiler. The glycol is thermally regenerated to remove excess water and regain the high glycol purity.The hot, lean glycol is cooled by cross-exchange with rich glycol entering the stripper. It is then fed to a lean pump where its pressure is elevated to that of the glycol absorber. The lean solvent is cooled again with a trim cooler before being fed back into the absorber. This trim cooler can either be a cross-exchanger with the dry gas leaving the absorber or an air-cooled exchanger.Other methods for regenerationSince the reboiler temperature is limited to 400F or less to preventthermal degradationof the glycol, almost all of the enhanced systems center on lowering the partial pressure of water in the system to increase stripping.Common enhanced methods include the use of stripping gas, the use of a vacuum system (lowering the entire stripper pressure), the DRIZO process, which is similar to the use of stripping gas but uses a recoverable hydrocarbon solvent the Coldfinger process where the vapors in the reboiler are partially condensed and drawn out separately from the bulk liquid.

The natural gas used by consumers is composed almost entirely of methaneRaw natural gas comes from three types of wells: oil wells, gas wells, and condensate wells. Natural gas that comes from oil wells is typically termed associated gas. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved gas). Natural gas from gas and condensate wells, in which there is little or no crude oil, is termed nonassociated gas. Gas wells typically produce raw natural gas by itself, while condensate wells produce free natural gas along with a semi-liquid hydrocarbon condensate. Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds.Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as pipeline quality dry natural gas.While the ethane, propane, butane, and pentanes must be removed from natural gas, this does not mean that they are all waste products.In fact, associated hydrocarbons, known as natural gas liquids (NGLs) can be very valuable by-products of natural gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. These NGLs are sold separately and have a variety of different uses; including enhancing oil recovery in oil wells, providing raw materials for oil refineries or petrochemical plants, and as sources of energy.heaters and scrubbers are installed, usually at or near the wellhead. The scrubbers serve primarily to remove sand and other large-particle impurities. The heaters ensure that the temperature of the gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates have a tendency to form when temperatures drop. These hydrates are solid or semi-solid compounds, resembling ice like crystals. Should these hydrates accumulate, they can impede the passage of natural gas through valves and gathering systems. To reduce the occurrence of hydrates, small natural gas-fired heating units are typically installed along the gathering pipe wherever it is likely that hydrates may form.Oil and condensate removalWhen this natural gas and oil is produced, it is possible that it will separate on its own, simply due to decreased pressure; much like opening a can of soda pop allows the release of dissolved carbon dioxide. In these cases, separation of oil and gas is relatively easy, and the two hydrocarbons are sent separate ways for further processing. The most basic type of separator is known as a conventional separator. It consists of a simple closed tank, where the force of gravity serves to separate the heavier liquids like oil, and the lighter gases, like natural gas.Water Removalthe removal of the water vapor that exists in solution in natural gas requires a more complex treatment. This treatment consists of dehydrating the natural gas, which usually involves one of two processes: either absorption, or adsorption.Absorption occurs when the water vapor is taken out by a dehydrating agent. Adsorption occurs when the water vapor is condensed and collected on the surface.Glycol DehydrationAn example of absorption dehydration is known as Glycol Dehydration. In this process, a liquid desiccant dehydrator serves to absorb water vapor from the gas stream. Glycol, the principal agent in this process, has a chemical affinity for water.The glycol solution, bearing all of the water stripped from the natural gas, is put through a specialized boiler designed to vaporize only the water out of the solution. While water has a boiling point of 212 degrees Fahrenheit, glycol does not boil until 400 degrees Fahrenheit. This boiling point differential makes it relatively easy to remove water from the glycol solution, allowing it be reused in the dehydration process.A new innovation in this process has been the addition of flash tank separator-condensers. As well as absorbing water from the wet gas stream, the glycol solution occasionally carries with it small amounts of methane and other compounds found in the wet gas. In the past, this methane was simply vented out of the boiler. In addition to losing a portion of the natural gas that was extracted, this venting contributes to air pollution and the greenhouse effect. In order to decrease the amount of methane and other compounds that are lost, flash tank separator-condensers work to remove these compounds before the glycol solution reaches the boiler. Essentially, a flash tank separator consists of a device that reduces the pressure of the glycol solution stream, allowing the methane and other hydrocarbons to vaporize (flash). The glycol solution then travels to the boiler, which may also be fitted with air or water cooled condensers, which serve to capture any remaining organic compounds that may remain in the glycol solution.

ADSORPTION (Solid-Desiccant Dehydration)Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and usually consists of two or more adsorption towers, which are filled with a solid desiccant. Typical desiccants include activated alumina or a granular silica gel material. Wet natural gas is passed through these towers, from top to bottom. As the wet gas passes around the particles of desiccant material, water is retained on the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto the desiccant material, leaving the dry gas to exit the bottom of the tower.

Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually installed as a type of straddle system along natural gas pipelines. These types of dehydration systems are best suited for large volumes of gas under very high pressure, and are thus usually located on a pipeline downstream of a compressor station. Two or more towers are required due to the fact that after a certain period of use, the desiccant in a particular tower becomes saturated with water. To regenerate the desiccant, a high-temperature heater is used to heat gas to a very high temperature. Passing this heated gas through a saturated desiccant bed vaporizes the water in the desiccant tower, leaving it dry and allowing for further natural gas dehydration.NGL EXTRACTIONThere are two basic steps to the treatment of natural gas liquids in the natural gas stream. First, the liquids must be extracted from the natural gas. Second, these natural gas liquids must be separated themselves, down to their base components.Techniques There are two principle techniques for removing NGLs from the natural gas stream: the absorption method and the cryogenic expander processThe Absorption Method

The absorption method of NGL extraction is very similar to using absorption for dehydration. The main difference is that, in NGL absorption, an absorbing oil is used as opposed to glycol. This absorbing oil has an affinity for NGLs in much the same manner as glycol has an affinity for water.The rich absorption oil, now containing NGLs, exits the absorption tower through the bottom. It is now a mixture of absorption oil, propane, butanes, pentanes, and other heavier hydrocarbons. The rich oil is fed into lean oil stills, where the mixture is heated to a temperature above the boiling point of the NGLs, but below that of the oil. This process allows for the recovery of around 75 percent of butanes, and 85 90 percent of pentanes and heavier molecules from the natural gas stream.The basic absorption process above can be modified to improve its effectiveness, or to target the extraction of specific NGLs. In the refrigerated oil absorption method, where the lean oil is cooled through refrigeration, propane recovery can be upwards of 90 percent, and around 40 percent of ethane can be extracted from the natural gas stream. Extraction of the other, heavier NGLs can be close to 100 percent using this process.The Cryogenic Expansion ProcessCryogenic processes are also used to extract NGLs from natural gas. While absorption methods can extract almost all of the heavier NGLs, the lighter hydrocarbons, such as ethane, are often more difficult to recover from the natural gas stream. In certain instances, it is economic to simply leave the lighter NGLs in the natural gas stream. However, if it is economic to extract ethane and other lighter hydrocarbons, cryogenic processes are required for high recovery rates. Essentially, cryogenic processes consist of dropping the temperature of the gas stream to around -120 degrees Fahrenheit.There are a number of different ways of chilling the gas to these temperatures, but one of the most effective is known as the turbo expander process. In this process, external refrigerants are used to cool the natural gas stream. Then, an expansion turbine is used to rapidly expand the chilled gases, which causes the temperature to drop significantly. This rapid temperature drop condenses ethane and other hydrocarbons in the gas stream, while maintaining methane in gaseous form. This process allows for the recovery of about 90 to 95 percent of the ethane originally in the gas stream. In addition, the expansion turbine is able to convert some of the energy released when the natural gas stream is expanded into recompressing the gaseous methane effluent, thus saving energy costs associated with extracting ethane.The extraction of NGLs from the natural gas stream produces both cleaner, purer natural gas, as well as the valuable hydrocarbons that are the NGLs themselves.Natural Gas Liquid FractionationOnce NGLs have been removed from the natural gas stream, they must be broken down into their base components to be useful. That is, the mixed stream of different NGLs must be separated out. The process used to accomplish this task is called fractionation. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation occurs in stages consisting of the boiling off of hydrocarbons one by one. The name of a particular fractionator gives an idea as to its purpose, as it is conventionally named for the hydrocarbon that is boiled off. The entire fractionation process is broken down into steps, starting with the removal of the lighter NGLs from the stream. The particular fractionators are used in the following order: Deethanizer- this step separates the ethane from the NGL stream. Depropanizer- the next step separates the propane. Debutanizer- this step boils off the butanes, leaving the pentanes and heavier hydrocarbons in the NGL stream. Butane Splitter or Deisobutanizer- this step separates the iso and normal butanes.By proceeding from the lightest hydrocarbons to the heaviest, it is possible to separate the different NGLs reasonably easily.Sulfur and Carbon Dioxide RemovalIn addition to water, oil, and NGL removal, one of the most important parts of gas processing involves the removal of sulfur and carbon dioxide. Natural gas from some wells contains significant amounts of sulfur and carbon dioxide. This natural gas, because of the rotten smell provided by its sulfur content, is commonly called sour gas. Sour gas is undesirable because the sulfur compounds it contains can be extremely harmful, even lethal, to breathe. Sour gas can also be extremely corrosive. In addition, the sulfur that exists in the natural gas stream can be extracted and marketed on its own.Sulfur exists in natural gas as hydrogen sulfide (H2S), and the gas is usually considered sour if the hydrogen sulfide content exceeds 5.7 milligrams of H2S per cubic meter of natural gas. The process for removing hydrogen sulfide from sour gas is commonly referred to as sweetening the gas.The primary process for sweetening sour natural gas is quite similar to the processes of glycol dehydration and NGL absorption. In this case, however, amine solutions are used to remove the hydrogen sulfide. This process is known simply as the amine process, or alternatively as the Girdler process. The sour gas is run through a tower, which contains the amine solution. This solution has an affinity for sulfur, and absorbs it much like glycol absorbing water. There are two principle amine solutions used, monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in liquid form, will absorb sulfur compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status. Like the process for NGL extraction and glycol dehydration, the amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.Although most sour gas sweetening involves the amine absorption process, it is also possible to use solid desiccants like iron sponges to remove the sulfide and carbon dioxide.Elemental sulfur is a bright yellow powder like material, and can often be seen in large piles near gas treatment plants, as is shown. In order to recover elemental sulfur from the gas processing plant, the sulfur containing discharge from a gas sweetening process must be further treated. The process used to recover sulfur is known as the Claus process, and involves using thermal and catalytic reactions to extract the elemental sulfur from the hydrogen sulfide solution.In cases where the dry liquid cooled condenser is situated far away from the chiller and the glycol, the amount of glycol that has to be added to the system is greater, raising the cooling cost. An intermediate plate heat exchanger minimises the glycol circuit, thus saving on glycol and cutting expenses.Kimray pump animationhttp://wycopump.com/kimray.htm

Flash EvaporationFlash (or partial)evaporationis the partial vapor that occurs when asaturated liquidstream undergoes a reduction in pressure by passing through athrottling valveor other throttling device. In the flash evaporation process is when the liquid is preheated and is then subjected to a pressure below its vapor pressure causing boiling or flashing to occur. Sea water is first heated in tubes and is then put in a chamber with a vapor pressure lower than in the heating tubes and the liquid evaporates. The vapors flash off the warm liquid and the salts exit with the remaining water.

the limit for water content is generally 7 lbm/MMscf in sales gas

At the high temperature, the glycol loses its ability to hold water; the water is vaporized and leaves through the top of the still.Inlet Separator Its function is to separate any condensed liquid from the gas before the gas enters the contactor. If the gas does not contain condensate (liquid hydrocarbon), the vessel is a two-phase separator. If the gas is a rich gas, with some condensate as well as liquid water forming at the inlet conditions of pressure and temperature in the separator, then a three-phase separator is installed. It is absolutely essential that none of the following enters the absorber section: Liquid Condensate WaterThe separator is usually equipped with a mist eliminator section in the top of the vessel. As the gas moves through the mist eliminator section, small droplets that might be in the gas will coalesce on the fine wire mesh and form larger droplets that drop down through the gas into the liquid section below.Absorber Detail:If it is a trayed vessel, it will contain several bubble-cap trays. Lean glycol is pumped into the upper portion of the contactor, above the top tray but below the mist eliminator. The trays are flooded with glycol that flows down from tray to tray in downcomer sections. The gas rises through the bubble caps and is dispersed as bubbles through the glycol on the trays. This provides the intimate contact between the gas and the glycol. The glycol is highly hygroscopic, and most of the water vapor in the gas is absorbed by the glycol. The rich glycol, containing the absorbed water, is withdrawn from the contactor near the bottom of the vessel above the chimney tray through a liquid level control valve and passes to the regeneration section. The treated gas leaves the contactor at the top through a mist eliminator and usually meets the specified water content.Most of the water vapor is extracted from the gas phase into the liquid glycol phase. For this to occur, it is necessary to create a large surface area between the gas and the liquid glycol. This is accomplished with specific internal equipment configurations, such as through the installation of: Trays Structured packing Random packingThe most common trays used in this application are bubble cap trays,Bubblecap tray processThe gas flows from below each tray through the bubble cap and forms small bubbles of gas in the glycol liquid that flows across and on top of each tray. After flowing across one tray, the glycol flows down to the next tray below through a downcomer, which ensures that the gas cannot bypass any tray. The gas bubbles provide the large surface area needed to effect the transfer of the water from the gas to the glycol. Because of the short contacting time on each tray, equilibrium in mass transfer is not reachedseveral trays are needed in a contactor to bring about the necessary dehydration of the gas. In the design of dehydrators, the calculations make use of theoretical equilibrium stages for determining how many times the gas and glycol must be contacted. Because of the dynamic conditions, equilibrium in mass transfer is not reachedapproximately four actual trays are used for each theoretical equilibrium stage. In practice, about 6 to 10 trays are installed in a contactor, usually spaced 24 in. apart. In more recent designs, 12 to 14 trays are installed in glycol absorbers to minimize glycol circulation.Structured packing consists of arrangements of corrugated steel internals, over which the glycol flows downwards as a thin film. Elements of structured packing are illustrated inFig. 4. The gas flows upward through the structured packing and is in intimate contact with the large surface area of the glycol that flows downward as a film on the packing. This creates a very efficient model for mass transfer to occur.[6]The design for the height of the packing required is related to the number of theoretical stages required.It is essential that the glycol be evenly distributed across the top of the packing. To ensure that the large surface area is provided by the downward flowing glycol, it is also essential that the steel be thoroughly clean, so that all of the steel is wetted by the glycol

3. Random PackingGlycol regenerationThe degree of water removal from natural gas by glycol, or the depression of the water dewpoint of the gas, depends on certain conditions: Glycol purity Glycol circulation rate (up to a certain limit) Number of contacting stages (trays) or packing height Amount of water in the inlet gas, which depends on the pressure and temperature of the gasThese parameters must be considered at the design stage of the contactor, in addition to the maximum rate, pressure, and temperature of the gas. The higher the glycol purity, the more effective is the dewpoint temperature depression. If the glycol purity is insufficient, increasing the glycol circulation rate will not necessarily achieve the desired dehydration of the gas.Glycol purity enhancement methodsIn some operating situations, a high glycol purity is required that cannot be achieved by the temperature in the glycol reboiler alone. There are several ways of enhancing the purity of the glycol beyond what is achieved in the reboiler.[5]One such method is the application of a small amount of stripping gas in the regenerating section.Fig. 7shows the effect of using stripping gas to enhance the purity of the lean glycol solution.[5]Stripping gas is simply a small stream of natural gas that is flowed into the hot glycol. The flow of this gas is usually regulated manually with a small needle valve and is measured by means of a small rotameter.The glycol circulating pumpThe circulation of glycol is done with a reciprocating pump. The pump is driven by: An electric motor Natural gas pressure High-pressure, rich glycol returning from the contactorElectric-motor-driven pumps are usually employed in central dehydration facilities where electric power is available. In field installations, a natural gas powered pump or a glycol powered pump can be used. In the latter case, the high pressure, rich glycol, with the assistance of a small amount of high pressure gas, flowing out of the contactor, is used to provide the power needed to stroke the pump.The main problems with glycol pumps are leaks through the packing around the plunger, as well as sticking check valves. If the packing gland nut is tightened too much, the rod may get scored. Usually, a small pan is placed under the pump or the plunger portion of the pump to contain the leaked glycol.

Heat Exchange:It is necessary to limit the temperature of the lean glycol to only a few degrees above the temperature of the gas to increase the absorption of the water by glycol. Too high a glycol temperature reduces the transfer of water from the gas to the glycol, and the water dewpoint may not be met. This is frequently the problem in summer operations, in which the gas is dehydrated after compression. On hot days, the glycol, as well as the gas, might be above normal temperatures. Usually, by exchanging heat with the dried gas through a double pipe exchanger or through a coil in the top of the contactor in small units, the temperature of the glycol is adjusted to a few degrees above the temperature of the gas leaving the contactor.FiltersIt is very important to maintain the glycol in as clean a condition as possible. For this reason, filters are always incorporated in a glycol circulating system. These filters are usually particulate filters (Sock filter) and carbon filters.The particulate filters are intended to remove solids down to a 5-m diameter. Solids can occur from corrosion in the glycol system. Carbon filters are designed to remove dissolved impurities, such as compressor oil or condensate from the glycol solution. Particulate filters are usually installed on the rich glycol side and are in operation all the time. Carbon filters may be bypassed most of the time, if there is no dissolved hydrocarbon in the glycol. Impurities in the glycol solution might promote foaming in the contactor or still.Surge drum (MORE)Because the glycol that is being circulated might not always flow evenly at the same rate throughout the system, a vessel, the surge drum, is required that can handle any surges in the circulation rate. The reboiler always contains a liquid level above the fire tube. Glycol levels in the absorber or flash tank are essentially constant but might fluctuate slightly. Thus, there is a need for a vessel that can absorb slight temporary differences in circulation flow between the various vessels, as well as the thermal expansion of the glycol upon startup.The surge drum is usually located below the reboiler or at least at a level below the glycol in the reboiler. The glycol level in the surge drum is important because in some instances there is a heat exchange coil in the surge drum, as explained earlier. The level of glycol in the surge drum should be about at the two-thirds full level. The liquid level in the surge drum is an item that is usually checked by the operators. If the level is lower than normal, this might be the first indication of trouble, such as: High glycol losses with the treated gas Losses with the vapors leaving the reboiler still Holdup in one of the vessels Leaks in the pipingStrainerA strainer should always be installed upstream of the suction of the glycol pump. The glycol strainer ensures that no solid particles enter into the glycol pump. The main problem with solids entering the pump is that they might lodge in the suction or discharge valves and prevent the pump from pumping at maximum efficiency.Glycol flash tankWhenever gas is in contact with a liquid at elevated pressures, such as natural gas and glycol in the contactor, some of the gas physically dissolves in the liquid. The greater the contacting pressure, the more gas dissolves in the liquid. Thus, some natural gas dissolves in the glycol in the absorber in addition to the water vapor. When the glycol reaches the flash tank, its temperature has been raised through the coil in the reboiler still, and the pressure in the flash tank is at a much lower level, generally between 15 to 50 psig, than the pressure in the contactor. In light of these changed conditions of pressure and temperature between the absorber and flash tank, most of the dissolved gases evolve from the glycol in the flash tank.Lean glycol circulation rateTo achieve the required water dewpoint depression, it is necessary to circulate a certain amount of lean glycol per pound of water to be removed from the gas. The rate of glycol circulation depends on several conditions, which are all interrelated. These conditions are: lean glycol purity, after regeneration, which depends on the reboiler temperature and whether or not stripping gas is used, with zero or one stage contacting for the stripping gas Water content of the gas, which depends on gas temperature and pressure in the inlet separator Number of actual trays (or equivalent packing height) in the contactor Design approach temperature in the contactorIn general, a circulation rate of 3 to 5 gal of lean glycol per pound of water to be removed from the gas is required. If the glycol purity is not sufficiently high, any larger circulation rate might not give the necessary dewpoint depression.Usually there is an attempt to match the circulation rate to near the minimum required rate to achieve the necessary drying. Overcirculation has disadvantages: Heat load on the regenerator is increased, requiring more fuel gas consumption Lean glycol returning to the contactor is at a higher temperature because of less efficient heat transfer more hydrocarbons are absorbed, especially compounds such as benzene, toluene, ethyl benzene, and xylene (BETX), if these compounds are present in the gas additional acid gas is absorbed, if sour gas is being dehydratedBecause there is concern about the absorption of other compounds besides water, as well as for energy efficiency, the glycol circulation rate should be set to remove the required water only. In field installations, using gas driven pumps, the pumps are set to the required pump rate by a gas control valve. This is usually a manually operated needle valve.Flame arrestorMost glycol reboilers are equipped with a flame arrestor at the air inlet to the burner. The flame arrestor consists of a tightly wound metal sheet, with sufficient space between the wound metal to allow sufficient air through the arrestor into the burner. If an external source of flammable vapors is sucked in with the air through the flame arrestor, such vapors will not ignite outside of the flame arrestor, as the temperature of the gas is cooled below the ignition point, thus preventing a backflash or explosion.

OTHER IMP STUFFIt is very important that no condensed liquid flows with the gas into the contactor. If condensate or salt water gets into the contactor, the result could be foaming or deposits of salt occurring on the fire tube. Heavy hydrocarbons will eventually gum up the packing in the reboiler column or plug the filter. Flashing of hydrocarbons in the still could damage the packing in the still column. In light of this, most glycol units are equipped with high-level alarms and shutdowns, which activate when the liquid level is exceeded in the inlet separator.The glycol level in the contactor is also important, as any increase in level above the gas inlet pipe can result in interruption of circulation of glycol because of insufficient glycol returns. Both liquid levels, in the inlet separator and the contactor, are controlled by conventional liquid level floats and outlet valves.Where a flash tank is employed, it is again important to ensure that the level of the glycol be maintained at a set level. The liquid outlet valve must be the throttling type, as opposed to snap acting, to ensure a smooth and steady flow of rich glycol to the regenerator. The glycol level in the surge drum should be at about 2/3 to 3/4 full.Normal operation checklistWhile glycol dehydration units are designed to operate unattended, periodic inspection of the equipment and its operation is necessary. All items listed next should be checked. Check the still column vent. Water vapors should be visible. There should be no pressure on the reboiler. Ensure that there is no ice buildup in winter. Check the lean glycol temperatures across all heat exchangers and in the reboiler. Check the pump operation, strokes per minute, and lubrication oil. Check the operation of the glycol filter for pressure drop. Change the filter if necessary. Check the glycol level in the surge drum. Add makeup glycol if necessary. Check the stripping gas rate. Adjust rate as required. Check the liquid levels in the inlet separator, contactor, and flash tank. Drain any fluid from the fuel gas scrubber. Check the operation of the burner in the fire tube. Check sight glass to ensure it is not broken and gasket is in good shape; clean if necessary. Check equipment for liquid leaks, and repair if required.Trouble diagnosisGlycol dehydrators usually operate trouble free. However, there are some problem areas that can occasionally occur.FoamingOne of the more serious problems is foaming. The cause of foaming is usually difficult to determine. However, if the solution is not continuously cleaned by filtration, certain materials can cause foaming. One of the more common causes of foaming is entrained hydrocarbon liquids. It is essential that the inlet separator provide good separation between condensed liquids and gas going to the contactor. Antifoam agent is usually a temporary solution, and the real problem must be identified and corrected.CorrosionCorrosion is usually caused by degradation products in the glycol, which can be generated by too high a skin temperature of the fire tube in the reboiler.Not meeting water dewpointThere can be many reasons for not meeting the required water dewpoint depression. The first step is to check the water dewpoint temperature with a dewpoint tester. A high water dewpoint can be caused by: Gas inlet temperature higher than design. Gas inlet pressure lower than design, combined with normal or higher temperature. Insufficient glycol circulation owing to too low a pump rate or a low glycol level in the surge drum, check valves on suction or discharge of pump not holding, or suction strainer plugged. Insufficient glycol regeneration because of a too low reboiler temperature, high water in inlet separator carrying water into absorber, a leak in the rich/lean glycol exchanger, insufficient stripping gas, or fouled stripping column packing. Foaming in absorber: check liquid level in inlet separator, place charcoal filter in service, or temporarily cut back throughput, if necessary.NPSH (Get more detail)In ahydrauliccircuit,net positive suction head(NPSH) may refer to one of two quantities in the analysis ofcavitation:1. The Available NPSH (NPSHA): a measure of how close the fluid at a given point is toboiling, and so to cavitation.2. The Required NPSH (NPSHR): the head value at a specific point (e.g. the inlet of a pump) required to keep the fluid from cavitating.NPSH is particularly relevant insidecentrifugal pumpsandturbines, which are parts of a hydraulic system that are most vulnerable to cavitation. If cavitation occurs, thedrag coefficientof theimpellervanes will increase drastically - possibly stopping flow altogether - and prolonged exposure will damage the impeller.NPSH design considerations[edit]Vapour pressureis strongly dependent on temperature, and thus so will both NPSHRand NPSHA.Centrifugal pumpsare particularly vulnerable especially when pumping heated solution near the vapor pressure, whereaspositive displacement pumpsare less affected by cavitation, as they are better able to pump two-phase flow (the mixture of gas and liquid), however, the resultant flow rate of the pump will be diminished because of the gas volumetrically displacing a disproportion of liquid. Careful design is required to pump high temperature liquids with a centrifugal pump when the liquid is near its boiling point.The violent collapse of the cavitation bubble creates a shock wave that can carve material from internal pump components (usually the leading edge of the impeller) and creates noise often described as "pumping gravel". Additionally, the inevitable increase in vibration can cause other mechanical faults in the pump and associated equipment.

Influid mechanics,pressure headis theinternal energyof afluiddue to thepressureexerted on its container. It may also be calledstatic pressure heador simplystatic head(but notstatic head pressure). It is mathematically expressed as:

Head is the height at which a pump can raise water up (FOR PUMP)http://www.pumpfundamentals.com/what%20is%20head.htm

Gibbs free EnergyJust as in mechanics, wherepotential energyis defined as capacity to do work, similarly different potentials have different meanings. The Gibbs free energy (SI unitskJ/mol) is themaximumamount of non-expansion work that can be extracted from athermodynamically closed system(one that can exchange heat and work with its surroundings, but not matter); this maximum can be attained only in a completelyreversible process. When a system changes from a well-defined initial state to a well-defined final state, the Gibbs free energy change Pequals the work exchanged by the system with its surroundings, minus the work of thepressureforces, during a reversible transformation of the system from the initial state to the final state.