LAURANCE REID GAS CONDITIONOING CONFERENCE 2004 GAS DEHYDRATION FUNDAMENTALS
INTRODUCTION
M. A. Huffmaster, Shell Global Solutions
Gas Conditioning refers to the steps taken to prepare gas for transportation, sales or further processing - such as recovery of natural gas liquids or chemical feed. This fundamental session deals with dehydration and hydrate prevention. Natural gas as produced normally contains water vapor. Water must be removed to a typical point of achieving a content of 7 lb/MMSCF for US transmission systems to a few ppm water and dew point of –150 °F for cryogenic processing feed pre-treatment.
The removal of water, or dehydration, is done to prevent hydrate formation (and potential plugging) or corrosion in the gas gathering, transmission system, or processing plant. Alternatively hydrate inhibitors may be injected into the gas stream to prevent or inhibit the formation of hydrates. Dehydration is typically preceded by other gas conditioning steps, separation of free hydrocarbons liquids and removal of acid gases, if present. Other gas conditioning steps may be performed prior to sales are recovery of hydrocarbon NGL’s or hydrocarbon dew-pointing.
Several process alternatives that can be utilized to accomplish dehydration are reviewed in this Fundamentals Manual. The principle processes of tri-ethylene glycol (TEG) dehydration, mole sieve desiccation, and new and advancing technologies will then be discussed in some detail.
A widely accepted and used chart showing the quantity of water vapor which natural gas at saturation can contain, under various conditions of pressure and temperature, was developed by McKetta and Wehe. This is included in the GPSA Engineering Data Book, 11th Edition, Chapter 20 as Figure No. 20. It has been updated with recent research. The chart shows when the temperature of gas is increased gas contains more water; this is because water vapor pressure increases. If gas pressure decreases, the amount of water vapor the gas will hold also increases, as water vapor pressure becomes a larger fraction of the total pressure. An important factor influencing which process to choose is the water content of the gas requiring dehydration
When the temperature of water-saturated natural gas is lowered, some of the water vapor condenses. If the temperature is low enough the condensed water vapor can combine with certain of the hydrocarbons (methane, ethane, propane, butane) and with H2S and CO2 - if these components are present - to form solids known as hydrates. Hydrates are cage like structures that can exist at temperatures well above the freezing point of water. A quantity of hydrates can accumulate in gas transmission and processing equipment and result in restriction or blockage. Conditions under which hydrates will form and a
method developed by Katz of calculating hydrate formation conditions using vapor-solid equilibrium constants are also included in the GPSA Engineering Data Book, chapter 20.
Gas hydrates will generally form when free (liquid) water is present and conditions are favorable for hydrate, although in some cold gas conditions hydrates can form even without free water. Once formed these hydrates can agglomerate and plug pipelines. Therefore, gas pipelines usually require that most of the water vapor be removed from the gas, down to a water content lower than the saturation water content at the lowest
expected pipeline temperature.
In the United States, the usual pipeline specification for water content is a maximum of 7 pounds of water per million standard cubic feet (lb/MMSCF); in Canada, this
specification is often about 4 lb/MMSCF. The constant of 21 ppm can be applied to convert lb/MMSCF water to ppm (mole). A water content of 7 lb/MMSCF corresponds to approximately 147 ppm water. The 7 lb/MMSCF also relates to about 32 °F water dew point at 1000 psia. A 4 lb/MMSCF relates to 15 °F dew-point at 1000 psia.
Hydrate Prevention In Flow Lines And Transmission Systems
If wet as is transported at temperatures below 80 °F then consideration is usually taken to prevent hydrates. The temperature and pressure at which hydrates will form are a
function of gas composition, presence of H2S and CO2, temperature, pressure and kinetics effects such as induction time and turbulence. Two types of hydrate inhibitors are used: thermodynamic or kinetic.
Thermodynamic inhibitors work by freezing point lowering, adding a water miscible or ionic compound. Examples of these are:
• Salt (brine) such as sodium chloride or calcium chloride
• Methanol – which has the capability of recovering from under dosing • Ethylene glycol – frequently the inhibitor of choice as this has very low
vapor phase losses.
Kinetic inhibitors have been a topic of recent hydrate research and innovation. The advantage of kinetic inhibitors is that quantity of inhibitor that has to be injected is
significantly less (10%) of that with thermodynamic inhibitors. These work by one of two methods:
• Inhibition of the rate of hydrate formation – through modification of the hydrate crystal morphology (suspending the hydrate in the precursor stage) or inhibition of mass transfer of hydrocarbon into the free water • Inhibition of the crystal growth size; actually promoting hydrate formation
but keeping crystals small and prevention of aggregation or agglomeration, to prevent blockages.
Calculation methods for hydrate prediction and inhibition are described below. Modern process simulation computer programs are available with good VLE correlations to make
precise calculations of hydrate formation point. The programs INFOCHEM, HYSYS and TSWEET have demonstrated the more accurate hydrate formation predictions, with and without inhibitors. Predictions, however, are only as good as forecast of conditions. Inhibitor recovery, regeneration and re-use have an impact on cost of application. A simple reboiler system is all that is required to remove the water from a glycol, or methanol from an aqueous mixture. However, the system must also consider corrosion and environmental requirements. Economic must address initial capital costs, make-up chemical cost and disposal of waste streams. Accumulation of salts (from produced fluids) can significantly impact cost and corrosion issues in regeneration.
Certainly the best means of hydrate control is to prevent their formation by elimination of water from the system. This is accomplished by removal of water by the process called dehydration.
Dehydration Process Alternatives
Any one, or a combination of, five basic methods may reduce the water vapor content of a gas. These are applied at the process pressure of the gas, except for the first one.
1) Compression to a higher pressure with subsequent cooling and phase
separation. As indicated on the chart of water vapor content at saturation, the higher the pressure, the lower the saturated water vapor content in lb/MMSCF at a given temperature.
2) Cooling below initial dew-point
3) Absorption with liquid desiccants; e.g. glycol or methanol.
4) Adsorption with solid desiccants, e.g. alumina, silica gel or mole sieve 5) Absorption with a deliquescing solid, such as calcium chloride.
Any of these methods may be used to dry gas to a specific water content. Usually the combination of the water content specification, initial water content, process character, operational nature, and economic factors determine the dehydration method to be
utilized. The two most common dehydration methods presently being used in natural gas processing beyond compression and cooling are liquid desiccant, i.e., glycol, or
adsorption with a solid desiccant, such as mole sieve or silica gel. These are discussed briefly in this introduction and presented in depth in subsequent portions of this
Fundamentals Manual. In addition membrane systems with selective water permeation have also been commercialized. These are not yet in widespread use.
The various dehydration processes, and their primary applications areas are briefly summarized below. All of these systems can be employed in an unattended operation situation, so there is no difference in requirement for surveillance between alternatives in the production environment.
Compression and cooling with separation is typically part of a production system / gas gathering and processing arrangement. For natural gas additional drying is usually applied. However, in some cases this simple approach may be sufficient for field use in
gas lift systems (though experience suggests operation is better if the free water is prevented).
In the case of CO2 systems and some acid gas injection systems a judicious selection of the compression pressure –temperature operating line can remove all the water that has to taken out of the stream for satisfactory operation. Natural gas streams have the
characteristic that as the pressure increases at a fixed temperature the saturated water content decreases. CO2 rich streams differ due to their high critical temperatures. At a fixed temperature, increasing pressure will reduce the saturated water content until a minimum in water content is reached at about 600 psig. At further increase in pressure water holding capacity increases substantially. Thus a CO2-rich stream cooled to say 100°F at 600 psig can be compressed to higher pressure and it will become under-saturated, or dry.
Often only compression/cooing is needed to protect a CO2 rich system. However if deeper dehydration is required, glycol can be a problem as the typical glycol’s gas phase solubility becomes quite high above a critical pressure of 1100 psia and there is
considerable loss of glycol into the dried gas stream. For the high pressure, high-density CO2-rich streams glycerol has been demonstrated to be a better choice.
Cooling below initial dew-point. The lower the temperature, the lower the saturated water vapor content of the gas. This method usually requires some means of hydrate
prevention and is applied as Low Temperature Separation, or LTS). Ethylene glycol is usually used for the lower temperature LTS for hydrate prevention and simultaneous dehydration of the gas. An example of a direct injection application is presented in a following section.
This approach is often combined with direct glycol injection on the front end of
refrigeration plants or lean oil absorption plants. Also new expansion technologies such as TWISTER have been combined with direct injection to achieve dehydration.
Absorption of water with a liquid desiccant. This usually uses one of the glycols, with contacting in an absorber column at ambient temperature. It is also applied in
combination with cooling, at lower than ambient temperatures. It is the most widely applied process, used extensively in production operations and in many refinery and chemical plant operations.
Usually in field gas or plant residue gas dehydration either diethylene- or triethylene glycol (DEG or TEG) is used. This type of contacting is commonly called glycol
dehydration. For lower than ambient temperature contacting, usually in conjunction with an LTS or plant processing of the gas by refrigeration or refrigeration-adsorption type process, ethylene glycol is used. This type of contacting is normally carried out by injecting the glycol solution into the gas system before cooling takes place and is commonly called glycol injection.
Natural gases can be dehydrated down to 7 lb/MMSCF with standard regeneration systems using TEG or DEG. With stripping gas addition to a glycol regenerator water contents can be achieved down to 3 or 4 lb/MMSCFD. With the enhanced glycol process
like the DRIZO process, where glycol and BTEX compounds are used to conduct azeotropic stripping to reduce water in lean glycol water to very low levels, gas water contents to 1 lb/MMSCFD can be achieved.
In the design of glycol injection systems, the solution injection rate is best determined by rigorous calculation methods available in qualified process tools; i.e. commercial
computer simulation programs listed previously. Manual methods are also available. BTEX predictions in glycol systems are most accurate in GlyCalc from GRI.
Methanol has also been applied for dehydration. This is via direct injection or contact in an absorber. However since methanol has a high vapor pressure, losses are considerably higher to the vapor and liquid hydrocarbon phases than with glycols. Recovery methods are applied and some special line-ups are licensed such as IFPEXOL.
Physical solvent systems such as propylene carbonate, poly-glycol-ether, or methanol remove acid gases and some portion of the water content.
Generally, liquid desiccants will not reduce the water content of the gas as low as the solid desiccants, but when either can be applied the liquid desiccant dehydration system usually has an appreciably lower cost of installation and operation than a solid desiccant system for the same volume of gas. Solid desiccants are generally selected to achieve dew-points below 0 °F and almost exclusively for processing below –40 °F down to cryogenic temperatures of -150 °F.
Adsorption of the water with a solid desiccant Molecular sieves have found wide acceptance in the gas processing industry for cryogenic plant feed conditioning applications and some sour gas applications with special acid resistant binder
formulations. Dehydration of natural gas to the usual pipeline requirement of 7 lb water / MMSCF is normally least costly utilizing a liquid desiccant such as glycol than using solid desiccants.
Activated alumina and silica gel have been successfully also used for many years in production and processing applications that require lower dew point than achieved by conventional glycol. With silica gel it is possible to simultaneously remove
hydrocarbons and water in so-called short cycle units.
As a minimum, two bed systems are used with thermal regeneration. Multiple bed systems are used on gases with relatively low water content. Typically one or more bed is in service drying gas and one bed is in regeneration - heating; other beds may be in various stages of cooling or in standby. Once a bed is loaded with water it is switched into regeneration. In order to achieve high energy-efficiency multiple bed systems can provide manifolds to switch a bed into cooling and allow its heat content to pre-heat the bed going into regeneration. Regeneration system design is important and switching valves must be of high quality to ensure wet gas is not bypassing the unit.
Deliquescent systems can be attractive for smaller volumes, such as an isolated production system or a fuel gas. Deliquescent desiccants are primarily made from various blends of alkali earth metal halide salts, e.g. calcium chloride and are naturally
hygroscopic. Water vapor is removed from natural gas as it flows through a bed of desiccant tablets in a pressure vessel. Moisture is attracted to salts in the deliquescent tablets, and coats them with hygroscopic brine. This brine continues to attract water, forms a droplet, and then flows down the desiccant bed into a liquid sump. Since, the desiccants dissolve upon attracting and absorbing water vapor (deliquesce), new desiccant is simply added to the vessel when needed.
Application Guideline MAP
General process application selection is outlined on the map below. The axes are water content in the wet gas, in lb/MMSCF and dry gas dew point, in °F.
140 100 10 1 1000 100 60 20 -20 -60 -40 0 40 80 120
Dry Gas Water Dew-Point, Degrees F
Wet Gas W ater Conten t, lb/MMSCF Compress & Cool Liquid Desiccants Glycol & Methanol Molecular Sieves Solids Alumina & Silcia-gel & Extended Glycol
Economics usually favor compression and or cooling up to about 600 to 1000 psig and 100 to 120 °F; this relates to 50 to 150 lb/MMSCF water content at saturation. Glycol based systems for are generally chosen for applications requiring water dew-points in the range of 0 to 30 °F, i.e., 4 to 7 lb/MMSCF. For lower dew-points, down to 10 or 20 ppm water adsorption with solid desiccant is generally applied. Both water content of the inlet gas stream and the outlet stream dew-point (or outlet water content) affect choice of system.
Dehydration with Liquid Desiccants
The liquid desiccants most commonly used at present are certain glycols – ethylene-, diethylene-, and triethylene glycol, although other compounds have been utilized for special circumstances, such as methanol or glycerol.
A key to understanding the reason glycol and methanol are effective in removing water and inhibition hydrates lies in their chemical structure.
Methanol Ethylene Glycol
H H H
H- C – OH HO - C - C - OH
H H H
In each of these molecules there is a hydroxyl group (OH) which hydrogen–bonds with water molecules. Glycol, having two hydroxyl groups, bonds even more strongly. Factors that influence the selection of the particular glycol for a specific application include:
1) Comparative cost of the glycols
2) Freezing point of the glycol/water solutions
3) Viscosities of the glycol water mixtures and the process fluids as well 4) Solubility of the glycol in the hydrocarbon process fluids, and
5) Temperature of operation. Glycol Dehydration
In glycol dehydration, the minimum dew-point attainable is dependent upon the concentration of the glycol solution with which the gas is in contact and upon the pressure and temperature of operation. Curves for various concentrations of triethylene glycol (TEG) are included in the GPSA Engineering Data book and similar data for the other glycols are available in the literature. Figures showing curves of useful glycol properties are included in the other sections of this Fundamentals Manual.
Glycol dehydration facilities normally utilize conventional tray-type columns, usually containing four to eight trays, for contacting the gas and the glycol solution. Structured
packing has also been applied to many more recent applications with good success and this has also been applied offshore, in floating production systems. The absorbed water is stripped from the glycol in a still column, either a packed-type or a tray-type with the equivalent of about four actual trays. Often the still column is mounted on top of the kettle-type still reboiler.
The design glycol circulation rate is usually set at about 3 - 4 gallons of glycol per pound of water to be removed. (Higher temperature gases, at say 120 – 130 °F with greater water content, require the higher circulation rates.) Since the resulting gas water content or dew-point depends primarily upon the water concentration of the circulated solution, it is essential to maintain the water content of the glycol solution at a minimum with out causing glycol degradation caused by excessively high still reboiler temperatures. The maximum recommended reboiler temperatures for diethylene- or triethylene glycols are 350 °F and 400 °F, respectively, equivalent to glycol concentrations of 97-98 % wt. This glycol concentration is adequate for obtaining water dew-point depressions of 55-65 °F; if dew-point depressions of more than 65 °F are desired, gas stripping is usually utilized to lower the water content of the glycol solution, thus increasing the dew-point depression attainable. A chart showing the effect of gas stripping on the water content of TEG is included in the GPSA Engineering Data Book.
Because of the extreme difference in boiling points of water and the glycols, a sharp separation can be accomplished in the still with a relatively short column. Some water reflux normally is provided at the top of the columns to effect rectification of the vapors and to minimize glycol losses. This reflux can be supplied by means of a rich glycol-cooled condensing coil inserted in the top of the column, an air-glycol-cooled finned section at the top of the column, or an external water source, such as demineralized water or steam condensate. The quantity of reflux is not critical, between 15 – 25 percent of the glycol circulation, on a mol basis, is generally adequate.
When sour gases are dehydrated with glycol an extra stripping step usually is
incorporated in the rich glycol work-up to remove acid gas from the rich glycol before the regenerator. This prevents discharge of acid gas to the atmosphere in the water vent. Recompression is used to recycle the stripping gas and acid gases to the inlet.
If high BTEX content natural gas is dehydrated then prevention of discharge of BTEX to atmosphere in the water vent is accomplished by one of the following methods:
• incorporating a stripping step similar to that employed for acid gases • cooling the vent to condense water and BTEX, with subsequent separation
and disposition of the hydrocarbons
• adsorption of BTEX using a sponge oil system, with separation, recovery and disposition of BTEX; or
Dehydration with Solid Desiccants
Dehydration of natural gas with solid desiccants is usually limited to those cases where essentially complete water removal is desired, for example in cryogenic plants operating in the region of –100 to – 150 °F or to where relatively small volume of gas are involved (ex fuel gas system).
The generally used solid desiccants are: • Silica gel
• Activated Alumina • Molecular Sieves
Solid desiccants may be divided into two classes: those that owe their activity to surface adsorption and capillary condensation and those that react chemically with water. The first type still has wide use in gas conditioning and production applications when there are reasons not to use glycol-based or methanol-based dehydration.
With the exception of molecular sieves, which normally require somewhat higher regeneration temperatures, the equipment and process flow arrangements for all these desiccants are essentially identical. In most cases, equipment designed for one desiccant can be readily operated using another, although the desiccant used can affect the capacity of the dehydration facilities markedly. The selection of desiccant depends, therefore, upon such factors as absorbing capacity and desired dew-point, cost of initial charge of desiccant, desiccant bed life, utility requirements, etc., with due consideration for the process limitations of each desiccant.
For normal natural gas dehydration applications, the following design loadings or water absorbing capacities should be assumed:
1) Activated alumina 4 – 5 percent by weight for pipeline gas (to 20% high water content streams) 2) Silica gel 6 – 7 percent by weight
3) Molecular sieves 8 – 10 percent by weight
These design loadings are usually reduced somewhat for unusual situations, such as cryogenic plants where a water dew-point of minus 100 °F and lower is desired. Some other factors that may affect the selection of the desiccant to be used are:
1) Operating temperature. The effect of temperature on absorbing capacity, e.g., 10 - 20°F, is much greater with activated alumina, than with others.
2) Presence of H2S. Alumina-type desiccants catalyze the formation of COS for H2S. Therefore, silica-type or molecular sieve desiccants are recommended for gases containing H2S. A caution should be noted on the formation of elemental sulfur on the bed during regeneration if oxygen is present in the gas. 3) Other contaminants. The presence of heavy hydrocarbons, often compressor
oils, in the gas can seriously affect the capacity of all the desiccants, although it affects molecular sieves less.
Regeneration is a critical design factor for success of these dehydration systems. Temperature requirements are higher than for glycol systems ranging form 450 °F for silica gel and alumina to 550 °F for mole sieves. Care must also be taken to ensure adequate heat input and gas flow are provided within cycle times. In this service proper design of the regeneration cycle is essential. In particular for mole sieves, water
condensation should not be permitted in the bed during heating. If this is allowed to happen caking, clumping, higher pressure-drop, flow mal-distribution, loss of capacity and shortened service life will result.
The following sample illustrates the conditions, which must be defined for design calculations for a typical solid desiccant unit. Details will be provided in mole-sieve presentation.
Design Basis Example value
Feed rate 50 MMSCFD
Molecular weight of gas 17.4 Operating temperature 110°F Operating pressure 600 psia
Inlet Dew-point 100°F (equivalent to 90 lb /MMSCF) Desired outlet dew-point 0°F (equivalent to about 2 lb/MMSCF) Conclusion
This introduction has covered overview of dehydration and hydrate formation. The concerns are integrity of pipeline and transport systems from flow blockages or corrosion. An example of hydrate inhibition with direct injection glycol has been provided. Now more detail discussion of TEG, mole-sieve and innovations will be presented.
GAS DEHYDRATION FUNDAMENTALS Glycol Injection Example
In low temperature separation plants, refrigeration plants, and refrigerated-absorption plants operating conditions can be down to minus 40 °F. A partially dilute glycol solution is used for injection into the gas stream. The glycol content is typically 80% weight (water significantly reduces viscosity of the glycol water mixture). The glycol water mixture is injected before the gas is cooled to prevent the formation of hydrates as the water and heavier hydrocarbons in the gas condense.
Ethylene glycol is normally used in this process because:
1) it has the lowest molecular weight of the glycols and, therefore, less is required;
2) it has a lower viscosity than the other glycols at the temperatures involved; 3) the freezing point of its water solution is appreciably lower than for the other
glycols; and
4) it is less soluble in the condensed hydrocarbons than the other glycols. Solutions in the range of 75 – 85% weight are used in injection systems.
A quick estimate can be made by calculation with the Hammerschmidt equation. This equation can also be used for estimation of inhibitor requirements for direct injection in flow lines. This equation is based on the phenomenon that addition of a solute lowers the freezing point of the solvent:
2335W
d = 100M – M × W
where d = °F lowering of the freezing point of the gas hydrate, M = molecular weight of the glycol,
W = weight percent of glycol in the liquid phase.
Normally, the condensed hydrocarbons and the diluted glycol solution containing the condensed water are separated in a conventional phase separator. The heavier glycol solution phase is then regenerated in a reboiled still column for re-use, in much the same manner as in the glycol dehydration system. Because the re-circulated, lean glycol solution is only about 80 percent glycol by weight, compared to 97 – 98 percent by weight for the dehydration system, reboiler temperatures are appreciably lower, e.g., about 260 °F for 80 percent ethylene glycol solution. As for the dehydration system, the amount of reflux to the still is not critical, between 5 – 10 percent of the lean glycol solution, on a mol basis, will be adequate.
The following sample problem illustrates the steps taken in design calculations for a glycol injection system.
Design Basis:
1,200 MMSCFD of gas at 1000 psia and 90 °F
Molecular weight of gas 17.45 (equivalent to 0.6 gravity)
Water content6 15 lb/MMSCF
Final gas temperature -40°F
Use 80 percent ethylene glycol that has molecular weight of 62.1
From Figure No. 20-15 in the GPSA Engineering Data Book, 11th Edition, the hydrate temperature for 0.6 gravity gas at 1000 psia is approximately 61 °F. Therefore, the desired minimum dew-point depression is 101 °F (61 + 40).
Using the Hammerschmidt equation:
2335 W d = --- 100 M - M * W 2335 W 101 = --- 100 * 62.1 – 62.1 W Solving:
W = approximately 73 percent by weight glycol in the final liquid phase. Water in gas = 1200 * 15 / 24 = 750 pounds/hour
Let X = pounds of glycol injected (pure MEG) per hour
Then 0.25 * X = pounds of water accompanying glycol (80% MEG) X
--- = 0.73 1.25 X + 750
X = 6275 pounds glycol per hour, theoretical requirement.
Add 25 to 50% to theoretical requirement for a design basis. Therefore the glycol requirement = 1.5 * 6257 = 9385 pounds per hour. The density of 80% ethylene glycol is 9.125 pounds / gallon (60 °F).
Therefore:
9385
--- = 22 gpm glycol injection rate 0.8 * 9.125 * 60
Rich glycol flow is:
( 9385 / 0.80 ) + 750 = 12450 pounds per hour. Concentration of glycol in the rich solution is:
( 9385 / 12450 ) * 100 = 70 % weight (approximately). Separation of the rich glycol and the condensed hydrocarbons is always imperfect at low temperatures (- 40F in the present example) because a stable dispersion, or even some emulsion, is formed due to the turbulence in the piping system and equipment. The stability and long break time for this mixture is due to the high viscosities of the fluids at the low temperature. It has been found that heating to about 170F effectively breaks this emulsion mixture. This is usually accomplished by heat exchange between the hot re-circulating lean glycol solution and rich glycol solution. Sometimes it is necessary to supplement the cross heat exchange with external heat in a pre-heater. This is to limit the lean glycol to 60 – 80 °F, preferred to obtain good distribution in the injection sprays.
Heat load on the lean glycol – rich glycol heat exchanger is:
Q = 11700 lb/hr ( 260 °F – 80 °F ) * ( 0.725 Btu/lb-°F ) = 1,530,000 Btu/hr
Temperature rise on the rich glycol side (ignoring hydrocarbons) is:
1,530,000 Btu/hr
∆T = --- = 180 °F 12,450 lb/hr * 0.680 Btu/lb-°F
and
T2 = -40 + 180 = 140 °F
Then rich glycol preheater duty is:
Q = 12,450 lb/hr * ( 170 °F – 140 °F ) * (0.740 Btu/lb-°F ) = 280,000 Btu/hr
Lean glycol solution (regenerator bottoms) consist of:
9385 lb/ hr ethylene glycol or (9385/62.1) = 151 mol/hr and 2315 lb/hr water or (2315/18.01) =129 mol/hr --- 280 mol/hr
For design, assume a reflux rate of 5% overall or 14 mol/hr. For comparison this is 250 lb/hr against water removed of 750 lb/hr or about 25% reflux (250/(750+250)).
Reboiler temperature at 80% MEG and atmospheric pressure is 260 °F (per industry data temperature-composition chart for ethylene glycol-water).
Heat loads are calculated for reboiler as follows:
Btu / hr Lean glycol, sensible heat
11,700 lb/hr * ( 260 °F – 170 °F ) * 0.770 Btu/lb-°F= 810,000 Water, vaporization 750 lb/hr * ( 1150.4 – 137.9 ) Btu/lb = 760,000 Reflux 250 lb/hr * 1000 Btu/lb = 250,000 --- Total 1,920,000
This illustrates the process design of the glycol injection system for a LTS system. Design criteria for sizing the vessels and heat exchange equipment follows industry
