C4 Hydrate and Gas Dehydration

Page 1Assoc. Prof. Abdul Razak Ismail

Assoc. Prof. Abdul Razak Ismail, UTM

HYDRATES & GAS DEHYDRATION


Hydrates & gas dehydration

Most natural gas contains substantial amounts of water vapor at the time it is produced from a well or separated from an associated crude oil stream

Water vapor must be removed from the gas stream because it will condense into liquid and may cause hydrate formation as the gas is cooled from the high reservoir temperature to the cooler surface temperature

Liquid water almost always accelerates corrosion, and the solid hydrates may pack solidly in gas gathering system, resulting in partial or complete blocking of flow lines



Hydrates are solid, semi-stable compounds that form as crystals and resemble snow in appearance

They are created by a reaction of natural gas with water, and when formed, they are about 10% hydrocarbon and 90% water

Hydrates have a SG ~ 0.98 and will usually float in water and sink in hydrocarbon liquids

What is hydrate


Plugging natural gas transmission pipelines and other gas handling equipment such as nozzles, valves, separation equipment, etc.

Reduces gas capacity due to excessive pressure drop

Cause corrosion in the presence of H2S or CO2 and water

What are the problems?



Hydrate point - The temperatures and pressures at which hydrates form in a gas mixtures

Dew point - The temperature at which the natural gas is saturated with water vapor at a given pressure. At the dew point, natural gas is in equilibrium with liquid water; a decrease in temperature or an increase in pressure will cause the water vapor to begin condensing


Natural gas at or below its water dew point with liquid water present

Temperatures below the ‘hydrate formation’ temperature for the pressure and gas composition considered

High operating pressures that increase the ‘hydrate formation’ temperature

High velocity or agitation through piping or equipment

Introduction of a small ‘seed’ crystal of the hydrate

Presence of H2S or CO2 is conductive to hydrate formation since these acid gases are more soluble in water than hydrocarbons

The conditions that tend to promote the formation of natural gas hydrates are:



All natural gases contain water vapor to some degree

Solubility of water increases as temperature increases and decreases as pressure increases

Salts dissolved in the liquid water in equilibrium with natural gas reduce the water content of the gas

Water content is usually expressed as pounds of water per million SCF of natural gas (lb/MMSCF)

Water content of natural gas streams


Figure 15-14 can be used to estimate water contents of natural gases with corrections for salinity and relative density (SG)



Example 1: What would be the pressure above which hydrates could be expected to form if the following gas is at 50oF?

Predicting hydrate formation

1. Fig. 15-1 is used to predict hydrate formation at a given P and T conditions

ComponentMole fraction in

gasC1 0.810C2 0.052C3 0.019iC4 0.004nC4 0.020N2 0.093

CO2 0.002Total 1.000


Solution:

Component yi Mi yi Mi

C1 0.810 16 12.96C2 0.052 30 1.56C3 0.019 44 0.84iC4 0.004 58 0.23nC4 0.020 58 1.16N2 0.093 28 2.60

CO2 0.002 44 0.091.000 19.44



2. Figures 15-2 through 15-6 is used to estimate permissible expansion of natural gases without the formation of hydrates

Fig. 15.2 Permissible expansion of a 0.6-gravity natural gas without hydrate formation.









Example 2: The 0.65 gravity gas is to be expanded from 2,000 psia to 800 psia. What is the minimum initial temperature that will permit the expansion without hydrate formation?

Solution 2:

By interpolation: Tmin = 116oF



Example 3:

a. How far may a 0.8 gravity gas at 1,500 psia and 120oF be expanded without hydrate formation?

Answer:

b. How far may a 0.9 gravity gas at 1,500 psia and 160oF be expanded without hydrate formation?

The temperature curve does not intersect the pressure line. Therefore, the gas may be expanded to atmospheric pressure without hydrate formation

Answer:


c. A 1.0 gravity gas is to be expanded from 2,000 to 400 psia. What is the minimum initial temperature that will permit expansion without danger of hydrates?

Therefore 180oF is the minimum initial temperature to avoid hydrate formation.

Answer:



Figures 15-1 through 15-6 may be used for approximations only

For more accurate determination, the vapor-solid equilibrium constant should be used

This method is based upon the condition that gases evolved during the decomposition of natural gas hydrates increase in density and therefore resemble solid solutions

The vapor-solid equilibrium constants behave as follows:

Calculation of pressure at which hydrate form

where:y = mol fraction of HC in the gas on a water free basisxs = mol fraction of HC in the solid on a water free basis


Figures 15-7 through 15-12 may be use to find the vapor-solid equilibrium constant (k) for C1, C2, C3, i-C4, CO2 and H2S at various P and T conditions

In the presence of lighter hydrocarbons with low concentrations (< 5 mole %) of n-C4, the value of k for n-C4 may be taken as those of C2

(actually, n-C4, is not known to form hydrates by itself, but it does participate in the formation of hydrates with lighter gases)

For hydrocarbons heavier than C4, the values of k are taken as infinity because these molecules are too large to form hydrates

Hydrate equilibrium constants are assumed to be functions of temperature and pressure only

The conditions for initial formation of hydrates are obtained by satisfying the relationship:



Figure 15-7 Vapor-Solid Equilibrium Constants for Methane


Figure 15-8 Vapor-Solid Equilibrium Constants for Ethane



Figure 15-9 Vapor-Solid Equilibrium Constants for Propane

Figure 15-10 Vapor-Solid Equilibrium Constants for Iso-Butane


Figure 15-11 Vapor-Solid Equilibrium Constants for Carbon Dioxide

Figure 15-12 Vapor-Solid Equilibrium Constants for Hydrogen Sulfide



Solution: The P of 300 and 400 psi to read k is obtain by first estimate the P using Example 1

* Use k for C2 when mol fraction of n- C4 < 5%# N2 does not form solid, k = y/0 = infinity

Example 4: Using the gas compositions from Example 1, calculate the pressure at which the hydrate will be formed at 50oF.

Component yi

At 300 psia At 400 psia

ki yi/ki ki yi/ki

Methane 0.810 2.040 0.397 1.750 0.463

Ethane 0.052 0.790 0.066 0.500 0.104

Propane 0.019 0.113 0.168 0.071 0.268

Isobutane 0.004 0.046 0.086 0.027 0.148

n-butane* 0.020 0.790 0.025 0.500 0.040

Nitrogen# 0.093 infinity 0.000 infinity 0.000

Carbon dioxide 0.002 3.000 0.001 1.900 0.001

Total 1.000 0.743 1.024

Interpolating linearly, y/k = 1.0 at 391 psia

Assoc. Prof. Abdul Razak Ismail, UTMFig. 15-13 show solubility of water in hydrocarbons



What is gas dehydration?

Gas dehydration means the removal of water from gas (water can be associated with natural gas in vapor form)

Reasons for dehydration

To prevent hydrate formation that plug/block pipelines and other equipment

To prevent corrosion from acid gases (H2S, CO2) To meet certain requirement (sales gas, contract specification*)

* The water content is normally reduced to about 6 – 8 lb of water per MMSCFof gas


Absorption: water vapor is removed from natural gas by bubbling the gas counter currently through certain liquid that have a special attraction or affinity for water

Adsorption: water vapor is removed from natural gas by flowing them through a bed of granular solids that have an affinity for water, and the water is retained on the surface of the particles of a solid material

Contactor/sorber: the vessel in which either absorption or adsorption take place

Desiccant: the liquid or the solid having affinity for water and used in the contactor in connection with either of the process

Definition of terms



There are 3 basic systems of hydrate control:

A. Changes to system T and P.

B. Use of hydrate inhibitors to suppress hydrate formation

C. Actual water removal from gas or gas dehydration

Methods of hydrate control


First method: The control of P is of not practical The use of T to prevent hydrate formation will be better choice

(will be discuss under flow line heaters and downholeregulators)

Second method: Involves inhibitors (e.g. methanol and ethylene) to selectively

dissolve in the water phase, → altering the availability of water for hydrate crystal growth (will be discuss under chemical injection)

Third method: Includes the actual removal of water vapor from the gas phase by– Absorption method by physical counter-current contact with

glycol or– Dry desiccant adsorption with alumina, silica gel or molecular

sieves



Indirect heater

ADownholeregulator

Hydrate absorption(liquid desiccant)

Methanol

C

BHydrate inhibition (chemical injection)

Glycol

Hydrate adsorption (solid desiccant)

Actual water

removal

Temp. control

Gas dehydration

Process Summary


1. Downhole regulators

A downhole regulator is used to eliminate surface hydration problem

A downhole regulator is a device that contains a spring-loaded valve and stem and is set by wireline in the tubing string

The spring compression is adjusted before the regulator is run in the well so that any specified pressure drop can be obtained

The pressure drop across the regulator is constant and does not depend on the flow rate

The tubing string above the regulator then acts as a sub-surface heater, transferring heat into the gas

A. Temperature control



2. Indirect heaters

Indirect heaters are commonly used to heat gas to maintain temperatures above the hydrate formation temperature

Most widely used type of heaters because it is simple, economical, and trouble-free

The heater consists of 3 basic parts:– Heater shell: thin-wall horizontal vessel having removal

flanged covers at both ends– Removable fire tube and burner assembly mounted on the

lower portion of one of the end cover– Removable coil assembly mounted on the upper portion of

the opposite end cover The shell and fire tube are design to withstand only atmospheric

pressure, whereas the coil assembly is usually designed to withstand shut-in wellhead pressure


Indirect heater



The high pressure fluid passed through heater inlet into coils

It is heated to suitable outlet temperature

The heater shell is filled with liquid (usually water) completely covering the fire tube and coil assembly

The water bath is heated by the fire tube (usually fired by gas) and the coil is heated by the water

Coil is located above the fire tube (for water circulation)

The direction of water current is controlled by thermo siphon baffle

Operation of indirect heater


Ammonia, brines, methanol and glycols have all been used to lower the freeing point of water and thus reduce or prevent hydrate formation in gas lines

However, methanol and ethylene glycol are the inhibitors mostly used

Injection of hydrate inhibitors may be applied for:

– Gas pipeline systems in which hydrate trouble is of short duration

– Gas pipelines which operate at a few degree below the hydrate formation temperature

– Gas gathering systems in pressure declining fields

– Gas line in which hydrates form at localized points

When hydrate inhibitors are injected in gas flow lines or gathering systems, installation of a high pressure water knockout at the well head will prove to be economical

Removing the free water from the gas stream will reduce considerably the amount of inhibitor required

B. Hydrate inhibition (chemical injection)



1. Methanol injection

Methanol is well suited for use as hydrate inhibitor because it is:

– Non-corrosive

– Does not react chemically with any constituent of the gas

– Soluble in all proportion in water

– Volatiles under pipeline conditions

– Reasonable in cost

– Vapor pressure is greater than water

If methanol injection is being utilized to prevent freezing in regulators, chokes or at localized points in the line, it is desirable to locate the injection point some distance upstream of the critical point in order to allow time for the methanol to completely vaporize before reaching the critical point in the line


Methanol is injected by a gas driven pump (3) into the flow line upstream of the choke or pressure control valve (2)

A temperature controller (5) measures the temperature of the gas in the low pressure flow line (7) and adjust the methanol rate accordingly

The methanol injection rate is controlled by the amount of power gas that is allowed to flow through the power gas control valve (4) to drive the pump

Typical methanol injection system

Note: Methanol evaporate at ambient condition



2. Glycol injection

The injection of glycol into a gas stream has the same effect as methanol injection i.e. lowering the hydrate formation point

However, glycol has a relatively low vapor pressure and does not evaporate into the vapor phase as readily as methanol

For these reasons, glycol can be more economically recovered, therefore reducing operating cost compared to methanol system


The injection parts of the system (item 1-5) is similar to methanol

The additional equipment in the glycol system is for recovering the glycol

A 3-phase separator (6) separates the water and glycol form the HC phases

Glycol injection and recovery system

The water-glycol solution in the separator is sent to the reboiler (7) while the gas is delivered to the sales line and the HC condensate is dumped to the condensate tanks

In the reboiler, excess water is boiled away from the glycol

The reconcentrated glycol in the boiler is then available again for injection into the gas stream



Separation of the glycol-water phase from the HC liquid phase is more difficult than separation of liquids from vapors

A glycol-HC mixture will separate more readily if the T > 60 – 70oF

At lower temperatures, emulsions can be form, especially in the presence of some well-treating compounds

The following steps can be taken:

– 10-15 min. residence time will normally allow separation of the glycol and HC

– Where emulsions are a problem, a large separator with a longer residence time is required

– Heat the emulsion in the separator the emulsion

– Lowering the glycol concentration in the injected fluid (the injection rate will have to be increased)

– Add anti-emulsion agents


There are 3 glycols normally used to prevent the formation of hydrates:

1. Ethylene glycol (EG)2. Diethylene glycol (DEG)3. Triethylene glycol (TEG)

Glycol selection



Comparison of the physical properties of methanol and glycols

Methanol EG DEG TEG

MW 32 62 106 150Boiling point @ 760 mm Hg, oF 148 387 473 533Vapor pressure @ 77 oF, mm Hg 94 0.12 < 0.01 0.01SG @ 77 oF (25 oC) 0.787 1.11 1.113 1.119SG @ 140 oF (60 oC) - 1.085 1.088 1.092Pounds per gallon @ 77 oF (25 oC) 6.55 9.26 9.29 9.34Freezing point, oF -144 8 17 19Pour point, oF - < -75 -65 -73Absolute viscosity in cp @ 77 oF 0.55 16.5 28.2 37.3Absolute viscosity in cp @ 140 oF 0.36 5.1 7.6 9.6Surface tension @ 77 oF, dynes/cm 22 47 44 45Specific heat @ 77 oF, Btu/lb/oF 0.27 0.58 0.55 0.53Flash point, oF - 240 280 320Fire point, oF - 245 290 330Decomposition temperature, oF - 329 328 404Heat of vaporization @ 14.65 psi, Btu/lb 473 - 150 179


If glycol is to be injected into a natural gas transmission line where glycol recovery is less importance than hydrate protection, EGwould be the best choice because it produces the greatest hydrate depression and has the highest vapor pressure of any of the glycols

If glycol is to be injected into a unit where it will contact HC liquids, EG is the best choice since it has the lowest solubility in high MW hydrocarbons

However, if vaporization losses are severe, DEG or TEG would be better to use because they have a lower vapor pressure. Sometimes DEG is used where there is a combination of both gas vaporization loss and liquid solubility loss factor

General guidelines for glycol selection

Note: It is important that the freezing point of the glycol solution be lower than the lowest temperature expected in the system



The 4 methods of hydrate prevention discussed earlier

– downhole regulators, indirect heaters, methanol injection and glycol injection are proven methods that can be design for safe and reliable operation

Other combinations of systems offer the best results, but overall evaluations should include development of:

– Capital cost

– Operating expense (including chemical and fuel requirement)

– Space (especially offshore operation)

– Potential operating problems and hazards

Comparison of hydrate prevention methods


Downhole regulators

– No routine service is required, but a wireline service company must be used each time the pressure drop has to be changed and when the regulator is finally removed

– Even in a well with downhole regulator, injection of methanol and glycol may be required when a well is brought on line after shut-in period until the flow and temperature stabilized

– After the well declines to less than allowable production, the downhole regulator will have to be removed and another form of hydrate prevention might be necessary

– Downhole regulators do not present any special safety hazards, but, since work with regulators involves working in the well, there is always the risk of losing the well

Comparison of hydrate prevention methods (ctd)



Heaters

– Capital cost and fuel expense of heaters are relatively high

– Pressurized fire boxes an flame have minimized the hazards, but only with proper attention to detailed design




– Advantages and disadvantages are as follows:

– For special equipment, the use of methanol requires only a free water separator and suitable injection, whereas the use of glycol requires a free water separator plus a gas-liquid separator and glycol re-concentration unit at the point of recovery stream

Chemical injection (methanol and glycols)

Inhibitor Advantages Disadvantages

Methanol Relatively low initial costLittle equipment involvedSimple system & little gas consumption

High operating costHauling methanol

Glycol Lower operating costSimple system & little gas consumption

High initial costHauling glycolLarge loss if line breaksPotential glycol contamination



1. Absorption process (liquid desiccant dehydration)

In absorption process, the water in the gas stream is dissolved in a relatively pure liquid solvent stream

The reverse process, in which the water in the solvent is transferred into the gas phase is known as stripping

The terms regeneration, reconcentration and reclaiming are also used to describe the stripping and purification process because the solvent is usually recovered for reuse in the absorption step

C. Actual water removal


The most common liquid used in absorption process is TEG (DEG may also be used). TEG is used because:

– It is more easily regenerated to 90 - 98% concentration

– It has a higher decomposition temperature (40oF)

– Lower vaporization losses than DEG

In general, transfer from the gas phase to the liquid phase (absorption) is more favorable at lower T and higher P and that transfer to the gas phase (stripping) is more favorable at higher T and lower P



Wet gas: Gas containing water vapor prior to contacting glycol in absorber

Dry gas: Gas leaving the absorber after contacting glycol

Desiccant: A drying or dehydrating medium (e.g. TEG)

Lean solution: A glycol-water solution whose glycol concentration ranges from 95 – 99% by weight (a lean solution can be the solution passing from the reboiler via the pump or TEG supplied in sealed drums)

Rich solution: A water-rich solution whose glycol content < 95% by weight or glycol solution that has contacted wet gas in the sorber

Definition of terms (for absorption process)


How the process works?

Flow diagram of a liquid-desiccant unit

The glycol dehydration process can be divided into 2 parts; the gas system and the glycol system



a. Gas system

The wet gas enters the unit through a scrubber or 3- phase separator to remove the liquid and solid impurities

The gas from the scrubber (or separator) passes into the bottom of the vertical glycol-gas absorber and flows upward through the valve trays in the column countercurrent to the glycol flow

As the wet gas contacts drier and drier glycol, more and more water is absorbed from the gas

Glycol absorber


b. Glycol system

Dry concentrated glycol is pumped from the surge tank by the glycol pump through the glycol-gas heat exchanger into the top of the contactor

Leaving the top tray, the gas passes through mist-extractor elements, sweep the glycol-cooling coils located in the upper end of the absorber, and passes to the pipeline

A small quantity of this dry gas is withdrawn from the absorber discharge for use as fuel and instrument gas

Typical Flow Diagram for a Tri-Ethylene Glycol Dehydration Unit



It then flows downward the column, absorbing more water as it passes across each tray

The wet (or rich) glycol from the base of the contactor passes through a filter before flowing through the heat exchanger

The wet glycol is then sent to a lower pressure separator, where most entrained gas and liquid HCs are removed

TEG dehydration flow diagram

The wet glycol then flows to reboiler where most of the water and some of the glycol are vaporized

From the boiler, the lean (dry) glycol flows to the surge tank to start another cycle

Assoc. Prof. Abdul Razak Ismail, UTMTEG dehydration unit



There are 5 operating variables which can have an important effect on the operation of a glycol dehyration system:

1. Temperature

a. Incoming gas The plant performance is sensitive to the T of the incoming gas At constant pressure the water content of the inlet gas increases as the T

is raised At the higher T, the glycol will have to remove about 3 times as much

water to meet the pipeline specification The glycol vaporization losses are also increased at the higher T

b. Lean glycol The T of the lean glycol entering the reboiler has a significant effect on

the gas dew point depression and should be held to a minimum to achieve the best operation

However, it should be kept above the inlet gas T to minimized HC condensation in the absorber

Effect of operating variables


c. Glycol reboiler The reboiler T controls the concentration of the water in the glycol With a constant P, the glycol concentration increases with higher reboiler

temperatures

d. Top of stripping still A high T in the top of the still column can increase glycol losses due to

excessive vaporization If the T is too low, too much water can be condensed and washed back

into the regenerator to flood the still column and fill the reboiler with excessive liquids

2. Pressure

a. Contactor At a constant T, the water content of the inlet gas decreases with

increasing P. Therefore, less glycol circulation is required at higher pressures

b. Reconcentrator P above atmospheric in the reboiler can significantly reduce glycol

concentration and dehydration efficiency



3. Glycol concentration

The dry gas leaves the contactor in equilibrium with the lean glycol The leaner the glycol going to the absorber, the more efficient its dehydrating

power will be

4. Glycol concentration rate

The glycol rate controls the total amount of water that can be removed

5. Number of absorber trays

A few additional trays in the contactor is much more effective than increasing the glycol circulation rate


Where the highest possible dew point depression is required, the solid- or dry desiccant dehydration system is the most effective type

Adsorption is a physical phenomenon which occurs when molecules of gas are brought into contact with a solid surface and some of them condense on the surface

Dehydration of gas (or liquid HC) with a dry desiccant is an adsorption process in which water molecules are preferentially held by the desiccant and removed from the gas stream

Commonly used desiccants are alumina, silica gel, fluorite and molecular sieves

Adsorption is encourage by low T and high P

Desorption (its reverse) is encourage by high T and low P

2. Adsorption process (solid desiccant dehydration)



The essential components of a solid-desiccant dehydration installation are:

An inlet gas stream separator

Two or more adsorption towers filled with solid desiccant

A high T heater to provide hot regeneration gas for drying the desiccant in the towers

A regeneration gas cooler for condensing water from the hot regeneration gas

A regeneration-gas separator to remove water from the regeneration-gas stream

Piping, manifolds, switching valves and controls to direct and control the flow of gases

Components

Two tower solid desiccant dehydration unit


Wet gas: gas containing water vapor prior to flowing through the adsorber towers

Dry gas: gas that has been dehydrated by flowing through the adsorber towers

Regeneration gas: wet gas that has been heated in the regeneration gas heater to T of 400 – 460 oF. This gas is passed through a saturated adsorber tower to dry the tower and remove the previously adsorb water

Desiccant: is a solid, granulated drying or dehydrating medium that has an extremely large effective surface area per unit weight because of multitude of microscopic pores and capillary openings

Definition of terms (for adsorption process)



All solids adsorb water to some extent, but their efficiency varies primarily with the nature of the material, its internal connected porosity and its effective surface area

Principles

Adsorption processes, as opposed to absorption processes, do not involve chemical reactions

Adsorption is purely a surface phenomenon

Enlargement of molecular sieves particles


A sponge is a good example of adsorption. If the water is spilled on the floor, a sponge can be placed in the water, and it will soak up (adsorb) the water

However, if a lot of water has been spilled and only a small sponge is available, it will be found that the sponge can only adsorb so much water before it become saturated. Therefore, water must be squeeze out (regenerated) before it can be used again



The desirable characteristics of a solid desiccant are:

High adsorptive capacity which reduces contactor size

Easily regenerated for simplicity and economic of operation

High rate of adsorption which allows higher gas velocities and thereby reduces contactor size

High adsorptive capacity retained after repeated regeneration allowing longer usage before replacement

Low resistance to gas flow to minimize gas P drop

High mechanical strength to resist crushing and dust formation

Chemically inert to prevent chemical reactions

No change in volume when wet which would necessitate costly allowance for expansion

Non-corrosive and non-toxic for safety

Low cost to reduce initial and replacement costs

Requirements for solid desiccants


Three separate functions or cycles must be alternately be performed in each dehydrator:

1. An adsorbing or gas drying cycle

2. A heating or regeneration cycle

3. A cooling cycle to prepare the regenerated bed for another adsorbing or gas drying cycle

The adsorption process is a batch procedure, with multiple desiccant beds used cyclic operation to dry the gas on a continuous basis

The number and arrangement of the desiccant beds may vary from two towers, adsorbing alternately to many towers

How the process works?

Dry bed dehydration unit



The wet inlet gas stream first passes through an efficient inlet separator where free liquids, entrained mist and solid particles are removed

This is important since free liquid may damage or destroy the desiccant bed and solid may plug it

At any given time, one of the towers will be on stream in the adsorbing or drying cycle and the other tower will be in the process of being regenerated and cooled

Several automatically operated switching valves and a controller route the inlet gas and regeneration gas to the proper tower at the proper time

Typically, a tower will be on the adsorb cycle for 4 – 12 hours with 8 hours being the average

The tower being regenerated would be heated for about 6 hours and cooled during the remaining 2 hours


Large volume system may have 3 towers:

– One adsorption cycle

– One heating cycle

– One cooling cycle

All the regeneration gas used in the heating and cooling cycle is passed through a heat exchanger, normally an aerial cooler, where it is cooled in order to condense the water removed from the regenerated tower



Quality of inlet gas

Temperature

Pressure

Cycle time

Gas velocities

Sources of regeneration gas

Direction of gas flow

Desiccant selection

Effect of regeneration gas on outlet gas quality

Effect of process variables


High dew point depressions cannot be obtained with standard equipment. Consequently, high inlet gas T cannot be tolerated

Glycol may become contaminated causing foaming and other operating difficulties

Pump packing leaks may be a nuisance and expense

Corrosion due to glycol decomposition products and/or acid gases is frequently a problem

Comparison between liquid and solid desiccant dehydrations

1. Liquid desiccant dehydrations (glycol dehydration)

Advantages Disadvantages

Initial investment for a standard unit is relatively inexpensive

P drop through the contactor is low. This may result in reducing compressor HP requirement

Effective dehydration can be obtained over a wide range of operating conditions



Initial investment is relatively expensive

P drop through the contactor is greater that of a glycol unit

Desiccant can be poisoned, especially by heavy lube oils which may come into the unit with compressed gas

At low flow rates, the heat required for regeneration is high relative to the amount of gas dehydrated

2. Solid desiccant dehydrations

Advantages Disadvantages

High dew point depression can be obtained

Effective dehydration can be obtained over a wide range of operating conditions

The nominal capacity of a unit may be increased by bypassing some wet gas around the unit so that the combined stream will meets the dew point requirement


Other methods of dehydration

Other methods of dehydration or hydrate inhibition that are less frequently used are:

Dehydration: by expansion refrigeration (Joule-Thomson) using of calcium chlorite

Hydrate inhibition: by alcohol or glycol* by use of flow line heaters

* These methods are not dehydration methods, but rather preventive methods that result in eliminating the hydrate problem, without removing the water from the gas

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C4 Hydrate and Gas Dehydration

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