C4 Hydrate and Gas Dehydration

HYDRATES & GAS DEHYDRATION

Assoc. Prof. Abdul Abdul Razak Ismail, UTM

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 removed from the gas stream

because it will will condense condense into liquid liquid and may cause hydrate formation formation as the gas is cooled from the 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 lines Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Assoc. Prof. Abdul Razak Razak Ismail

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What is hydrate  Hydrates are solid, semi-stable compounds that form as

crystals and resemble snow in appearance reaction of natural gas with water, water,  They are created by a reaction and when formed, they are about 10% hydrocarbon and 90% water will usually float in water water  Hydrates have a SG ~ 0.98 and will and sink in hydrocarbon liquids


What are the problems?  Plugging natural gas transmission pipelines and other gas

handling equipment such as nozzles, valves, separation equipment, etc. excess ive pressure drop  Reduces gas capacity due to excessive  Cause corrosion in the presence of H2S or CO2 and water



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temperatures res and pressures pressures at which  Hydrate point - The temperatu hydrates form in a gas mixtures temperature re at which the natural natural gas is  Dew point - The temperatu 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


The conditions that tend to promote the formation of natural gas hydrates are:  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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


Page 3

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


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



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

Example 1: What would be the pressure above which hydrates could be expected to form if the following gas is at 50oF? Component C1 C2 C3 iC4 nC4 N2 CO2 Total

Mole fraction in gas 0.810 0.052 0.019 0.004 0.020 0.093 0.002 1.000 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Solution: Component

yi

Mi

yi Mi

C1 C2 C3 iC4 nC4 N2 CO2

0.810 0.052 0.019 0.004 0.020 0.093 0.002 1.000

16 30 44 58 58 28 44

12.96 1.56 0.84 0.23 1.16 2.60 0.09 19.44



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2. Figu Figurres 15-2 5-2 through 156 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. Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Fig. 15.3 Permissible expansion of a 0.7-gravity Fig. 15.4 Permissible expansion of a 0.8-gravity natural gas without hydrate formation. natural gas without hydrate formation. Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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Fig. 15.5 Permissible expansion of a 0.8-gravity Fig. 15.6 Permissible expansion of a 1.0-gravity natural gas without hydrate formation. natural gas without hydrate formation.


Example 2: The 0.65 gravity 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? f ormation?

Solution 2:

By interpolation: T min = 116oF



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Example 3:

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

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

The temperature curve does not intersect the pressure line. Therefore, the gas may be expanded to atmospheric pressure without hydrate formation Assoc. Prof. Abdul Abdul Razak Ismail, UTM

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? Answer:

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



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Calculation of pressure at which hydrate form  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:

where: y = mol fraction of HC in the gas on a water water free basis xs = mol fraction of HC in the solid on a water free basis Assoc. Prof. Abdul Abdul Razak Ismail, UTM

 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 variou variouss P and T conditions hydrocarbons with low concentrations (< 5  In the presence of lighter hydrocarbons mole %) of n-C 4, the value of k for n-C4 may be taken as those of C 2 (actually, n-C4, is not known to form hydrates by itself, it self, but it does participate in the formation of hydrates with lighter gases)  For hydrocarbons heavier than C 4, the values of k are taken as

infinity because these molecules are too large to form hydrates 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:



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Figure 15-7 Vapor-Solid Equilibrium Constants for Methane


Figure 15-8 Vapor-Solid Equilibrium Constants for Ethane



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Figure 15-9 Vapor-Solid Eq uilibrium Constants for Propane

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


Figure 15-11 Vapor-Solid Eq uilibrium Constants for Carbon Dioxide

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



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

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

yi

At 300 psia

At 400 psia

ki

yi/ k ki

ki

yi/ k 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. 0.000

infinity

0. 0.000

Carbon dioxide

0.002

3.000

0.001

1.900

0.001

Total

1.000

0.743

1.024

Interpolating linearly, linearly, y/k = 1.0 at 391 psia * #

Use k for C 2 when mol mol fraction fraction of n- C 4 < 5% N 2 does not form solid, k = y/0 = infinity Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Fig. 15-13 show solubility of water in hydrocarbons



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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 f ormation that plug/block pipelines and other

equipment  To prevent corrosion from acid gases (H 2S, CO2)  To meet certain requirement (sales gas, contract specification*) * The water water content content is normally normally reduced reduced to about about 6 – 8 lb of of water water per MMSCF of gas Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Definition of terms  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



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Methods of hydrate control

 There are 3 basic systems of hydrate

control: A. Chan Change gess to sys syste tem m T and P. B. Use of of hydrat hydratee inhib inhibito itors rs to to suppress hydrate formation C. Actual Actual wate waterr remova removall from from gas or or gas dehydration


 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 downhole regulators )  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 – Absorp Absorptio tion n metho method d by physi physical cal coun counter ter-cu -curren rrentt contac contactt with with glycol or – Dry desi desicca ccant nt adsorp adsorptio tion n with with alumin alumina, a, silic silicaa gel gel or molec molecula ularr sieves →



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Process Summary A

Indirect heater

Temp. control

Hydrate absorption (liquid desiccant)

Downhole regulator

Glycol Gas dehydration

Actual water removal

Hydrate inhibition (chemical injection)

Hydrate adsorption (solid desiccant)

Methanol

C

B


A. Temperature control Downhole regulato regulators rs 1. Downhole  A downhole downhole regulator is used to eliminate surface hydration

problem  A downhole downhole regulator is a device that contains contains a spring-loaded

valve and stem 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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2. Indi Indirrect ect heat heater erss  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 fire tube and burner assembly mounted on the – Removable fire 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Indirect heater Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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Operation of indirect heater  The high pressure fluid passed through heater inlet i nto 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


B. Hydrate inhibition (chemical injection) 

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 f ew degree below the hydrate for mation 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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1. Meth Methan anol ol inje inject ctio ion n  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 t he critical point in order to allow time for the methanol to completely vaporize before reaching the critical point in the line Assoc. Prof. Abdul Abdul Razak Ismail, UTM



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

Note: Methanol evaporate at ambient condition

Typical Typical methanol injection system Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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2. Glyc Glycol ol inje inject ctio ion n  The injection of glycol into a gas stream has the same effect as

methanol injection i.e. lowering the hydrate formation point  However, 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



The water-glycol solution in the separator is sent to the reboiler reboiler (7) while the 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 reconcentrated glycol glycol in the boiler is then available again for injection into the gas stream

Glycol injection and recovery system Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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 Separation of the glycol-water phase from the HC liquid phase is

more difficult than separation of liquids from fr om vapors  A glycol-HC glycol-HC mixture will separate more readily 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Glycol selection There are 3 glycols normally used to prevent the formation of hydrates: 1. Ethy Ethyle lene ne glyc glycol ol (EG) (EG) 2. Diet Diethy hyle lene ne glyc glycol ol (DE (DEG) G) 3. Triet riethy hyle lene ne glyc glycol ol (TEG) (TEG)



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Comparison of the physical properties of methanol and glycols

MW Boiling point @ 760 mm Hg, oF Vapor pressure @ 77 oF, mm Hg SG @ 77 77 oF (25 oC) SG @ 140 140 oF (60 oC) Pounds per gallon @ 77 oF (25 (25 oC) o Freezing point, F Pour point, oF Absolute viscosity in cp @ 77 oF Absolute viscosity in cp @ 140 oF Surface tension @ 77 oF, dynes/cm Specific heat @ 77 oF, Btu/lb/ oF Flash point, oF Fire point, oF Decomposition temperature, oF Heat of vaporization @ 14.65 psi, Btu/lb

Methanol

EG EG

DEG

TEG

32 148 94 0.787 6.55 -144 0.55 0.36 22 0.27 473

62 387 0.12 1.11 1.085 9.26 8 < -75 1 6 .5 5.1 47 0.58 240 245 329 -

106 473 < 0.01 1.113 1.088 9.29 17 -65 28.2 7.6 44 0.55 280 290 328 150

150 533 0 .0 1 1.119 1.092 9.34 19 -73 37.3 9.6 45 0.53 320 330 404 179


General guidelines for glycol selection  If glycol is to be injected into a natural gas transmission line where

glycol recovery is less importance than hydrate protection , EG would 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 choice since it has has the lowest solubility solubility in high MW hydrocarbons  However, if vaporization losses are severe , DEG or or TEG would be

better to use because they have a lower vapor pressure. pressure. Sometimes DEG is used where there is a combination of both gas vaporization loss and liquid solubility loss factor Note: It is important that the freezing point of the glycol solution be lower than the lowest temperature expected in the system Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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Comparison of hydrate prevention methods  The 4 methods of hydrate prevention discussed earlier

downhole regulat regulators ors, indirect heaters, methanol injection and – downhole 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Comparison of hydrate prevention methods (ctd)  Downhole Downhole regulato regulators rs

– No routine service is required, but a wireline service company company must be used each time the t he pressure drop has to be changed and when the regulator is finally removed – Even in a well well with downhole regulator, injection of methanol 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 not present any special special safety hazards, hazards, but, since work with regulators involves working in the well, there is always the risk of losing the well Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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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


Comparison of hydrate prevention methods (ctd)  Chemical injection (methanol and glycols)

–

Advan Advantag tages es and and disa disadva dvanta ntages ges are as follow follows: s:

Inhibitor

Advantages

Disadvantages

Methan Methanol ol Relati Relativel vely y low init initial ial cost cost Little equipment involved Simple system & little gas consumption

High operating cost Hauling methanol

Glycol

High initial cost Hauling glycol Large loss if line breaks Potential glycol contamination

–

Lowe ower operating cost Simple system & little gas consumption

For specia speciall equipm equipment, ent, the use of methan methanol ol require requiress only 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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C. Actual water removal (liquid desiccant dehydration) 1. Absorption process (liquid  In absorption process, the water in the gas stream is dissolved in

a relatively pure liquid solvent stream str eam  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


 The most common common liquid used in absorption process process is TEG (DEG

may also be used). TEG is used because: because: – It is more easily regenerated 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



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Definition of terms (for absorption process) Wet gas:

Gas co contai taining wa water va vapor pr prior ior to to co contac tactin ting gl glycol in absorber

Dry gas:

Gas lea leaving the the absorber after contac tacting glycol

Desiccant :

A dryin rying g or or deh dehyd ydra rati tin ng mediu edium m (e (e.g. .g. TEG) EG)

glycol-water -water solutio solution n whose whose glycol glycol concentr concentration ation Lean solution: A glycol ranges from 95 – 99% by weight (a lean solution can be the solution passing passing from the reboiler via the pump or TEG supplied supplied in sealed sealed drums) Rich solution: A water-rich water-rich solution solution whose whose glycol glycol content content < 95% by weight or glycol solution that has contacted wet gas in the sorber Assoc. Prof. Abdul Abdul Razak Ismail, UTM

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

Flow diagram of a liquid-desiccant unit



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a. Gas system  The wet gas enters the unit

through through a scrubber scrubber or 3- phase 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

 Leaving the top tray, 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 b. Gly Glycol col sys system tem  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 Typical Flow Diagram for a Tri-Ethylene Glycol Dehydration Unit Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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 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 before flowing through the heat exchanger exchanger  The wet glycol is then sent to a lower l ower pressure separator, where most entrained gas and liquid HCs are removed  The wet glycol then

flows to reboiler 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 TEG dehydratio dehydration n flow diagram Assoc. Prof. Abdul Abdul Razak Ismail, UTM

TEG dehydratio dehydration n unit unit



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Effect of operating variables There are 5 operating variables which can have an important effect on the operation of a glycol dehyration dehyration system: 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 t he higher T b. Lean glycol entering the reboiler has a significant effect on  The T of the lean glycol entering 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

2.

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 column and fill the reboiler with excessive liquids

Pressure

a.

Contactor  At a constant T, the water content of the inlet gas decreases with increasing P. P. Therefore, less glycol circulation is required at higher pressures

b. Reconcentrator glycol  P above atmospheric in the reboiler can significantly reduce glycol concentration and dehydration efficiency Assoc. Prof. Abdul Abdul Razak Ismail, UTM


Page 28

3.

Glycol concentration  

4.

Glyc Glycol ol conc concen entr trat atio ion n rat ratee 

5.

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

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

Numb Number er of abso absorb rber er tray trayss 

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


2. Adsorption Adsorption process process (solid (solid desiccant desiccant dehydration) dehydration)  Where the highest possible dew point depression is required, the

solid- or dry desiccant dehydration dehydration system is the most effective 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 molecular sieves sieves  Adsorption is encourage by low T and high P  Desorption (its reverse) is encourage by high T and low P Assoc. Prof. Abdul Abdul Razak Ismail, UTM


Page 29

Components The essential components of a soliddesiccant 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

Two tower solid desiccant dehydration unit


Definition of terms (for adsorption process) Wet gas:

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

Dry gas:

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

Regeneration gas:

wet gas gas that that has has been been heated heated in in the regene regenerat ration ion gas heater to T of 400 – 460 oF. oF. This gas is passed through a saturated saturated adsorber 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


Page 30

Principles  Adsorption processes, as opposed to absorption processes, do not

involve chemical reactions  Adsorption is purely a surface phenomenon  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 Enlargement of molecular sieves particles Assoc. Prof. Abdul Abdul Razak Ismail, UTM



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

 However, 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



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Requirements Requirements for solid desiccants 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

How the process works? 

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



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

Dry bed dehydration unit Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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

The wet inlet gas stream first p asses 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 tower s: –

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 o rder to condense the water removed from the regenerated tower



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Effect of process variables  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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM

Comparison between liquid and solid desiccant dehydrations dehydrations

1.

Liquid Liquid desi desicca ccant nt dehyd dehydrat ration ionss (glyc (glycol ol dehyd dehydrat ration ion)) Advantages

Disadvantages

 Initial investment for a standard unit

 High dew point depressions cannot

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

be obtained with standard equipment. Consequently, 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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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2. Soli Solid d desi desicc ccan antt dehy dehydr drat atio ions ns Advantages  High dew point depression can be

obtained

Disadvantages  Initial investment is relatively

expensive

 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

 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


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 Assoc. Prof. Abdul Abdul Razak Ismail, UTM


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C4 Hydrate and Gas Dehydration

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