05-Gas Dehydration by GLYCOL 81

8/13/2019 05-Gas Dehydration by GLYCOL 81

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Gas Dehydration

GAS DEHYDRATION

INTRODUCTION

Natural as is usuall in contact wi th waterin the roducinreservoir, and comes to the wellhead saturated with all thewater vapor it can hold.

It may either be dehydrated at the wellhead or brought intothe plant as it is wet by using some means to prevent hydrateproblems as heating , or injecting methanol.

If an amine or other aqueous sweetening process is usedin the plant, the sweetened gas will again be saturated withwater.


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Removing most of the water vaporfrom the gas isrequired by most gas sales contracts. because it

1. Prevents hydrates from forming when the gas iscooled in the transmission and distribution systems .

. prevents water vapor rom con ens ng an creat ng acorrosion problem.

3. Dehydrat ion also increases line capacity marginally.it means water will reduce the line capacity bycreating a layer parallel to the line walls.

.

5. Water vapor Minimize Gas Heating Value ( Grossheating value , net heating value) see the next slide.

6. Water cause unsatis factory instrument operation.


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toequalnearlyof gas iskg1The heating value ofthe heating value of 1 kg of oil

of oil )3m1of gas and3m1NOT(

The heating value increase as the carbon atoms number increased.

ComponentHeating value in MJ /

kg

Heating value in MJ

/ m3 DENISTY

Methane 55.5 37.69 0.68

n- heptanes 48.5 205.4 4.24

1 Kg of Methane has about 62 carbon atoms 1000 gram / 16 gram = 62.5Carbon atoms = 62.5 x 1 = 62.5 , Hydrogen atoms =

1 Kg of heptanes has about 70 carbon atoms 1000 gram / 100 gram = 10Carbon atoms = 10 x 7 = 70

Remarks nearly the same about 6 times

Most sales contracts call for reducing thewater content in the gas:-

In the Southern United States to less than 7lb/mmscf

In colder climates, in the Northern United Statessales gas water content is less than 4 Lb /mmscf

In Canada requirements is 2 to 4 lb/mmscfare.

In Egypt based on the agreement and the furthertreatment requirements LNG asking for watercontent less than 1 ppm.


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ppm & Lb / mmscf

If the water content is 147.5 ppm

Convert it to Lb / mmscf

147.5 ppm = 147.5 ft3 / mmscf

18 Lb occupy 379.4 ft3 so 147.5 ft3 will weight ?

(147.5 x 18) / 379.4 = 7 Lb / mmscf

7 Lb = 3.17 Kg

Lb / mmscf = 147.5 / 7 = 21.06 ppm

The molar heat of vaporization of water is 40.79 kJ at 100oC what is the

heat of vaporization of 1 g of water?

well you have not mentioned the complete unit...it is 49.79 kJ/mole or also

2.766 kJ/gramjust divide 49 KJ/Mole by 18 g / mole (which is the molar mass of water)

and have your answer

Each gram of water exist in the fuel will consume 2.76 KJ heat from

the gross heating value of the fuel the remaining heat value is the net


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in the gas stream is the

hydrate

Basics of Hydrates

Basic Hydrates Defini tion :-

Natural gas hydrates are ice-like physical

structures com osed of free waterand li ht end

hydrocarbons molecules Under favorable

conditions of pressure and temperature.

What are the light end hydrocarbons?

Watermolecules form cages which encapsulate

light end hydrocarbon molecules inside ahydrogen-bonded solid lattice.

Host = water molecules

Guest = gas molecules


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When Hydrates forms?

Hydrates form when these factors are present:-

A suff ic ient amount of waternot too much, not too little.

A hydrate former ,

Hydrate formers related to guest molecules , lightends hydrocarbons C1 , C2 , C3 ,iC4 ,Co2 ,H2S

The right combination of temperature and pressure.

Hydrate formation is favored by low temperatureand high pressure, but it can happened at low

pressure ( see the next slide chart )

Just Move the arrows up and down also right andleft to check the right P & T combination


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some useful facts regarding hydrates

They can form in gas, gas condensate & oil systems. Hydrate formation temp depends on gas composition Richergases will tend to form hydrates at higher temperatures.

1cubic foot of hydrate can contain 180 scfof gas.

Hydrate blockages can occur very rapidly, due to hydrateparticles ability and tendency to collide.

Brines needs more sub cooling for hydrate formation.

u u y u w u , u y

treatment process of the gas may cause the gas to besaturated with water as sweetening process, what issaturation means ??


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Start-up, shutdown & blow down can leads tohydrates, due to high pressure drop and so a

temperature drop.

Hydrate ice crystals are generally softerthan

damage to tubing, flow line, or vessels. However,in some cases the crystals are harder and causeerosion or destroy sensitive parts in the productionfacilities.

,

final arrangement being dependant on the specificavailability of guest molecules , where the waterlattice surrounding the available guestmolecules


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Other phenomena that enhance hydrate formation:-

Turbulence

1. High velocity:-

Hydrate formation is favored in regions where the fluid.

subject to hydrate formation. First, there is usually asignificant temperature drop when natural gas is chokedthrough a valve because of the Joule-Thomson effect.

2. Agitation and Mixing in a pipeline, process vessel, heatexchanger, and so on enhances hydrate formation.

proper sites ( locations) for hydrate accumulation include animperfection in the pipeline, as a weld spot, a pipeline fitting(e.g., elbow, tee, valve), and so on. Silt, scale, dirt, and sandall make good nucleation sites.( a place for hydrate toaccumulate ).

Water crystal formation sequence

At temperatures above 0oC, watermolecules aremoving freely from each other, called theBrownian movement of molecules.Brownian motion named after the Scottish botanist Robert Brown isthe seemingly random movement of particles suspended in a fluid(i.e. a liquid or gas)

When temperatures are approaching the normalfreezing point of water, these movements arebecoming slowerand the water molecules tend to

.

This is done via the so-called Hydrogen Bonding inwhich the Hydrogen atoms from the water moleculesare forming a loose bond with the Oxygen atom ofanotherwater molecule.


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In this way clusters of water molecules are beingformed where the hydrogen bonds move from one

molecule to another.

During these changes in hydrogen bonding,

a so t e ormat on o unsta e crysta e

lattices may occur.

In the presence of certain Guest Moleculeswhich have a size to nicely fit in the cavity of alattice of water molecules, the total structure canthereby ** be stabil ized such to form a hydrate

crystal.

As result hydrate ice crystals can be formedabove the pure water freezing point.


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Two hydrate structures are often encountered in oil

and gas production operations.

Firstly, the simplest of all crystalline cavity structurescan be formed by a pentagonal dodecahedral of 20water molecules linked together by hydrogen bonds

This structure has 12 regular pentagonal (five-ring) faces.

accommodate small molecules such as Methane,Ethane and Hydrogen sulphide.


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As a result of minor deformations, other structurescontaining cavities can be formed besides theregular pentagonal-dodecahedron ones.

,sixteen face cavity structure are shown on thenext figure to the left and right of the twelve facesstructure.

The larger the cavity the larger molecules that it, , -

carbon dioxide.


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is a hydrate test cell for research the effectively and efficiency ofkinetic andthermodynamic gas hydrate inhibitors, as well as anti-agglomerates.


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Examination of Gas Hydrate Formation

Characteristics

1. Pressure range up to 700 bar

2. Visual observation during test

3. Take photos and videos

4. Simulates pipeline conditions.


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The densities of some pure hydrates at 0o C are given inTable 8-2. Note that the densities of the hydrates of the

hydrocarbons are similar to ice.The hydrates of carbon dioxide and hydrogen sulfide aresignificantly more dense In fact, they are denser than water.

note 1 A =10 -10 meter


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Indicates the cavity occupied by the simple hydrate former.

Indicates that the simple hydrate is only formed at very high pressure.

a The structure has been confirmed by single crystal x-ray analysis(Udachin et al., 2002).b Molecular diameters obtained from von Stackelberg and Muller (1954),Davidson (1973),Davidson et al. (1984a, 1986a), or Hafemann and Miller (1969).c The cavity diameter is obtained from the cavity radius from Table 2.1minus the diameterof water (2.8 ).


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Figure 1-3. Micro photographs of snow flakes.


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The hydrogen bonding structure of the hydrateis weak and will collapse unless it is supported

by molecules occupying the cavities.This explains why propane and butane, which

on y can e arger cav es,

unstable hydrates- as they do not fill enoughcavities to support the weak lattice structure.(C3 & C4 can't fill the small cavity and also they are smallerthan the large cavities so they form unstable hydrate).

Molecules largerthan butane are too big to formhydrates as they cannot fit into the cavities. Infact they tend to inhibit hydrate formationbecause the crystal tries to form around it.

The number of guest molecules that can enter

the cavities is dependant upon temperature andpressure (pressure distorts the lattice, and sochange the cavity shape). Not all the voids may befilled and hence h drate structure tend to bevaried.

The existence of single guest molecule stabilizedhydrate crystals would not cause a problem inproduction facilities as their physical size is verysmall +/_0.50 nm. However like normal ice the

crystal particles tends to group themselves intypical three dimensional crystal shapes,Assuch their size increases to that extend thatblockages of the flow system can occur.


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General conditions for hydrate formation

Hydrate formation in natural gas can, only be formed inthe presence of water.Its formation temp is mainly dependant on pressure.

hydrates can be formed both in the gas and liquid phaseof the gas (any where to the left of the hydrate line inthe picture below).

At lower pressures, the temperature has an effecton hydrate formation, but the temperature effect

.

At 3000 psi hydrate may formed at 25o c

Hydrateformation area


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Component MW RVPpsia

Gross

heatingvalueBtu / ft3 @std cond.

CriticalPressurepsia

Criticaltemperatureo F

Methane 16 5000 1016 666.4 - 116.67

Ethan 30 800 1769.6 706.5 89.92

Propane 44 188 2516 616 206.06

i-butane 58 72 3251.9 527.9 274.46

n- u ane . . .

i-pentane 72 20 4000.9 490.4 369.1n-pentane 72 15 4008.9 488.6 385.8

hexane 86 5 4755.9 436.9 453.6

( 25o C)


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When the water molecules line up, they form a, ,

well known that the angle between the sides of aregular hexagon is 120 degrees, which is greaterthan the 105-degree angle in the water molecule

,So the volume increased.


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or at least buried the pipe line

Anti-Freezes

Do Not React with gas hydrates but dilute the liquidwaterphase thereby shifting the hydrate curve to lowertemperatures by 0.8 degrees per mole % of particlesdissolved in the Water

Glycols, due to their higherboiling points compared towater, can more easily berecovered from the gas in gasdehydration systems, and is

preventative method.Methanol however, due to its lower viscosity, acts fasterandis mostly used for remedial applications when hydratesalready have been formed.The methanol freezing temperature is ( 144o F )


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Methanol

Formula CH3OH

Freezing point, F 143.8

Molecular Wt 32.04

Boilin oint 760 mm H F 148.1

Specific gravity 20C/20C 0.7917

Flash point, F 58


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Polar compounds (alcohols, glycols) fight with hydrates for hydrogenbonding

By using the glycol More Hydrogen Bonding Opportunity With WaterThrough One More Hydroxyl Group Than Alcohols

TEG formula HOCH CH OCH CH OCH CH OH

Glycols Generally Have Higher Molecular Weights Which Inhibit Volatility( TEG MW 150.17)

Alcohols & Glycols when dissolved in aqueous solutions formhydrogen bond with the water molecules and make it difficult for thewater molecules to participate in the hydrate structure.

MEG is preferred over DEG for applications If the temperature isexpected to be

10 C or lower due to high viscosity at low

temperatures

Other chemicals which depress the hydratefreezing point are:-

salts such as common kitchen salt (NaCl) orAmmonium Chloride (NH4Cl).

Regardless of being cheap products, theirdisadvantages are the relatively large quantitiesrequired and their corrosively to carbon steel.

Heating is a third option to prevent hydrateformation. This option is often applied in gas salessystems where the lines around the pressurereduction system are insulated and electrically heated.


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Salts Alcohol/diols

NaCl Methanol

Thermodynamic Hydrate inhibitors

KCl Ethanol

CaCl2 Glycerol

Na-Formate Ethylene glycol

K-Formate Propylene glycol

NaBr Pol alk lene l col

CaBr2

ZnBr2


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How salts prevent / delay the hydrate formation

Salt Ionizes In Solution And Interacts With The

Clustering

This ClusteringAlso Causes A Decrease In TheSolubility Of Potential Hydrate Guest MoleculesIn The Water

-

Form Hydrates.

The last option for hydrate formation prevention is by

crystal growth prevention.This can be achieved in two ways namely: -

The first is the Cr stal sha e modif icat ion in which thecrystal is reshaped into a more shapelessappearance. ( loose fitting , fluid appearance)

The second type of growth preventers are the so-calledcrystal-crystal bond fighting , damaging products.

As the word says it does interfere with the growth ofcrystals by positioning around the single crystal lattice,resulting in only very fine (and harmless) hydrate

particles to be formed, An example of the chemical is theShell developed product Armoblen 802.


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Kinetic Inhibitors

Delay the onset of formation Slow the rate of formation Prevent the agglomeration of hydrates Reduce the amount of hydrate that form

While kinetic inhibitors work by slowing down the kineticsof the nucleation, anti-agglomerants do not stop thenucleation, they rather stop the agglomeration (stickingtogether) of gas hydrate crystals.

Hydrate Hydrate

Kinetic Inhibition


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Low dosage hydrate inhibitors (LDHIs) have been developed over the last 15 yr

as a new gas hydrate control technology for the oil industry, which can be morecost-effective than traditional practices such as the use of thermodynamicinhibitors e.g. methanol and glycols. Two classes of LDHI called kinetic inhibitors(KHIs) and anti-agglomerants (AAs) are already being successfully used in the

. ,a high degree of propoxylation. High pressure tests in sapphire cells show thatpolyamine polypropoxylates and other branched polypropoxylates are able todisperse gas hydrates in a hydrocarbon fluid as long as there is good agitation inthe fluids. Formation of an emulsion is not required for this AA effect. Linear,unbranched or low molecular weight polypropoxylates did not perform well underthe same conditions, as well as many other surfactant classes including anionicand various polyethoxylated surfactants. Some polyamine polypropoxylates gaveweak kinetic h drate inhibition effects. Addition of kinetic h drate inhibitors suchas polyvinylcaprolactam reduces the performance of polyamine polypropoxylates

as AAs.

Part of the mechanism for the AA effect of the surfactant polypropoxylates isproposed to rely on their low solubility in both the aqueous and hydrocarbonphases. The surfactant polypropoxylates form a separate layer between the two

phases, which coat the dispersed water droplets as they are converted to gashydrates, keeping them from agglomerating. After shutting in the cell by stoppingthe stirring for some hours the hydrates can be redispersed again have a highinterfacial concentration, were tested as AAs. Some other demulsifiers showed thesame anti-agglomeration properties as the polypropoxylates. One demulsifier,Dowfax DM655, an alkylphenol formaldehyde resin alkoxylates, gave good AAperformance at up to 16.5 C subcooling when dosed at 10,000 ppm in syntheticsea water. However, the performance decreased at low salinity ( 0.5 wt.%) and atwater cuts of 35% or more.


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Interesting Properties of hydrate

Large amounts of methane hydrates exist in nature

Capture large amounts of gas (up to 15 mole%) so

may e use o remove g componen s rom o .

Form at temperatures well above 0 C

Generally lighter than water , only pure Co2

and H2S hydrate is more dense than water.

ee re a ve y arge a en ea o ecompose.

Result from physical combination of water and

gas, both water & gas prosperities not changed when combined

Reject salts and other impur ities.(clean energy level )


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Hydrates have potential as a future

energy resource each cubic feet ofhydrate contain 180 ft3 of gases.

pipeline transmission as a way to

move natural gas from deep water to

the terminals of existing offshore

A source of c lean burning fuel?

For a given THydrate

increases asHC sizedecreases


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As the molecular weight of the gas increase the hydrate may beformed at higher temperature assume the pressure is constant

They are crystalline water based solids physically

similar to ice, in which small non polarmolecules(typically gases) are trapped inside "cages" ofhydrogen bonded water molecules.

ou e suppor o e rappe mo ecu es, elattice structure of hydrate clathrates would

collapse into conventional ice crystal structure or

liquid water

Most low molecular weight gases (including O2, H2, N2, CO2,CH4, H2S, Ar, Kr, and Xe), as well as some higher

y rocar ons an reons w orm y ra es a su a e

temperatures and pressures.

gas hydrates are not chemical compounds as thesequestered molecules are never bonded to the

lattice.


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Around 6.4 trillion (i.e. 6.4x1012) tonnes of methane istrapped in deposits of methane clathrate on the deep

ocean floor. Such deposits can be found on theNorwegian continental shelf

These natural gas hydrates are seen as a potentiallyvast energy resource, but an economic extractionmethod has so far proven elusive.

Hydrates have a strong tendency to agglomerate andto adhere to the pipe wall and thereby plug thepipeline. Once formed, they can be decomposed by

pressure. Even at these conditions, the clathratedissociation is a slow process.

The experiments indicates that methane hydrate willnot be formed at temperature more than 30o C

Hydrate inhibitor

Two options generally exist:-Thermodynamic inhibitorsKinetic inhibitors/anti-agglomerants

The most common thermodynamic inhibitors are,methanol, monoethylene glycol (MEG) and diethyleneglycol (DEG) commonly referred to as glycol . All maybe recovered and re-circulated, but the economics ofmethanol recovery will not be favorable in most cases.

MEG is preferred over DEG for applications where the

high viscosity at low temperatures. Tri-ethylene glycol (TEG) has too low vapor pressureto be sui ted as an inhibitor injected into a gas stream.

More methanol is lost in the gas phase whencompared to MEG or DEG.


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The use of Kinetic inhibitors/anti-agglomerants in actual fieldoperations is a new and evolving technology, It requires

extensive tests and optimization to the system.

While kinetic inhibitors work by slowing down the kinetics of thenucleation, anti-agglomerants do not stop the nucleation, theyrather stop the agglomeration (sticking together) of gas

hydrate crystals.

These two kinds of inhibitors are also known as Low-Dosage-Hydrate-Inhibitors because they require much smaller

concentrations than the conventional thermodynamic

inhibitors.

Kinetic inhibitors (which do not require water and

copolymers and anti-agglomerants (requires water and

hydrocarbon mixture) are polymers or zwitterionic (usually

ammonium and COOH) surfactants being both attracted to

hydrates and hydrocarbons.

No Hydrates Forming

o

Hydrates Forming


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Initial P =3000 psiaInitial T = 170oF

Safe (no hydrate) final P =350 psia and final T = 50oF

In the study of hydrates, n-butane is an interesting anomalyBy itself, n-butane does not form a hydrate; however, itssize is such that it can f it into the lar e ca es of the T e II

n-Butane

hydrate lattice.

Thus, in the presence of another hydrate former, n-butanecan enter the cages, Where n-butan usually linked with

propane molecules

- ,

component.

Molecules smaller than n-butane are hydrate formers,

whereas molecules larger than n-butane do not form Type I

or Type II hydrates.


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Liquid Hydrate Formers

It is a commonly held beliefthat hydrates do not form in thepresence of a Non-aqueous liquid phase (i.e., that hydratewill not form in the presence of condensate or oil). This

is not t rue. Many experimental investigations

demonstrate that liquid hydrocarbons can form hydrates.

As discussed all that is required is the presence of ahydrate former, enough water present to form a hydrate,

and the right combination of press. and Temp.

No mention was made of the phase of the former. There isan unfortunate ( bad )habit among engineers of referring tothese compounds as gas hydrates. This leaves the

impression that they form only w ith gases.

MixturesAlthough the behavior of pure formers is interesting,in industrial practice we usually deal with mixtures. What type

of hydrate is formed in a mixture? What is the effect when anon-former is in the mixture? We have already encounteredone interesting situation that arises with the behavior of n-butane.

The hydrate formation conditions in mixtures of ethane, aType I former, and propane, a Type II former. Theydeveloped a map (reproduced here as next Figure), showingwhich regions each type of hydrate would form . As anapproximation of their results, if the mixture is greater than

,

II. When the hydrate is Type I, the propane does not enterthe crystal lattice; only the ethane does.

On the other hand, mixtures ofmethane, a Type I former, andpropane, a Type II former, almost always form a Type II.


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Volume of Gas in Hydrate

The purpose of this section is to demonstrate the volume ofgas encaged in a hydrate. Therefore, we examine only themethane hydrate.

The properties of the methane hydrate at 0oC: arethe density is 913 kg/m3, the molar mass (molecularweight) is 17.74 kg / kmol, and methane concentration is14.1 mole percent; this means there are 141 molecules ofmethane per 859 molecules of waterin the methane hydrate.

s n orma on can e use o e erm ne e vo ume o gasin the methane hydrate. From the density, I m3 of hydrate hasa mass of 913 kg. Converting this to moles 913/17.74 = 51.45kmol of hydrate, of which 7.257 kmol are methane as follow( 51.45 * 14.1% = 7.257 k mole).


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The ideal gas law can be used to calculate the volume of gaswhen expanded to standard conditions (15C and 1 atm or101.325kPa).

Therefore Im3 of hydrate contains about 170 Sm3 ofmethane gas.

American Engineering Units, this converts to l ft3 of hydratecontains 170 SCF of gas

To look at this another way, to store 25,000 Sm3 (0.88

mmscf ) of methane requires about 150 m3 (5,300 ft3) ofhydrates

So these days it is under studies to use the hydrate for

gas transportation

From this table it can be seen that water has a fairly large enthalpyof vaporization , even in comparison to other polar substances. Ittakes significantly more energy to boil 1 kg of water than it does to

boil any of the hydrocarbons listed in the table about 5 times


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GAS HYDRATES AND HYDRATE CONTROL

Gas hydrates are rather complicated compounds ofhydrocarbons, waterand other substances such ashydrogen sulfide or carbon dioxide which form granularsolids, very similar to ice, under certain conditions of

temperature and pressure.

There is some doubt whether hydrates can form if the wateris mixed with liquid hydrocarbons, however, it should berealized that :-

If Water Is Present in the liquids, it very probably will also bepresent in the gaseous phase through the equilibriumconditions which will be reached in any stage of pipelinesystem.

Individual components alone, or mixtures of the lightercomponents of natural gas, will form hydrates over a widerange of temperatures, depending upon the system pressure.These temperatures are considerably above the normalfreezing point of waterand may go higher.

The effect of heavier components is to increase thetemperature at which hydrates will form for any given pressure,Normal-ly, hydrates of components heavier than butane arenot considered to occur.

In all cases, free water in the system is required to formhydrates.

The presence of hydrogen sulphide greatly increases thetemperature at which hydrates will form. Sour gases may havehydrate temperatures into the 90F temperature range underhigh pressures.


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End of hydrate

WATER DEW POINT

If it is said that the gas is water saturated at specificpressure and temperature, that means it hold the maxcarrying capacity and so any additional water added atthe saturation point will not vaporize , but will fall out asfree liquid.

Also at this point , if the pressure is increased and / orthe temperature decreased the capacity of the gas tohold water will decrease and some water vapor willcondense (drop out).

be defined as the temperature at which the natural gas issaturated with water vapor at a given pressure.

At the dew point, natural gas is in equilibrium withliquid water.


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DEW POINT DEPRESSION

The difference between the dew point temperature of water insaturated gas stream and the stream after it has beendehydrated is known as the dew point depression .

To illustrate the concept of dew point depression, suppose thatthe natural gas at 500 psia, and 60 F , at the saturation pointcontains 30 Ibm of water per million cubic feet.The dew point of this gas is 60F.

Suppose this natural gas is going to be transported in pipeline .

The original 30 Ibm of water, if left in the gas, will exist in thefrom of 7 Ibm of water vapor and 23 Ibm of free water permmscf, if the pressure remains the same.

This free water is a potential source of hydrates to form and

plug the line .

Suppose the natural gas is processed in a dehydration unitand the dew oint is de ressed 50 F .

This means that no free water will exist in the gas until thetemperature goes to 10 F or lower.

Gas at 500 psia and 10 F contains about 5 Ibm of watervapor mmsc .

The dehydration unit must remove 25 Ibm of water from each1 million scf of gas in order to achieve the 50 F dew pointdepression.


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Gas dehydration techniques

Techniques for dehydrating natural gas include:-

Absorption using liquid desiccants.

Adsor tion usin solid desiccants.

Mechanical Refrigeration.

Expansion Refrigeration.

Water can removed from gas by:-

Compression.

oo ng.

But removing the water with these two methods will leavethe gas stream saturated with water vapor so extra dropin temp. or increase in pressure will cause watercondensation.

Absorption Process

The more common liquids in use for gas dehydrating areMonoethylene glycol, diethylene glycol, triethyleneglycol and tetraethylene glycol.

Monoethylene and Diethylene glycol usually used inglycol injection system.

Most glycol dehydrators use triethylene glycol, whichcan be heated to about 400 F.

Tetraethylene glycol is more expensive, but it canhandle hotter gas near 50o C without high losses and itcan be heated up to 460F.


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Choice of Glycol

GLYCOL:

CHEMICAL NAME B.P Thermal decomposition

EHYLENE GLYCOL (MEG). 197.6 C >165 C

DIETHYLENE GLYCOL (DEG). 246.0 C > 165 C

TRIETHYLENE GLYCOL (TEG). 278.0 C > 206 C

TETRAEHYLENE GLYCOL(TREG). 300.0 C > 250 C


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TEG has gained almost universal acceptance as

the most cost effective choice because:

TEG is more easily regenerated.

TEG has a higher decomposition temperature of 460 F

Vaporization losses are lower than EG or DEG

TEG is not too viscous above 70 F.

TEG dew point depressions range from 40 150o F

As the lean Glycol temperature decreased its absorption

capacity increased & also its tendency to flash decreased

normal operating temp. of TEG is between 25 & 48o C

TEGTriethylene glycol (TEG) is a member of a homologousseries of di-hydroxy alcohols.It is a colorless, odorless ,stable liquid with lowv scos es an g o ng po n s.

Properties

Molecular formula C6H14O4Molar mass 150.17 g mol1

qu ens y . gBoiling point 285o C

pour point -58o C


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DRY GAS

DRY GLYCOL

difference in boiling point?

Water boils at 212o F.

o

Dehydration basic process

WATER

VAPOUR

DEHYDRATION

.

HEAT

WET

GLYCOLWET

GAS

Basic components of a glycol unit

Contactor tower .

Glycol pumps.

Reflux condenser ( still column ).

Glycol / glycol low temp. Exchanger.

Flash drum.

Sock filter.

arcoa er.

Glycol / glycol high temp. Exchanger

Re-boiler & surge vessel.

Gas / lean glycol exchanger.


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Flow Diagram for Glycol System


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Contactor towers:-

As it is appears f rom the name lean glycolcontact the wet gas at the contactors towers.

Towers usually contains internal or externalscrubberand mist extractor at the top.

Towers may be packed tower or trays , the trayed towers have many models of trays

bubble cap , valve trays or molecular sieve themost common used is the bubble cap trays.

Dry gas lean glycol heat exchanger

.

It is the most widely used because it is not weep at lowgas rate, and dont drain the tray even during the unitshut down.

See the video describing different trays operations

Inlet scrubber is an essential part of the glycol:-

Free water will increase glycol f low rate, increasere-boiler heat duty, overload the unit

Heavy hydrocarbons tends to form emulsion withglycol, it can plug the absorber trays, it may Coked onthe heat transfer surfaces which decrease the heattransfer efficiency and cause hot spots With the firetube

e we pore own o e a ves, corros on

inhibitor ,acidizing, fluids could cause foaming. Solids may cause corrosion, plug the pump, trays,

packing, and enhance the foaming formation.


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Gas / glycol heat exchanger, or glycol air cooler upstream the contactor must working properly where ifthe glycol entering the contact with high temp., thiswill leads to

High water vapor pressure which decrease thedrying efficiency also

High lean glycol temperature will leads to switchingthe top tray to act as heat exchanger and

.

Cooling of the glycol stream before entering thecontactor will Increase its absorption capacity, whereits capacity decrease as its temperature close to 120 o F

MIST

EXTRACTOR AT

THE TOP

DRY GAS

DRY GLYCOL WEAR

DOWN COMER

WET GLYCOL


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DRY GAS

Glycol mist extractor

MIST

EXTRACTOR


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Flash separator: -

Usually glycol absorb 1 scf gas / gal circulation rateat 1000 psig &100o F

reduce the glycol viscosity and improve theseparation.

Flash drum pressure should be adjusted to minimum3 bars to achieve the following:-

1-Insure sufficient pressure for glycol circulation.

2-Prevent BTEX evaporation from glycol.BTEX is an acronym for benzene, toluene, ethylbenzene, and xylene.

3-It is a suitable gas pressure if the gas used as a fuel.


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Flash tankTypes of flash tanks.

3phase vessel.

What is flashing?

What is the pressure change?GAS VAPOUR

.

Inter phase level control.

Process problems.

GLYCOL

FROM

HEAT EXCHANGER

GLYCOLHYDROCARBON

Filters setPurposes:-

Prevent pump wear, plugging of heat exchangers,foamin foulin of contactor tra s cell corrosion andhot spots on the fire tubes.

Operating Parameters:-

Keep solids below 100 ppm Sock filter designed to remove 5 micron and larger

particles Sock filters are designed for an initial pressure loss of3 to 6 psi and change out at 15 to 25 psi.

Activated charcoal filters used to remove condensate,surfactants and treating chemicals.


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degradation

1. A TEG tested by expose for air for 1 week

2. In less than a week in dry air at 70oC ONLY 30 % ofthe TEG remains

3. The degradation products found to some degree

4. It found that TEG is stable in the nitrogenenvironment

Re-boilerPurpose:-

Provides heat necessary to boil the water out of the rich orwet glycol.

Operating Parameters:-

Direct fired heaters often used onshore. Indirect heating often used offshore. TEG does not undergo thermal decomposition if

temperature is kept below 400 F. U-sha ed fire tube should be sized for 7000 Btu/hr-ft2.

Water comes off as steam.To check the hot spots of the fire tube, it must be checkedduring the night , and then you must shut off The Flame, so thehot spot will stay bright ,Hot spot may be due to depositsaccumulation around the fire tube as heavy hydrocarbon, salt,solids coked off


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Glycol re-boiler

REFLUX COIL

Water Vapour

And Stripping gas

Reflux condenser

Reflux condenser by pass

GLYCOLINLET

FUEL

REGENERATED GLYCOL

Still column packing

RE-BOILER

Stripping Gas

GLYCOL RE-BOILER.

REFLUX COIL

STEAM

STILLCOLUMN

Glycol inlet

FUEL

REGENERATED

GLYCOL

RE-BOILER

FIRE TUBE

Good flam specifications: - Laminar, long, rolling, with yellow tip


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Table4.2FlameColorsandTemperature(F)RangesFlameColor Temperature FlameColor Temperature

Lightred 900 1000 Salmon 16001700Darkred 10001100 Orange 17001800Darkcherry 11001200 Lemon 18001900MediumcherryLight 12001300 yellow 19002100Lightcherry 13001400 White 21502250Brightred 14001500 Brightwhite 2500andover

Note: Overall the lighter the color of the flame, the higher the

temperature. The significance of the color of smoke and flames in afire should be considered with the time at which they were observed.


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Fire Suppression

Combustion ends when one of the four faces of the firetetrahedron (fuel , oxygen, heat, chemical chain reaction)is removed.

1. Fuel Combustion ends either when the fuel is

consumed or when the source of fuel is removed .

2. Oxygen Combustion ends when the oxygen leveldrops below that needed to maintain it (normally 15%).

extinguish (smother) the fire by cutting off the oxygensupply. Remember that oxygen is not a fuel, and neitherburns nor explodes. It merely suppor ts oxidativecombustion.

Fire Suppression

3. Heat Water is the most commonly used extinguishing

agent. It is used because of its great heat-absorbing.

fuel to a point below its ignition temperature.

4. Chemical chain reaction When the oxidation reaction

is chemically inhibited, the fire is extinguished. Certainextinguishing agents (Halon, carbon tetrachloride,

, .

radicals freed during the process of combustion to formnew molecules. This chemical action preventstransfer of heat energy, and the fire is extinguished.


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Flow Diagram for TEG Dehydration

Design Factor Affecting The Glycol Performance

Inlet gas temperature must be between 80o F to110o F& not excess 120o F, reduce the gas temperature aspossible to recover max water & heavy components

Lean glycol temperature exceed gas temperature withabout ( 7 10o F ).

Contactor pressure has a little effect on theperformance as the pressure remains less than 3000psig. (preferred to operate at pressure between 500 to

.

Contact time which is determined by the No. of trays,or height of packing.

Glycol concentration preferred to be max as possible.


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Design Factor Affecting The Glycol Performance

Glycol concentration has an effect more than theglycol circulation rate (Pump & re-boiler load).

Glycol re-boiler temp. Between 370o F & 390o F to.

Glycol re-boiler pressure must be atmosphere orless ( vacuum ) if required.

Glycol circulation rate @ fixed no of trays & glycolconcentration as the circulation rate increased thedew point depression also increased ( 2 4 galglycol / lb water removed ).

Glycol Ph must be kept between 6.8 up to 7.5 whereas the PH of the glycol decreased the absorptionefficiency of the glycol decreased & as the PHincrease the glycol tendency to foaming increased.

Glycol unit design considerations details:-

Most TEG units are designed to operate between 80o

Fto 110o F.

1- Inlet gas temp.

Must be as minimum as possible where at highpressures (above 1000 psi) only 20o F could duplicatethe water content , using the water content chart.

Max temp < 120 o F (48 o C)

> o. .

Where from 60o F to 70o F glycol can form a stableemulsion with liquid hydrocarbon & cause foaming inthe contactorand also below 60o F glycol becomevery viscous & could not be pumped.


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2-Contactor pressure:-

Contactor pressure has a little affect on absorptionprocess as long as the pressure is below 3000 psig

Usually typical dehydration pressures range is from500 to 1200 psig.

3-Number of contactor tray

depression increase and also the effect of the No.of trays is greater than the glycol circulation rate.Usually from 6 to 8 trays are common designed for

7 lb /mmscf water content (may be 10 -12 trays).

4- Lean glycol temp:-

Must be hotter than the gas inlet temperature withabout 10o F to 15o F.

- yco oncen ra on:-

The glycol concentration has a great effect in the dewpoint depression, as the concentration increased thewater content decreased

usually glycol & gas may reaches to equilibrium temp.Inside the contactor this based on:-

Contact temperature.

Glycol concentration.


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6-Glycol re-boiler temperature:-

Typical re-boiler temp. between 370o F to 390o F if stillextra glycol concentration required and could not achieved

by all the operational control factors the stripping gas must

be used.

It is not preferred exceed the re-boiler temperature over 400 o F

avoid the glycol degradation.

7-Reboiler pressure:-

As the pressure decreased below atmosphere the higher glycol

concentration may be achieved so in some cases (rarely) re-

boiler operated at vacuum , the main reason of the rarely

usage of the vacuum pump is that any minor air leak will

cause glycol degradation (oxidation of glycol)

8-Stripping gas:-

Improve the glycol concentration instead of increasing the re-

boiler temperature or glycol flow rate.

9-Glycol circulation rate:-

Usually 2-4 gal. glycol / lb water removed excessive glycol flow

rate may over load the re-boiler, so the high glycol rate may

decrease the re-boiler temp , which will leads to a drop in the

,

of water removed , and increase the dry gas dew pointOnly when the re-boiler temperature is constant the

increase in glycol circulation rate will decrease the dew point.


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10- Still column temp:-

Must be adjusted to max 212O

F where at 250O

F orabove some glycol will be carried out with the watervapor , and so glycol loss will occurred, Heat transfer

. .condenser coil.

Also the Heat transfer factor U can be near to 10 - 12BTU/hr.ft2.oF for lean glycol / rich glycol exchanger,and 45 BTU/hr.ft2.oF for dry gas / lean glycol.

Foaming may be mechanical or chemical foam:-

Mechanical foam, caused by high gas flow rate in the absorber

where chemical foam, may caused by any contaminates such as

salt, solid corrosion inhibitor and / or condensate.

Inlet scrubber is an essential part of the glycol:-

Free water will increase glycol flow rate, increase re-boiler heat duty, overload the unit

Heavy hydrocarbons tends to form emulsion withglycol, it can plug the absorber trays, it may Coked on

the heat transfer surfaces which decrease the heat

transfer efficiency and cause hot spots on the fire tube.

At the well head down hole additives, corrosioninhibitor ,acidizing, fluids could cause foaming.

Solids may cause corrosion, plug the pump, trays,packing, and enhance the foaming formation.


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Contact temperature.

usually the actual dry gas dew point be 5 to 10o

F higherthan the equilibrium

Common rule dew point depression is 60o F for the firstfour trays plus 7o F for each additional tray

For 10 trays = 60 + (7x 6) =102o F dew point depression

If the inlet dew point is 110o F so the outlet dew point is 8o F

The dew point depression will depend on the number ofachieved equilibrium stages with the glycol circulation

rate and concentration; it usually assumed that each traymay achieve 25 % from each equilibrium stage.

( 25% of glycol mixes with gas ) each 4 trays gives onlyone equilibr ium stage

Design considerations

Glycol flash drum:-

-

Height (ft) = 3.4 +0.4 GPM ( gallon glycol per minute)

Min height = 4 ft

Min diameter = 1.5 ft


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Design considerations

Glycol flash drum:-

- or zon a separa or

Length to diameter ratio = 3

Min length = 3 ft

Min diameter = 2 ft

Still column:-

Diameter (inch) = 9 x (glycol circulation rate gpm) 0.5

And typical packing height at least 4 ft may be increased to 8

ft for hi h dut units.

Re-boiler :-

Re-boiler duty can be estimated as:

Q = 900 + 966 m

Q : BTU/ lb water removed

m :- ga g yco or eac wa er remove .

Re-boiler (length / diameter) ratio = 5

Min diameter = 1.5 ft

Min length = 3.5 ft


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PH control , must be add slowly and as 1 lb

Amine for each 400 gallon glycol

case where the source of the PH drop may bedifferent from place to place and the correctiveaction of the Amine will different based on the PHdrop root causes if it is CO2 , H2S , glycoloxidization etc .

Recommended glycol unit operating temperature

Inlet gas 80 100o F

o

Glycol to flash drum 100 -150 (preferred to be 150o F)

Glycol into filters 100 150 (preferred to be 150o F)

Glycol to still column 300 -350o F

Top of the still column max 212o F

Re-boiler 380 400 ( preferred to be 380o F) Glycol to pumps < 250o F (preferred to be 180o F)


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Question: Find the moisture content of a gas at 20,000 kPa and 70 deg.

C. if it is made up of 35 mole % H2S and 10 mole % CO2.

1) Find moisture content of sweet gas in Fig. 15-14 = _____ mg/m3(note: psia conversion from kPa) (Psia = 0.145 kPa)

2) Find moisture content of CO2 in Fig. 15-21 = _____ mg/m3

3) Find moisture content of H2S in Fig. 15-22 = _____ mg/m3

4) Find total moisture content in gas:Total moisture content = sum of ( individual moisture content times mole

frac).Therefore moisture content = 0.55 ( ______) + 0.10 ( ______ ) +

0.35 ( ______ ) =________ mg/m3 waterat standard conditions


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GLYCOL INJECTION

WET GAS

HEAT EXCHANGER

GLYCOL

DRY GAS & WET GLYCOLFLUSHING VALVEDELTA PRESSURE

GAUGE

PH

Controlling pH is very important in most of the processesthe following is offered to assist in understanding electrolytesolutions and PH.

An electrolyte is a substance or material that will provideionic conductivity when dissolved in water.

Both bases and acids, if they ionize in water, can beelectrolytes.

In water, acids ionize or split, into H+ and the cation

The H+ combines with a water molecule to form H3O+which is usually written as H+ and is referred to as ahydrogen ion, or proton.


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Water soluble bases, on the other hand, ionize in

water to produce hydroxyl or OH ions and an anion.

Pure water ionizes such that the concentration of H +(and OH ) in the solution is 10 7 gram ions / liter.

The method used for measuring hydrogen andhydroxyl ion concentrations uses pH (from the Frenchpouvoir hydrogene), where the pH of a solution is thelo arithm base 10 of the rec i rocal of the h dro enion concentration (gram mole / liter).

For pure water, then, the pH would be:

PH = log (1/ [H+]) = 7

completely in water solution. Typical are HCl orNaOH.

At an acid concentration of 0.1 mole / liter, the pH ofa stron acid will be 1 as follows

PH = log (1/ [H+]) = log ( 1 / 0.1 ) = log ( 1 / 10 -1)

# PH = log10 101 = 1 ( very strong acid )


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pH Control


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pHConcentration, mole/liter

H+ OH-

1 1.0*10-1 1.0*10-13

2 1.0*10-2 1.0*10-12

3 1.0*10-3 1.0*10-11

4 1.0*10-4 1.0*10-10

AcidSide(ExcessH+)

5 1.0*10-5 1.0*10-9

6 1.0*10-6 1.0*10-8

7 1.0*10-7 1.0*10-7

8 1.0*10-8 1.0*10-6

9 1.0*10-9 1.0*10-5

10 1.0*10-10 1.0*10-4

NeutralSolution

11 1.0*10-11 1.0*10-3

12 1.0*10-12 1.0*10-2

13 1.0*10-13 1.0*10-1BasicSide

Examinationofthetableleadsonetotheconclusionthatweakelectrolytes(thesetowhichtheconceptofpHcanbeusefullyapplied)rangeoverstrongacid(base)concentrationsupto0.1grammole/liter

First, consider the exposure of i ron to aerated water at roomtemperature (aerated water will contain dissolved oxygen).

The corrosion rate for iron as a function of pH is illustrated inFigure 7.

In the range of pH 4 to pH 10 the corrosion rate of iron isrelatively independent of the pH of the solution.

In this pH range, the corrosion rate is governed largely byThe rate at which oxygen reacts with absorbed atomichydrogen thereby depolarizing the surface and allowingthe reduction reaction to continue.

For pH values below 4.0, ferrous oxide (FeO) is soluble.,Thus, the oxide dissolves as it is formed rather thandepositing on the metal surface to form a film.


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In the absence of the protective oxide film, the metal surfaceis in di rect contact with the acid solution, and the corrosion

reaction proceeds at a greater rate than it does at higher pHvalues.

solut ions below a pH of 4, indicating that the corrosion rate

no longer depends entirely on depolarization by oxygen,but on a combination of the two factors

(hydrogen evolution and depolarization).

,observed to fall as pH is increased. This is believed to be dueto an increase in the rate of the reaction of oxygen with

Fe(OH) (hydrated Fe O) in the oxide layer to form the more

protective Fe O

Effect of Ph on the corrosion of iron exposed to aerated waterat room temperature


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A plot of the relative corrosion rate for Iron at various pH

values in 59o F

05-Gas Dehydration by GLYCOL 81

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