gas dehydration.pdf

POLPetroleum Open Learning

OPITO

THE OIL & GAS ACADEMY

Gas DehydrationPart of the

Petroleum Processing Technology Series

Petroleum Open Learning

Designed, Produced and Published by OPITO Ltd., Petroleum Open Learning, Minerva House, Bruntland Road, Portlethen, Aberdeen AB12 4QL

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OPITO 1993 (rev.2002) ISBN 1 872041 85 X

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Visual Cues training targets for you to

achieve by the end of the unit

test yourself questions to see how much you understand

check yourself answers to let you see if you have been thinking along the right lines

activities for you to apply your new knowledge

summaries for you to recap on the major steps in your progress

Gas Dehydration(Part of the Petroleum Processing Technology Series)


Contents Page* Training Targets 2

* Introduction 3

* Section 1 - Water in Natural Gas 4 QuantityofWaterinGas ProblemsofWaterinGas HydratePrevention

* Section 2 - Auto Refrigeration 25 TheJoules/ThompsonEffect TheLowTemperatureSeparation(LTS)System TheLowTemperatureExtraction(LTX)System

* Section 3 - Solid Desiccant Dehydration 40 Adsorption SolidDesiccantDehydrationPlant

* Section 4 - Liquid Desiccant Dehydration 46 LiquidDesiccants GlycolDehydrationPlant

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Training TargetsThe aim of this unit is to help you understand :

the capacity of natural gas to hold water the problems which result from the presence of water in gas the methods used to reduce the water content of natural gas

Upon completion of the unit you should be able to:

Quantify the amount of water in saturated natural gas under given conditions. q List the problems associated with water in gas. q Define the conditions that contribute toward hydrate formation. q Describe Joules/Thompson Effect. q Explain the Auto Refrigeration process. q Define Adsorption and Absorbtion. q Detail a simple two-tower desiccant dehydration process. q Describe a basic glycol dehydration plant. q List and explain operational variables in the glycol dehydration process. q

Tick the box when you have met each target.

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Natural gas can be referred to as Associated Gas or Non-associated Gas. The former is produced togetherwith liquids from an oil reservoir and is liberated from the liquids at the surface. The latter is producedindependently of an oil accumulation, from what is commonly called a gas reservoir.

Irrespective of whether the gas is associated or non-associated, it invariably contains water in the form of a vapouror a liquid.

Surface equipment is used to remove the water from the gas. This process is called dehydration, which is thesubject of the present unit.

The unit comprises 4 Sections :

Section 1, Water in Natural Gas, looks at the amount of water which can be held in gas and discusses the problems that the water creates. In this section we will also look at options preventing hydrate formation.

Section 1 will be followed by 3 further sections which deal with process systems used to remove water from gas.

Section 2, Auto Refrigeration, describes how water is removed by reducing the gas temperature.

In Section 3, Solid Desiccant Dehydration, you will look at theory of adsorption, and how it is applied to water removal.

Finally, in Section 4, Liquid Desiccant Dehydration, we will look at how liquid desiccants work and see how glycol is used in a typical dehydration plant.

You should be aware that the water removal processes described in Sections 2,3 & 4, are applicable to bothassociated and non-associated gas treatment facilities. The actual process chosen for a particular applicationdepends on a number of factors. These include, location of plant, gas characteristics and so on.

Gas DehydrationIntroduction

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Natural gas contains water, but how much? In thissection we will look at how we can specifyamount of water contained the gas. We willalso review the problems that water in gas cancause, and look at inhibiting one of the problems,that of hydrate formation.

Quantity of Water in GasHydrocarbons contained in oil and gas reservoirsusually are, or have been, in close contact withformation water. Any gas is normally, therefore,very wet, at the reservoir temperature and pressureconditions. Up to a certain point, the water beheld in the gas in the form of vapour. Beyond thatpoint the water will appear as liquid. However,terms such as very wet are not very scientific, nordo they provide us with any indication of the actualwater content

In order to rectify this, I have listed below threeterms which are used to describe the three mainstates of wet gas :

Unsaturated. In this state the gas is in a condition where it is able to hold additional water in the form of vapour.

Saturated. This is a state in which the gas contains the maximum amount of water it can hold in vapour form.

Over-Saturated. In an over-saturated state the gas contains water in excess of the amount it can in its saturated state. The excess water will exist as free liquid.

There are a number of factors that can affectamount of water vapour that may be present in gas.

These include:

gas composition and gravity

temperature

pressure

the amount of water with which the gas been in contact.

The composition of natural gas varies, because theproportions of its constituents will vary from tofield.

Gas DehydrationSection 1 - Water in Natural Gas

The main constituents are the following hydrocarbongases:

Methane

Ethane

Propane

Butane

Pentanes

The list is longer, but the amounts of otherhydrocarbons present are usually small.

The gases are listed above, starting the lightestat the top. They get heavier, or denser, as you movedown the list.

Density gas is usually expressed as the weight inpounds per cubic foot at standard conditions oftemperature and pressure.

4


Specific gravity is the more commonly usedmeasure of density. It is the ratio of a gas densityto the density of air at the same conditions oftemperature and pressure.

As I said a little earlier, the percentage compositionof different natural gases varies. Methane is usuallythe most abundant component, and is the principalsource of energy in our mains gas supply. As youmove down the list you undoubtedly recognisepropane and butane, which commonly appear asbottled liquid gas.

Natural gas also contains impurities such ashydrogen sulphide (H2S), carbon dioxide (C02) ,non-combustible gases and water vapour. Howeverwe are going to be concentrating on the watercontent.

For the purposes analysing water content, it issafe to consider natural gas as having a fixedcomposition. To further lighten our immediate task,we will initially be looking at the amount of waterneeded to render the gas saturated.

The actual amount of water required to saturategas will depend on the pressure and temperaturethe gas. This can be represented in the form of asimple graph as shown in Figure 1. Lets see howthis figure can be used in practice. Take a look atFigure 1.

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The curve illustrated on the graph is the saturationcurve for natural gas at 1 000 psi. For varying gastemperatures in degrees Fahrenheit, it illustrateshow much water in pounds per standardcubic feet (mmscf) is needed to saturate the gas at1 000 psi.

To use the graph, select your temperature on thehorizontal axis, move vertically to intersect thecurve, and then horizontally to find the amount ofwater vapour needed for saturation.

Take an example:

Question:

What is the water content of 1 000 psi natural gas atsaturation, assuming a temperature of 70 deg F?To find the answer follow the steps listed below.

find 70 deg F on lower axis

follow this line up until it intersects the curve

now move horizontally and read off the figure on the vertical axis.

Answer:

You can see from the point where the horizontal lineintersects the vertical axis, that 24 lbs of water arerequired to saturate one cubic feet of gas at70 deg F and 1 000 psi. Or, in abbreviated form 24Ibs of water per mmscf.

Figure 1 gave us the saturation curve for just onepressure. If the curves for other pressures areillustrated in a similar fashion, the graph as shown inFigure 2 will be the result.

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As you can see, the different pressure curves arealmost parallel, which makes it fairly easy toestimate for intermediate pressures.

Lets use Figure 2 :

Take a reservoir pressure of 3 000 psi and atemperature of 150 deg F. Using the methoddescribed earlier, you can see that gas under theseconditions will have a saturated water content of94 Ibs per mmscf of gas.

As I said earlier, up to the saturation point, the waterin the gas will be in the form of vapour. For thepurposes of this unit, we can consider the watervapour as being similar in behaviour to a gas.

Now take the same reservoir pressure of 3 000 psias in the previous example, but a temperature of120 deg F. Look at the graph in Figure 2 again.This time you will see that only 48lbs of water, inthe form of water vapour, is required to saturateevery mmscf of gas at these conditions.

From the two examples I have just given, you cansee that gas at the higher temperature of 150 deg Fis capable of holding 46 lbs per mrnsct more watervapour than if its temperature was 120 deg F.

This means that, if the temperature of the gas in theabove example were lowered from 150 deg F to120 deg F at a constant pressure, 46 Ibs (94 - 48)water per mmscf would condense and appear asfree water.

From the above, a useful fact emerges - one thatwe will remember and use throughout this unit:

As the temperature drops, the water vapour required to saturate a given volume of gas decreases

Or, in other words:

When the temperature of water-saturated gas is lowered, water vapour condenses to produce free water.

Now have a go at the following Test Yourselfquestion. It should help you to understand what wehave covered up to now.

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Test Yourself 1 Assume that gas from the reservoir indicated above (3 000 psi, 120 deg F) is produced up a well to the surface. At the surface the pressure has dropped to 1 500 psi and the temperature to 100 deg F. Now answer the following:

a) What water content in lbs/mmscf is required to achieve saturation of the gas at the surface?

b) Will the change in conditions from reservoir to surface result in the gas being unsaturated at that point, or free water be present?

If free water is present, how many pounds will there be for every mmscf of gas?

You will find the answers in Check Yourself 1 on page 59

Problems with Water in GasAs gas flows through the reservoir and into the wellbore, it usually becomes saturated with water. Inaddition, it picks up free water along the way.

This is a very important fact regarding natural gas.Let me just repeat it :

Gas produced to the surface is, in most cases,saturated with water vapour and is likely to betransporting free water.

As you may gather from the heading, water in gasis, for most of the time, bad news! Water in gasgives rise to various problems. Let me now list andbriefly discuss the more important ones.

These are:

liquid accumulation in the wellbore

corrosion

pipeline efficiency

gas quality

hydrate formation

lets look at each of these problems in turn.

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Liquid Accumulation in the WellboreThis usually occurs in lower pressure, low flow rate gaswells. Liquids, of which free water is one, start to build upin the bottom of the wellbore when the flowing velocity istoo low to lift the liquid to the surface. The wellbore actsas a separator and the gas bubbles through the liquid.

The liquid column building up in the well causes anincreasing back-pressure to be exerted on the reservoir.This further reduces the flow rate and thus the velocity ofthe well fluids. The process can continue until eventuallythe well dies ( ceases to flow) or only flows intermittently.The deteriorating situation is illustrated in the left handsketch in Figure 3.

The normal method for avoiding this problem is to ensurethat the flow velocity is maintained at a level high enoughto prevent fall-back of liquid droplets. The simplest way ofaccomplishing this is to increase the flow rate. This is notalways possible, particularly if the well has naturallydeclined in performance. Another way of increasing flowvelocity is to install smaller bore production tubing closerto the perforations. This means that the same amount ofgas has to flow through a smaller cross-sectional area oftubing. To do this, it must flow more quickly.

This is illustrated in the right hand sketch of Figure 3

There are other techniques which can be used to removeliquids from the wellbore. However, these are beyond thescope of this programme and we will not discuss themhere.

11


CorrosionCorrosion is the next problem on our list. In naturalgas systems, corrosion carbon steel occurs whenfree water forms in the presence of carbon dioxide(C02) or hydrogen sulphide (H2S). You willremember that these two substances are impuritieswhich may be found in natural gas.

Carbon dioxide and water together to formcarbonic acid which then reacts with an exposedsteel surface. The reaction causes chemicalsubstances to form which are called corrosionproducts.

(The most common corrosion product in everydaylife is, of course, rust, which forms on iron or steelexposed to the air).

These corrosion products are removed by theforce of the flowing gas stream, exposing freshmetal for further attack. This action results in metalloss and, therefore, corrosion pitting. The rate ofmetal loss, called the corrosion rate, depends onmany factors, but principally on the amount ofcarbon dioxide and free water present. Corrosionrate also increases dramatically with increase intemperature.

Hydrogen sulphide has a similar action, causingmetal loss and pitting when free water is available.This particularly applies if carbon dioxide-relatedcorrosion is also present - they appear toencourage each other!

Protection against carbon dioxide and hydrogensulphide corrosion attack is provided by:

choice of corrosion-resistant materials (such as stainless steel)

use of protective coatings

application of corrosion inhibitors (chemicals with special protective properties)

These options may be used singly or incombination. The choice will be based on bothtechnical and economic factors.

Pipeline Efficiency

Natural gas is usually transported by pipelines, andwater in gas pipelines causes our next problem.

The presence of free water in a gas pipeline cangive rise to the complication of two-phase flow. Bytwo-phase flow we mean that gas and liquid (say,water) are flowing in the line together. (Gas is onephase, and liquid is the other).

Free water can occupy quite a lot of the pipeline volume.This will reduce the amount of pipelinecross sectional area available for gas flow, resultingin increased gas flow velocity. The severity of thiseffect will depend on a number of factors:

length of pipeline

flow velocity

undulations in the line

the volume of liquid

Figure 4a illustrates the effect.

Build up of liquid may continue until the critical pointat which liquid slugs are formed.

This is shown in Figure 4b.

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Figure 4 a: Liquid Build Up in a Gas Pipeline

Liquid levels can build up in a pipeline, particularly at low spots. This continue until a critical point isreached. At this point the available flow area is insufficient for the gas flow rate. This results in anintermittent plug or slug flow which will break the continuity of gas supply at the pipeline destination.

Figure 4 b: Illustration of a Slug Flow in a Pipeline

Usually this is not considered a desirable situation. For example, if the gas is feeding a gas compressor,this can be seriously damaged by water slugs.

13


Gas Quality The influence on quality is the most self evident,and undesirable, effect of water in gas. Gas isusually burnt as a fuel and water is used to put firesout - hardly compatible qualities!

For the end-user of gas, and for those who transportit, the quality is strictly specified, especially asregards water content.

The water content specification is usually called thewater dewpoint (in order to distinguish it from thehydrocarbon dewpoint, which is a separate aspectof the gas quality specification). Let us have a lookat what this means.

As we have seen earlier, when the temperature ofsaturated gas is decreased, some of the watervapour condenses and appears as free water. Putanother way - the lower the temperature the lesswater vapour it takes to saturate a given volume ofgas. Bearing this in mind, the water dewpoint ofgas is defined as :

The temperature at which natural gas at anyspecified pressure is saturated by the watervapour it contains.

The quality specification for a natural gas will definea water dewpoint so that:

water vapour will not condense as free water under any foreseeable conditions.

HydratesAs you will see, we have left the most important effect until last!

Hydrates are solids that form as snow like crystals.They are created by a chemical reaction betweennatural gas and free water. Once formed, hydratecrystals can pack together in gas processing plant,partially or completely blocking flow lines oraccessories such as valves. The blockages willtend to occur at turbulent regions such as pipebends or changes of diameter.

One particular danger of hydrate deposits ariseswhen they form a blockage downstream of apipework pressure rating change, for example inflare or vent pipework. This may subject the lowerrated pipework to dangerous over pressures.

Figure 5 shows the general effect.

14


Figure 5 : Shows a possible effect of a hydrate blockage

Hydrates can occur at temperatures considerablyabove the freezing point of water. At a givenpressure and in the presence of free water, hydrateswill form when the temperature of the gas is at orbelow a certain level. Understandably, this is calledthe hydrate temperature.

Now a short exercise:

Test Yourself 2

The hydrate temperature must be below, the same as, but never above the dewpoint temperature. Why is this?

You will find the answer in Check Yourself 2 on page 59

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Take a look at Figure 6. This graph shows thepressure and temperature conditions needed forhydrate formation, when a typical natural gas is incontact with free water.

The example given on the graph shows howhydrates form in gas 400 psi when thetemperature drops to 50 deg F.

Hydrate formation conditions can be showngraphically in a slightly different way. Have a look atFigure 7. You will probably recognise this graph asbeing very similar to Figure 2. However, this time,superimposed on the various pressure curves is ahydrate temperature line. For each pressure, itindicates a temperature below which hydrates willform in the presence of free water.

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Test Yourself 3

Using Figure 7, read off the temperature below which hydrates will form in natural gas at 1 500 psi, in the presence of free water.

Check your answer in Check Yourself 3 on page 59

As I said earlier, hydrates are undesirable in gasprocessing as they can, in certain circumstances,disrupt the normal degree of control that we shouldhave over a process.

As the problem of hydrates is so important, let melist for you once more the conditions which couldlead to their formation :

gas, with free water present

temperature and pressure conditions within the hydrate formation region

Have a go at Test Yourself 4.

18


Now you can work through an example :

Test Yourself 4

a. We have looked at some problems caused water in natural gas. Which of these will affect our attempts at processing the gas.

b. By reference Figure 7, indicate whether you think that gases at the following conditions are in the hydrate formation regions (Yes) or not (No).

Yes No i) 1 500 psi, 40 deg F.

ii) 300 psi, 50 deg F.

iii) 1 500 psi, 70 deg F.

Iv) 500 psi, 60 deg F.

v) 3000 psi, 70 deg


19


Hydrate PreventionFrom what we have covered thus far, you willremember that hydrate formation was mentioned asprobably being the most troublesome problemassociated with water in natural gas.

So, how can we prevent these hydrates fromforming?

Activity

Jot down three things that you could do to a gas stream, in order to discourage hydrate formation.

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You have probably written down something alongthe following lines:

1. Reduce the pressure2. Remove the water3. Raise the temperature

At this point we are going to cheat a little! - byapplication of lateral thinking. Hydrate formation is aprocess which may be compared with ice formationin water. It is possible to prevent ice formation bylowering the freezing point of water. This can bedone by adding a chemical to the water. (Thinkabout the effect of adding salt to icy roads).

In a similar way, we can add a chemical to a gasstream to prevent hydrate formation.

This gives us a fourth method to add to our list:

4. Lower the hydrate formation temperature

When a chemical is added to the gas to preventhydrate formation, it is often known as chemicalinhibition.

Lets consider each of the four preventativemeasures we have just listed.

1. Lowering the pressure.This is not always possible. The reservoir is at acertain pressure and we have no control over this.

2. Removal of water.This is, of course, what this unit is all about.Dropping free water out of the gas wheneverpossible will reduce the likelihood of hydrateformation.

However, the pressure and temperature changesinvolved in the dehydration process will, inmost cases, give rise to the condition forhydrate formation before enough water can beremoved to inhibit such formation.

A real chicken and egg situation!

We are, therefore, left with the last two - heatingand chemical inhibition - as the most convenientmethods of hydrate prevention.

The decision on the type of inhibition is invariablymade on an economic basis. Usually, acombination of heating and chemical inhibition is theresult.

3. Heating.It is certainly possible to discourage hydrateformation by heating the gas. However this is notalways a practical solution.

Consider, for example, a long undersea gaspipeline. This will lose heat to the surroundingwater. It would not be possible to raise the initialtemperature of the gas to a point which guaranteesthat the temperature at any point in the line, alwaysremained above the hydrate formation temperature.

If heat is the answer, maximum use is made of heatconservation within the process by using heatexchangers. For example. the relatively hightemperature of gas at the wellhead may be used towarm up the cold, processed gas, as we shall seelater.

4. Chemical inhibition.I want to concentrate on chemical injection as amethod used to prevent hydrate formation.Ammonia, brines, glycol and methanol have all beenused to lower the freezing point of water in gas.Methanol and glycol are the inhibitors most widelyused. These are fed into the gas by low volumeinjection pumps. The injection point is usually justupstream of the point where hydrate formationconditions are expected.

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One such point is illustrated in Figure 8 at the Xmastree. The inhibitor can be used here to preventhydrates forming on the valves of the tree during ashut-down. This injection point can also be used toinject inhibitor into the flowing gas stream to preventhydrate formation in pipework and processesimmediately downstream.

Methanol is mainly used where only occasionalinhibition is needed, for example plant start-up orwhen working on the well. The reason is that,although methanol is fairly cheap, its recovery isdifficult and costly. It is, therefore, invariably lost. Inaddition, methanol is hazardous to store and handle;it has a fairly low flash point.

Where continuous inhibition is needed, ethyleneglycol (EG) is commonly used. Although it is moreexpensive than methanol, its regeneration is areasonably straightforward process. There arethree main forms of glycol used in gas processing,but it is ethylene glycol that is usually used forhydrate inhibition. We will talk about the other formsof glycol and their uses later.

The injected glycol mixes with any free water that ispresent in the gas and lowers the hydrate formationtemperature, in much the same way as the additionof anti-freeze to a car engine cooling system lowersthe freezing point of the cooling water. The resultingglycol-water mixture can be processed to enablerecovery and re-use of the glycol. This regenerationwill be discussed later in this unit, as the process isidentical for regeneration of any of the glycols.

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Test Yourself 5

a. It was mentioned in the text that. in gas processing, the maximum use is made of heat conservation within the process. Why do you think that this is done?

b. Indicate whether you would use methanol or glycol for the following inhibition requirements: Methanol Glycol

i) For initially starting a new oil well which has a high gas content? ii) For continuous injection into an offshore pipeline feeding an onshore gas plant?

iii) For long term storage offshore for use in gas well servicing jobs?

23


Summary of Section 1In this first section the origins of water in natural gas have been explained and you know that it cantake the form of vapour or liquid.

You should now be able to find out how much water is required to saturate a given gas, if youknow its temperature and pressure (by reference to the graphs). It is important to remember thatwhen the temperature of natural gas is lowered, water vapour condenses to produce free water.

We have discussed the problems created by the presence of water in gas, which are :

liquid accumulations in the wellborecorrosionlower pipeline efficiencypoor gas qualityhydrate formation.

Finally, we looked at preventing the formation of hydrates in gas, in particular by chemical inhibitionwith methanol or glycol. We will be applying our knowledge of hydrate prevention, both by heatand chemical inhibition, later on in this unit.

You now have the necessary background knowledge for working through the following sectionsand understanding the processes described.

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In this section we are going to look at one of thecharacteristics of natural gas that assists in theseparation of water from the gas - the Joules/Thompson Effect.

We will also look at a typical process plant whichuses this principle in practice.

The Joules/Thompson EffectWe have seen that, as the temperature is reduced,water vapour condenses into free water, which isfairly easy to separate from the gas. There areproblems involving hydrates, of course, but we candeal with those by inhibition or process design, aswe will see later on.

The main hurdle we face is how to reduce thetemperature at an acceptable cost. Fortunately,nature takes a hand. Gas has a property which canassist us to reduce the temperature fairly easily. Letme describe this property :

If a natural gas is rapidly expanded by reducingthe pressure, Its temperature will drop.

This temperature drop associated with gasexpansion is known as the JouleslThompsonEffect. The greater the pressure drop, the greaterthe temperature reduction. You can see this effectillustrated in Figure 9.

Gas DehydrationSection 2 - Auto Refrigeration

25


This chart is only by way of an example. It will notbe accurate for all gases. However it serves toillustrate the use of such charts.

In order to find a temperature drop associated with agiven pressure drop, just follow the steps I havelisted here for you.

Find the point on the graph which corresponds to the temperature and pressure of the gas before expansion takes place.

Follow the curve to the left until it intersects the vertical line which corresponds to the pressure of the gas after expansion.

Read off from the left hand vertical axis of the graph, the temperature at this point.

Lets do that with some actual figures.

Take the following example:

A natural gas at 3 000 psi and 90 deg F is expandedto 1 000 psi. What will be the temperature drop?

Find the point on the graph which corresponds to 3000 psi and 90 deg F. (You will find that this point lies on the fourth curve from the bottom of the graph).

Follow this curve to the left until it intersects the vertical line at 1 000 psi.

Move horizontally from this point to the left hand vertical axis.

Read off the temperature at this point. You should find that it is 18 deg F.

The temperature drop therefore is( 90 - 18 ) = 72 deg F.

Of course, the starting pressure and temperaturewill not always coincide exactly with one of thesecooling curves. In such a case, a curve parallel tothe nearest printed curve needs to be drawn orimagined.

For example, gas at 2 800 psi and 130 deg F isexpanded to 1 400 psi. With a little imagination, youwill see that the new temperature will be86 deg F - a drop of 44 deg F.

Now have a go at Test Yourself 6. In this exampleyou will have to visualise your own curve from thefigures given and work from that.

Test Yourself 6A gas is at 2400 psi and 80 deg F. FromFigure 9, work out what temperature risewould be needed in this gas so that, afterexpansion to 1 500 psi the final temperaturewill be 75 deg F.

Check your answer in Check Yourself 6 onpage 60

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The graph (Figure 9) also gives an indication ofwhether we can expect hydrates to form. This isshown by the broken line. Any point below this lineprovides conditions suitable for hydrate formation inthe presence of free water. For instance, theexample we used of 3 000 psi gas at 90 deg F beingexpanded to 1000 psi will place it firmly in thehydrate formation range.

You may have wondered how the expansion of thegas is brought about, in order to utilise the Joules /Thompson effect. In fact, there are a number ofways of doing this. The most common one is toexpand the gas across a choke valve.

A choke valve is a type of valve designed to controlgas or liquid flow. In its simplest form it consists ofa cone and seat arrangement, both of which arehardened to resist the erosive effects of the flow.The closer the cone is to the seat, the more the flowis reduced, or choked. Such a device is illustratedin Figure 10.

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Before we go on to look at processes usingthe Joules / Thompson effect. practice usingFigure 9 further.

Test Yourself 7Complete the following chart

Expanded toStarting Starting Final Final Hydratespressure temperature pressure temperature expected(psi) (deg F) (psi) (deg F) Yes/No

4000 102 2000

3800 154 1000

2800 90 1800

2000 86 1200

1800 123 600


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The Joules/Thompson Effect forms the basisof a common method used to extract waterfrom gas. This method is called lowtemperature separation.

Low temperature separation makes use of thenatural characteristics of gas expansion. This,together with efficient heat exchange withinthe plant design, leads to a very cost effectiveprocess.

This is illustrated below.

A low temperature separation process may bedescribed as follows :

The inlet gas is passed through a chokevalve and cooled by the resulting pressurereduction and expansion. This causeswater and liquid hydrocarbons tocondense. Dry gas, condensate and freewater can then be separated from eachother.

We will be looking at this in more detailshortly.

The effectiveness of this process depends on theinitial pressure being high enough to allow anadequate pressure drop. Often dehydration can beachieved with a pressure drop as little as 1 000 psi.The downstream pressure is usually determined bythe pressure of the pipeline being used to export ordeliver the gas.

By dropping the temperature, we may move into thehydrate formation region. This potential problem isdealt with in one of two ways:

1. Inhibition

or

2. Melting

Lets look at two typical process plants which useeither inhibition or melting to deal with hydrates.

First, inhibition :

Low Temperature Separation with HydrateInhibition (LTS)

This process is illustrated as a simple flow diagramin Figure 11.

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30


Follow the path of the well fluids as they flowthrough the plant.

The well stream first flows to a high pressureknockout vessel that separates any free liquid.The free liquids are removed from the vessel andpassed on to another part of the plant for disposal.

Ethylene glycol (EG) is then injected into theprocess gas stream immediately upstream of a heatexchanger HE-1. (You will remember fromSection 1 that EG is a chemical used to inhibithydrate torrnation.)

The gas, with glycol added, is then cooled in theheat exchanger. This exchanger is known as a gas/gas exchanger. It means that cold sales gas is thecooling medium which cools the incoming gasstream. (Sales gas is a term often used to describegas treated to meet a laid down specification).

A further temperature drop occurs as the gasexpands during the pressure drop across the chokevalve.

This cooling causes further condensate and water tocondense from the gas stream as it enters the coldseparator.

At this point we have all the conditions necessary forhydrate formation. It means that the glycol injectionrate upstream of here needs to be carefullycontrolled. It must be sufficient to prevent hydrateformation, in the heat exchanger, pipework or theseparator.

In the cold separator, glycol, water and condensateare separated from the gas and the condensate isrecovered for further processing and sale.

We want to be able to use the glycol again. In orderto do this, the water glycol mix is further processedin a glycol regeneration system.We will be looking at this regeneration system inmuch more detail when we come to Section 4 of thisunit.

Briefly, however:

The glycol may have absorbed some hydrocarbonsas it mixes with the gas in the process. These mustbe removed. The glycol and water are routed fromthe separator, via another heat exchanger (HE-2)where the mixture is heated up, to a flash tank. Inthis vessel, hydrocarbon vapours are removed fromthe warmed mixture.

In the final part of the process the water is removedfrom the glycol. The glycol water mixture passes toa regeneration package where the mix is heated andthe water is boiled off as steam.

The hot glycol-can now be used again. It is firstpassed through heat exchanger HE-2, where it isused to warm the incoming glycol/water mix fromthe cold separator. The regenerated glycol itself iscooled down here, prior to reinjection into theincoming well stream to act as a hydrate inhibitoragain.

Why dont you go through the process once again atthis point, and then have a go at Test Yourself 8.

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Test Yourself 8The following statements refer to a series of steps in a low temperature separation processwith hydrate inhibition (LTS).

The steps are out of order. Without looking at the flow diagram (Figure 11), rearrange the stepsin their correct sequence.

1. injection of glycol

2. separation of free liquids in the high pressure knockout vessel

3. condensation of water and condensate in the cold separator

4. cooling of the well stream in the gas/gas heat exchanger

5. expansion of gas across the choke valve

6. separation of water/glycol and condensate in the cold separator


In this process, the main pieces of equipment, apartfrom the regeneration package which we will look atlater, are the separator and the heat exchangers.Lets take a look at these pieces of plant in a littlemore detail.

The cold separator used in our example is aHorizontal Three Phase Separator. This type ofseparator is illustrated in Figure 12.

32


33


The three phases are gas, condensate and water inthis case. The condensate, being lighter, sits on topof the water and flows over a Weir into a separatecompartment. From here the outlet valve isactuated by a level controller, to maintain a steadycondensate level in this compartment. A secondlevel controller maintains a constant watercondensate interface.

The gas section is fitted with a series of baffles thatencourage the separation of condensed liquiddroplets from the gas. This ensures that the gasleaving the separator is liquid-free.

Let us now look at heat exchangers. We repeatedlyrefer to heat exchangers in this Unit, and you willmeet up with them in most hydrocarbon processes.

Figure 13 shows a typical heat exchanger.

Figure 13 : Heat Exchanger

One medium flows via the coils and the other in the outer body. Either medium canbe liquid or gas. Due to the temperature difference, the colder medium heats up, andthe hotter one cools down.

34


Now we will consider the other process which uses Low Temperature Separation.

This Figure shows a simple flow diagram of a typical process of this type. It is called a Low Temperature Extraction Process (LTX)

35


The basic differences between this process and theprevious one are the routing of the warm wellstream, the separator design and the absence ofglycol injection or regeneration.

Once again, follow the flow paths through theprocess, using Figure 14.

This time, the warm incoming stream is first routedthrough coils in the bottom of the low temperatureseparator. This starts to cool the gas, which is thenfurther cooled as it passes through a heatexchanger.

The effect of cooling is to condense somehydrocarbon liquids and water from the gas stream.These free liquids are separated from the gas inthe liquid knockout drum and fed into the liquidsection of the low temperature separator.

After leaving the liquid knockout drum, the gaspasses to the choke at the separator inlet. Here thegas is expanded to a lower pressure. Again, rapidexpansion of the gas causes a drop in temperature.

At this point, hydrates tend to form becauseconditions have now changed to values whichencourage hydrate formation. The hydrates fall intothe liquid section of the separator where they aremelted by the warm coils.

Cold gas, which has now had its water and liquidhydrocarbons removed, is taken from the separatorand used as the cooling medium in the heatexchanger. (A by-pass line round the exchangerincorporating a 3-way valve maintains the correcttemperature in the process). The gas, now at thecorrect specification, can be sold.

The low temperature separator is again a 3 phasevessel, but of a different design. I have included asimple drawing of one (Figure 15) so that you cancompare the two.

36


From here, the condensate and water are removedunder controlled conditions. The condensate is soldand the water led off to disposal.

The LTX process is obviously more cost effectivethan LTS, as glycol inhibition and regeneration areeliminated. Glycol or methanol injection may benecessary, however, for start up purposes, when thewell stream will be cold.

Now that you have worked through this section,have a go at the following Test Yourself question.

37


Test Yourself 9The following statements apply to the LTS process or the LTX process or both. Indicate, byticking the box, which one is applicable.

LTS LTX BOTH

1 The incoming well stream passes through coils in the separator.

2 The choke is at the separator inlet.

3 Inhibitor is normally injected into the well stream.

4 The glycol is regenerated.

5 A heat exchanger is used to cool the gas.

6 Hydrates form in the separator.

7 The process makes use of the Joules/Thompson effect.

8 The inhibitor injection point is before the heat exchanger.


38


Summary of Section 2This section opened with a description of the Joules/Thompson Effect, where gas expansionresults In a temperature drop. You have seen how this characteristic of gas is used to good effectin low temperature separation, by condensing liquids from the gas phase.

Two main processes were described:

a. LTS, where hydrate formation is inhibited by the injection of glycol.

b. LTX, where hydrates are melted by passing the incoming, warm, gas stream through coils in the bottom of the separator.

The LTX was seen to be more efficient as it utilised heat exchange within the process, thuseliminating the need for expensive glycol inhibition or regeneration.

You now understand the principles of the first method of gas dehydration, using low temperatureseparation which can be described as an Auto Refrigeration process.

We will now move on to look at a system which uses the principles of adsorption for gasdehydration - the Solid Desiccant Dehydration process.

39


In the last section, we examined how the principle oflow temperature separation could be used toreduce the water content of a gas.

In this section we will look at the first of two types ofprocess which utilise a substance called adesiccant to remove water from gas. Thedesiccant can either be a solid or a liquid. We willstart with a solid desiccant, which uses the principleof adsorption to achieve this.

AdsorptionAdsorption is a process in which a solid selectivelyremoves a particular component from a fluid (liquidor gas) mixture and holds this component on itssurface.

This solid is known as an adsorbent material.

In our case the mixture consists of gas and watervapour, and it is the water which is removed.The adsorbent material, which removes the water, iscalled a solid desiccant.

An everyday example of the adsorption process isthe use of sachets of silica gel, packed along withsensitive photographic or electrical equipment. Thesilica gel is a solid desiccant which preventsmoisture from damaging this equipment.

A gas dehydration process which uses thisphenomenon is the Solid Desiccant DehydrationPlant.

In such a plant the gas is dehydrated by passing itthrough a bed of solid desiccant which removes thewater vapour.

This desiccant consists of solid granular materialshaving an extremely large surface area per unitweight. This is because the granules have amultitude of microscopic pores and capillaryopenings. Common desiccants used in the plantare:

silica gelsorbeadactivated aluminamolecular sieves

After a time the desiccant will itself becomesaturated with water. This reduces its capacity forfurther adsorption and, in order to use it again, itmust be regenerated. In other words, we must getrid of the adsorbed water.

This is usually achieved by heating with hot gas,which vaporises the water from the desiccant. Forthis reason, a dry bed dehydrator usually has atleast two beds of desiccant - one being used to drythe gas, while the other is being regenerated.

Lets now look at a Solid Desiccant DehydrationPlant.

Gas DehydrationSection 3 - Solid Desiccant Dehydration

40


Figure 16 shows a simple flow diagram of such a plant.

41


The diagram shows a two tower dehydration layout.Take a look at the diagram and follow the processthrough. The solid lines represent the gas beingprocessed, and the broken lines the regenerationcycle gas flow. One tower is on the adsorption cyclewhile the other is being regenerated.

Gas being treated flows in at the top of the towerand adsorption takes place from top to bottom.Water saturation of the desiccant also, therefore,starts at the top of the tower. Lighter hydrocarboncomponents are also adsorbed in the lower layers ofthe desiccant bed. As the lower layersprogressively become water saturated, thehydrocarbon components are displaced. Theadsorption cycle must stop before the desiccantbed is totally saturated.

Regeneration takes place in the reverse direction,that is, bottom to top. The regeneration gas isheated and fed in to the bottom of the tower. Itpasses through the desiccant and out through thetop of the tower. The hot regeneration gas drives thewater from the desiccant as steam. This wet, hotgas is then cooled and passed through a separatorto remove the liquids. After the bed has beenheated and the water driven off, it has to be cooledbefore it is switched to adsorption again.

Effective regeneration is the secret of this process.The bed must be thoroughly regenerated or itscapacity will be reduced. Effective regenerationrelies on quantity and temperature of theregeneration gas. The higher the temperature, theless gas is required, but too high a temperature canruin the desiccant, and drastically reduce itsadsorptive properties.

A typical cycle time is 8 hours of adsorption and8 hours regeneration. Figure 17 gives a graphicalrepresentation of the regeneration cycle time andtemperature.

42


Use the figure to have a go at the following TestYourself question.

43


Test Yourself 10

a. Referring to curve 2 in Figure 17, describe what is happening from the start to the end of the regeneration cycle.

b. Why do you think that the regeneration gas is fed in at the bottom of the tower?

c. Why is the regeneration gas cooled after leaving the tower, before entering the separator?


Solid desiccant dehydration can produce Virtuallydry gas for processes sensitive to feed gas quality,such as cryogenic-type gas processing plants.(Cryogenic processing involves extremely lowtemperatures, much lower than the LTX and LTSplants we have been looking at). The effectivenessof the unit, however, depends upon the incominggas being free of liquids, entrained mist and solids.Liquids may destroy or damage the desiccant bed,and solids could plug it.

44


Summary of Section 3You have been introduced to the removal of water vapour from gas using the mechanism ofadsorption.

You saw that adsorption is a process in Which a solid desiccant selectively removes onecomponent from a fluid mixture. The solid desiccant has the capacity to attract and hold thecomponent on its surface.

We examined the workings of a dry bed dehydration unit, and concluded that such a unit reliesmainly on effective regeneration of the desiccant. Such plants can dry gas very thoroughly.

We are now going to look at a second process which utilises a desiccant, one in which a liquid,rather than a solid, is used to dehydrate the gas - the Liquid Desiccant Dehydration process.

45


In the last section we looked at a process Whichremoves water vapour from gas using a soliddesiccant. We now turn to the use of a liquid, ratherthan a solid desiccant. This is known as anAbsorption process.

AbsorptionAbsorption of water by liquid desiccant is a processin which the water is taken into the body of thedesiccant. This is in contrast to adsorption, wherethe water is held on the surface of the (solid)desiccant.

Water vapour is removed by bubbling the gasthrough a hygroscopic liquid, that is, a liquid withan affinity for water.

This hygroscopic liquid is our liquid desiccant.

Liquid DesiccantsThe liquid desiccant used is almost always one ofthe glycols. Glycols which have the necessaryattraction for water are listed below :

Monoethylene glycol (MEG or EG); rarely used nowadays as a desiccant due to high evaporation and chemical degradation losses. If you think back to Section 1 you will remember that MEG is used as a hydrate Inhibitor.

Diethylene glycol (DEG); a cost effective liquid desiccant where moderate dehydration is required and where DEG has also been used earlier in the process as a hydrate inhibitor.

Trlethylene glycol (TEG); the most expensive but the most effective liquid desiccant in the glycol family. It possesses superior dewpoint depression qualities.

A balance must be struck between the degree ofeffectiveness and the cost. Nowadays, therefore,TEG is the preferred liquid desiccant. TEG has beenused successfully to dehydrate gases over thefollowing operating ranges and conditions:

Dewpoint depression 40 - 140 deg F

Gas pressure 25 - 2 500 psi

Gas temperature 40 - 160 deg F

We have our liquid desiccant. All we need now is aplant in which to use it.

For the rest of this unit we will be looking at theequipment used in, and the layout and operation of,a Glycol Dehydration Plant.

Glycol Dehydration PlantIn a typical glycol dehydration plant the wet gas isbrought into intimate contact with TEG. The glycolabsorbs water from the gas, which then leaves theplant as dry gas. The glycol now contains waterwhich reduces its absorbing properties. In orderthat the glycol can be used again, it must beregenerated. This is done by heating it and drivingthe water off as vapour (steam).

Lets follow the flow of gas and glycol through atypical dehydration plant.

Gas DehydrationSection 4- Liquid Desiccant Dehydration

46


Figure 18 shows a simple flow diagram for a typical unit. Look at the figure and trace the flow paths withthe aid of the following brief description.

The gas containing water vapour ( wet gas) entersthe contactor, or absorber tower at the bottom. Itpasses up the contactor, through a series of traysdown through which the TEG is flowing. The traysare so designed that the gas is forced to mixintimately with the glycol.

The water from the gas is absorbed by the glycoland dry gas leaves the tower at the top.

47


The glycol, now containing water and called richglycol, leaves the contactor tower at the bottom andflows to the regeneration section of the plant.

The TEG also absorbs some light hydrocarbonvapour, and so the stream is directed to a flashtank. This reduces the pressure and thereforeallows most of the hydrocarbon vapours to escape.

Next, the lEG flows through a filter which removesany tarry solids which may have formed in theprocess.

The glycol is then pre-heated in a heat exchangerand passed to the reboiler where the water is boiledoff and the TEG reconcentrated.

The glycol is now capable of being used again. It isknown as lean glycol at this point.

From the reboiler, the lean glycol flows to a surgetank. It is pumped from here to the heat exchanger,where it is cooled. From there it flows back to thetop of the contactor tower. (Note how the hot glycolfrom the reboiler is used as the heating medium inthe heat exchanger).

The process you have just followed is a continuousprocess and could be called a Regenerative GlycolDehydration Process.

This simplified description will help you gain a broadunderstanding of the process. Let us now study it inmore detail and see how the equipment works.

Gas FlowLets start with the flow of gas through the system.

The heart of the process is the contactor tower. Itis in this unit that the dehydration takes place. Thetower is called either the contactor or the absorbertower. For the rest of this section, however, I willuse the term contactor.

Look at Figure 19(a) which shows a contactor towerwith a scrubber section and an absorber section.

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49


Before the gas enters the absorber section of thetower, it passes through a scrubber to separate anyfree liquids. The scrubber may be a separate vesselor, as is the case here, may form part of the toweritself.

It is essential that the contact between the gas andthe TEG is intimate. This is achieved by bubblingthe gas through the TEG via bubble capspositioned on a series of trays within the absorbersection of the contactor.

The contactor trays with the bubble caps, are shownin Figure 19(b).

The trays incorporate a weir which maintains a fixedlevel of glycol on each tray. As the gas flows upthrough the centre of a bubble cap it is forced backdown through the glycol and round the outside of thecap. This ensures that all the gas must flow throughliquid glycol as it passes each tray.

The flow path of the gas through a bubble cap isshown in Figure 19(c).

After the top tray, the gas passes around glycolcooling coils. These act as heat exchangers toreduce the temperature of the incoming lean glycol.(The temperature of the lean TEG entering the topof the tower should be as close as possible to thegas exit temperature. This helps to prevent theglycol from foaming, which might occur if there wastoo great a temperature difference between leanglycol and gas).

Finally, before leaving the contactor the gas passesthrough a mist extractor. This device extracts anydroplets of liquid glycol which may have been pickedup by the gas. It helps to reduce glycol losses.

The gas leaving the contactor should now be freefrom water vapour and meet the required dewpointspecification.

Glycol FlowLets now look at what happens to the glycol.

The TEG, cooled in the coils (at the top of thetower), passes down through the tower from tray totray, dehydrating the gas. This diluted (or rich)glycol solution collects at the bottom of the absorbersection of the contactor tower.

Before the glycol can be used to dehydrate moregas, it must be regenerated.

Before we go on to look at the regeneration processitself, we should consider three other pieces ofequipment. These are:

flash tank

filter

heat exchanger

Look again at Figure 18 and check the location ofthis equipment.

The flash tank is simply a three phase separatorwhich is capable of separating glycol, gas andhydrocarbon liquids from each other.

You can probably imagine that, as the glycol flowsthrough the contactor, it can pick up small amountsof gas, and liquids which have condensed from thegas. These are removed in the flash tank. Any gaswhich is liberated is led away to be used as fuel or isdisposed of by flaring. Liquid hydrocarbons areremoved from the tank and are collected for sale orotherwise disposed of. What remains is rich glycolwhich passes on to the next stage in the process.

Within the glycol a certain amount of solid materialmay accumulate. This can take the form of dirt,scale, rust or tarry reaction substances. A filter isused to remove these. It is usually of the type whichcontains a cartridge which can be removed andreplaced while the plant is in operation.

I said earlier that the glycol must be heated in theregeneration process. In order to save energy, theglycol is pre-heated in a heat exchanger before itgoes to the regenerator. The exchanger uses hotglycol from the regenerator itself as the heatingmedium.

Lets move now to the actual process of glycolregeneration.

50


Simply boiling the dilute glycol would remove thewater as steam. but would also result inconsiderable loss of glycol vapour. As the boilingpoints of water and TEG are so far apart (212 and549 deg F respectively). A process called fractionaldistillation is used to regenerate the glycol.

The regenerator consists of two parts, the Reboilerand the Stripper column. Take a look at Figure 20which shows such a unit.

51


You will see that the cool, rich glycol passes first ofall through a coil in the top of the stripper column.This is called a reflux coil. I will explain its functionshortly.

After pre-heating in the heat exchanger, the glycol isthen fed to the stripper column near the top. Itdescends through packing in the stripper and mixeswith a rising stream of water rich, hot vapours.These vapours are created by heating the glycol inthe reboiler to a high temperature. This temperatureshould be above that of boiling water but below theboiling point of the glycol itself.

Within the stripper column, two things arehappening:

the cooler, rich glycol liquid causes the hot glycol vapour in the rising vapour stream to condense out as a liquid and fall back.

the hot, water rich, vapour stream strips out the liquid water from the glycol stream as vapour and carries it to the top of the column, from where the water vapour is vented to atmosphere.

All being well, at the top of the column the vapourwill be virtually pure water.

As long as the temperature at the top of the columnranges between 210 and 212 deg F, glycol lossesare minimised. This process is aided by the refluxcoil which I mentioned earlier. The cool glycolpassing through the coils assists any glycol vapourto condense and fall back into the reboiler.

Having passed down the stripper column, the glycolenters the reboiler and is heated further. Thiscreates the hot, water-rich vapours required forstripping.

From the reboiler the glycol passes to a surge tankwhich acts as a storage vessel. From there it ispumped via the heat exchanger back to thecontactor to continue the dehydration process.

So, you should by now have a good idea of how aliquid desiccant dehydration process works. Tracethe flow path of gas and glycol again and thenattempt the following Test Yourself.

Test Yourself 11Following the flow path of glycol, place thejumbled list of equipment given below into alogical process order, starting with theReboiler;

Reboiler

Contactor tower

Heat exchanger

Filter

Surge tank

Flash tank

Pump


52


Plant operationsA glycol dehydration plant will only work efficiently ifcertain process variables are maintained at constantvalues.

The more important process variables are :

glycol concentration

glycol circulation rate

glycol solution condition

Lets look at each of these in turn.

Glycol ConcentrationGlycol concentration refers to the amount of pureglycol in solution and is measured as a percentageby weight:

For instance, the rich glycol leaving the contactortower is a water rich solution whose glycol content isless than 95% by weight.

However, after the glycol has been through theregeneration section of the plant it isreconcentrated. Now its concentration can varyfrom 95% to 99% by weight, although we try toachieve as near to 100% as possible.

The concentration of the glycol fed to the contactortower determines the dewpoint depressionachievable for a given contact temperature. Thecontact temperature is the temperature at which thegas leaves the top of the contactor tower. Thetemperature of the lean TEG entering the top of thetower should be as close as possible to this contacttemperature.

Test Yourself 12Think about the process plant. What piece ofequipment is used to try to keep thetemperature of the TEG entering thecontactor as close as possible to that of thegas leaving it?


53


We can use a graph again to see how glycolconcentration and contact temperature can affectthe dewpoint of the gas.

Figure 21 shows the relationship betweendewpoints, contact temperature and TEGconcentration.

If, for example, we need to achieve a reductionin water dewpoint of the gas from 55 deg F to35 deg F at a contact temperature of 120 deg F,you can see that the TEG concentration must beincreased from 96.0% to 98.0% by weight.

This increased TEG concentration can be achievedby increasing the reboiler temperature. This can beshown in another graph, Figure 22, which appearson the next page.

54


Take a look at Figure 22. In order to increase theTEG concentration from 96% to 98%, the reboilertemperature would have to be increased from322 deg F to 380 deg F.

There is a limit, however, to the temperature atwhich we can operate the reboiler. TEG begins todegrade at temperatures around 450 deg F, whichclearly represents the upper limit.

Lets work through an example to determine TEGconcentration and reboiler temperature for aparticular dehydration problem. For this example,let us assume that dehydrated gas must contain notmore than 5lbs of water per mmscf when deliveredat 1 000 psi and 100 deg F.

Looking way back at Figure 2, which gives us thewater content of natural gas at saturation, you cansee that the required dewpoint is 24 deg F.

If the gas leaves the contactor at 100 deg F it canbe seen from Figure 21 that a 24 deg F dewpointrequires a TEG concentration of around 97.6%.(You will have to estimate between the curves todetermine this).

Figure 22 shows that 97.6% TEG concentrationrequires a reboiling temperature of 364 deg F (atsea level).

Again some estimation or interpolation is required.

If you are happy with the above example, try thefollowing Test Yourself. You will see that you haveto think back to some of the previous sections tocomplete it.

55Figure 22 : Graph of Triethylene Glycol Reboiler Temperature versus TEG Concentration


Test Yourself 13Gas at the wellhead is at 3000 psi and 120 deg F. After separation, its pressure is reducedacross a choke to 1 000 psi, after which it is routed to enter the cold separator. The gas entersan absorption tower for dehydration. The required water content should not be more than4lbs per mmscf. The gas leaves the contactor at 90 deg F.

i) Is hydrate inhibition (or melting) required?

ii) What volume of free water is knocked out by the expansion (per mmscf)?

iii) What concentration of TEG is required to achieve the gas delivery specification?

iv) What reboiler temperature is necessary (at sea level) to achieve the TEG concentration?


Another method of achieving higher TEGconcentrations is to use stripping gas for finalwater removal. Stripping gas is dry, low pressuregas introduced to remove additional water from theglycol in the reboiler.

Look again at Figure 20 which shows the glycolregenerator. You will see an inlet pipe at the bottomof the reboiler through which gas is entering theTEG. This is the stripping gas being used duringreboiling.

The effect of stripping gas being in contact with leanTEG is shown in Figure 23.

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Now to the next process variable :

Glycol Circulation RateIt is important to maintain an optimum TEGcirculation rate for effective dehydration.

Each plant will be designed for specific conditions. As a rule of thumb, however, about 2 gallons of glycol must be circulated for every 1 lb of water removed at the 55 deg F dewpoint depression.These figures are based on operations over a normal pressure range and a glycol solution of 95%.

Sometimes, greater dewpoint depressions can beobtained by increasing the circulation rate. However,an upper limit can be reached where increasing thecirculation rate actually reduces the dewpointdepression.

And finally:

Glycol Solution ConditionFor effective dehydration, the glycol solution mustbe kept in good condition. In other words, it must befree from impurities. Solids must be filtered from thecirculating stream and filters must be kept clean.

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Hydrocarbons in the TEG solution which have notbeen removed in the flash tank can cause additionalfoaming problems in the contactor. It is thereforeessential that the efficiency of the flash tank ismaintained.

Now that you have completed Section 4, haveanother look at the process flow diagram and satisfyyourself that you understand how the plantoperates.

Summary of Section 4In Section 4, I explained the difference between Adsorption and Absorption. However, weconcentrated on the Absorption process.

You saw that Triethylene Glycol (TEG) is most commonly used as a liquid desiccant to absorbwater from gas.

You followed the operation of a glycol dehydration plant, and you will have noted that this consistsof two main units:

the contactor, in which gas dehydration is accomplished

the glycol regeneration system, in which water is removed from the wet glycol so that it can be used again

Finally in this section, you looked at some of the process variables which must be maintained at aconstant value for efficient dehydration.

Now that you have completed the whole unit, you should have a basic understanding of the theoryand practice of gas dehydration.

Go back to the training targets on Page 2 of the unit, and check that you are able to meet thosetargets.

58


Check Yourself 1A water content of 45 Ibs per mmscf will be required to achieve saturation of the gas at surface conditions.

As 48 Ibs of water per mmscf were thesaturation conditions at the reservoir, ie, morewater vapour than required for saturation at thesurface, the gas at the wellhead will besaturated. As there is a decrease in theamount of water vapour required for saturationbetween reservoir and surface, free water willexist in liquid form.

The amount will be 48 - 45 = 3lbs per mmscf.

Check Yourself 2Because above the dewpoint temperature, one of the conditions for hydrate formation would not exist,ie free water.

Check Yourself 370 deg F.

Check Yourself - Answers

59


Check Yourself 4a. The problems associated with water in gas that could affect gas processing, in the short term, are:

gas quality pipeline efficiency hydrate formation

Corrosion is not included as it is unlikely toaffect actual processing in the short term.

b. i) Yes ii) No iii) Yes* iv) No v) Yes

* Remember that hydrates can form at orbelow the hydrate temperature.

Check Yourself 5 a. It saves money to use any naturally available sources of heat before considering paying for additional, external energy.

b. i) Methanol, as a glycol regeneration unit would not be available.

ii) Glycol, as long as the onshore gas plant has a glycol regeneration facility. iii) Glycol, because it is safer to store for long periods.

Check Yourself 625 deg F.

The starting point has to be the final conditions of1 500 psi and 75 deg F. Follow an imaginarycooling curve parallel to the nearest printed curveuntil the 2 400 psi line is intersected. This givesus the temperature to which the gas requiresheating. Temperature rise = 105 - 80 = 25 deg F.

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Check Yourself 7 Expanded toStarting Starting Final Final Hydratespressure temperature pressure temperature expected(psi) (deg F) (psi) (deg F) Yes/No

4000 102 2000 (63) (Yes)

3800 154 1000 (74) (No)

2800 90 1800 (60) (Yes)

2000 86 1200 (52) (Yes)

1800 123 600 (65) (No)

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Check Yourself 8The correct sequence of steps should be : 2 - 1 - 4 - 5 - 3 - 6

Check Yourself 9

LTS LTX BOTH1 The incoming well stream passes through coils in the separator. a

2 The choke is at the separator inlet. a

3 Inhibitor is normally injected into the well stream.

4 The glycol is regenerated. a

5 A heat exchanger is used to cool the gas. a

6 Hydrates form in the separator. a

7 The process makes use of the Joules/Thompson effect. a

8 The inhibitor injection point is before the heat exchanger. a

62

a

a

a

a

a

a

a

a


Check Yourself 10a. At first, hot gas warms up the tower and the contents. At 240 deg F water will begin to boil and vaporise. The bed continues to heat up, but more slowly, as water is being driven out of the bed. After the water, any heavier hydrocarbons will be driven off at a high temperature, and the bed will become fully regenerated. The bed is cooled for a couple of hours by unheated gas flowing through it.

b. The regeneration gas is flowed bottom to top due to the lower layers of the desiccant being less wet. Flowing from top to bottom would result in time being wasted in saturating the drier lower layers with the wet regeneration gas flow.

c. The regeneration gas is cooled before the separator in order to condense the water removed from the regenerated tower, which can then be taken out at the scrubber.

63


Check Yourself 11ReboilerSurge tankPumpHeat exchangerContractor towerFlash tankFilter

Check Yourself 12The cooling coil at the top of the contactor tower (reflux coil)reduces the temperature of the glycol to near that of the gas.

64


Check Yourself 13i) Yes, as the expansion process takes the gas into the hydrate formation range (Figure 9).

ii) From Figure 2, water content at 3 000 psi and 120 deg F = 48 lbs per mmscf.

From Figure 9, expansion to 1 000 psi drops the temperature to 53 deg F.

From Figure 2, water content at 1 000 psi and 53 deg F = 14 Ibs per mmscf.

Water knocked out by expansion = 48 - 14 = 34 Ibs per rnmscf.

iii) Figure 2, shows that for 4lbs water content a dewpoint of 19 deg F is required at 1 000 psi. From Figure 21, a TEG concentration of 97.5% is necessary to achieve sales specification.

iv) From Figure 22, the reboiler temperature will need to be set at about 360 deg F.

65

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