Gas Dehydration.pdf

POL Petroleum Open Learning

Gas Dehydration Part of the Petroleum Processing Technology Series

OPITO THE OIL & GAS ACADEMY

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© OPITO 1993 (rev.2002)

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Petroleum Open Learning

Gas Dehydration

Petroleum Open Learning

(Part of the Petroleum Processing Technology Series)

Contents

Page

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Training Targets

2

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Introduction

3

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Section 1 - Water in Natural Gas

4



Quantity of Water in Gas Problems of Water in Gas Hydrate Prevention

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Section 2 - Auto Refrigeration



The Joules/Thompson Effect The Low Temperature Separation (LTS) System The Low Temperature Extraction (LTX) System

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Section 3 - Solid Desiccant Dehydration



Adsorption Solid Desiccant Dehydration Plant

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Section 4 - Liquid Desiccant Dehydration



Liquid Desiccants Glycol Dehydration Plant

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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

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Training Targets The aim of this unit is to help you understand :

the capacity of natural gas to hold water



the methods used to reduce the water content of natural gas



the problems which result from the presence of water in gas

Upon completion of the unit you should be able to:



• Quantify the amount of water in saturated natural gas under given conditions. • List the problems associated with water in gas.

• Define the conditions that contribute toward hydrate formation. • Describe Joules/Thompson Effect.

• Explain the Auto Refrigeration process. • Define Adsorption and Absorbtion.

• Detail a simple two-tower desiccant dehydration process. • Describe a basic glycol dehydration plant.

• List and explain operational variables in the glycol dehydration process.

q q q q q q q q q

Tick the box when you have met each target.

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Gas Dehydration

Introduction

Petroleum Open Learning

Natural gas can be referred to as Associated Gas or Non-associated Gas. The former is produced together with liquids from an oil reservoir and is liberated from the liquids at the surface. The latter is produced independently 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 vapour or a liquid. Surface equipment is used to remove the water from the gas. This process is called dehydration, which is the subject 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 both associated and non-associated gas treatment facilities. The actual process chosen for a particular application depends on a number of factors. These include, location of plant, gas characteristics and so on.

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Gas Dehydration

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Section 1 - Water in Natural Gas Natural gas contains water, but how much? In this section we will look at how we can specify amount of water contained the gas. We will also review the problems that water in gas can cause, and look at inhibiting one of the problems, that of hydrate formation.

Quantity of Water in Gas Hydrocarbons contained in oil and gas reservoirs usually are, or have been, in close contact with formation water. Any gas is normally, therefore, very wet, at the reservoir temperature and pressure conditions. Up to a certain point, the water be held in the gas in the form of vapour. Beyond that point the water will appear as liquid. However, terms such as very wet are not very scientific, nor do they provide us with any indication of the actual water content

• 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.

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

• Methane • Ethane • Propane • Butane

There are a number of factors that can affect amount of water vapour that may be present in gas. These include: • gas composition and gravity • temperature • pressure

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

The main constituents are the following hydrocarbon gases:

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

• Pentanes The list is longer, but the amounts of other hydrocarbons present are usually small. The gases are listed above, starting the lightest at the top. They get heavier, or denser, as you move down the list. Density gas is usually expressed as the weight in pounds per cubic foot at standard conditions of temperature and pressure.

The composition of natural gas varies, because the proportions of its constituents will vary from to field.

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Specific gravity is the more commonly used measure of “density”. It is the ratio of a gas density to the density of air at the same conditions of temperature and pressure. As I said a little earlier, the percentage composition of different natural gases varies. Methane is usually the most abundant component, and is the principal source of energy in our mains gas supply. As you move down the list you undoubtedly recognise propane and butane, which commonly appear as bottled liquid gas.

For the purposes analysing water content, it is safe to consider natural gas as having a fixed composition. To further lighten our immediate task, we will initially be looking at the amount of water needed to render the gas saturated. The actual amount of water required to saturate gas will depend on the pressure and temperature the gas. This can be represented in the form of a simple graph as shown in Figure 1. Let’s see how this figure can be used in practice. Take a look at Figure 1.

Natural gas also contains impurities such as hydrogen sulphide (H2S), carbon dioxide (C02) , non-combustible gases and water vapour. However we are going to be concentrating on the water content.

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The curve illustrated on the graph is the saturation curve for natural gas at 1 000 psi. For varying gas temperatures in degrees Fahrenheit, it illustrates how much water in pounds per standard cubic feet (mmscf) is needed to saturate the gas at 1 000 psi. To use the graph, select your temperature on the horizontal axis, move vertically to intersect the curve, and then horizontally to find the amount of water vapour needed for saturation. Take an example: Question:

Answer: You can see from the point where the horizontal line intersects the vertical axis, that 24 lbs of water are required to saturate one cubic feet of gas at 70 deg F and 1 000 psi. Or, in abbreviated form 24 Ibs of water per mmscf.

Figure 1 gave us the saturation curve for just one pressure. If the curves for other pressures are illustrated in a similar fashion, the graph as shown in Figure 2 will be the result.

What is the water content of 1 000 psi natural gas at saturation, 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.

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As you can see, the different pressure curves are almost parallel, which makes it fairly easy to estimate for intermediate pressures. Let’s use Figure 2 : Take a reservoir pressure of 3 000 psi and a temperature of 150 deg F. Using the method described earlier, you can see that gas under these conditions will have a saturated water content of 94 Ibs per mmscf of gas. As I said earlier, up to the saturation point, the water in the gas will be in the form of vapour. For the purposes of this unit, we can consider the water vapour as being similar in behaviour to a gas. Now take the same reservoir pressure of 3 000 psi as in the previous example, but a temperature of 120 deg F. Look at the graph in Figure 2 again. This time you will see that only 48lbs of water, in the form of water vapour, is required to saturate every mmscf of gas at these conditions.

This means that, if the temperature of the gas in the above example were lowered from 150 deg F to 120 deg F at a constant pressure, 46 Ibs (94 - 48) water per mmscf would condense and appear as free water. From the above, a useful fact emerges - one that we 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 Yourself question. It should help you to understand what we have covered up to now.

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

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Problems with Water in Gas

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)

b)

As gas flows through the reservoir and into the well bore, it usually becomes saturated with water. In addition, it picks up free water along the way. This is a very important fact regarding natural gas. Let me just repeat it :

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

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

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

As you may gather from the heading, water in gas is, for most of the time, bad news! Water in gas gives rise to various problems. Let me now list and briefly discuss the more important ones. These are: • liquid accumulation in the wellbore • corrosion

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

• pipeline efficiency • gas quality • hydrate formation let’s look at each of these problems in turn.

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

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Liquid Accumulation in the Wellbore This usually occurs in lower pressure, low flow rate gas wells. Liquids, of which free water is one, start to build up in the bottom of the wellbore when the flowing velocity is too low to lift the liquid to the surface. The wellbore acts as a separator and the gas bubbles through the liquid. The liquid column building up in the well causes an increasing back-pressure to be exerted on the reservoir. This further reduces the flow rate and thus the velocity of the well fluids. The process can continue until eventually the well dies ( ceases to flow) or only flows intermittently. The deteriorating situation is illustrated in the left hand sketch in Figure 3. The normal method for avoiding this problem is to ensure that the flow velocity is maintained at a level high enough to prevent fall-back of liquid droplets. The simplest way of accomplishing this is to increase the flow rate. This is not always possible, particularly if the well has naturally declined in performance. Another way of increasing flow velocity is to install smaller bore production tubing closer to the perforations. This means that the same amount of gas has to flow through a smaller cross-sectional area of tubing. 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 remove liquids from the wellbore. However, these are beyond the scope of this programme and we will not discuss them here.

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Corrosion Corrosion is the next problem on our list. In natural gas systems, corrosion carbon steel occurs when free water forms in the presence of carbon dioxide (C02) or hydrogen sulphide (H2S). You will remember that these two substances are impurities which may be found in natural gas. Carbon dioxide and water together to form carbonic acid which then reacts with an exposed steel surface. The reaction causes chemical substances to form which are called corrosion products. (The most common corrosion product in everyday life is, of course, rust, which forms on iron or steel exposed to the air). These corrosion products are removed by the force of the flowing gas stream, exposing fresh metal for further attack. This action results in metal loss and, therefore, corrosion pitting. The rate of metal loss, called the corrosion rate, depends on many factors, but principally on the amount of carbon dioxide and free water present. Corrosion rate also increases dramatically with increase in temperature.

Hydrogen sulphide has a similar action, causing metal loss and pitting when free water is available. This particularly applies if carbon dioxide-related corrosion is also present - they appear to encourage each other! Protection against carbon dioxide and hydrogen sulphide 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 in combination. The choice will be based on both technical and economic factors.

Free water can occupy quite a lot of the pipeline volume. This will reduce the amount of pipeline cross sectional area available for gas flow, resulting in increased gas flow velocity. The severity of this effect 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 point at which liquid slugs are formed. This is shown in Figure 4b.

Pipeline Efficiency Natural gas is usually transported by pipelines, and water in gas pipelines causes our next problem. The presence of free water in a gas pipeline can give rise to the complication of two-phase flow. By two-phase flow we mean that gas and liquid (say, water) are flowing in the line together. (Gas is one phase, and liquid is the other).

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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 is reached. At this point the available flow area is insufficient for the gas flow rate. This results in an intermittent 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.

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Gas Quality

Hydrates

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

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

For the end-user of gas, and for those who transport it, the quality is strictly specified, especially as regards water content. The water content specification is usually called the water dewpoint (in order to distinguish it from the hydrocarbon dewpoint, which is a separate aspect of the gas quality specification). Let us have a look at what this means. As we have seen earlier, when the temperature of saturated gas is decreased, some of the water vapour condenses and appears as free water. Put another way - the lower the temperature the less water vapour it takes to saturate a given volume of gas. Bearing this in mind, the water dewpoint of gas is defined as :

Hydrates are solids that form as snow like crystals. They are created by a chemical reaction between natural gas and free water. Once formed, hydrate crystals can pack together in gas processing plant, partially or completely blocking flow lines or accessories such as valves. The blockages will tend to occur at turbulent regions such as pipe bends or changes of diameter. One particular danger of hydrate deposits arises when they form a blockage downstream of a pipework pressure rating change, for example in flare or vent pipework. This may subject the lower rated pipework to dangerous over pressures.

Figure 5 shows the general effect.

The temperature at which natural gas at any specified pressure is saturated by the water vapour it contains. The quality specification for a natural gas will define a water dewpoint so that: • water vapour will not condense as free water under any foreseeable conditions.

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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? Figure 5 : Shows a possible effect of a hydrate blockage

Hydrates can occur at temperatures considerably above the freezing point of water. At a given pressure and in the presence of free water, hydrates will form when the temperature of the gas is at or below a certain level. Understandably, this is called the hydrate temperature. 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 the pressure and temperature conditions needed for hydrate formation, when a typical natural gas is in contact with free water. The example given on the graph shows how hydrates form in gas 400 psi when the temperature drops to 50 deg F. Hydrate formation conditions can be shown graphically in a slightly different way. Have a look at Figure 7. You will probably recognise this graph as being very similar to Figure 2. However, this time, superimposed on the various pressure curves is a hydrate temperature line. For each pressure, it indicates a temperature below which hydrates will form 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.

As I said earlier, hydrates are undesirable in gas processing as they can, in certain circumstances, disrupt the normal degree of control that we should have over a process. As the problem of hydrates is so important, let me list for you once more the conditions which could lead to their formation : • gas, with free water present • temperature and pressure conditions within the hydrate formation region

Have a go at Test Yourself 4.

Check your answer in Check Yourself 3 on page 59

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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).

i)

Yes

No

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

Check your answer in Check Yourself 4 on page 60

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Hydrate Prevention From what we have covered thus far, you will remember that hydrate formation was mentioned as probably being the most troublesome problem associated with water in natural gas. So, how can we prevent these hydrates from forming?

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 along the following lines: 1. 2. 3.

Reduce the pressure Remove the water Raise the temperature

At this point we are going to cheat a little! - by application of lateral thinking. Hydrate formation is a process which may be compared with ice formation in water. It is possible to prevent ice formation by lowering the freezing point of water. This can be done by adding a chemical to the water. (Think about the effect of adding salt to icy roads).

1.

Lowering the pressure.

Heating.

This is not always possible. The reservoir is at a certain pressure and we have no control over this.

It is certainly possible to discourage hydrate formation by heating the gas. However this is not always a practical solution.

2.

Consider, for example, a long undersea gas pipeline. This will lose heat to the surrounding water. It would not be possible to raise the initial temperature of the gas to a point which guarantees that the temperature at any point in the line, always remained above the hydrate formation temperature.

Removal of water.

This is, of course, what this unit is all about. Dropping free water out of the gas whenever possible will reduce the likelihood of hydrate formation.

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

However, the pressure and temperature changes involved in the dehydration process will, in most cases, give rise to the condition for hydrate formation before enough water can be removed to inhibit such formation.

4. Lower the hydrate formation temperature

A real chicken and egg situation!

When a chemical is added to the gas to prevent hydrate formation, it is often known as chemical inhibition.

We are, therefore, left with the last two - heating and chemical inhibition - as the most convenient methods of hydrate prevention.

Let’s consider each of the four preventative measures we have just listed.

The decision on the type of inhibition is invariably made on an economic basis. Usually, a combination of heating and chemical inhibition is the result.

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

3.

If heat is the answer, maximum use is made of heat conservation within the process by using heat exchangers. For example. the relatively high temperature of gas at the wellhead may be used to warm up the cold, processed gas, as we shall see later.

4.

Chemical inhibition.

I want to concentrate on chemical injection as a method used to prevent hydrate formation. Ammonia, brines, glycol and methanol have all been used to lower the freezing point of water in gas. Methanol and glycol are the inhibitors most widely used. These are fed into the gas by low volume injection pumps. The injection point is usually just upstream of the point where hydrate formation conditions are expected.

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One such point is illustrated in Figure 8 at the Xmas tree. The inhibitor can be used here to prevent hydrates forming on the valves of the tree during a shut-down. This injection point can also be used to inject inhibitor into the flowing gas stream to prevent hydrate formation in pipework and processes immediately downstream. Methanol is mainly used where only occasional inhibition is needed, for example plant start-up or when working on the well. The reason is that, although methanol is fairly cheap, its recovery is difficult and costly. It is, therefore, invariably lost. In addition, methanol is hazardous to store and handle; it has a fairly low flash point. Where continuous inhibition is needed, ethylene glycol (EG) is commonly used. Although it is more expensive than methanol, its regeneration is a reasonably straightforward process. There are three main forms of glycol used in gas processing, but it is ethylene glycol that is usually used for hydrate inhibition. We will talk about the other forms of glycol and their uses later. The injected glycol mixes with any free water that is present in the gas and lowers the hydrate formation temperature, in much the same way as the addition of anti-freeze to a car engine cooling system lowers the freezing point of the cooling water. The resulting glycol-water mixture can be processed to enable recovery and re-use of the glycol. This regeneration will be discussed later in this unit, as the process is identical 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:

i) For initially starting a new oil well which has a high gas content?



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

Methanol

Glycol

ii) For continuous injection into an offshore pipeline feeding an onshore gas plant?

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Summary of Section 1 In this first section the origins of water in natural gas have been explained and you know that it can take 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 you know its temperature and pressure (by reference to the graphs). It is important to remember that when 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 wellbore corrosion lower pipeline efficiency poor gas quality hydrate formation. Finally, we looked at preventing the formation of hydrates in gas, in particular by chemical inhibition with methanol or glycol. We will be applying our knowledge of hydrate prevention, both by heat and chemical inhibition, later on in this unit. You now have the necessary background knowledge for working through the following sections and understanding the processes described.

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Gas Dehydration

Section 2 - Auto Refrigeration

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In this section we are going to look at one of the characteristics of natural gas that assists in the separation of water from the gas - the Joules/ Thompson Effect. We will also look at a typical process plant which uses this principle in practice.

The Joules/Thompson Effect We have seen that, as the temperature is reduced, water vapour condenses into free water, which is fairly easy to separate from the gas. There are problems involving hydrates, of course, but we can deal with those by inhibition or process design, as we will see later on. The main hurdle we face is how to reduce the temperature at an acceptable cost. Fortunately, nature takes a hand. Gas has a property which can assist us to reduce the temperature fairly easily. Let me describe this property : If a natural gas is rapidly expanded by reducing the pressure, Its temperature will drop. This temperature drop associated with gas expansion is known as the JouleslThompson Effect. The greater the pressure drop, the greater the temperature reduction. You can see this effect illustrated in Figure 9.

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This chart is only by way of an example. It will not be accurate for all gases. However it serves to illustrate the use of such charts. In order to find a temperature drop associated with a given pressure drop, just follow the steps I have listed 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. Let’s do that with some actual figures. Take the following example: A natural gas at 3 000 psi and 90 deg F is expanded to 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.

Test Yourself 6 A gas is at 2400 psi and 80 deg F. From Figure 9, work out what temperature rise would be needed in this gas so that, after expansion to 1 500 psi the final temperature will be 75 deg F.

Of course, the starting pressure and temperature will not always coincide exactly with one of these cooling curves. In such a case, a curve parallel to the nearest printed curve needs to be drawn or imagined. For example, gas at 2 800 psi and 130 deg F is expanded to 1 400 psi. With a little imagination, you will see that the new temperature will be 86 deg F - a drop of 44 deg F. Now have a go at Test Yourself 6. In this example you will have to visualise your own curve from the figures given and work from that.

Check your answer in Check Yourself 6 on page 60

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The graph (Figure 9) also gives an indication of whether we can expect hydrates to form. This is shown by the broken line. Any point below this line provides conditions suitable for hydrate formation in the presence of free water. For instance, the example we used of 3 000 psi gas at 90 deg F being expanded to 1000 psi will place it firmly in the hydrate formation range. You may have wondered how the expansion of the gas is brought about, in order to utilise the Joules / Thompson effect. In fact, there are a number of ways of doing this. The most common one is to expand the gas across a choke valve. A choke valve is a type of valve designed to control gas or liquid flow. In its simplest form it consists of a cone and seat arrangement, both of which are hardened to resist the erosive effects of the flow. The closer the cone is to the seat, the more the flow is reduced, or choked. Such a device is illustrated in Figure 10.

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Before we go on to look at processes using the Joules / Thompson effect. practice using Figure 9 further.

Test Yourself 7 Complete the following chart Expanded to Starting Starting Final pressure temperature pressure (psi) (deg F) (psi) 4000

102

2000

3800

154

1000

2800

90

1800

2000

86

1200

1800

123

600

Final temperature (deg F)

Hydrates expected Yes/No

Check your answer in Check Yourself 7 on page 61

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The Joules/Thompson Effect forms the basis of a common method used to extract water from gas. This method is called low temperature separation. Low temperature separation makes use of the natural characteristics of gas expansion. This, together with efficient heat exchange within the plant design, leads to a very cost effective process. This is illustrated below. A low temperature separation process may be described as follows : The inlet gas is passed through a choke valve and cooled by the resulting pressure reduction and expansion. This causes water and liquid hydrocarbons to condense. Dry gas, condensate and free water can then be separated from each other. We will be looking at this in more detail shortly.

The effectiveness of this process depends on the initial pressure being high enough to allow an adequate pressure drop. Often dehydration can be achieved with a pressure drop as little as 1 000 psi. The downstream pressure is usually determined by the pressure of the pipeline being used to export or deliver the gas. By dropping the temperature, we may move into the hydrate formation region. This potential problem is dealt with in one of two ways: 1.

Inhibition

or 2.

Melting

Let’s look at two typical process plants which use either inhibition or melting to deal with hydrates. First, inhibition : Low Temperature Separation with Hydrate Inhibition (LTS) This process is illustrated as a simple flow diagram in Figure 11.

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Follow the path of the well fluids as they flow through the plant. The well stream first flows to a high pressure knockout vessel that separates any free liquid. The free liquids are removed from the vessel and passed on to another part of the plant for disposal. Ethylene glycol (EG) is then injected into the process gas stream immediately upstream of a heat exchanger HE-1. (You will remember from Section 1 that EG is a chemical used to inhibit hydrate torrnation.) The gas, with glycol added, is then cooled in the heat exchanger. This exchanger is known as a gas/ gas exchanger. It means that cold sales gas is the cooling medium which cools the incoming gas stream. (Sales gas is a term often used to describe gas treated to meet a laid down specification). A further temperature drop occurs as the gas expands during the pressure drop across the choke valve. This cooling causes further condensate and water to condense from the gas stream as it enters the cold separator.

At this point we have all the conditions necessary for hydrate formation. It means that the glycol injection rate upstream of here needs to be carefully controlled. It must be sufficient to prevent hydrate formation, in the heat exchanger, pipework or the separator. In the cold separator, glycol, water and condensate are separated from the gas and the condensate is recovered for further processing and sale.

The hot glycol-can now be used again. It is first passed through heat exchanger HE-2, where it is used to warm the incoming glycol/water mix from the cold separator. The regenerated glycol itself is cooled down here, prior to reinjection into the incoming well stream to act as a hydrate inhibitor again. Why don’t you go through the process once again at this point, and then have a go at Test Yourself 8.

We want to be able to use the glycol again. In order to do this, the water glycol mix is further processed in a glycol regeneration system. We will be looking at this regeneration system in much more detail when we come to Section 4 of this unit. Briefly, however: The glycol may have absorbed some hydrocarbons as it mixes with the gas in the process. These must be removed. The glycol and water are routed from the separator, via another heat exchanger (HE-2) where the mixture is heated up, to a flash tank. In this vessel, hydrocarbon vapours are removed from the warmed mixture. In the final part of the process the water is removed from the glycol. The glycol water mixture passes to a regeneration package where the mix is heated and the water is boiled off as steam.

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

In this process, the main pieces of equipment, apart from the regeneration package which we will look at later, are the separator and the heat exchangers. Let’s take a look at these pieces of plant in a little more detail. The cold separator used in our example is a Horizontal Three Phase Separator. This type of separator is illustrated in Figure 12.

The steps are out of order. Without looking at the flow diagram (Figure 11), rearrange the steps in 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

Check your answer in Check Yourself 8 on page 62

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The three phases are gas, condensate and water in this case. The condensate, being lighter, sits on top of the water and flows over a Weir into a separate compartment. From here the outlet valve is actuated by a level controller, to maintain a steady condensate level in this compartment. A second level controller maintains a constant water condensate interface. The gas section is fitted with a series of baffles that encourage the separation of condensed liquid droplets from the gas. This ensures that the gas leaving the separator is liquid-free. Let us now look at heat exchangers. We repeatedly refer to heat exchangers in this Unit, and you will meet 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 can be liquid or gas. Due to the temperature difference, the colder medium heats up, and the hotter one cools down.

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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)

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The basic differences between this process and the previous one are the routing of the warm well stream, the separator design and the absence of glycol injection or regeneration. Once again, follow the flow paths through the process, using Figure 14. This time, the warm incoming stream is first routed through coils in the bottom of the low temperature separator. This starts to cool the gas, which is then further cooled as it passes through a heat exchanger.

Cold gas, which has now had its water and liquid hydrocarbons removed, is taken from the separator and used as the cooling medium in the heat exchanger. (A by-pass line round the exchanger incorporating a 3-way valve maintains the correct temperature in the process). The gas, now at the correct specification, can be sold. The low temperature separator is again a 3 phase vessel, but of a different design. I have included a simple drawing of one (Figure 15) so that you can compare the two.

The effect of cooling is to condense some hydrocarbon liquids and water from the gas stream. These free liquids are separated from the gas in the liquid knockout drum and fed into the liquid section of the low temperature separator. After leaving the liquid knockout drum, the gas passes to the choke at the separator inlet. Here the gas is expanded to a lower pressure. Again, rapid expansion of the gas causes a drop in temperature. At this point, hydrates tend to form because conditions have now changed to values which encourage hydrate formation. The hydrates fall into the liquid section of the separator where they are melted by the warm coils.

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From here, the condensate and water are removed under controlled conditions. The condensate is sold and the water led off to disposal. The LTX process is obviously more cost effective than LTS, as glycol inhibition and regeneration are eliminated. Glycol or methanol injection may be necessary, however, for start up purposes, when the well stream will be cold. Now that you have worked through this section, have a go at the following Test Yourself question.

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

LTS

LTX

BOTH

Check your answer in Check Yourself 9 on page 62

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Summary of Section 2 This section opened with a description of the Joules/Thompson Effect, where gas expansion results In a temperature drop. You have seen how this characteristic of gas is used to good effect in 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, thus eliminating the need for expensive glycol inhibition or regeneration. You now understand the principles of the first method of gas dehydration, using low temperature separation 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 gas dehydration - the Solid Desiccant Dehydration process.

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Gas Dehydration

Section 3 - Solid Desiccant Dehydration In the last section, we examined how the principle of low temperature separation could be used to reduce the water content of a gas.

A gas dehydration process which uses this phenomenon is the Solid Desiccant Dehydration Plant.

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

In such a plant the gas is dehydrated by passing it through a bed of solid desiccant which removes the water vapour.

Adsorption Adsorption is a process in which a solid selectively removes a particular component from a fluid (liquid or gas) mixture and holds this component on its surface. This solid is known as an adsorbent material. In our case” the mixture consists of gas and water vapour, and it is the water which is removed. The adsorbent material, which removes the water, is called a solid desiccant. An everyday example of the adsorption process is the use of sachets of silica gel, packed along with sensitive photographic or electrical equipment. The silica gel is a solid desiccant which prevents moisture from damaging this equipment.

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Let’s now look at a Solid Desiccant Dehydration Plant.

This desiccant consists of solid granular materials having an extremely large surface area per unit weight. This is because the granules have a multitude of microscopic pores and capillary openings. Common desiccants used in the plant are: silica gel sorbead activated alumina molecular sieves After a time the desiccant will itself become saturated with water. This reduces its capacity for further adsorption and, in order to use it again, it must be regenerated. In other words, we must get rid of the adsorbed water. This is usually achieved by heating with hot gas, which vaporises the water from the desiccant. For this reason, a dry bed dehydrator usually has at least two beds of desiccant - one being used to dry the gas, while the other is being regenerated.

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

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The diagram shows a two tower dehydration layout. Take a look at the diagram and follow the process through. The solid lines represent the gas being processed, and the broken lines the regeneration cycle gas flow. One tower is on the adsorption cycle while the other is being regenerated. Gas being treated flows in at the top of the tower and adsorption takes place from top to bottom. Water saturation of the desiccant also, therefore, starts at the top of the tower. Lighter hydrocarbon components are also adsorbed in the lower layers of the desiccant bed. As the lower layers progressively become water saturated, the hydrocarbon components are displaced. The adsorption cycle must stop before the desiccant bed is totally saturated.

Effective regeneration is the secret of this process. The bed must be thoroughly regenerated or its capacity will be reduced. Effective regeneration relies on quantity and temperature of the regeneration gas. The higher the temperature, the less gas is required, but too high a temperature can ruin the desiccant, and drastically reduce its adsorptive properties. A typical cycle time is 8 hours of adsorption and 8 hours regeneration. Figure 17 gives a graphical representation of the regeneration cycle time and temperature.

Regeneration takes place in the reverse direction, that is, bottom to top. The regeneration gas is heated and fed in to the bottom of the tower. It passes through the desiccant and out through the top of the tower. The hot regeneration gas drives the water from the desiccant as steam. This wet, hot gas is then cooled and passed through a separator to remove the liquids. After the bed has been heated and the water driven off, it has to be cooled before it is switched to adsorption again.

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Use the figure to have a go at the following Test Yourself question.

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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 Virtually dry gas for processes sensitive to feed gas quality, such as cryogenic-type gas processing plants. (Cryogenic processing involves extremely low temperatures, much lower than the LTX and LTS plants we have been looking at). The effectiveness of the unit, however, depends upon the incoming gas being free of liquids, entrained mist and solids. Liquids may destroy or damage the desiccant bed, and solids could plug it.

Check your answer in Check Yourself 10 on page 63

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Summary of Section 3 You have been introduced to the removal of water vapour from gas using the mechanism of adsorption. You saw that adsorption is a process in Which a solid desiccant selectively removes one component from a fluid mixture. The solid desiccant has the capacity to attract and hold the component on its surface. We examined the workings of a dry bed dehydration unit, and concluded that such a unit relies mainly 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.

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Gas Dehydration

Section 4- Liquid Desiccant Dehydration In the last section we looked at a process Which removes water vapour from gas using a solid desiccant. We now turn to the use of a liquid, rather than a solid desiccant. This is known as an Absorption process.

•

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.

Absorption

•

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

Absorption of water by liquid desiccant is a process in which the water is taken into the body of the desiccant. This is in contrast to adsorption, where the water is held on the surface of the (solid) desiccant. Water vapour is removed by bubbling the gas through a hygroscopic liquid, that is, a liquid with an affinity for water.

A balance must be struck between the degree of effectiveness and the cost. Nowadays, therefore, TEG is the preferred liquid desiccant. TEG has been used successfully to dehydrate gases over the following operating ranges and conditions:

This hygroscopic liquid is our liquid desiccant.

• Dewpoint depression 40 - 140 deg F

Liquid Desiccants

• Gas pressure 25 - 2 500 psi

The liquid desiccant used is almost always one of the glycols. Glycols which have the necessary attraction 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.

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Glycol Dehydration Plant In a typical glycol dehydration plant the wet gas is brought into intimate contact with TEG. The glycol absorbs water from the gas, which then leaves the plant as dry gas. The glycol now contains water which reduces its absorbing properties. In order that the glycol can be used again, it must be regenerated. This is done by heating it and driving the water off as vapour (steam). Let’s follow the flow of gas and glycol through a typical dehydration plant.

• Gas temperature 40 - 160 deg F

We have our liquid desiccant. All we need now is a plant in which to use it. For the rest of this unit we will be looking at the equipment used in, and the layout and operation of, a Glycol Dehydration Plant.

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

The gas containing water vapour ( wet gas) enters the contactor, or absorber tower at the bottom. It passes up the contactor, through a series of trays down through which the TEG is flowing. The trays are so designed that the gas is forced to mix intimately with the glycol. The water from the gas is absorbed by the glycol and dry gas leaves the tower at the top.

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

This simplified description will help you gain a broad understanding of the process. Let us now study it in more detail and see how the equipment works.

The TEG also absorbs some light hydrocarbon vapour, and so the stream is directed to a flash tank. This reduces the pressure and therefore allows most of the hydrocarbon vapours to escape.

Gas Flow

Next, the lEG flows through a filter which removes any tarry solids which may have formed in the process. The glycol is then pre-heated in a heat exchanger and passed to the reboiler where the water is boiled off and the TEG reconcentrated.

Let’s start with the flow of gas through the system. The heart of the process is the contactor tower. It is in this unit that the dehydration takes place. The tower is called either the contactor or the absorber tower. For the rest of this section, however, I will use the term contactor. Look at Figure 19(a) which shows a contactor tower with a scrubber section and an absorber section.

The glycol is now capable of being used again. It is known as lean glycol at this point. From the reboiler, the lean glycol flows to a surge tank. It is pumped from here to the heat exchanger, where it is cooled. From there it flows back to the top of the contactor tower. (Note how the hot glycol from the reboiler is used as the heating medium in the heat exchanger). The process you have just followed is a continuous process and could be called a Regenerative Glycol Dehydration Process.

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Before the gas enters the absorber section of the tower, it passes through a scrubber to separate any free liquids. The scrubber may be a separate vessel or, as is the case here, may form part of the tower itself. It is essential that the contact between the gas and the TEG is intimate. This is achieved by bubbling the gas through the TEG via bubble caps positioned on a series of trays within the absorber section of the contactor. The contactor trays with the bubble caps, are shown in Figure 19(b). The trays incorporate a weir which maintains a fixed level of glycol on each tray. As the gas flows up through the centre of a bubble cap it is forced back down through the glycol and round the outside of the cap. This ensures that all the gas must flow through liquid glycol as it passes each tray. The flow path of the gas through a bubble cap is shown in Figure 19(c). After the top tray, the gas passes around glycol cooling coils. These act as heat exchangers to reduce the temperature of the incoming lean glycol. (The temperature of the lean TEG entering the top of the tower should be as close as possible to the gas exit temperature. This helps to prevent the glycol from foaming, which might occur if there was too great a temperature difference between lean glycol and gas).

Finally, before leaving the contactor the gas passes through a mist extractor. This device extracts any droplets of liquid glycol which may have been picked up by the gas. It helps to reduce glycol losses. The gas leaving the contactor should now be free from water vapour and meet the required dewpoint specification.

Glycol Flow Let’s now look at what happens to the glycol. The TEG, cooled in the coils (at the top of the tower), passes down through the tower from tray to tray, dehydrating the gas. This diluted (or rich) glycol solution collects at the bottom of the absorber section of the contactor tower. Before the glycol can be used to dehydrate more gas, it must be regenerated. Before we go on to look at the regeneration process itself, we should consider three other pieces of equipment. These are: • flash tank • filter • heat exchanger

The flash tank is simply a three phase separator which is capable of separating glycol, gas and hydrocarbon liquids from each other. You can probably imagine that, as the glycol flows through the contactor, it can pick up small amounts of gas, and liquids which have condensed from the gas. These are removed in the flash tank. Any gas which is liberated is led away to be used as fuel or is disposed of by flaring. Liquid hydrocarbons are removed from the tank and are collected for sale or otherwise disposed of. What remains is rich glycol which passes on to the next stage in the process. Within the glycol a certain amount of solid material may accumulate. This can take the form of dirt, scale, rust or tarry reaction substances. A filter is used to remove these. It is usually of the type which contains a cartridge which can be removed and replaced while the plant is in operation. I said earlier that the glycol must be heated in the regeneration process. In order to save energy, the glycol is pre-heated in a heat exchanger before it goes to the regenerator. The exchanger uses hot glycol from the regenerator itself as the heating medium. Let’s move now to the actual process of glycol regeneration.

Look again at Figure 18 and check the location of this equipment.

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Simply boiling the dilute glycol would remove the water as steam. but would also result in considerable loss of glycol vapour. As the boiling points of water and TEG are so far apart (212 and 549 deg F respectively). A process called fractional distillation is used to regenerate the glycol. The regenerator consists of two parts, the Reboiler and the Stripper column. Take a look at Figure 20 which shows such a unit.

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You will see that the cool, rich glycol passes first of all through a coil in the top of the stripper column. This is called a reflux coil. I will explain its function shortly. After pre-heating in the heat exchanger, the glycol is then fed to the stripper column near the top. It descends through packing in the stripper and mixes with a rising stream of water rich, hot vapours. These vapours are created by heating the glycol in the reboiler to a high temperature. This temperature should be above that of boiling water but below the boiling point of the glycol itself. Within the stripper column, two things are happening: • 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.

As long as the temperature at the top of the column ranges between 210 and 212 deg F, glycol losses are minimised. This process is aided by the reflux coil which I mentioned earlier. The cool glycol passing through the coils assists any glycol vapour to condense and fall back into the reboiler. Having passed down the stripper column, the glycol enters the reboiler and is heated further. This creates the hot, water-rich vapours required for stripping. From the reboiler the glycol passes to a surge tank which acts as a storage vessel. From there it is pumped via the heat exchanger back to the contactor to continue the dehydration process. So, you should by now have a good idea of how a liquid desiccant dehydration process works. Trace the flow path of gas and glycol again and then attempt the following Test Yourself.

Test Yourself 11 Following the flow path of glycol, place the jumbled list of equipment given below into a logical process order, starting with the Reboiler; Reboiler Contactor tower Heat exchanger Filter Surge tank Flash tank Pump

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

Check your answer in Check Yourself 11 on page 64

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Plant operations A glycol dehydration plant will only work efficiently if certain process variables are maintained at constant values. The more important process variables are : • glycol concentration • glycol circulation rate • glycol solution condition

The concentration of the glycol fed to the contactor tower determines the dewpoint depression achievable for a given contact temperature. The contact temperature is the temperature at which the gas leaves the top of the contactor tower. The temperature of the lean TEG entering the top of the tower should be as close as possible to this contact temperature.

Test Yourself 12 Think about the process plant. What piece of equipment is used to try to keep the temperature of the TEG entering the contactor as close as possible to that of the gas leaving it?

Let’s look at each of these in turn.

Glycol Concentration Glycol concentration refers to the amount of pure glycol in solution and is measured as a percentage by weight: For instance, the rich glycol leaving the contactor tower is a water rich solution whose glycol content is less than 95% by weight. However, after the glycol has been through the regeneration section of the plant it is reconcentrated. Now its concentration can vary from 95% to 99% by weight, although we try to achieve as near to 100% as possible. Check your answer in Check Yourself 12 on page 64

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We can use a graph again to see how glycol concentration and contact temperature can affect the dewpoint of the gas. Figure 21 shows the relationship between dewpoints, contact temperature and TEG concentration. If, for example, we need to achieve a reduction in water dewpoint of the gas from 55 deg F to 35 deg F at a contact temperature of 120 deg F, you can see that the TEG concentration must be increased from 96.0% to 98.0% by weight. This increased TEG concentration can be achieved by increasing the reboiler temperature. This can be shown in another graph, Figure 22, which appears on the next page.

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Take a look at Figure 22. In order to increase the TEG concentration from 96% to 98%, the reboiler temperature would have to be increased from 322 deg F to 380 deg F. There is a limit, however, to the temperature at which we can operate the reboiler. TEG begins to degrade at temperatures around 450 deg F, which clearly represents the upper limit.

Let’s work through an example to determine TEG concentration and reboiler temperature for a particular dehydration problem. For this example, let us assume that dehydrated gas must contain not more than 5lbs of water per mmscf when delivered at 1 000 psi and 100 deg F. Looking way back at Figure 2, which gives us the water content of natural gas at saturation, you can see that the required dewpoint is 24 deg F. If the gas leaves the contactor at 100 deg F it can be seen from Figure 21 that a 24 deg F dewpoint requires a TEG concentration of around 97.6%. (You will have to estimate between the curves to determine this). Figure 22 shows that 97.6% TEG concentration requires a reboiling temperature of 364 deg F (at sea level). Again some estimation or interpolation is required. If you are happy with the above example, try the following Test Yourself. You will see that you have to think back to some of the previous sections to complete it.

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

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Test Yourself 13

Another method of achieving higher TEG concentrations is to use stripping gas for final water removal. Stripping gas is dry, low pressure gas introduced to remove additional water from the glycol in the reboiler.

Gas at the wellhead is at 3000 psi and 120 deg F. After separation, its pressure is reduced across a choke to 1 000 psi, after which it is routed to enter the cold separator. The gas enters an absorption tower for dehydration. The required water content should not be more than 4lbs per mmscf. The gas leaves the contactor at 90 deg F.

Look again at Figure 20 which shows the glycol regenerator. You will see an inlet pipe at the bottom of the reboiler through which gas is entering the TEG. This is the stripping gas being used during reboiling.

i)

Is hydrate inhibition (or melting) required?

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

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?

Check your answer in Check Yourself 13 on page 65

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Now to the next process variable :

Glycol Circulation Rate It is important to maintain an optimum TEG circulation 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 be obtained by increasing the circulation rate. However, an upper limit can be reached where increasing the circulation rate actually reduces the dewpoint depression. And finally:

Glycol Solution Condition For effective dehydration, the glycol solution must be kept in good condition. In other words, it must be free from impurities. Solids must be filtered from the circulating stream and filters must be kept clean.

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Hydrocarbons in the TEG solution which have not been removed in the flash tank can cause additional foaming problems in the contactor. It is therefore essential that the efficiency of the flash tank is maintained.

Summary of Section 4 In Section 4, I explained the difference between Adsorption and Absorption. However, we concentrated on the Absorption process. You saw that Triethylene Glycol (TEG) is most commonly used as a liquid desiccant to absorb water from gas.

Now that you have completed Section 4, have another look at the process flow diagram and satisfy yourself that you understand how the plant operates.

You followed the operation of a glycol dehydration plant, and you will have noted that this consists of 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 a constant value for efficient dehydration. Now that you have completed the whole unit, you should have a basic understanding of the theory and practice of gas dehydration. Go back to the training targets on Page 2 of the unit, and check that you are able to meet those targets.

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Check Yourself - Answers

Check Yourself 1

Check Yourself 2

Check Yourself 3

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

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

70 deg F.

As 48 Ibs of water per mmscf were the saturation conditions at the reservoir, ie, more water vapour than required for saturation at the surface, the gas at the wellhead will be saturated. As there is a decrease in the amount of water vapour required for saturation between reservoir and surface, free water will exist in liquid form. The amount will be 48 - 45 = 3lbs per mmscf.

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Check Yourself 4

Check Yourself 5

Check Yourself 6

a.

The problems associated with water in gas that could affect gas processing, in the short term, are:

a.

25 deg F.



gas quality pipeline efficiency hydrate formation

b. i)

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

ii) iii)

Glycol, as long as the onshore gas plant has a glycol regeneration facility.

Corrosion is not included as it is unlikely to affect actual processing in the short term. b.

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

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

The starting point has to be the final conditions of 1 500 psi and 75 deg F. Follow an imaginary cooling curve parallel to the nearest printed curve until the 2 400 psi line is intersected. This gives us the temperature to which the gas requires heating. Temperature rise = 105 - 80 = 25 deg F.

Glycol, because it is safer to store for long periods.

* Remember that hydrates can form at or below the hydrate temperature.

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Check Yourself 7 Expanded to Starting Starting Final pressure temperature pressure (psi) (deg F) (psi)

Final temperature (deg F)

Hydrates expected 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 8

Check Yourself 9

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



LTS

LTX

1

The incoming well stream passes through coils in the separator.

a a

2

The choke is at the separator inlet.

a

3

Inhibitor is normally injected into the well stream.

a

4

The glycol is regenerated.

a a

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.

a

BOTH

a a a a a a

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Check Yourself 10 a.

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.

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Check Yourself 11

Check Yourself 12

Reboiler Surge tank Pump Heat exchanger Contractor tower Flash tank Filter

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

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Check Yourself 13 i)

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.

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