oil & gas separation book 1.pdf

POLPetroleum Open Learning

OPITO

THE OIL & GAS ACADEMY

Oil and GasSeparation

Part of thePetroleum Processing Technology Series

1

Petroleum Open Learning

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

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Contents Page* Training Targets 2* Introduction 3* Section 1 -The gathering System 4 Flow Lines

Headers

* Section 2 - The Theory of Separation 11 Methods of Separation

Stage Separation

* Section 3 - Construction of Separators 22 Classification of Separators

Separator Internals External Features of Separators

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 yoyu 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

Oil and Gas Separation Systems - Workbook 1(Part of the Petroleum Processing Technology Series)


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Training Targets

When you have completed Workbook 1 of this unit you will be able to :

Describe the construction and function of a typical gathering system

Explain the basic theory of oilfield separation

Explain how a typical separator achieves its process objectives

Describe the four main classifications with regard to separators

Describe the principal internal features of separators

Describe the external features of separators

Tick the box when you have met each target.


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Petroleum Open LearningOil and Gas Separation Systems IntroductionThe separation process is a fundamental part of all petroleum producing operations, whether they be in oilfields or gasfields.

The fluids which are produced from hydrocarbon reservoirs consist mainly of a mixture of oil, water and gas, in varying proportions. Before any further treatment of the fluids can be carried out, these three components must be separated from each other.

So, the objectives of a separation system are to :

* obtain oil which is free from gas and water

* obtain gas which is free from any liquids

The process which achieves these objectives is carried out in vessels which are called, not surprisingly, separators. These pieces of process equipment are common to all oil and gas producing operations, whether they are carried out on large offshore platforms or small land-based installations.

The term, Oil and Gas Separator, in petroleum production terminology, refers to a pressure vessel which is designed to separate reservoir fluids into liquid and gaseous components. You may, however, come across a number of other terms which are used to describe these or similar vessels. I have listed below a few of the alternative designations.

* trap

* knockout vessel

* stage separator

* flash drum

* scrubber

These terms are commonly used for specific applications. Throughout this unit I will simply use the term separator.

Before the fluids can be separated, the individual well streams must be combined and directed to the process. This involves the use of some form of pipework system. This system we will call the gathering system, and this is where I intend to start the unit.

The complete unit consists of 6 sections and occupies 2 workbooks. The first 3 sections are in Book 1 with the remainder in Book 2.

In Section 1, we will look at the function and layout of a typical gathering system.

Five further sections will follow this and these consist of:

Section 2, in which we will consider the basic theory of separation.

Section 3, where we will look at the construction of separators and discuss both their internal and external features.

In Section 4, we will have a look at the control of separators.

Section 5 covers separator safety systems.

Finally, in Section 6, we will look at routine separator operations.

In this training programme, I will use an imaginary separation system to illustrate the process. You should remember, however, that each production process is unique, and each one will differ in terms of number of vessels, process layout, etc.


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Reservoir fluids are produced to the surface via individual wells. You could think of the well tubing as a vertical pipeline topped with isolation valves, i.e. the Xmas tree.

The location of the Xmas tree will vary according to the type of production installation. If the production facility is on land, the Xmas trees will be located over a large area, possibly many square miles. On a conventional offshore production platform, the trees would be placed fairly close together on the cellar deck or wellhead area. A facility with subsea completions would have its Xmas trees on the sea bed, either close together on a template or remote from the production platform.

In this section we will concentrate on a typical offshore platform system. Here the Xmas trees are all located at the surface in an area of the platform known as the wellhead area.

Figure 1 is a simplified drawing of a typical Xmas tree indicating the terms used to describe the various valves.

flow wing valve (automatically activated)

Figure 1 Typical Xmas tree

choke

upper master gate

valve(automatically activated)

lowermaster gate

valve

Killwingvalve

swabvalve

Oil and Gas Separation Systems Section 1 - The Gathering system


From each Xmas tree, the well fluids have to be gathered together and transported to the process system. Each tree, therefore, is connected to a series of pipelines which will direct the flow of fluids to the process. This series of lines is the gathering system.

There are two types of line which make up the complete gathering system. These are flow lines and headers. Lets briefly look at each in turn.

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Flow LinesFlow lines are relatively small diameter pipes which connect each producing well to one or more of the headers which we will be looking at shortly.

Figure 2 is a simple line diagram showing the layout of a Xmas tree and its flow line.

You will see from Figure 2 that each well flow line is connected to its Xmas tree at the outlet of the choke valve (CV).

If you follow the flow path of the fluids along the flow line, you will see that immediately downstream of the choke valve is a non-return valve (NRV). The NRV is installed to remove any possibility of oil from one well back-flowing down another well.

In Figure 2 we can also see that two pressure switches are fitted to the flow line of each well.

The pressure switch low (PSL) will warn the operator if the flow line pressure is too low. The pressure switch high (PSH) will warn the operator if the flow line pressure is too high.

In both instances the pressure switches are tied in to the platform emergency shutdown (ESD) system. This is a safety system which enables a safe and effective shutdown of plant and equipment in a controlled manner if a hazardous situation should arise. We will be looking in more detail at ESD systems in Section 5. For the moment, I would ask you to accept the fact that, if either of the pressure switches is activated, then the ESD system will shut down the well.

Figure 2

Test Yourself 1

Which valve or valves on the Xmas tree would be activated from the ESD system to shut down the well?

You will find the answer to Test Yourself 1 on page 38

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The actual pressures at which the pressure switches will operate, i.e. the set points, will change during the life of the well. As the oilfield is depleted the pressure in the flow line will fall. As the normal operating pressure falls the set points will be lowered accordingly.

To see why the pressure switches are fitted to the flow line, we must think about what can occur whilst the well is flowing.

ActivityTake a few minutes to jot down on a piece of paper all the events which you think may cause the two pressure switches to operate.

What can happen to cause a low pressure situation?

What can happen to cause a high pressure situation?

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A number of events spring to mind. You have probably written something along the following lines:

Low pressure situations can be caused by :

* The well beginning to flow less oil due to problems with the well itself. These problems may be anything from a build up of wax in the tubing to a slug of water entering the bottom of the well.

* A valve closing on the Xmas tree. This could be due to operator error, or maybe a problem with the hydraulic system which should hold open the surface safety valve(s) on the Xmas tree.

* A large leak in the flow line itself. This could be due to a flange failure or a rupture of the piping.

* A low pressure problem further downstream.

The four low pressure situations described above are all triggered by unplanned events.

Now think about what would happen if a well is shut in intentionally for operational reasons - for example, if work needs to be done on the well.

When the well is closed, the pressure in the flow line will fall, and the PSL will activate the ESD system.

The well, therefore, has been manually shut down for operational reasons and the surface safety valve has been automatically closed.

So, when we want to reopen this well, we have a chicken and egg situation.

We cannot open up the wells surface safety valve because of the low pressure in the flow line, but, to restore the pressure we need to open up the well!

Obviously, in this situation, we need to override the ESD system in order to open up the well For this reason all PSLs are fitted with a by-pass switch. The by-pass switch allows the operator to open the surface safety valve when he brings the well on line.

Remember: once the well is back on stream the PSL by-pass must be deactivated.

Now lets look at some events which could cause high pressure in the flow line.

In your activity you have probably written something like:

High pressure situations can be caused by :

* The well beginning to flow more oil due to problems with the well itself. These problems may be caused by a slug of gas building up in the tubing, or the choke valve being eroded away as the oil flows across it.

* A valve being closed on the outlet of the flow line. This could be due to operator error when attempting to change over the well from one flow path to another or when putting the well on test.

* A high pressure problem further downstream in the process.

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Test Yourself 2

From the tubing of a well, fluids flow through a number of valves and along a flow line. The following valves would be found in this flow path, but they are not in the correct sequence. Place the valves in the right order, starting with the first valve in the Xmas tree.a choke valve.b upper master gate valve.

c non-return valve.

d lower master gate valve.

e flow wing valve


HeadersThe following diagram, Figure 3, shows how the flow path is continued from the flow lines to the separation system. In the process I am describing throughout this unit, the separation system comprises two parallel separator trains and a test separator.

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A separator train is a sequence of separator vessels. We will look at the layout and operation of such a sequence in Section 2.

In Figure 3 we can see that the flow line is connected to three short pipes. Each pipe is fitted with a block (isolation ) valve.

By opening one of the valves, and keeping the other two closed, we can divert the flow from each well to a different section of the separation system.

In the illustration we can see that there are three headers. The headers are relatively large diameter pipes which connect the well flow lines to the various parts of the separation process.

You can see from Figure 3 that the headers are routed to :

* Separation Train A

* Separation Train B, and,

* Test Separator.

Each well on the platform can be connected to each header.

The assembly of pipework where the different flow lines enter the headers is called a manifold.

The illustration shows :

Well A1 flowing to Separation Train A,

Well A2 flowing to Separation Train 'B' and

Well A3 flowing to the Test Separator.

We will look at the different types of separation systems later. At this stage you should note that any of the wells may be routed to any part of the separation process.

The manifold area of a typical offshore platform is a maze of pipes and valves. In our illustration we are connecting three wells to three headers. For these purposes we need nine valves. On a large platform there could be forty wells and five headers. Such a manifold area would require two hundred valves, all of which have to be located in a relatively small space. In an equivalent onshore processing system, the general layout is similar to the one I have just described. However, space is not usually such a problem and the manifold system can occupy a much larger area.

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Summary of Section 1In this rather brief section we have seen how the reservoir fluids are gathered together for further processing. The system of pipework used to do this is called the gathering system which comprises flow lines and headers.

You saw that flow lines are relatively small diameter pipes which connect each producing well to the headers. Flow lines incorporate pressure switches which sense abnormally high or low pressures and are part of the platform Emergency Shutdown ( ESD ) system.

Headers are larger diameter lines which transport the produced fluids from a number of wells to various parts of the separation process. We noted that the area of the gathering system where the flow lines enter the headers via the isolation valves is called the manifold.

At this point let me repeat once more that every process is unique. The layout of the pipework and the way that the ESD system works will vary from installation to installation. In this section we have simply looked at a typical system which is not meant to represent any specific installation.

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Methods of SeparationAny process which is designed to separate substances, relies on the fact that the substances are different from each other in some way. Lets consider for a moment how these differences can enable a separation process to take place.

Imagine that you have a mixture of sand, sugar and iron filings. What are the differences between these substances which would enable you to separate them from each other?

Oil and Gas Separation Systems Section 2 - The Theory of Separation

ActivityJot down in the box provided below a list of the properties of (or differences between) sand, sugar and iron filings which could assist in their separation.

Some of the things which you might have listed include :

The individual grains or particles may be of a different size.

Iron filings are attracted by a magnet, the other two are not.

The substances have different densities.

Sugar will dissolve in water, the other two will not.

Im sure that you will have thought of other differences but we could use just two of the above to separate sand, sugar and iron filings from each other.

If a magnet were to be introduced to the mixture, the iron filings would stick to it leaving sugar and sand behind.

Figure 4 on the next page, shows this being done.

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Figure 4

If the sand and sugar were stirred in a beaker of water the sugar would dissolve. The sugar solution could then be poured off leaving sand behind.

The following drawing, Figure 5 shows this.

Figure 5

In this simple example we have seen how differences between sand, sugar and iron filings can be used to separate them.

In an oilfield separation system the substances to be separated are oil, water and gas. The difference in this case is density.

Before we go on to consider the oilfield separation process in more detail, lets look at the components to be separated.

Crude Oil - this is a complex mixture of hydro-carbons produced from the reservoir in liquid form. Its density usually ranges from around 640 kg/m3 to 880 kg/m3.

Natural Gas - which is associated with an oil accumulation may be termed free gas or solution gas.Free Gas - is a hydrocarbon mixture which exists in a gaseous state at reservoir conditions of temperature and pressure. It remains as a gas when it is produced under normal conditions.Solution Gas - is dissolved in the oil at a certain temperature and pressure. If the pressure is reduced and/or the temperature is increased, the solution gas may be liberated from the oil. When this occurs the gas assumes the characteristics of free gas.The density of the gas depends upon the pressure at which it is confined. At 50bar a typical hydrocarbon gas may have a density of 36 kg/m3. However, at atmospheric pressure the density of that same gas may only be 1.6 kg/m3.There is a relationship between the volumes of gas and oil produced from a reservoir. This relationship is known as the Gas Oil Ratio (G.O.R.).G.O.R. is defined as the volume of gas produced per unit volume of oil production. The usual oilfield units for this ratio are standard cubic metres of gas per standard cubic metres of oil (sm3/ sm3). You may also come across the units standard cubic feet of gas per barrel of oil (scf/bbl).

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Test Yourself 3If the daily production from a field is 4400 sm3 of oil and 110,000 sm3 of gas, what is the field G.O.R?


Water produced with oil or gas may be in the form of liquid or vapour. The liquid water may also be in the form of free water or it may be emulsified in the oil. Other units in the Petroleum Processing Technology Series will deal with the problems of oilfield emulsions and water vapour in gas. In this unit we will just concern ourselves with the separation of free water from the oil and gas.

Produced water is usually salty and has a density somewhat higher than that of sea water. A typical oilfield water may have a density of 1072 kg/ m3.

If the three reservoir fluids of oil, water and gas were to be placed in a closed container and allowed to stand, separation would occur.

The water, being the most dense of the fluids, would sink to the bottom of the container. The oil would float on top of the water. Finally, gas, the least dense component, would occupy the space on top of the oil.

This then is the basis of oilfield separation.

However, reservoir fluids are being continuously produced and must be continuously separated. This takes place in one or more pressure vessels which are designed to achieve optimum separation as a continuous process.

The Oilfield Separation Process

The process can be described as :

* 2 phase separation or

* 3 phase separation

The phases referred to are oil, water and gas. In 2 phase separation, gas is removed from total liquid (oil plus water). In 3 phase separation, however, in addition to the removal of gas from liquids, the oil and water are separated from each other.

Figure 6 on the next page, shows the difference between 2 and 3 phase separation in a very simplistic way.

To check that you understand this ratio, have a go at the following Test Yourself:

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Lets consider 2 phase first. This would normally be used when the reservoir fluids contain only a small proportion of free water.

The total process within the separator can be broken down into 4 parts which we will follow now.

Part 1, Primary Separation

As the reservoir fluids enter the vessel an initial separation of gas and liquid takes place. This happens because of:

a reduction in velocity

a reduction in pressure

a change in flow direction

The velocity of the inlet stream is reduced as the fluids flow from a relatively small diameter pipeline into the large volume separator.

The pressure is reduced by maintaining a controlled pressure on the vessel lower than that of the inlet stream.

The change in flow direction is accomplished by placing some form of deflector at the inlet to the separator. (We will be looking in more detail at the internal features of separators in the next section).

Part 2, Secondary Separation

After the initial separation, gas will flow towards the outlet of the vessel. However, it will still contain a certain amount of liquid in the form of droplets. In the secondary separation process these liquid droplets are removed from the gas stream.

Liquid droplets which are suspended in the gas stream will tend to fall or settle towards the bottom of the vessel. This is simply due to the force of gravity.

Figure 614


The ease with which the droplets will settle out of the gas stream and fall into the liquid accumulation section of the separator depends on a number of factors. These include :

the size of the droplets.

the density of the liquid droplet compared to the density of the gas.

the velocity at which the gas stream is travelling through the separator.

the turbulence which exists in the flowing gas stream.

Of these factors :

The difference in density between oil and gas and the droplet size will be determined by the composition of the well stream.

The velocity of the gas stream is determined by the size of the separator and its throughput.

Turbulence can be reduced by having devices called straightening vanes built into the separator to make the gas flow more streamlined.

Figure 7 shows a typical set of straightening vanes inside a vessel.

Figure 7

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Part 3, Mist Extraction

The secondary separation of liquid droplets from the gas by gravity settling will not usually remove very small particles. These particles tend to remain in the gas stream in the form of a mist. In order that the gas leaving a separator is as free as possible from liquid, a final mist extraction section is built into the vessel.

Mist extraction is accomplished using either an impingement or a centrifugal force mechanism.

The most common mist extraction device is the knitted wire mesh pad which is an impingement mechanism.

Figure 8 shows a knitted wire mesh pad.

This type of mist extractor is placed near to the gas outlet from the vessel. As the gas containing the very small droplets flows past the wire mesh, the gas turns to flow round the strands of wire. The droplets, however, tend to continue in a straight line so they will strike the wire strands and stick to them.As more droplets stick to the wire, a film

of liquid forms which slowly moves to the lowest point on the wire. At this point the liquid accumulates to form a drop. When the drop is large enough it will break away from the surface where it has collected. From there it will fall down to the liquid accumulation section of the separator under the influence of gravity.

Figure 8

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Figure 10 shows a centrifugal force type mist extractor.

Figure 10

In centrifugal extraction, a continual change in gas flow direction at high velocities is required for small particle removal. This results in relatively large pressure drops across the extractor, which may limit its application.

Figure 9 shows the action of a knitted wire mesh pad.

Figure 9

The use of centrifugal force for mist extraction is usually confined to vessels where the gas flow is vertically upwards. If the gas stream containing liquid mist is made to flow in a circular motion, centrifugal force throws the liquid particles outwards. This causes the particles to impinge on the walls of the vessel or container. Here the small droplets will coalesce into larger droplets until they are large enough to gravitate to the liquid accumulation section.

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Test Yourself 4Reservoir fluids are flowing into a separator at the rate of 3600 sm3/day. If the liquid accumulation section of the separator is 7.5 sm3,

Is the retention time in this case sufficient for:

a. gas to be liberated from the liquid?

b. oil and water to separate?


Part 4, Liquid Accumulation

The lowermost section of a separator is where the liquids from the other three sections accumulate before being discharged from the vessel. Initially, this liquid will have gas bubbles entrained within it which must be removed.

Just as liquid droplets tend to fall through a gas stream, gas bubbles tend to rise to the surface of liquids due to density differences.

The time required for the bubbles to reach the surface and re-enter the gas stream will vary. However, for most oilfield applications it will occur in one to four minutes. This means that the liquids must stay in the vessel for this period of time, which is known as the retention time.

If the separator is of a sufficiently large capacity, this will ensure that the reservoir fluids stay in the vessel for the required retention time. You will remember that a 3 phase separation process not only removes gas from liquid, as we have just seen, but also separates oil and water.

This, in effect, adds a fifth part to the total process within the separator.

Part 5, Oil and Water Separation

Oil and water do not mix. If these liquids are left long enough in a vessel, separation will occur and the oil will float on top of the water.

Oil and water will separate faster than gas will be liberated from the oil. So, if the separator is large enough to allow efficient gas separation, then the retention time required for oil and water separation will be exceeded.

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Stage SeparationWe have just been looking at the separation process as it is carried out in one separator vessel. In practice, however, it is common to separate the reservoir fluids in a series of separators. This is known as stage separation and we will have a look at this now.

1 said in the Introduction that the objectives of a separation system are to obtain liquids which are free from gas, and gas which is free from liquids. When ideal separation has been accomplished, the gas and liquids have reached a state of equilibrium at the temperature and pressure within the vessel. In other words, at these conditions of temperature and pressure, no further separation would take place.

In most oilfield applications the goal is to stabilise the crude oil for shipment at pressures at or near to atmospheric. This means that the separator would have to be operated at this pressure.

In many circumstances it may well be possible to do this. However, imagine a situation where the pressure of the reservoir fluids at the wellhead is 170 bar and the gas oil ratio is 350 sm3/sm3.

If separation is to yield stabilised oil and gas at atmospheric pressure, then the separator may need to be extremely large. With a throughput of, say, 12,000 sm3/day) of oil, the separator must be capable of handling all that oil plus 4,200,000 sm3/day of gas. The pressure would also have to be reduced in one go, from wellhead conditions to atmospheric conditions.

In order to achieve optimum separation in such a case the process would be carried out in a number of separator vessels working in series. Each separator would operate at a lower pressure than its predecessor. This process is known as stage separation. At each stage the gas which is liberated and separated is removed and the liquid passes to the next vessel in the sequence.

The series of vessels used in a stage separation process is known as a train of separators. The number of vessels in a train varies, but usually ranges from two to four. We can refer therefore to a two, three or four stage separation train.

Figure 11 over the page, shows a train of separators for a 3 stage separation process.

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Summary of Section 2In this section we have looked at the basic theory behind separation.

You saw that, in order to separate substances from each other, there must be some physical or chemical differences between them.

The components to be separated in an oilfield system are oil, water and gas, and you saw that, in this case, thedifferent densities of the 3 phases allowed separation to take place. We broke the total process of separation down into 5 sections which take place in a separator. These are:

* The primary separation, which occurs at the inlet to the vessel due to three things.

- A reduction in pressure

- A reduction in velocity

- A change in flow direction.

* The secondary separation where gravity settling of liquid droplets from the gas takes place.

* The mist extraction section which removes very small droplets of liquid from the gas.

* The liquid accumulation section of the separator where retention time allows gas bubbles to be liberated from the liquid.

* The oil and water separation section (in a 3 phase separator).

In the last part of Section 2 of the programme we looked at stage separation. This allows the total separation process to take place in a number of separator vessels working in series. Stage separation is used where there is a large throughput of relatively high gas oil ratio reservoir fluid and where there is a large total pressure drop to be accommodated.

In the next section, we will be looking at the classification of separators, and the details of their construction.

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I have said already that a separator is a pressure vessel used to separate reservoir fluids into their constituent components. Most separators operate under pressure. Therefore, they are made from high quality steel and are constructed according to rigid specifications.

In a complete separation system there may be several vessels, and these can be classified in a number of ways.

So, before we go on to look at the construction of the vessels lets consider this classification of separators.

Classification of Separators1. Classification according to configuration.

Here we can divide separators into three types.

Horizontal Separators

Vertical Separators

Spherical Separators

The first two are the most common and are the ones we will concentrate on during the rest of this programme.

Oil and Gas Separation Systems Section 3 - Construction of Separators

Figure 12a : Horizontal Separator

Figure 12 shows a simple outline of these two types.

Figure 12b : Vertical Separator

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2. Classification according to number of phases separated.

These are :

* 2 Phase Separators

* 3 Phase Separators

In a 2 phase separator, gas is separated from total liquids. A 3 phase vessel however also separates oil and water from each other.

Figure 13 shows a sketch of a 2 phase vertical separator and a 3 phase horizontal separator.

Note that the 2 phase vessel has one inlet and two outlets, whilst the 3 phase vessel has 3 outlets, one each for oil, water and gas. Figure 13b : 3 phase Separator

Figure 13a : 2 phase Separator

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3. Classification according to duty.

In this classification we can describe separators as :

* Bulk Separators

* Test Separators

* Clean-up Separators.

As the name suggests Bulk Separators are used to process most of the fluids passing through a system, and they are in continuous use.

Test Separators are used to check the production rates of individual wells. At regular intervals, each well in turn will be taken out of the main process flow stream and diverted to the test separator. Because this vessel has only to handle the production from one well at a time, it is frequently smaller than the bulk vessels. The test separator is always equipped with meters on each outlet line, to measure the flow rates of oil, water and gas.

When a new well is brought on stream it will often produce drilling fluids and other contaminants for a period of time. Such a well may be flowed initially through a Clean-up Separator, with the fluids being disposed of by flaring until clean reservoir fluids are being produced. A clean-up separator can often double as a second test separator.

4. Classification according to position in a train of separators.

As you have seen, a separator train may consist of a number of vessels operating in series.

These separators may be designated :

* 1st stage - 2nd stage - 3rd stage and so on.

or

* High pressure - Medium pressure - Low pressure.

Figure 14 on page 25, shows a complete separation system.

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Note that the system shown in Figure 14 is a continuation of the manifold system shown in Figure 3 in Section 1.

Look at the two figures and follow the flow from each well in Figure 3 through the separation system in Figure 14. You will see from Figure 14 that the liquid outlet from the test separator can be directed to either train 'A' or train 'B', at the inlet to the second stage.

Figure 14

Now lets have a look at the internal features of separators which help to achieve the process objectives.

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A horizontal separator relies on properly shaped and positioned deflector devices to perform the function. A simple baffle plate may suffice for lower G.O.R. streams, while a dish deflector would be more suitable for most applications.

Figure 16 shows an example of each type.

Figure 16a : Baffle Plate Inlet Deflector

Figure 16b: Dish Deflector

Separator Internals

1. Inlet DeflectorsYou saw in Section 2 that a change in flow direction of the inlet stream is required as part of the primary separation process. This rapidly dissipates the energy of the incoming stream and quickly removes large slugs and droplets of liquid from the gas.

It can be carried out in a vertical separator by having the inlet nozzle to the vessel constructed at a tangent to the vessel shell. This causes the inlet stream to swirl around the inside of the separator under the influence of centrifugal force. Large volumes of fluid can be separated quickly in this way.

Figure 15 shows the tangentially positioned inlet nozzle on a vertical separator.

Figure 1526

Gas

liquid

liquid


2. Straightening VanesYou will remember from Section 2 that turbulence in the flowing gas stream can be reduced by incorporating straightening vanes in the separator.

I have included Figure 17 which is the same as Figure 7 on page 15 to remind you of the construction of a set of straightening vanes.

Figure 17

3. Mist Extractor

We also looked at mist extractors in Section 2.

Test Yourself 5Make a simple sketch of a mist extractor which you might find in a separator.


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4. Horizontal BafflesThese are flat plates located in the separator just above the liquid accumulation section. They help to prevent waves in the liquid which might result in liquid re-entrainment in the gas stream.

The horizontal baffles may also provide the support for some of the other internal features of the separator. Look back to Figure 17. You will see that the straightening vanes are supported on horizontal baffles.

5. Vortex BreakersWhen large volumes of liquid are being run out of a vessel through an outlet at the bottom, a vortex may form. I'm sure you have noticed this when you have pulled the plug in the bath and watched the water run out. It is the cone shaped whirlpool which forms above the plughole. If this occurred in a separator, it could drag gas into the outgoing liquid stream, thus defeating the purpose of the vessel.

To prevent the formation of a vortex, some type of breaker may be used. A typical one is shown in Figure 18.

Figure 18 : The Liquid Outlet End of a Separator Showing a Vortex Breaker

This internal pipe with holes, is fitted to the liquid outlet nozzle inside the separator. The outlet stream from the vessel cannot swirl around to form a vortex.

6. WeirsThese are vertical baffles placed in the liquid accumulation section of the separator. In a 3 phase vessel they separate the oil accumulation area from the water accumulation part. They may also be used to isolate a section of the oil accumulation part of the separator. This will then provide a calm area for level control equipment to operate in.

We will be looking at the controls of a separator in Section 4 of this programme.

The six internal features of separators I have just described are the most common.

The two parts of Figure19 between them show all the six features I have just described.

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Vortex Breaker


Figure 19a : A 3 phase Horizontal Separator

Figure 19b : A 2 phase Horizontal Separator

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However, other internal devices may be found in separators. These can include :

Coalescing Plates. A type of mist extractor consisting of a series of parallel plates on which small droplets of liquid mist collect and join (coalesce) to form larger ones. The straightening vanes which we looked at earlier also act as coalescers.

Water Jets. Sometimes sand may be produced from the wells, and these solids would tend to accumulate in the bottom of the separator. Where sand accumulation is a problem, water washing facilities may be installed. These devices consist of nozzles inside the separator with an external connection to which can be fitted a high pressure water supply. Accumulated sand at the bottom of the vessel can be stirred up prior to draining it from the separator during maintenance of the equipment.

Now that you are familiar with what is likely to be found inside a separator, let's go on to look at the external features of these vessels.

External Features of SeparatorsEvery separator has a number of connections to the vessel shell. Some of these connections are simply the fluid inlet and outlet pipes. Other connections support equipment used to monitor the operations, control the operations or to ensure safe operating conditions.

In Section 4 we will be looking in more detail at the control of separators. Here, I just want to consider the basic equipment used to monitor the liquid levels and pressure inside separator. These are the simple Pressure Gauge and the Sight Glass.

Pressure GaugeThe most common type of pressure measuring instrument found on a separator is a mechanical device incorporating a Bourdon Tube.

In its simplest form, the Bourdon Tube consists of a metal tube with an oval cross section. The tube is bent into the shape of a letter 'C'.

One end of the tube is fixed and open to the pressure to be measured. The other end is sealed and free to move. This free is connected via a series of linkages to pointer which moves around a scale

When pressure is applied to the inside of the tube its cross section tends to change from an oval to a circular shape. This makes the tube try to straighten out. The free end movement of the tube is transmitted via the linkage to the pointer of the gauge.

Figure 20 on page 31, shows the inner mechanism of the Bourdon Tube type Pressure Gauge.

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Figure 20 : The Inner Mechanism of a Bourdon Tube Type Pressure Gauge

ActivityMake a note below of a potential problem which might arise from having a pressure gauge attached directly to the shell of the separator.

The shell of the separator has threaded outlets, called bosses, for connecting pressure gauges. However, the gauges should never be attached directly to the vessel itself. A suitable pressure gauge valve should be connected to the vessel and the gauge screwed into the valve.

Why do you think that the gauge should never be connected directly onto the separator?

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Imagine a pressure gauge screwed directly to a separator as is shown in Figure 21.

Figure 21

If for some reason the gauge needs replacing, how can it be done? It will require the separator to be taken out of service and depressurised before the gauge can be removed.

If, however, a valve is connected to the vessel and the gauge screwed into the valve there is no problem. The valve can be closed to isolate the gauge from the vessel pressure, then the gauge removed and replaced without interrupting the process.

Figure 22 shows this being done.

Figure 22

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Sight Glass

Sight glasses, which are commonly called gauge glasses, provide a continuous visual indication of liquid level in a vessel.

The simplest type of sight glass consists of a vertical glass or plastic tube connected to the vessel by piping. The liquid level in the tube will be the same as that in the vessel.

Figure 23 shows this very simple arrangement.

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The simple glass or plastic tube is only suitable for very low pressure applications. For higher pressures a much more substantial piece of equipment is required.

A reflex sight glass is commonly used on separators for this purpose.

It consists of a special metal column with a recess machined in one side. A tempered glass window fits over the recess and is held in place by U' bolts and a housing. The glass window forms a pressure tight seal with the column.

Figure 24 shows this construction.

The recess in the column is connected via pipework to the separator, so the level in the sight glass is the same as that in the vessel.

The glass slab of the window is smooth on the outside but has triangular grooves cut in its inside face. This feature helps to give a clear indication of the interface between liquid and gas. This is particularly important where the liquid is transparent, such as water

Figure 2434


The clear indication comes about because of the way that light behaves. Light rays entering the glass above the liquid level strike the grooves which are in contact with gas. These are reflected back to the outside which makes the outside of the glass look light. However, when the light rays enter the glass where the grooves are in contact with liquid, some of the light is absorbed. Less light is reflected back to the outside of the glass and it will look much darker.

The insets of Figure 24 shows this.

Sight glasses are fitted to the separator using special valves called ball check valves. These are designed to block off the flow of liquid or gas should the sight glass itself rupture.

Figure 25 shows a typical ball check valve.Figure 25Figure 25

The ball within the valve remains stationary under normal operating conditions. It allows the normal flow of liquid or gas through the valve as the level moves up or down. If the glass should break, however, there would be a rush of fluid through the valve. This would force the ball tightly against its seat, stopping the loss of fluid.

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Test Yourself 6From the following list items, indicate whether they are internal components of separators, external features, or not part of a separator at all.

Internal External None

1. Inlet nozzle o o o 2. Horizontal baffle o o o 3. Sight glass o o o 4. Pressure gauge o o o 5. Swab valve o o o 6. Mist extractor o o o 7. Master gate o o o 8. Outlet nozzle o o o 9. Inlet deflector o o o10. Header o o o11. Straightening vanes o o o12. Vortex breaker o o o


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Summary of Section 3In this section we have been looking at the physical appearance of separators and their construction.

We started the section by first considering how separators may be classified. You saw that the main classifications are based on :

configuration

number of phases separated

duty

position in train

You saw a drawing of a complete system having 2 trains of 2 phase horizontal separators, with 3 stages in each train. A test separator was also included in the system.

In the second part of the section we looked at separator internals. We identified the six common internal features as :

Inlet deflectors

Straightening vanes

Mist extractors

Horizontal baffles

Vortex breakers

Weirs

Finally we had a look at the external features of separators.

These included :

Pressure gauges

Sight glasses

Inlet and outlet nozzles

Make sure that you are completely familiar with these features before proceeding to the next section.

In the next section we will look at the basics of separator control.

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Check Yourself 1 If you look at Figure 1 you will see that 2 valves are automatically activated. These are the ones which would be activated from the ESD system, i.e. the upper mastergate valve and the flow wing valve. These two valves are also referred to as surface safety valves.

Check Yourself 2 The valve order would be :

d - b - e - a - c

Check Yourself 325 sm3/ sm3

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Check Yourself 4 The flowrate into the vessel is 3600 sm3/day or2.5 sm3/min. The retention time is therefore (7.5/2.5) = 3 minutes

In most cases this is sufficient time for both gas and water to be separated.

Check Yourself 5

This is the same type of mist extractor as Figure 8 in the text. i.e. a knitted wire mesh pad. However you may have sketched a centrifugal extractor, which is shown as Figure 10 on page 17.

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Check Yourself 6From the following list items, indicate whether they are internal components of separators, external features, or not part of a separator at all.

Internal External None

1. Inlet nozzle o o o 2. Horizontal baffle o o o 3. Sight glass o o o 4. Pressure gauge o o o 5. Swab valve o o o 6. Mist extractor o o o 7. Master gate o o o 8. Outlet nozzle o o o 9. Inlet deflector o o o10. Header o o o11. Straightening vanes o o o12. Vortex breaker o o o

3 3 3 3 3 3 3 3 3 3 3 3

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