Produced Water Treatment

POL Petroleum Open Learning

Produced Water Treatment Part of the Petroleum Processing Technology Series

OPITO THE OIL & GAS ACADEMY

Petroleum Open Learning

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

Printed by Astute Print & Design, 44-46 Brechin Road, Forfar, Angus DD8 3JX www.astute.uk.com

© OPITO 1993 (rev.2002)

ISBN 1 872041 85 X

All rights reserved. No part of this publication may be reproduced, stored in a retrieval or information storage system, transmitted in any form or by any means, mechanical, photocopying, recording or otherwise without the prior permission in writing of the publishers.

Petroleum Open Learning

Produced Water Treatment

Petroleum Open Learning

(Part of the Petroleum Processing Technology Series)

Contents

Page

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Training Targets

4

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Introduction

5

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Section 1 - The Problems Associated with Produced Water

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The Mechanics of Water Production Corrosion Problems Scale Problems Transportation Problems Disposal Problems

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Section 2 - The Basics of Produced Water Treatment



Primary Separation Gravity Separation Coalescence Short Distance Gravity Separation Gas Flotation Centrifugal Force Separation Chemical Treatment

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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Petroleum Open Learning

Petroleum Open Learning

Produced Water Treatment

Petroleum Open Learning

(Part of the Petroleum Processing Technology Series)

Contents (cont’d) *

Section 3 - Produced Water Cleaning Equipment



API Separators Plate Interceptors (or Separators) Oil / Water Filters Coalescers Gas Flotation Units Hydrocyclones Use of Chemical Additives

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Section 4 - A Typical Produced Water System



Tilting Plate Separators The Flotation Unit Chemical Dosing Package Produced Water Caisson

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Test Yourself - Answers

Page 23

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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 When you have completed this unit on Produced Water Treatment you will be able to : • List the sources of produced water • Describe the mechanics of water production • Explain what problems can arise from the production of water • Explain the basic principles which govern the separation of oil from produced water • Describe the construction and operation of 5 types of oily water clean up facility • Explain the requirement for chemical injection in a produced water treatment system



• Describe the flow of water and separated oil through a typical produced water treatment facility Tick the box when you have met each target.

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Produced Water Treatment

Petroleum Open Learning

Introduction

In the vast majority of oil fields, water production becomes a problem as the field gets older. Towards the end of their useful lives some oil wells may be producing 95% of their total liquid as water. This produced water may be extremely salty and likely to be of little value to the operator. It is removed from the oil stream during primary separation and by other facilities, and has then to be disposed of. However, we are talking of a great deal of water in some cases. How do we dispose of it, and where do we put it?

Offshore, the obvious place would be into the sea. Dumping this produced water directly from separators into the sea, would however, soon have the operator in trouble with the authorities. Even after initial separation the water still contains oil in small amounts. Serious environmental pollution would build up if oil contaminated water were to be dumped directly to the sea. Onshore, disposal wells may have to be drilled, into which the produced water can be injected for disposal. This also may have its problems. Oil in the water, or fine solids, could plug the injection wells in a very short time. So the water which is produced with, and separated from, the oil in an oilfield must be cleaned prior to disposal. This is what this unit is all about. In the

unit, we will be looking at the produced water handling system of an oil production facility. Before we examine a typical system, however, I think we should look at where the water comes from and the problems it poses in a little more detail. So, I have split the unit into four sections as follows: • In Section 1 we will look at the sources of produced water and the problems which may be encountered if we fail to treat it. • Section 2 will cover the basic principles involved in the treatment and clean-up of produced water. • In Section 3 we will examine the construction and operation of produced water clean-up equipment. • Finally, in Section 4, I will take you through a typical produced water handling facility which may be found on an offshore production platform.

Although produced water treatment applies to both onshore and offshore locations, I will be concentrating on the offshore situation in this unit. However, most of what I have to say would apply to both.

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Produced Water Treatment

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Section 1 - The Problems Associated with Produced Water Water is present in some form, in most oil reservoirs before any production takes place. There are however, many different types of reservoir. In one very common one, the oil accumulates above large volumes of water, which is usually salty. This water is what remains of ancient seas from an earlier period of Earths history.

The Mechanics of Water Production Look at Figure 1 which shows a cross section through a typical water drive reservoir.

This body of water is called an aquifer, and the reservoir is known as a water drive reservoir. In addition, a considerable amount of water may also be found as small droplets distributed throughout the oil (and gas) in a reservoir. For reservoir engineering purposes this water is called connate water or interstitial water. We will just call it formation water. During production, further injection water may be pumped into the reservoir to assist in pressure maintenance. Any of these types of water may eventually find their way into the oil wells and be produced to the surface along with the oil. It is all then called produced water. Before we look at the problems which can be caused by this produced water, let us first consider how the water gets into the producing wells,

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You can see that the oil lies above the aquifer and the well is taking oil which is not contaminated with water. The point at which the oil and water touch each other is called the oil water contact. The oil is able to flow through the reservoir rock towards the well because the rock is porous and permeable. These are probably the two most important properties of reservoir rocks. POROSITY Porostiy is the property of the rock which enables it to hold fluids within itself. The oil, gas and water are contained in tiny holes in the rock called pores. Sandstone is a common reservoir rock. It is made up of grains of sand which are cemented together at the points where they touch. Between the sand grains are void spaces - the pores. The ratio of the volume of the pores to total rock volume expressed as a percentage is the rocks porosity. This means that, if you have a sandstone reservoir with a porosity of 25%, for every 4m3 of reservoir rock, 1m3 consists of holes and 3m3 solid sand grains. Another common reservoir rock is limestone. This is a rather brittle rock which contains lots of tiny cracks and fissures. These tiny cracks give the limestone its porosity.

PERMEABILITY Permeability is a measure of the ability of a fluid to flow through the rock from one pore to another. In order for it to be able to do this, the pores must be interconnected. Permeability is measured in d’arcys- named after a French engineer who studied the flow of liquids through filters. He found that the flow increased in proportion to the pressure increase. However he also discovered that the flow was affected by the thickness, or viscosity, of the fluid.

The high pressure water in the aquifer, therefore, will tend to displace the oil towards the low pressure areas surrounding each well bore.

Figure 2 on the next page, shows the situation with just one producing well and one water injection well.

Generally there is a wide spread of permeability in reservoir rocks. So, the rock properties of porosity and permeability allow the oil to flow towards the producing wells. But what causes the oil to flow through the reservoir? Let’s look at that now. You are probably aware that fluids always flow from areas of high pressure to areas of low pressure: • The oil producing wells create areas of low pressure in the surrounding reservoir rock as the well is opened at the surface and oil flows into the well • The aquifer is usually at a relatively high pressure. In addition, the injection of water into the aquifer is intended to maintain the reservoir pressure

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If this situation remained constant there would be no problem. However the situation does not remain constant. Think about this and try to answer the following Test Yourself question.

Test Yourself 1 As oil is removed from the reservoir what will happen to the position of the oil water contact ?

You will find the answer to Test Yourself 1 on Page 47

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Over a period of time, as the oil water contact approaches the well intakes, the water will start to flow preferentially to the oil wells. This occurs because the water is much less viscous than the oil and therefore flows more easily through the rock, bypassing the oil. The water is said to finger through the oil. Figure 3 shows water starting to follow these preferential routes through the reservoir rock.

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Once water starts to break through to the producing wells, it tends to be produced in ever increasing amounts. The ratio of water produced to total production is called the water cut and is expressed as a percentage. To make sure you understand this, have a go at the following Test Yourself question.

The water cut from a particular well or field depends on a large number of factors. These include:

Test Yourself 2 a)

If a well produces 3975m /d of oil and 795m3/d of water, what is the water cut.

b)

A well produces a total of 875m3/d liquids and the water cut is 20%. What is the oil production from this well.

c)

What is the water cut of a well if the total production is 556m3/d., and the oil production is 397m3/d

3

• The geology and porosity of the reservoir rock • The size and, particularly, the vertical thickness of the reservoir • The degree of fracturing of the oil field • The position and depth of the producing wells in relation to the oil water contact • How long the reservoir has been producing oil Actual water cuts vary tremendously, of course, but can be as much as 99%. Imagine a field which produces a total of 15,900m3 of liquid per day with a water cut of 60 %. This means that 9540m3 of water are produced every day. This can pose significant operating problems and these are what we will look at now.

You will find the answers to Test Yourself 2 on Page 47

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Corrosion Problems We said earlier that the aquifer water can be very salty. Injection water, being in the main sea water, is salty as well. It follows then that the produced water will be salty also. In fact the saltiness, or salinity, of produced water is usually considerably more than that of normal sea water. To put it in perspective: • fresh water from streams, lakes etc. usually contains less than 0.2 % salt • sea water has an average salt content of 3.5% • produced water can contain up to 15% salt Pure water in itself is not particularly corrosive. However, up to a point, the more saline it becomes the more corrosive it is. If the produced water is allowed to pass through all the surface processing equipment to the oil transportation system, it could cause considerable corrosion damage to pipes, vessels and other equipment. In fact, corrosion costs the petroleum industry millions of pounds annually. It makes sense to try to reduce this expense.

One of the ways of reducing corrosion damage is to separate the water from the oil at the earliest opportunity and dispose of it. In fact this, together with the separation of gas, is one of the first processes in a production facility. This however gives rise to another problem - one of disposal. We will look at this shortly.

Scale Problems Salts are initially dissolved in the water present in a reservoir. As conditions change when this water is produced, the salts may be precipitated as solids and deposit as scale. This can reduce pipe diameters, plug vessels and equipment which in turn can lead to lost production. Once again, removal and disposal of produced water can help prevent the problems of scaling.

Transportation Problems The produced oil may have to be transported from an offshore location to a shore based refinery or tanker terminal. There are two ways of doing this. If the field is large and the economics justify it, the best way is by pipeline to shore. However, some fields are too small to justify the expense of a pipeline or are too far from shore. In this case the oil is loaded into a tanker at the point of production via a tanker loading facility. Either way, water in the oil to be transported can cause problems: • The obvious one we have looked at already, that of corrosion. Salt water in pipelines or tanker loading units can corrode facilities rapidly. I don’t think I need to elaborate on that at this time. • If the oil is going down a pipeline, excess water reduces the efficiency of the line, leaving less space for oil. • Water being sent to a refinery with the oil can cause serious upsets in the distillation process. Refinery operators usually limit the amount of salt and water which they will accept. • When loading oil to a tanker there are laid down limits of water in oil which it is permitted to take. If more than, say, 0.5 % of the cargo loaded is water, then the producing company can face severe penalties.

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It would seem from the foregoing that one of the first things which we must do on a production facility is get rid of the water. This is of course what happens. On most installations water is separated from the produced oil in the first process system. The separated water has no value and has to be disposed of. But how? This brings us to our final problem, that of produced water disposal.

Disposal Problems When trying to decide how to get rid of the water we must consider first of all the location of the production facility. Think for a moment and try to decide how you would dispose of 1590m3 per day of produced water from a site on land. You may have come up with one of the following: • Dump the water into lakes or rivers • Dump the water into sewers Both of these solutions would be totally unacceptable. In the first case, pollution of the fresh water by the Salts in the produced water would cause damage to the environment and could destroy wildlife. Drops of oil in the water would also cause considerable environmental pollution.

Sewers are not built for these amounts of water and would be overloaded, in addition to suffering pollution problems at the outfalls.

For instance, discharging produced water into the sea in the UK sector of the North Sea is subject to compliance with the following conditions at present:

You may have thought of drilling wells and injecting the water back into a reservoir. This is in fact done. But the water has usually to be treated before it can be injected. It may have to be filtered and dosed with chemicals to make it suitable for injection.

• On average, discharged water must not contain more than 30 ppm by weight of oil.

If the production facilities are located offshore the problem of disposal may seem easier. Why not just dump it into the sea? Unfortunately it is not quite that simple.

• For a normal month of sampling, not more than three samples (4% a month) may exceed the limit of 100 ppm.

After initial separation, the produced water is still likely to contain a considerable amount of oil in the form of small droplets. The actual amount will vary from installation to installation but could be of the order of 150 ppm. (The unit ppm means parts per million. In other words, in every million drops of liquid 150 of them would be oil, the rest water.) This may not seem very much, but if those quantities were dumped into the sea, an oil slick would soon form and pollution would occur. In most countries the removal of oil from produced water before dumping it into the sea is a legal requirement. The quality of produced water disposed of in this way is subject to strict control.

• An oil content of up to 100 ppm is allowed in individual monitoring samples

• Regular monitoring of effluent discharged from each platform to the sea is a stipulated requirement • Samples should be taken at 0700 and 1700 hrs each day The figures of 30 ppm is the one currently in force and is constantly under review. It is not inconceivable that it could be reduced even further at some future date. So, bearing in mind that I said that we would concentrate on an offshore location, it would seem that our biggest problem is getting the oil-in-water concentration down to acceptable limits. This is what we will concentrate on for the rest of this unit.

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Before going through the summary of this section, try the following Test Yourself question,

Test Yourself 3 Are the following statements true or false?

a) Permeability is a measure of the ability of a rock to allow fluids to pass through it. b)

The oil water contact within a reservoir tends to move down as the production from the field proceeds.

c)

Seawater usually has a greater salt content than produced water.

d)

Produced water can cause loss of efficiency in pipelines.

e)

In the UK sector of the North Sea discharged water must not contain more than 130ppm by weight of oil.

True

False

You will find the answers to Test Yourself 3 on Page 47

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Summary of Section 1 During this section I have tried to introduce you to the problems arising from the production of water with oil. We started by looking at the sources of produced water and you saw that it can be from the aquifer, formation water or the injection water which is used to maintain reservoir pressure. We then looked at the mechanics of water production and considered the rock properties of porosity and permeability which allow fluids to flow through a rock. You saw that the relatively high pressured water underlying the oil pushes the oil towards the wellbores. However the water may eventually start to finger through the oil and be produced in ever increasing quantities. You discovered that very large quantities of water may be produced and I defined the ratios of oil and water production as the water cut.

We then moved onto the problems of water production and saw that they could be classified as : • corrosion problems • scale problems • transportation problems • disposal problems We concentrated on disposal problems offshore and I indicated that dumping water into the sea is the easiest option but this is often governed by legislation. I gave as an example that the average oil in water content permitted to be discharged into the UK sector of the north sea must not exceed 30 ppm. In the next section we will go on to look at some of the basic theory behind produced water treatment. In particular we will concentrate on the removal of oil.

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Produced Water Treatment

Petroleum Open Learning

Section 2 - The Basics of Produced Water Treatment In this section we are going to look at some of the methods which could be used to treat produced water. The water can contain dissolved gases and solids and also some suspended solid particles such as sand. However, we are going to concentrate on the removal of oil from water, so that it can be dumped to the sea. Let’s start with the separation of water from the main oil stream. That is, after all, the first part of the treatment programme.

Primary Separation The total production from an oil field flows from the wells to the primary separation system. The function of this system is to separate the production into its individual phases of oil, gas and water. The process is carried out in large vessels - the separators. A typical 3-phase separator is shown in Figure 4.

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The vessel is called a 3-phase separator because it separates the total flow stream into the three individual streams of oil, water and gas. A 2-phase vessel would separate the stream into the liquid and gas streams.

Test Yourself 4

I don’t intend to go through the construction and operation of a separator at this point. A programme on Oil and Gas Separation is also available in the Petroleum Processing Technology Series.

If you shake a mixture of oil and water in a beaker and allow it to stand for a period of time, what will happen to the two substances ?

Briefly, however, the oil, water and gas stream enters the vessel at the inlet and is deflected by the inlet deflector. The gas passes towards the gas outlet via straightening vanes and mist extractor and the liquids fall into the liquid accumulation section.

Can you explain your answer?

What you have read in the answer to Test Yourself 4 is exactly what happens in the separator. The water and oil separate due to a difference in their densities. Providing the oil and water stay in the vessel for a sufficient period of time, the bulk of the water can be separated from the oil. This water is the produced water which has now to be disposed of. Although primary separation is quite efficient, oil may remain in the water as small droplets. These have also to be removed. We can now look at some ways of doing that.

This is where the separation of oil and water takes place. But how does it occur? Think about it for a moment then answer the following Test Yourself question.

You will find the answer to Test Yourself 4 on Page 47

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Gravity Separation The primary separation we have just looked at is an example of gravity separation. Oil and water separate because of the difference in their density or specific gravity. Most crude oils are less dense than water so they tend to float on top of water. Even where the amount of oil in the water is minimal, given sufficient time and under the right conditions, the crude oil will float to the surface of the water where it can be removed. There is, however, a theoretical lower limit to the size of crude oil droplets which will rise freely through the water. Oil droplets which have a diameter of less than, say, 5 microns will not rise through the water, but will stay in suspension indefinitely. A micron is one millionth of a metre. In practical terms, the limiting droplet size in an oil/ water gravity separator is much higher, and in the range of 50 to 150 microns. This is because of such factors as turbulence, limited retention time, and so on.

However, if the smaller droplets will not rise, something else must be done to remove them. Why not try to combine them into larger drops, which will then rise? This is indeed done by using various types of coalescer.

Coalescence To coalesce simply means to join together or unite. Entrained oil droplets in the water which are too small to rise rapidly by gravity, can be coalesced in a number of ways. One way is to pass the oily water through a specially developed cartridge. This is made of a porous plastic medium such as polypropylene or polyurethane foam. When in use the oily water flows to the centre of the cartridge and out through the walls, where coalescence takes place. The larger oil droplets then rise to the surface of the water by gravity as before, Figure 5 shows the cartridge coalescer principle.

It would appear then that a certain amount of produced water clean up can be done in a simple tank where the water stays long enough for the oil droplets to rise to the surface and be removed.

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Short Distance Gravity Separation

Gas Flotation

Under constant conditions, a drop of oil suspended in water tends to rise at a fixed rate. This rate is called the terminal velocity. The time required for separation therefore depends on the distance the drop has to rise to reach the surface.

Flotation is a process which has long been used for cleaning industrial waste water. The operating principle depends on increasing the buoyancy of entrained oil or solid particles, enabling them to rise more freely through the water. This increase in buoyancy is achieved by attaching gas bubbles to the suspended particles.

In order to speed up this process, various types of equipment have been developed which reduce the distance the particles have to travel. This type of equipment provides closely stacked parallel plates or tubes through which the water flows without turbulence. As the oil droplets rise within these confined spaces they have only a short distance to travel before reaching a solid surface. where they concentrate and coalesce. Figure 6 shows an end view of a simple plate pack.

The gas bubbles are generated by : • dissolving gas in the water under pressure and then releasing the pressure prior to entering the cleaning unit • mechanically introducing the gas into the water. It is the second of these methods which is more commonly used in the oil industry.

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Figure 7 shows oil droplets with gas bubbles attached rising through water.

In a flotation cell, the oil and gas mixture accumulates on the surface of the water as a layer of oily froth. This is skimmed from the top of the water to a channel which directs the oil to a recovered oil system. The skimming may be over a simple adjustable weir. Alternatively a system of paddles may be used to sweep the oily froth continuously from the surface of the water. Figure 8 shows a much simplified version of a flotation cell. I will describe this in much more detail in Section 3.

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Centrifugal Force Separation You are probably familiar with the principle of centrifugal force, but let’s just remind ourselves of it in a rather simple way.

This is the principle of a hydrocyclone, another piece of equipment used in the separation of oil from water. Figure 9 illustrates this principle.

Imagine a spinning disc, similar say to a record on a record player. If you dropped a liquid onto the disc near the centre it would be flung to the outer rim of the disc. The force which causes this to happen is centrifugal force.

• Oil-in-water emulsions where a small amount of oil is dispersed in a larger amount of water The first type is the more common, but oil in water emulsions can occur and may be a problem in the treatment of produced water.

(A familiar example of a vortex is the cone-shaped whirlpool which forms above the plug hole when water runs out of a bath).

In order to break down this type of stable emulsion, chemicals are injected. These chemicals, called demulsifiers, help the oil droplets to coalesce and separate from the water.

If a mixture of two liquids, of different densities, was pumped into the container, centrifugal forces would tend to separate the two liquids: • the liquid having the lower density would migrate towards the middle of the vortex

If the two liquids are water and oil, it would be the oil which would migrate towards the centre of the container.

Sometimes emulsions form in the produced water which are very difficult to break down. An emulsion is a stable mixture of two or more immiscible liquids, one dispersed in another, in the form of very small droplets. There are two distinct types of emulsion. They are: • Water-in-oil emulsions where a small amount of water is dispersed in a larger amount of oil

If the liquid was pumped into a container, in such a way that it was made to swirl within that container, the centrifugal force would cause a vortex to be formed.

• the liquid with the higher density would migrate towards the outside of the vortex

Chemical Treatment

Demulsifiers are usually used in conjunction with some other form of water clean up facility.

The oily water is introduced continuously to the unit. A low pressure outlet is connected to the centre. Through this outlet the oil is continuously removed. Clean water is thrown towards the outside wall of the unit, where it leaves by a separate outlet.

Before summarising Section 2, try Test Yourself 5, which will help you bring together the basic principles of water treatment we have covered in this section,

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Test Yourself 5 In the first column of the table below I have listed the following terms: porous medium, plate pack, oil droplets rising, demulsifier, finely dispersed bubbles, vortex. Each is associated with one or more methods of oil removal from produced water. Put a tick in the appropriate column (s) to show which one(s). Gravity Coalescence Separation

Short Distance Gravity Gas Separation Flotation

Centrifugal Force Separation

porous medium plate pack oil droplets rising demulsifier finely dispersed bubbles vortex

You will find the answers to Test Yourself 5 on Page 48

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Summary of Section 2 In this section we have been looking at some of the basic principles which govern the separation of oil from water in a water clean up facility. First of all we considered the primary separation of the water from the main oil stream. You saw that this was a simple gravity separation process. You also saw that gravity separation is the basis of most produced water treatment facilities. However, in order to speed up the process or make it more efficient you saw that other types of treatment could be undertaken. We considered: • coalescence • short distance gravity separation • gas flotation • centrifugal force separation You also saw that chemicals may have to be injected into the produced water to assist in separation, particularly if an oil-in-water emulsion has formed.

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Produced Water Treatment

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Section 3 - Produced Water Cleaning Equipment In this section we are going to have a look at the construction and operation of equipment which can be used to clean up produced water. A variety of such equipment is available, but we will concentrate on the most common: • API Separators

However, the time available on an offshore production facility is very limited and residence times are extremely short. As API Separators require relatively long residence times, there are very few of them found offshore. I have included the API Separator because they are very common in land installations and contain features which are found in other devices.

• Filter Coalescers

The API Separator is basically a very large open tank or pond which permits a long residence time for the oil to separate from the water.

• Gas Flotation Units

Figure 10 is an illustration of a typical API Separator.

• Plate Interceptors (or separators)

The produced water enters the unit on the left hand side. As it enters the chamber it hits a small stilling plate. The stilling plate distributes the incoming liquids evenly over the width of the separator and reduces turbulence and mixing. Underneath the stilling plate is a sludge/debris trap which will catch small solids as they sink. The sludge outlet is normally designed so that it can easily be freed if it should become blocked.

• Hydrocyclones The simplest of the above pieces of equipment is the first on the list so let us start with this.

API Separators As we have seen, the most common way of separating oil and water is by the use of gravity acting on the density difference between the two liquids. Time is also required for this process to work effectively. Each separator is designed to retain the liquid mixture within it until separation has been accomplished. This time is known as the residence time or retention time.

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The water flows: • from the stilling plate • above and below an intermediate baffle (water with oil in it will rise above the baffle water with no oil in it will fall under the baffle) • under the final baffle • over the outlet weir • out of the separator via the water outlet. The level in the separator is controlled by adjusting the height of the outlet weir. The oil flows: • from the stilling plate • above the intermediate baffle • to the surface where it forms a layer of oil on top of the water • into an adjustable oil skimmer

The adjustable oil skimmer is normally set at between 1/4th to 1/8th of an inch above the level of the water. API Separators require careful adjustment of the skimmer to remove as much of the oil as possible, but without removing any water. Slight changes in flow will raise or lower the height of water falling over the weir and, if the oil/ water interface is disturbed, water could slop over with the oil. As I said earlier, API Separators are not suitable for offshore applications. There, more efficient means of oil and water separation are necessary. Facilities are needed which are designed to reduce the residence time required for efficient oil/water separation to take place.

Coalescing devices provide a solid surface which can be contacted by small oil droplets. An accumulation of these oil droplets creates a thick oil film which becomes a source of large drops. Eventually enlarged drops of oil break loose from the solid surface. These large drops separate from the water phase much faster than the original small droplets. Coalescing surfaces come in two basic forms: • Plate interceptors • Cylindrical cartridges (called “fixed media” cartridges)

This reduction in residence time is important. For a given flow rate of fluid the residence time can only be extended by increasing the volume of the separator. Offshore, where space is at a premium, this is extremely difficult. One way of reducing the required residence time is to include some form of coalescing device in the water cleaning unit.

Let’s look at a couple of plate interceptors first. Two main types are in use, the parallel plate and the corrugated plate interceptor.

• out of the oil skimmer via the oil outlet

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Plate Interceptors (or Separators) Figure 11 shows a typical parallel plate interceptor. Plate interceptors work on the principle of short distance gravity separation, which we looked at in Section 2. Have a look at the figure now and try to visualise the flow through the unit.

Now follow the flow with me with reference to Figure 11. • The produced water flows into an inlet chamber which is equipped with a sludge/ debris trap. • Any gas in the produced water stream then rises, and leaves the separator by a vent. • The produced water then flows through the parallel plate pack. The pack consists of a number of parallel steel or plastic plates connected together with small gaps between them. It is set at an angle of about 45˚ to the horizontal and the produced water flows downwards, towards the right of the illustration. Flow between the plates is far more streamlined than in the inlet chamber. In addition, the distance through which oil droplets have to rise before reaching a surface is much smaller. Oil droplets coalesce on the underside of the plates and slide upwards and backwards against the flow of the water. The oil then breaks free and rises to the surface where it forms a layer on top of the water. The oil is removed from the surface by a skimmer. The water carries on towards the outlet chamber, then doubles back over the outlet weir which controls the height of the liquids in the separator.

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The water then flows away, under gravity, out of the separator. A parallel plate separator will often reduce the amount of oil in the produced water from 5 000 ppm to : • 100 ppm of oil (with a residence time of, say, 10 minutes) or • 50 ppm (With a residence time of 30 minutes) Their main disadvantage is that frequent cleaning is required to remove solids which stick to the plates. A variation of the parallel plate separator is the corrugated plate interceptor which we can look at now. The plate pack is installed in the same manner as the parallel plate interceptor pack, at an angle of 45°, and the oil and water flows are identical. Figure 12 illustrates the major difference between the two types of separator - in this type the plates are corrugated. In the tops of the corrugations are slots which enhance the oil removal process. Oil coalesces on the underside of the plates, and accumulates beneath each corrugation. From there it migrates backwards and upwards until, eventually, it forms a layer of oil on the surface, as before.

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A corrugated plate separator will often reduce the amount of oil in the produced water from 5 000 ppm to 30 ppm oil with a residence time of 5 to 10 minutes. This type of separator has been adapted for use on offshore systems and has even been tried in high pressure systems at the wellhead so as to separate production water before dissolved gas is released.

Oil/Water Filter Coalescers In an oil / water filter coalescer the oil / water separation is achieved by coalescence of dispersed oil droplets within specially designed coalescer cartridges.

In our example in Figure 13, a set of cartridges would be mounted on a deck-plate within a vertical pressure vessel. Note that, for simplicity, I have only shown one cartridge in the vessel, and omitted the deck-plate.

The corrugated plates can be made of polypropylene, polyvinyl chloride, stainless steel or carbon steel. As we have seen, both the parallel plate separator and the corrugated plate separator have their plates tilted at an angle of 45°. Because of this, both types are often referred to as tilting plate separators. When you are satisfied that you understand the construction and principle of operation of the plate interceptors, we can move on to another type of coalescer unit.

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The flow through the unit is as follows: • oily water enters the base of the vessel

Before moving on to the next part of this section, have a go at the following Test Yourself question.

• is distributed to the cartridges

Test Yourself 6

• flows radially outwards, through each cartridge into the main part of the vessel As the fluid passes through the cartridges, the oil droplets are forced into close contact with each other. They coalesce within the cartridge wall and rise from the outer cartridge surface to the top of the vessel. These droplets then form an oil layer which is discharged through the oil outlet. (Have another look at Figure 5 on Page 13.) An oil/water interface level is maintained in the vessel by a level controller (LC), which controls flow from the oil outlet. An oil/water filter coalescer will often reduce the amount of oil in the produced water from 5 000 ppm to between 2 and 15 ppm.

Fill in the missing word or words from the following sentences. a)

In an A.P.I. separator the produced water enters the unit and hits a small ................... ....................... which distributes the incoming liquids.

b)

In a plate interceptor the inlet chamber is equipped with a ...............or ...................trap.

c)

The outlet ..................... controls the height of the liquids in the unit.

d)

The pack consists of a number of ......................plates.

e)

Tilting plate separators may have .....................or .......................plates.

f)

The oily water flows radially outwards through the ..................... where the oil droplets .......................

Under severe operating conditions, the cartridges may not last very long. However cartridge life can be improved by : • pre-filtering the oily water • steady state operation • scale inhibition, where required

You will find the answer to Test Yourself 6 on Page 49 We can now take a look at a produced water clean-up facility which has a somewhat different operating mechanism. This is the gas flotation unit.

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Gas Flotation Units You will remember from Section 2 that the principle of operation of a gas flotation unit (also called a depurator) is that the oil droplets, and any suspended solids, are assisted to the surface by small gas bubbles. The oil and suspended solids are then skimmed off as a froth. Part of a typical flotation unit is illustrated in Figure 14. Study the illustration carefully.

Let us first of all take a look at the flow of produced water through the unit. The produced water: •

enters the inlet chamber

•

flows out of the inlet chamber, under a baffle, and enters the first flotation cell where most of the oil is removed from the water

•

flows over the top of an internal baffle and enters the second flotation cell where the rest of the oil is removed from the water

•

flows out of the second flotation cell, under a baffle, and enters the exit chamber as clean water

•

flows out of the exit chamber into the suction of the recirculation pump

•

leaves the recirculation pump and goes to the water outlet or back into the two flotation cells

Make sure you can follow the flow of the water before proceeding.

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We will now look at how the water is aerated. You can see in Figure 14 that the recirculation pump takes water from the exit chamber. The water can go in one of two directions: • water outlet • back to the flotation unit The level in the exit chamber is controlled by a level controller (LC) which opens and closes the valve in the water outlet.

The oil and gas then form a layer of foam on top of the water. In the type of unit we have been looking at, a venturi was used to create the gas bubbles. As you saw in Section 2, other methods of creating the bubbles may be used. But what happens to the oil ?

Take a look at Figure 15. This shows a side view of the flotation cells. You can see the layer of oily foam on top of the water. To the side of the unit is a collecting box called a launder. The oily foam spills over a weir into the launder where it separates into oil and gas. The gas flows back into the flotation cells and the oil collects at the bottom of the launder. The oil level is controlled by a level controller (LC) which opens and closes a valve on the oil outlet line.

If the level rises the valve will open and allow water to leave the system. If the level falls, the valve will close and retain water in the system. The bulk of the water (up to 70% of the design throughput) is recirculated back to the two flotation cells. As the water enters each cell it passes through a venturi. This is a device which uses the flow of water to create a low pressure area. Gas, from the area above the water, is sucked into the venturi and mixes with the water. The gas and water mixture is then discharged at the outlet at the bottom of each cell. The gas drawn into the venturi results in millions of tiny bubbles being released at the bottom of the flotation cell. These bubbles attach themselves to oil droplets in the water, and carry them to the surface.

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In general: • In some large units there maybe as many as ten flotation cells

Test Yourself 7

• The residence time in a flotation unit may be as low as three minutes

Correct the following sentences, which all refer to a flotation unit.

• A flotation unit may reduce the amount of oil in the produced water to around 10 ppm

a)

Oil spills over a weir into the exit chamber.

• Flotation units may also remove most of the solids suspended in the produced water

b)

Water flows under the middle (internal) baffle, in a two cell unit

c)

The recirculation pump takes its suction from the launder.

A problem associated with flotation units is that they are difficult to control. The size of the bubbles affects the efficiency of the unit and it may take many hours to set up each venturi to give the optimum operating conditions.

d)

Gas is introduced to the top of the cells as finely dispersed bubbles.

e)

Gas from the area above the water is sucked into a venturi and mixed with the oil.

f)

In the launder, oil and water separate and the oil level is controlled by a level controller.

If you are happy with the construction and operation of flotation units, try the following Test Yourself question. You will find the answers to Test Yourself 7 on Page 49

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Hydrocyclones The most important development in oil / water treatment in recent years is the hydrocyclone. This is a unit which uses centrifugal force to separate oil and water. Figure 16 is an illustration of a hydrocyclone.

The hydrocyclone has a cone shaped liner within a pressure shell. The cone shaped liner of the unit is fabricated as a thin walled vessel. Oily water enters the unit through an inlet into the liner. The inlet is designed to spin the water as it enters the swirl chamber. Inside the swirl chamber the flow forms a vortex which passes along the length of the liner.

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The water / oil mixture is accelerated to high velocity and strong centrifugal forces develop. This promotes oil / water separation. The more dense water phase moves to the wall of the liner and displaces the lighter oil phase towards the centre of the vortex. The water continues to flow to the water outlet along the sides of the liner. The oil flows in the opposite direction, via the low pressure central core, to be removed at the oil outlet. The oil stream is called the reject oil stream. Total residence time of the liquid in the hydrocyclone is about two seconds. Hence the equipment can be compact. The capacity of a hydrocyclone is dependent on the pressure drop between inlet pressure and reject oil stream pressure. Hydrocyclones are usually mounted as groups in parallel to increase capacity. Each unit can be opened up or closed in. This enables the operator to maintain optimum conditions during varying flow rates. In addition, units can be installed in series to increase oil removal. The water leaving one hydrocyclone enters the next, and so on. Using this system oil concentrations as low as 5 ppm can often be achieved.

The major factors influencing the performance of a hydrocyclone are: • The specific gravity difference between the oil and water. The greater the difference, the greater the potential for rapid separation. • The oil droplet size. Larger droplets move more rapidly towards the central core. • Temperature. This affects both density and viscosity. Higher temperatures increase the potential for easy separation and therefore hydrocyclones are most often installed upstream of any produced water coolers. • Higher flow rates. These increase the intensity of the centrifugal separation forces. The reject oil stream will not be 100% oil. It will be a mixture of oil and water. This mixture is then fed back into the main process, where the oil is recovered. Hydrocyclones have a weight / efficiency ratio which makes them attractive for use offshore.

Use of Chemical Additives Chemicals are increasingly used in produced water treatment facilities. I don’t intend to go into the chemistry of the way that they work. However, I think that you should be aware of the main types of chemical used and what their function is. Emulsion breakers or demulsifiers. These chemicals assist in separating oil/water emulsions. They break down the mechanisms which cause the emulsion to form. Flocculation and flotation agents. These chemicals act as seeds around which small solid particles or oil droplets may collect. The increased size assists in the separation process. Corrosion Inhibitors. These chemicals help prevent corrosion of the vessels and pipework of the produced water system. Biocides. These chemicals kill bacteria in the water. They are used to prevent the formation of slimes. Oxygen scavengers. These chemicals are used to remove residual oxygen in water. This also helps to prevent corrosion. Scale inhibitors. These chemicals prevent dissolved solids coming out of solution and being deposited on pipework, etc., as scale.

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In all instances, great care is needed to ensure that: • the chemicals used are harmless to the environment • one chemical will not counteract the effects of another chemical used in the process • the chemicals used will not affect downstream processing In all cases chemicals should be introduced to the system at the correct dosage rates. Too high a dosage rate is often worse than no dosage at all.

Summary of Section 3 In this section we have looked at different types of oil/water separators which may be found on an oil production facility. We have looked at the construction and operation of : •

API separators

•

parallel plate separators

•

corrugated plate separators

•

oil / water filter coalescers

•

gas flotation units

•

hydrocyclones

We have also taken a brief look at chemicals which may be used in a Produced Water System.

In the final section of this unit we will consider a typical produced water handling system. Before you move on to that however have a go at the following Test Yourself question.

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Test Yourself 8 State whether the components listed on the right are part of : a)

An A.P.I. separator

List of components

b)

A tilting plate separator

1. swirl chamber

c)

An oil / water filter coalescer

2. adjustable oil skimmer

d)

A flotation unit

3. baffle

e)

A hydrocyclone

4. weir 5. cartridge

Note: some of the components are found in more than one type of unit.

6. level controller 7. sludge trap 8. cone shaped liner 9. venturi

You will find the answers to Test Yourself 8 on Page 49

10. recirculation pump

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Produced Water Treatment

Section 4 - A Typical Produced Water System

Petroleum Open Learning

In this final section, we are going to look at a complete produced water system. The system I will use as an illustration includes two tilting plate separators, a flotation unit and a produced water caisson. It is fairly typical of produced water handling systems which you might find offshore. In our example, the function of the system is to remove: • oil • entrained gas • fine solids from the produced water streams. This is achieved by short distance gravity separation and flotation. Take a look at Figures 17. This is a simple block diagram of the overall system. Study this for a moment and get a general idea of the relationship between the various subsystems. As we work through the system in detail, however, we will need a more complex drawing. This is Figure 18, entitled “A Typical Produced Water System”. In order to allow easy reference to this drawing, I have included it as a separate sheet in your pack. Take this out now and study it for a few minutes. In order to help you, I have also included a symbol key, which includes those symbols used in the drawing.

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Look at Figure 18. You should be able to identify four separate parts of the system. They are: • the two tilting plate separators (TP-01 and TP·02) in the upper left hand corner of the figure • the flotation unit (DP-01) in the upper right hand corner • the chemical dosing system in the bottom left hand corner

Tilting Plate Separators The produced water enters the system from the main oil, gas and water separation facilities. Find the entry point in Figure 18 and follow the flow. The first thing you will see is that a chemical is injected at this point. The chemical being injected is a demulsifier which assists in the separation of the oil and water. You will remember we discussed the use of demulsifiers in Section 2.

The diagram indicates that the chemical enters the produced water line via an injection quill. Figure 19 is an illustration of an injection quill. It is designed to ensure that the chemicals are efficiently mixed with the water flow.

• the circulation and recycle pumps in the bottom right hand corner We will look at each of these sections in turn as I guide you through the flow diagram. Because the pumps are part of the flotation unit equipment we will study these two sections together.

Not shown in Figure 18 is the produced water caisson where the treated water enters the sea. We will look at that later as a separate item.

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The chemical injection line is protected from any back flow by a non-return valve (Figure 18). Downstream of the injection quill, oily water from the platform drains system joins with the produced water. Just after this connection is a sample point. In order to obtain a true sample, this connection is placed after the point at which the two streams combine. Beyond the sample point another line enters the produced water line. It is protected from back-flow by a non-return valve. This line is the discharge line from the float recycle pumps P-02A and P-02B. We will be looking at these two pumps later. The produced water then splits into two individual lines, one to each of the two tilting plate separators. Each line is fitted with a butterfly valve which is indicated as being LO. This means that the valves are normally locked open to make sure that TP-01 and TP-02 are not accidentally isolated. The tilting plate separators are identical, so we will just look at TP-01. In our example, TP-01 has three sets of corrugated tilted plates. The produced water enters the side of TP-01 via three separate connections. This ensures that turbulence is reduced at these points by reducing the produced water flow rate.

Any gas which is released from the produced water is vented off to the vent header. Note that in our example, there is no valve on the vent line. There are no pressure relief valves on TP-01 so, to prevent an accidental over-pressure situation, the vent line is fitted without an isolation valve. TP-01 is also fitted with a nitrogen purge connection. If TP-01 is shut down, the vessel can be purged with nitrogen. The nitrogen ensures that an air/gas flammable mixture cannot occur, by sweeping out any flammable gases before the vessel is opened for maintenance. TP-01 is fitted with a level gauge (LG-01) so that the operator can check the liquid level in this separator. Connected to the level gauge is a level switch high (LSH-01). If LSH-01 is activated it will : •

sound an alarm in the Control Room via level alarm high (LAH-01)

•

cause a shutdown of the produced water system via the E.S.D. system

At this point. let me say a few words about shutdown systems. All offshore production facilities are protected by a safety shutdown system. This comprises dedicated sensors, actuators, valves, pipework, etc. They are installed to enable a safe and effective shutdown of plant and equipment in a controlled manner. The whole system is called an emergency shutdown system (E.S.D. system). Levels of shutdown may be designated. These depend on the degree of hazard 10 personnel, plant and the environment. Less serious hazards may only require the shutdown of individual items of plant or equipment. Severe hazards, however, may necessitate a total platform shutdown. If our platform had four designated levels of shutdown, with level 1 being the most severe hazard level, then the produced water shutdown would probably be a level 3. This is indicated in Figure 18. You will appreciate that E.S.D. systems are very complex and I do not intend to talk about them any further here. Other units in the Petroleum Processing Technology Series will describe these systems in much more detail.

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The Flotation Unit

Now back to the tilting plate separators. You will notice that a water jetting hose connection is fitted. This allows a high pressure water hose to be connected into the system for washing out any sludge which collects in the sludge trap of TP-01. Each trap is also fitted with a connection to allow the liquidised sludge to drain away to disposal.

Test Yourself 9

The water which leaves the tilting plate separators should have a fairly low oil content - say 60-80 ppm. We now have to polish the water to reduce the oil content to less than 30 ppm (the standard for our system). This is done in the flotation unit.

You will remember from Sections 2 and 3 that separation of oil from the produced water takes place in the tilting plate separator. These two liquid phases are discharged via separate lines.

With reference to the tilting plate separators in our typical system, see if you can answer the following questions.

You should remember the principle of operation of such a unit from Section 3. If you need to refresh your memory, do that now before continuing.

The recovered oil flows from TP-01 and joins with the oil line from TP-02. The combined oil stream then flows to a slop oil tank. The oil from the slop oil tank will be pumped back into the primary separation system.

a)

What is the function of an injection quill ?

b)

Why is the sample point downstream of the connection for the oily drains system?

Referring back to Figure 18, you will see that, from the tilting plate separators the water can be routed either:

c)

What system is used to ensure that the tilting plate separators are not accidentally isolated?

d)

What is the nitrogen purge connection used for?

The water from TP-01 passes through a butterfly valve before joining with the water line from TP-02. The combined water line then takes the water towards the flotation unit DP-01 That completes our look at the tilting plate separators. Before you move on to look at the flotation unit however, have a go at the following Test Yourself question.

You will find the answers to Test Yourself 9 on Page 50

• to flotation unit (DP-01) • to a by-pass round DP-01 The reason for the by-pass is to allow the flotation unit to be taken out of service for maintenance etc. If you look at the system you can see that there are two tilting plate separators, but only one flotation unit. Normally both separators are in use. We can, however, keep one separator on line whilst we clean and maintain the other one. Any loss of efficiency would be taken care of by the flotation unit.

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But what happens if we have to clean or maintain the flotation unit? We have already seen that corrugated plate separators, (The type we have selected), can reduce the oil content of produced water to 30 ppm. So, if both tilting plate separators are on line, it would be possible to by-pass the flotation unit, temporarily, so that it, too, could be maintained. Under normal conditions the water from the separators flows through a butterfly valve towards the flotation unit. Downstream of the butterfly valve is a second chemical injection point where demulsifier can be injected from the chemical dosing package. The chemically treated water enters the inlet chamber of the flotation unit and from there into each aeration cell in turn. Our unit has four separate aeration cells. Within each cell oil foam accumulates on top of the water. A motor (M) is indicated on the left hand side of the unit. This motor drives a set of paddles which skim the oil foam from the surface of each cell into the launder. The launder is fitted with a level gauge (LG-03) to allow the operator to check the level of oil in the launder. Connected to the gauge is : • a Level Switch High (LSH-03) • a Level Switch Low (LSL-03)

If LSH-03 is activated it will start float recycle pump P-02A or P-02B. The pump running light (XL-03 or XL-04) will light in the control room to alert the operator that the pump is running. The oil is pumped back into the inlet line to the tilting plate separators. From there it is recovered again and discharged to the slop oil tank. If LSL-03 is activated it will stop P-02A or P-02B. The pump running light (XL-03 or XL-04) will extinguish in the control room to alert the operator that the pump has stopped. The oil leaving the launder is filtered before it enters the suction of the float recycle pumps. Each pump is fitted with a discharge pressure relief valve (PSV-01 and PSV-02). The PSV is fitted on the pump side of the discharge Isolation valve. If the discharge pressure exceeds a pre-set value, say 30 psi, then PSV-01 or PSV-02 will lift. This will relieve the discharge pressure by circulating oil back to the suction of the pump.

The oil from the float re-cycle pumps is fed into the produced water line downstream of the chemical injection point and downstream of the sample point. If it was fed into the line upstream of : • the chemical injection point - it would get a second dose of chemicals • the sample point - it would affect the amount of oil being measured as entering the system for treatment Neither of these conditions are desirable. The exit chamber of the flotation unit is fitted with a level gauge (LG-04) to allow the operator to check the level of water in the exit chamber. Connected to the level gauge is : • a Level Switch High (LSH-04) • a Level Switch Low (LSL-04) If LSH-04 is activated it will : • sound an alarm in the Control Room via Level Alarm High (LAH-04) • will cause a level 3 shutdown A level 3 shutdown generated by LSH-04 would shut down the flow of produced water which is leaving the primary separation system.

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If LSL-04 is activated it will stop the hydraulic circulation pumps (P-01 A or P-01 B). The pump running light (XL-01 or XL-02) will extinguish in the Control Room to alert the operator that the pump has stopped. The exit chamber of the flotation unit is also fitted with a level transmitter (LT-05) which feeds a signal to a level controller (LC-05). The level controller opens and closes a level control valve (LV-05) to maintain a constant level in the exit chamber. The water which flows through LV-05 is the treated water leaving the system. There is a sample point just downstream of LV-05. This is the position where the final water quality is checked.

Test Yourself 10 Which of the following components are not part of the flotation unit. skimmer motor float recycle pumps plate pack launder pump running light filter cartridge hydraulic circulation pumps level gauge discharge pressure relief valve exit chamber level switch low chemical injection point

At this point I think that you should go back over what we have looked at up to now in this section, then have a go at Test Yourself 10.

inner liner You will find the answers to Test Yourself 10 on Page 50

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Lets now continue with the flotation unit by looking at the gas aeration of the water. Water is fed into the gas aeration side of the flotation unit by either hydraulic circulation pump P-01A or P-01B. These pumps take their water supply from the exit chamber of DP-01, and the water is then filtered before being recirculated to DP-01. The combined discharge of P-01A and P-01B splits into four separate lines, one for each of the flotation cells. The operator can balance the flow of water to each cell, by adjusting the opening or closing of the individual inlet butterfly valves. A fuel gas line provides the gas required for aeration via PCV-01. PCV-01 is a forward pressure control valve. This means that it controls the pressure downstream of where it is installed. PCV-01 maintains a blanket of gas on the flotation unit with a constant pressure of a few inches water gauge. The water flowing through a venturi causes the gas to be sucked into the water. It is then released as tiny bubbles. (If you are having difficulty visualising this, go back to the description of flotation units in Section 3 and refresh your memory.)

If there is a problem in the fuel gas system the pressure of the gas blanket could fall and affect the operation of the produced water handling system. However, tied into the fuel gas line, downstream of PCV-01 is an automatic nitrogen back-up system. The nitrogen back-up facility is activated automatically if the fuel gas pressure fails below a pre-set value. The system comprises: • flow orifice (FO-01) - a flow orifice is a small plate with a precision drilled hole in the centre -the size of the hole determines the amount of flow through the orifice •

emergency shutdown valve (XV-01) - this has an FO indication underneath. This means that the valve will fall open if the instrument air pressure is lost.

• solenoid valve (XV-01) - a solenoid valve is a valve which is opened or closed by an electro-magnet • limit switches (ZSH-01 and ZSL-01) Solenoid valve XY-01 is fitted into the instrument air supply to XV-01. This valve is a three-way valve.

In normal operation: • the electrical signal to the solenoid of XY-01 is live • the air flows through XY-01 and maintains pressure on the actuator of XV-01 • the valve stays closed • limit switch ZSL-01 is activated and the signal valve closed is indicated in the Control Room. If the low fuel gas pressure condition is activated then the electrical signal to the solenoid is made dead. When this occurs: • XY-01 changes position • the air supply to XV-01 is cut off • the air supply to XY-01 is vented to atmosphere The result of these actions is that XV-01 will open. When this occurs the movement of the valve will activate ZSH-01 which will signal to the control room that the valve has opened.

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Nitrogen will then be supplied to DP-01. The amount of nitrogen will be regulated by the orifice size of FO-01. There is another connection to DP-01 which we have not yet mentioned. This is a third chemical injection point positioned on the top of the unit. It enables demulsifier to be injected into the main body of DP-01.

We have completed our look at the flotation unit. By the time the water leaves the unit it should have an oil content down to specification. To achieve this, we have injected demulsifier into: • the tilting plate separators • the flotation unit

We will now take a look at the chemical injection dosing package, which is the final part of Figure 18.

Chemical Dosing Package This package consists of : • demulsifier drum D-01 • chemical dosing pumps P-03A and P-03B Demulsifying chemicals are pumped into D-01 from drums with a small hand pump via the hose connection. A level indicator (LI-06) allows the operator to stop filling the drum when the correct level is reached and to monitor the level of demulsifier in the drum during normal operations. If the operator fails to re-fill the drum when a low level is reached, a level switch low (LSL-07) will activate. This will ;

These pumps are fitted with discharge pressure relief valves PSV-03 and PSV-04. The PSV’s are fitted on the pump side of the discharge isolation valves. If the discharge pressure exceeds say, 30 psi, then PSY-03 or PSY-04 will lift. This will relieve the discharge pressure by circulating chemical back to the demulsifier drum. Chemical dosing pump P-03A supplies the demulsifier to the tilting plate separators. Pump P-03B supplies the demulsifier to the flotation unit. The flow of demulsifier leaving the pumps is monitored by a sight glass (SG) in each of the lines. That completes our look at the chemical dosing package.

• activate a low level alarm (LAL-07) in the control room to warn the operator • shut down the chemical dosing pumps The chemical dosing pumps are reciprocating / positive displacement / variable stroke pumps. (In a reciprocating pump a piston moves backwards and forwards inside a cylinder. In a variable stroke reciprocating pump the amount of liquid pumped is controlled by changing the length of the stroke of the pump cylinder.)

The treated water has finally to be disposed of to the sea. This brings us to the final part of this section, the produced water caisson.

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Produced Water Caisson Basically, the produced water caisson is a long residence time vertical separator. It is designed to remove any traces of oil which may be left in the produced water when it leaves the flotation unit. Figure 20 is an illustration of the produced water caisson.

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The caisson is a pipe of about 1.2m diameter which hangs from the lower deck level of the platform into the sea. The bottom of the caisson may be 30m or so below sea level. The actual length of the caisson will depend on water depth and the height of the lower deck above sea level,

When the oil in the sump reaches a pre-set high level it will activate a level switch high (LSH-09). When activated LSH-09 will start the oil sump pump. The oil is pumped to the slop oil system, from where it will be returned to the primary separation system.

The bottom of the caisson is open to the sea and the level of water inside the caisson will go up and down with the rise and fall of the tide.

When the oil in the sump reaches a pre-set low level it will activate a level switch low (LSL-09). When activated, LSL-09 will stop the oil sump pump.

The produced water line from the flotation unit enters the top of the caisson at deck level. This line extends down into the caisson to a point where its end is under the level of the water, even at low tide. The produced water discharges into the caisson at this point. The produced water may stay in the caisson for upwards of 30 minutes, This is a much longer residence time than anywhere else in the system and traces of oil will be able to float to the surface, where they can accumulate. Inside the caisson is a small sump with a weir set at a level which is just above the highest high tide level. The oil which has accumulated on top of the water can then spill over the weir into the sump.

You have now completed the section on a typical produced water system. Have a go at the final Test Yourself question before going through the section summary.

Test Yourself 11 With reference to the system you have been following in Section 4, answer the following questions, a)

In the automatic nitrogen purge system on the flotation unit, what controls the flow of gas?

b)

What is used to skim the oil from the surface of the water into the launder?

c)

Where does the separated oil from the tilting plate separators go to?

d)

Why is there a by-pass around the flotation unit?

e)

Where does the oil accumulate in the produced water caisson?

You will find the answers to Test Yourself 11 on Page 50.

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Summary of Section 4 In this section we have looked at how a typical produced water system operates, I have described a system which includes: • tilting plate separators • flotation unit • chemical dosing • produced water caisson and which combine to treat produced water for dumping to the sea. As you worked through the section you followed the main flow lines and traced the path of the water and oil. I pointed out the points where chemical is injected into the system and where sampling takes place. You also discovered the function and operation of the instrumentation associated with such a system and the safety features involved.

Although the system I described is similar to many you would come across offshore, it is a hypothetical one. You must remember that, if you are working on a produced water system you should become familiar with the layout and operating procedures of that particular system.

Now go back to the training targets for this unit and make sure that you have met those targets,

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Check Yourself - Answers

Check Yourself 3

Check Yourself 1 The water underlying the oil pushes the oil towards the producing wells. The aquifer expands to fill the space left by the oil which has been removed. The oil water contact therefore will rise up the reservoir towards the producing well intakes.

Check Yourself 2 a)

total production =

a)

True

b)

False

c)

False (produced water can contain up to 5 times the amount of salt present in sea water.)

d)

True

e)

False (the current figure is 30 ppm)

4770m3/d (3975+ 795)

Therefore water cut = 795 4770

x

100% =

b) oil production is 80% ( 100 - 20) 875m3/d Therefore oil production = 875 x 80 100

16.67%

Check Yourself 4 =

c) water production = 159m3/d (556 - 3971) Therefore water cut = 159 x 100% = 556

700m3/d

Oil and water have different densities. Water is the most dense, and would sink, allowing the oil to float on top. The two liquids would separate from each other and the oil would tend to float on top of the water.

28.6%

47

Petroleum Open Learning

Check Yourself 5 Your answer should look like the following:

Gravity Coalescence Separation porous medium

Short Distance Gravity Gas Separation Flotation

Centrifugal Force Separation

√

plate pack

√

oil droplets rising

√

√

√

√

demulsifier

√

√

√

√

finely dispersed bubbles

√

√

vortex

√

48

Petroleum Open Learning

Check Yourself 6

Check Yourself 7

a)

stilling plate

a)

Oil spills over a weir into the launder.

b)

sludge debris

c)

weir

b)

Water flows over the middle (internal) baffle in a two cell unit.

d)

parallel

c)

The recirculation pump takes its suction from the exit chamber.

e)

flat or corrugated

f)

cartridge, coalesce

d)

Gas is introduced to the bottom of the cellsas finely dispersed bubbles.

e)

Gas from the area above the water is sucked into a venturi and mixed with the water.

f)

In the launder, oil and gas separate and the oil level is controlled by a level controller.

Check Yourself 8 1.

e

2.

a

3.

a-d

4.

a-b-d

5.

c

6.

c-d

7.

a-b

8.

e

9.

d

10.

d

49

Petroleum Open Learning

Check Yourself 9

Check Yourself 10

Check Yourself 11

a)

The injection quill is designed to ensure that the chemicals are efficiently mixed with the main water flow.

plate pack

a)

The size of the hole in the flow orifice.

b)

In order to ensure that a true sample is obtained, i.e. after the two streams have mixed together.

inner liner

b)

A motor driven set of paddles.

c)

To a slop oil tank and from there to the main separation system.

c)

The inlet valves have a lock open facility.

d)

In order that nitrogen can be introduced to sweep out any flammable gases before the vessels are opened for maintenance. This ensures that an explosive air gas mixture cannot form.

d)

To allow the unit to be taken out of service for maintenance whilst the plate separators are still working.

e)

On top of the sea water from where it spills over a weir into a sump.

filter cartridge

50