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Petroleum Open Learning

Oil Pumping and Metering(Part of the Petroleum Processing Technology Series)

Contents

Section 1 - Centrifugal Pumps : Terms and Concepts..................................3Liquids, Gases and Fluids...........................................................................................3Mass, Force and Weight.............................................................................................3Density and Specific Gravity.......................................................................................3Centrifugal Force........................................................................................................5Kinetic Energy and Pressure Energy..........................................................................7Head Pressure............................................................................................................8Pressure.................................................................................................................... 10Net Positive Suction Head (NPH).............................................................................11Cavitation..................................................................................................................12Flow v Differential Pressure......................................................................................13

Section 2 – Construction and Operation of Centrifugal Pumps.................16Impeller Speed..........................................................................................................19Bearings....................................................................................................................20Seals......................................................................................................................... 21Pump Configurations................................................................................................23Centrifugal Pump Performance Curves.....................................................................24A Centrifugal Pump Arrangement.............................................................................27

Section 3 – Oil Metering and Sampling.........................................................31Turbine Meters..........................................................................................................35Metering Systems.....................................................................................................36

Sampling Systems..........................................................................................41

Section 4 – Pig Launching Facilities.............................................................42Pig Launchers...........................................................................................................44

Section 5- A Typical Oil Pumping and Metering System.........................48

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Training Targets

When you have completed this unit on Oil Pumping and Metering, you will be able to

Explain some of lie technical terms and concepts which lie behind the operation of a centrifugal pump List component pails of a centrifugal pump Explain the operating principle; of a centrifugal pump Describe the construction and operation of turbine and differential pressure Meters Explain the function and operation of a typical meter run Describe the procedure for proving a meter List the essential element of an ail sampling system Detail the main features of a pig launching oysters, and its method of operation Describe a typical layout for the ail handling (or oil pumping and metering) section of a production facility

Tick the box when you have met each target

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Oil Pumping and MeteringSection 1 - Centrifugal Pumps : Terms and Concepts

In this first section, we will look briefly at a number of concepts which relate to the operation of centrifugal pumps. I will also explain some of the terms often used when we are discussing how these concepts can be applied in practice.Throughout this unit we will be concentrating on centrifugal pumps because these are the most common ones used in oil pumping and metering services.

Liquids, Gases and Fluids Both liquids and gases are called fluids because each has the

ability to flow.

In this unit we will use the term fluid when describing something which can happen to a gas or a liquid. When we need to make a distinction, I will use the specific term liquid or gas.

Mass, Force and Weight The mass of an object is a measure of the quantity of matter

present. This object may have various forces acting on it, the most important of which is likely to be the force of gravity. You can easily Demonstrate that there is a force acting on the abject. Hold it out and release it - the force of gravity will pull it towards the earth.

Weight is a measure of this force acting on the object. Therefore, a one pound mass will have a force of one pound weight acting' on it, due to gravity.

The two terms "mass" and "weight" cause a lot of confusion. Very often they are used as if they mean the same thing. In many cases, however, this is not all that important and I think that the brief explanation given above should be sufficient to guide you through the remainder of this unit without any undue problems.

Density and Specific Gravity The density of a substance is defined as the mass per unit volume

of that substance. For the same material, density can be expressed in a variety of units. For example, the density of water is

1 gram per cubic centimeter-1 gm/cm3

or 62.4 pounds per cubic foot,- 62.4 Ibs/ft3

Specific gravity (s.g.) compares the mass of a certain volume of a material with the mass of an equal volume of a reference substance. In other words

Specific gravity (s.g.) = Mass of a certain volume of material

Mass of an equal volume of reference substance

For solids and liquids, the reference material used is usually water. For gases, the reference is often to air.

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Test Yourself 1 A gallon of water has a mass of 10 pounds. A gallon of gasoline has a mass of 6.s pounds. A gallon of salt water brine has a mass of I f pounds. What are the specific gravities of gasoline and brine ? You will find the answers to Test Yourself 1 on Page 65,

Centrifugal Force

Have a look at Figure 2.It shows a spinning disk. If we let a drop of water fall onto the face of the disk, near to the centre spot, it will follow the type of path shown. This is because the drop is affected by two forces during its travel:

centrifugal force, which tends to throw the droplet outwards, causing it to speed up as it approaches the edge of the diskfriction, which will cause the disk to attempt to drag the droplet round with it as it rotates.

The relative size of these two forces will determine the angle at which the droplet leaves the disk edge.

This angle is important, as you will see when we come to the section on Construction and Operation of Centrifugal Pumps (Section 2). The design features of the pump encourage a flow path for the liquid being pumped, which is very similar to the droplet trajectory in Figure 2.

This ensures that the pump imparts the maximum amount of energy to the liquid. In this case, energy of motion, or kinetic energy is transferred.

Kinetic Energy

We have seen that kinetic energy is energy of motion, or movement.The amount of kinetic energy possessed by any moving object depends upon .

Its mass (“weight”)

its velocity ("speed")

In mathematical terms, kinetic energy (KE) can be calculated by using a formulaKE = '/Z mass x velocity'

If the mass is expressed in kilograms and the velocity in metres per second, the kinetic energy will be in joules.

To confirm your understanding of this relationship try the following Test Yourself.

?Test Yourself 2

A small car has a mass of 1 000 kilograms and is travelling at 180 kilometres per hour,

A large truck has a mass of 20 000 kilograms, and is travelling at 90 kilometres per hour,

Which one has the greater kinetic energy ?

You will find the answer to Test Yourself 2 on 5.

Kinetic Energy and Pressure EnergyFigure 3 illustrates the flow of a fluid across a restriction, and how the fluid velocity and pressure vary during this process.

Figure 3 : Flow Across a Restriction

Let us go into a little more detail on these pressure and velocity changes by considering six separate paints in the process:

point A: fluid is flowing along the pipe at a steady speed and .almost constant pressure. You will remember that the kinetic energy of this fluid can be calculated by the equation:

KE = ½ mass x velocity2

The velocity of the fluid at point A is constant, In addition, the mass of fluid passing each point in the pipeline per unit of time (mass flow rate) is also constant. This means that the kinetic energy content of the fluid at that point is also constant.

point B : the fluid starts to enter the restriction. The mass flow rate remains constant but, because the pipe diameter is smaller, the fluid velocity must increase.

Looping again a. the kinetic energy equation, you will see that the kinetic energy of the fluid will start to increase at this point as the fluid speeds up.

Head Pressure

The term head pressure or head is often used in the oil and gas industry, especially when referring to pumps. It is the pressure developed by a head, or column height, of liquid.

In the paragraph entitled "Pressure", we saw that the head pressure applied by one foot depth of water will be 0.433 psi. For 10 feet of water the head pressure would be 4.33 psi; for 100 feet, 43.3 psi, and so on.

Now let us combine what we know about specific gravity and head pressure. Try the following Test Yourself to combine these two factors together

We have already shown that centrifugal force can impart kinetic energy to a substance as a result of a spinning action. We have also seen

that kinetic energy can be converted into pressure energy.

Centrifugal pumps are dynamic pumps which, primarily, impart kinetic energy to the fluid being pumped. They do not create pressure directly. Pressure results from the liquid slowing down, and the kinetic energy converting to pressure energy.

The pressure developed will depend on the density of fluid being pumped.

A centrifugal pump, working at a fixed flowrate, will generate the same height of head, but will generate a lower head pressure, when pumping gasoline, than when water is being pumped, because water is heavier than gasoline.

The different categories of head pressure referred to in pumping operations are shown in Figure 5 on the next page.

Test Yourself 3

The specific gravity of gasoline is 0.85, and that for a particular salt water is 1.1.

What will be the head pressure developed by 10 feet of the gasoline, and 16 feet of this brine ?

The answers to this Test Yourself are on Page 65.

The suction head represents the head pressure present at the pump suction.

The discharge head represents the head pressure delivered by the pump.

The total head (which is the difference between suction and discharge heads) represents the additional pressure imparted to the liquid by the pump

Now let me introduce you to another principle of science - Conservation of Energy.

This tells us that the total energy content of a system will always remain constant.

If the kinetic energy content of our system increases then, to compensate for this, some other form of energy possessed by the system must decrease. This other form of energy is pressure energy. Figure 3 shows that, as the velocity (kinetic energy) increases, the pressure (pressure energy) decreases.

point C : this is a new steady state. The fluid has a higher velocity and a lower pressure but both of them are steady as the fluid passes across the restriction.

points D and E reverse the changes which occurred at points A and B.

It is worth noting that, across the process overall, a small reduction of pressure has occurred. Due to turbulence in the system, some pressure energy has been converted into heat energy. You will no doubt appreciate that, under conditions of high flow rates, high turbulence, or extended restrictions (say, a long pipeline run), pressure losses will be greater.

We will look into the effects of pressure loss and flow 'a little later on in this section.

Pressure

Pressure expresses the relationship between force (or weight) and area, as follows :

pressure = pounds force (or weight)area

Like density, it can be measured in a variety of units. One of the most common is pounds weight per square inch, or psi.

Picture a foot cube of water

This cubic foot of water weighs 62.4 pounds. In other words, due to the effects of gravity, it is applying a downward force of 62.4 pounds, spread over its base.

The pressure on the base of the cube is therefore:

62.4 Ibs/sq.ft.

However, we have just seen that pressure is usually expressed in Ibs/sq.in., or psi.

As you will see from Figure 4, the base of this water cube has an area of one square foot, or

12 inches x 12 inches = 144 square inches (144 sq.in.)

So, on each square inch of the base a downward force of 62.4Ibs/144 is applied.

The pressure on the base can, therefore, also be expressed as

62.4 Lbs/sq.in = 0.433 lbs/sq.in (or)144 0.433 psi

Net Positive Suction Head (NPH)

I would like you to think about two common situations in which you have seen bubbles coming out of a liquid.

1. If you heat up a per? 0 1 water, two things happen:

long before the water boils, bubbles are seen rising through the liquid as dissolved air comes out of solution when the temperature begin; to increase

at the boiling point, the liquid bubbles vigorously as the water is rapidly converted into steam

Water at sea level boils at 100°C (212°F). I am sure you will have heard, however, that the boiling point of water (or any other liquid) as you climb from sea level, so that it can be difficult to cook an egg properly on top of a high mountain. This is because atmospheric pressure falls the higher up we get.

2. If you open a bottle lemonade, bubbles are seen rising through the liquid as dissolved gas comes out of solution when the pressure is released (reduced).

If these effects are observed in water and lemonade, it is roil to assume that they will happen in other liquids as well. So let us now visualise how these effects can influence the operation of a pump.

We already know that fluids can only flow from areas of high pressure to areas of low pressure. Suppose that the liquid being pumped enters an area of low pressure. Then:

If the liquid was near its boiling point, the pressure drop may cause the liquid to boil and release gas or vapour

if the liquid was near to the pressure at which dissolved gases are released, the pressure drop may cause these gases to come out of solution

In either case we can predict that, if the pressure is increased again, the released gases will go back into the liquid, either because boiling stops or the released gases re-dissolve.

When a centrifugal pump is running, a low pressure area is created at the suction. This encourages liquid further upstream to flow into the pump suction.

The accompanying drop in pressure may cause gas or vapour to be released for either of the reasons described above. It is important that we prevent this happening, for reasons that I will explain a little later under “Cavitation”.

We must therefore always have sufficient pressure at the pump suction to prevent gas or vapour release for whatever reason. The

minimum pressure necessary to do this is called the net positive suction head (NPSH).

A further pressure reading which is relevant to the suction end of the pump is called the static suction line pressure. As the name implies, this is the measured pressure at the pump suction when pumping has stopped.

We now have three pressure values which relate to the pump suction:

a) the pressure at which gas or vapour is released

b) the static suction line pressurec) the NPSH

A pump manufacturer will specify the NPSH and maximum operating temperature required for each pump to handle a given liquid effectively. The NPSH should be maintained over the entire range of the pump.

To be safe, most pumps will be operated just above their NPSH. An adequate safety margin for most applications would be 3 feet, or 10%, head of water pressure above the NPSH specified by the manufacturer (whichever is the larger).

In general, the industry standard is to work in terms of "head of water". This is because everyone knows the density of water and pumps can easily be tested to make sure that they produce the level of head specified.

Cavitation

We have discussed at some length the importance of NPSH and other factors in preventing the release of gas or vapour bubbles in the suction of the pump. We will now look at why it is so important to prevent this.

If gas is released at this point in the system, it will give rise to an effect known as cavitation.

The formation of bubbles is, in itself, quite harmless. However, as the liquid containing these gas bubbles, or cavities, passes through the pump, the pressure will rise. Now we already know that, if gas is released from a liquid for the reasons I have described, an increase in pressure will drive this gas back into the liquid again.

As these tiny cavities created in the liquid collapse, the liquid tends to rush in from all

angles to fill the cavity. The cavity is said to implode.

This inrushing liquid can transmit very large forces. When the bubbles are near a metallic surface, these forces are applied directly to the solid surface. When a pump is cavitating, this process is being repeated many thousands of times each second and the effect results in noise, vibration and eventual erosion of metal from the surfaces. In very severe cases, for example where the pump is handling liquids carrying small solid particles, the impeller can be eroded in a relatively short space of time.

An equally important factor is that severe cavitation can result in a failure of the pump to deliver flow at the expected head.

When pumping oil, the drop in head and efficiency is not quite so severe as with water because the liquid is composed of mixtures of different hydrocarbon compounds. The bubbles which appear will consist of lighter hydrocarbons such as methane or ethane. These can be more easily reabsorbed as the pressure is increased. When pumping water the bubbles are nearly always caused by the water boiling at a reduced pressure. In this situation the bubbles collapse violently and each implosion is of a high intensity.

? Test Yourself 4As a check on whether you have understood what I have been saying about pressures at the suction end of the pump, list these three pressure values:

a) the pressure at which gas or vapour is released

b) the static suction line pressurec) the NPSH

In order of decreasing pressure, and see if you can explain the reasons for your answers.

You will find the correct answers in Check yourself 4 on page 66.

Flow v Differential Pressure

Take another look at Figure 3. You will recall that it illustrate the conversion of pressure energy to kinetic energy, and the reverse, as a fluid passes through a restriction. Remember also that, because )f turbulence, some pressure energy is converted to seat energy. This conversion is responsible for the pressure loss shown in Figure 3.

Any pipeline will contain a whole series of restrictions. These may be bends, changes in diameter, obstructions and rough internal surfaces, or example.

You will probably realise, therefore, that:

at low flow rates the turbulence caused by these restrictions may well be small, therefore minimising the pressure loss

at high flow rates the turbulence could be very high, as will be the pressure loss

We will now take a look at the relationship between flow and differential pressure between two points in, say, a pipeline.

Have a look at Figure 6.

Figure 6 : Flow v Differential Pressure

This shows the relationship between flow and differential pressure, both expressed as a percentage of the maximum possible under those particular circumstances.

We can see, for example, that 50% of the maximum flow is equivalent to 25% of the maximum differential pressure.

Now let us suppose that, in our pipeline, we can generate up to 50 psi of pressure at the inlet and deliver up to 50 gallons of liquid per minute. Let us also suppose that, at the outlet, the liquid discharges into a pond at 0 psi.

We therefore have a differential pressure of 0-50 psi and a flow rate of 0-50 gals/min. Let us look at the conditions under different flows and pressures.

if we regulate the inlet flow to 5 gals/min (10% of maximum) we could expect very little turbulence. From Figure 6 we can estimate that the differential pressure will be 1 % of maximum, or 0.5 psi, at this flow rate.

if the flow is increased to 10 gals/min (20% of maximum), both turbulence and the pressure drop will increase. At a 20% flow rate, the differential pressure will rise to 4% of maximum, or 2.0 psi.

(You will have noticed that, when the flow rate doubled, the differential pressure increased by a factor of 4).

let us now increase the flow rate to 20 gals/min (40% of maximum). The differential pressure rises to 16% of maximum, or 8.0 psi. Again, as the flow rate doubles, from 10 to 20 gals/min, the differential pressure quadruples, from 2 to 8 psi.

This relationship between flow and differential pressure can be expressed as a mathematical equation

F = D P x 10

whereF = flow rate as a % of maximumDP = differential pressure as a % of maximum(DP means the square root of DP)

That ends our brief look at some of the key factors which affect the design and operation of centrifugal pumps. Before we go onto the next Section, however, try the following Test Yourself.

? Test Yourself 5In the example we have just used, if th6 differential pressure fell from 70°}4 to 40%. of maximum, what would be the change in flow rate, expressed in gallons per minute ?

The answers can be found in Check yourself 5 on page 66.

In this section, we have looked at some of the scientific terms and concepts which help us to understand the design and operation of centrifugal pumps.

You will remember, for example, that both liquids and gases are called fluids because they have the ability to flow. We saw how fluids flow from high energy areas to low energy areas.

We examined the relationship between mass, force and weight, and I tried to clear up some of the confusion which exists in the common use of these words.

Density and specific gravity were explained.

I illustrated centrifugal force by asking you to visualise the movement of a water drop on a spinning disk.

This led us to a description of kinetic energy, and how kinetic energy and pressure energy can be interchanged. We introduced the concept of conservation of energy.

Net positive suction head (NPSH) was fully described, and we saw how important it was in relation to preventing cavitation.

We -looked at differential pressure and flow. The relationship was expressed as a graph, and also as a mathematical equation.

Yon: are now ready to take a look at the construction and operation of a centrifugal pump, and see how the terms and concepts covered in Section 1 can be applied to the design and performance of this type of pump.


Oil Pumping and MeteringSection 2 – Construction and Operation of Centrifugal Pumps

The centrifugal pump is the commonest form of pump in use today. It is relatively cheap, easy to maintain and is to be found almost everywhere when large flows are required.

We will first take a look at the basic configuration of a centrifugal pump and then at the component parts, to see what they do and how they work.

The type of pump illustrated in Figure 7 is one of the simplest. It consists of a casing, which contains and supports the rest of the pump

components. Access to the inside of the pump is via a vertical split at the back of the casing (not shown)

a suction flange, which directs the liquid entering the pump casing into the impeller

an impeller, which imparts kinetic energy to the liquid

a pump shaft, connected through a coupling to a motor which drives the shaft and the attached impeller(s)

a bearing housing, which supports the shaft

a shaft seal, which prevents liquid escaping from the casing along the shaft

a discharge flange, which directs the liquid away from the pump

Figure 7 : A Typical Centrifugal Pump

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Figure 8 shows a cross section through a single impeller pump, illustrating three more key items of equipment:

The wear rings, which act as seals between the high pressure discharge side and the low pressure suction side of the impeller

The wear rings are so called because they wear in preference to the impeller. They are `sleeved' on to the impeller, and may be replaced when worn

The balance holes, which allow the packing to operate at suction pressure rather than discharge pressure. This reduces the differential pressure across the packer and impeller, and therefore reduces the "thrust" forces

The packing, which prevents liquid escaping from the casing

We will now examine some of these components in more detail.

Figure 8 : Cross Section Through a Single Impeller Pump

ImpellersWe have already seen that a spinning disk can impart kinetic energy to a drop of water on its surface. A centrifugal pump, which is a dynamic pump, does a similar job on the liquid it is pumping. The pump then converts this kinetic energy into pressure energy before the liquid leaves the outlet.

The elements of the pump which impart kinetic energy to the liquid are called impellers. We will now look at the three basic kinds of impeller and see how they differ from each other.

All impellers are fitted with curved vanes which spread out radially from the centre. The impellers are attached to the pump shaft and rotate with it.

Figure 9 shows the three most common types of impeller.

Your washing machine at home probably has a pump with an open impeller similar to the one shown at the top of the diagram. Open impellers are cheap to make but they are inefficient.

The one on your washing machine will be there to empty the machine. Washing machine pumps, however, have to cope with debris - buttons, fluff, coins and the like. An open impeller is ideal. It will handle most foreign objects and, if it is broken, it is cheap to replace. Figure 9 : Types of Impellers

The water pump on your car will probably be fitted with a semi-open impeller similar to the one shown in the centre of Figure 9. The semi-

open impeller is a little more efficient and a little more expensive than the open impeller.

The car pump has to be reasonably efficient to provide engine cooling by circulating water around the engine and through the radiator. But, every bit of energy used in the water pump means that there is less available to propel the car itself. The semi-open impeller is therefore a compromise between efficiency and cost.

In the oil industry, the closed impeller is the one most often used. This is shown at the bottom of Figure 9. It is more efficient than other types of impeller, but is also considerably more expensive.

This is because special techniques are needed to weld the vanes to the inside of the shroud which covers the impeller.

You should notice, in particular, the curve on each impeller vane, and compare this shape with the shape of the droplet trajectory in Figure 2. They are very similar.

Vanes are designed in this way to impart the maximum amount of kinetic energy to the liquid being pumped, and to ensure that this liquid leaves the impeller rim at a particular angle.

This angle will be matched by the shape of the volute, or angle of the diffusers, depending on the pump design. (I will talk about volute and diffuser casings shortly).

Impeller Speed

The type of impeller selected will depend on the planned speed of rotation, and the type and size of pump.

As a general rule

low pressure, high capacity pumps will have large diameter impellers with a low rotating speed

high pressure, high capacity pumps will have small diameter impellers with a high rotating speed

Pump Casings

We already know that the velocity of the liquid increases as it passes across the impeller. We also know that, as the velocity decreases, the pressure will increase. Figure 10 shows the two main types of casing which allow this to happen within the pump.

The upper diagram shows a volute casing. In this type of pump, the liquid leaves the tip of the impeller, and is thrown into a channel with an increasing area of cross-section. Here the liquid slows down and kinetic energy . is converted into pressure energy.

The volute design ensures that it is aligned with the trajectory of the liquid leaving the impeller. This ensures efficient energy transfer and conversion.

The liquid is then guided towards the pump discharge flange.

The volute type of pump is the most common type in use.

The lower diagram shows a diffuser casing. In this type of pump, as the liquid leaves the tip of the impeller it moves through a set of angled vanes known as diffusers. Again, these are lined up with the direction of the pumped liquid as it leaves the impeller. The diffusers then guide the liquid into the outer section of casing where its velocity decreases and pressure increases before flowing to the discharge flange.discharge flange

Pump discharge flange

SINGLE VOLUE CASING

Figure 10 : Volute and Diffuser Casings

Bearings

Figure 11 is an illustration of a simple bearing arrangement. The shaft is supported by two radial ball bearing races, which allow it to rotate with minimum friction.

Thrust force is a force which is directed along the axis of the pump shaft. It arises because of the difference in pressure between the discharge and suction sides of the pump acting on the impeller. In Figure 11, the thrust force will be from right to left, (from high pressure to low pressure).

In this case, to counteract the thrust force, a ball bearing race (the thrust bearing) is mounted between two vertical plates. It allows the shaft to turn with a minimum of friction as it takes up this thrust force.

The slinger rings (also called flinger rings) are two slender rings, often of brass, which slide up and down the shaft as it rotates. The slinger rings dip into the lubricating oil and, as they turn, transfer oil onto the shaft. The oil then runs along the shaft and contacts the faces of the bearings. Centrifugal force throws the oil outwards along the bearing faces to lubricate and cool them.

The oil in this type of bearing is either topped up through an oil fill plug, as shown, or is automatically replenished via an oil bottle arrangement.

oil fill plug

sump drain plug oil sump

Figure 11 : A Typical Bearing Arrangement

Motor

Seals

Figure 12 is an illustration of a typical packed seal. In this type of seal the packing consists of rings of asbestos rope which are impregnated with graphite. The rings are placed around the shaft and compressed into a packing gland by means of a gland follower, the pressure on which can be adjusted by four bolts.

In some cases a lantern ring is fitted between sections of the asbestos packing so that any liquid which has leaked along the shaft can be removed.

The problem with this type of shaft seal is that small leaks almost always occur, whatever liquid is being pumped. These leaks are usually necessary in order to keep the

packing lubricated and to prevent the shaft from overheating.

However, any leak would be dangerous when pumping oil or other hazardous liquid. In such cases, a mechanical seal would probably be used. A typical seal is illustrated in Figure 13 on the next page.

Figure 12 : A Typical Packed Seal

The shaft enters the pump casing from the right hand side of the diagram and passes through a stationary seal . The stationary seal is fixed to the pump casing and does not rotate.

Attached 10 the Shaft is a rotary (of rotating) seal. Leakage along the length of a shaft prevented by 'O' rings which seal the gap between shaft and rotating seal. The '0' rings turn together with the shaft and rotating seal.

The sealing faces of the rotating and stationary seals are usually of machined carbon or high grade stainless steel which are polished to a mirror finish. The two faces are held very closely together by a spring and by the pressure of the liquid in the pump.

A small amount of the liquid being pumped is often taken form the discharge of the pump, filtered, and then returned through the mechanical seal via the seal flush inlet. This liquid helps to keep the mechanical seal clean, cool and lubricated.

drive end

Stationary seal

Figure 13 : A Typical Mechanical Seal

Pump ConfigurationsFigure 14 shows examples of how centrifugal pumps may be configured to increase flow, or to increase pressure.

Figure 14 a, b and c:Centrifugal Pump Configurations

n Figure 14a, a single pump is delivering 100 gallons per minute with a total head of 50 psidischarge head - suction head = total head.

Figure 14b shows that, to increase the flow, two pumps arranged in parallel are needed - that is, the pumps have a common suction and a common discharge.

In this case, we can

b)

c)

run either pump on its own to produce a flow rate of 100 gallons per minute and a total head of 50 psi, or,

run both pumps together to produce a flow rate of 200 gallons per minute and a total head of 50 psi.

In Figure 14c, we can increase the pressure by running two pumps in series. This means that the first pump discharges into the suction of the second pump.

In this case both pumps must be run together the combination of both pumps will produce a flow rate of 100 gallons per minute and a total head

of 100 psi.

In most instances where high pressures are required, it is easier to mount a number of impellers on a single shaft. These pumps are called multi-stage pumps. They give us high flow rates, and a gradual pressure rise over as many stages as required. Some main oil Figure 14 a, b and c : pipeline pumps may have more than eight impeller stages.

Centrifugal Pump Performance Curves

Every centrifugal pump is designed and manufactured for a specific purpose. This purpose is summarised in a pump performance curve.

Figure 15 shows a typical performance curve which gives us the following details about a specific pump:

on the left hand side of the curve which gives us the following details about a specific pump

1) efficiency - from 0-100%. This compares the power the pump is using to the work it is achieving

2) power - from 0-24 kilowatts in this case. This indicates the amount of power the motor is consuming

3) total head - this indicates the pressure which the pump can achieve

on the top right hand side of the chart we can see the required NPSH (net positive suction head) in metres of liquid. (you will recall that NPSH was described in Section 1 on Page 13)

the horizontal axis of the chart gives flow rate in cubic metres per hour.

in the body of the chart we find curves which show the relationship between

1) NPSH and flowrate2) efficiency and flowrate3) power and flowrate4) total head and flowrate

Take a few minutes to study Figure 15 and then try Test Yourself 6 and 7.

The answers to these can be found in Check Yourself 6 and 7 on Pages 66 and 67

Now, to summarise what we have covered so far in Section 2, try Test Yourself 8:

Check your answers in Check Yourself 8 on Page 67.

Item Casing Impeller Bearing Seal

shaft sleeve 'O' Ping

Shroud

lantern ting

wear rings

Flush inlet

Vane

Slinger ring

Glance holes

Gland follower

Volute

bell bearing race

Diffuser

A Centrifugal Pump Arrangement

Before we look at a typical oil pumping system, let us think about those items of equipment which you are most likely to come across.

Figure 16 is an illustration of a typical centrifugal pumping arrangement.

Figure 16 : A Typical Centrifugal Pump Arrangement

The motor which drives the pump is called the main driver. In this case, the main driver is an electric motor, but for bigger pumps it may be a gas turbine or a diesel engine.

The motor has a set of local switches for starting and stopping. In some cases a local ammeter is fitted to check whether the motor is running properly. In many instances, the pump motor may also be started from a remote location, such as a control room, either manually or via an automatic start system.

The motor shaft is linked to the pump shaft via a coupling, designed to transmit power from the motor to the pump, and to take care of any small shaft misalignments which may occur.

The flow of liquid into the pump is through a suction block valve, which can be used to isolate the pump from the upstream process if required. Occasionally, a strainer or filter (not shown) may be fitted to the suction line, downstream of the suction block valve, to prevent debris from entering the pump.

The pump casing is fitted with:

a casing vent valve, used to bleed off any gas or air in the pump before starting

a casing drain valve, used to drain liquid from the pump after shutdown

The discharge of the pump is fitted with:

a discharge pressure gauge, which indicates the pressure produced by the pump

a discharge check valve, which only allows flow in one direction, away from the pump. This valve, therefore, prevents liquid flowing back through the pump, back-spinning it and causing damage to the seals and bearings of both pump and motor

a discharge block valve, which can be used to isolate the pump from the downstream process, if required

Minimum Flow System

All centrifugal pumps require one other item of equipment for their protection.

If we look back at the performance curve in Figure 15 we can see that, when the pump is running at zero flow, it is still using about 4 kilowatts of power. We also know, from the performance curve, that the pump efficiency will have fallen to zero.

So, what has happened to the power we are using ?

The answer, of course, is that it is converted into heat energy.

There would be great turbulence inside a pump with the impeller turning through liquid trapped within the pump. The temperature would rise, increasing the chances of cavitation.

In some instances, with large and powerful pumps, damage can then occur in a matter of seconds. In smaller machines it may take

much longer - but damage will eventually occur.

To prevent this situation from happening, a minimum flow must be established and maintained through the pump at all times while running. This minimum flow level is specified by the pump manufacturer.

All centrifugal pumps which are at risk can be fitted with a minimum flow system. This ensures that, while the pump is running, there is sufficient liquid flow to ensure that no damage occurs.

In some instances, the minimum flow system consists of a simple orifice plate, sized for the correct flow. The plate is inserted into a line through which is re-cycled a fixed flow from pump discharge to pump suction at all times.

In other instances a flow measuring device is fitted into the suction of the pump. This device controls a flow control valve, inserted into a line which re-cycles a fixed amount of flow. If the flow falls below the pre-set minimum level, the flow control valve will open to restore flow rate to the minimum.

A simple and very common device is illustrated in

Summary of Section 2

Shaft seals

We exarnined Finally we looked at wly cenlrHugal pumps are fitted with a mintmum Ilew 5qstern, oriSuring thatflow difterent types of pump casing played a they do not become damaged due to overheating part in converting kirxatic energy into pressure and cavilMion. energyhow e can change flow and!ar prassuracharacteris,tfcs by changirG pump In the next s9olian. We Will ta'r.C_ ;1 I:i-„k at a typicj~Oceniigu:alions (parallel v. series) aid metering land sampling systernIn particular, we looked atthe construction and :inierp-re;etion of a set of pump performance curves for a typical centrifugal pump and how they incorporate the concepts and ideas which we had previously enc,ountereda typicat centriluga' pump arrangement with its inlet and outtlet lines and associated equipment

Oil Pumping and MeteringSection 3 – Oil Metering and Sampling

We have considered the basic design and operation of a centrifugal pump.

Now it is time to take a look at crude oil metering, metering systems, and sampling techniques.

There are four main reasons for metering and sampling a flow of crude oil

1) to measure the amount of hydrocarbons removed from the reservoir. This allows field production plans to be updated and revised.

2) to determine the amount of each component in a mixed oil stream. This is particularly important where the production from separate oil fields are mixed (perhaps as part of pipeline sharing agreements) prior to the point of sale.

3) to measure the product for tax purposes. This is called fiscal metering.

4) to ensure that no loss of product has occurred. In an offshore oilfield, the amount of metered offshore product, plus any losses or gains due to packing or unpacking of the pipeline (see below), is compared regularly with the amount of onshore metered product.

Multi-component liquids such as crude oil are slightly compressible. Increases or decreases in the overall pipeline pressure will produce small changes in the volume of oil contained within the pipeline. The terms packing and unpacking are used to describe these small changes in volume. If they are ignored, apparent losses or gains in the pipeline inventory can accumulate.

The sampling and metering system is placed as late in the oil handling sequence as possible. There are a number of reasons for this:

it should be downstream of any booster pump which is fitted. (On many installations, the crude oil passes through a booster pump to raise the pressure prior to entering the metering and sampling section. This ensures that no gas or vapour will break out of the liquid whilst it is being metered and sampled)

no further processing of the fluid occurs before export, and the fluid sampled and metered is representative of the fluid being exported

metering takes place downstream of water removal. At a water content higher than about 1 %, serious discrepancies occur in meter accuracy which conflict with the objectives of metering and sampling

The process of metering and sampling is therefore given a very high priority. Meters themselves are checked regularly, using a permanently installed meter prover. The meter prover itself is checked regularly to ensure that it, too, is accurate.

To emphasise this point, try Test Yourself 9:

There are many methods used to measure fluid flow. It is worth noting, however, that most flow rates are arrived at indirectly by measuring some other property of the flowing fluid, and then relating the value of this property to flow rate by some form of calibration. This is true for the two most common devices used for metering produced oil:

the differential pressure meter the turbine meter

For example, as you will see later on

in the differential pressure meter, it is a pressure difference which is measured directly

in the turbine meter, we measure the frequency of electrical pulses

In this Unit, we will take a brief look at the differential pressure meter, and how it operates. We will then consider the turbine meter.

Differential Pressure Meters

Differential pressure metering is one of the oldest methods of measuring flowrates. It is simple, accurate, reliable and relatively inexpensive. It will record volume flowrates (say, cubic meters per day), but mass flowrates (say, tonnes per day) can be calculated if the density of the oil is known.

The most common differential pressure device is one which uses a restriction, usually an orifice plate, in the pipeline. The pressure drop across this restriction is measured. This pressure differential can then be related to flowrate by the use of, for example, calibration tables or graphs. A large amount of calibration data has been published on this.

The orifice plate is popular because it has no moving parts and is very accurate if calibrated and maintained correctly.

In order to measure the pressure drop, there should be pressure tappings on either side of the orifice plate, as shown in Figure 18.

These are usually located:

one pipe diameter upstream of the orifice plate and a half diameter downstream

or

in the flanges which hold the orifice plate in the pipeline

The first method provides more accuracy, but the second method is most widely used.

In general, accurate metering can only be achieved when the orifice plate is designed, fabricated and installed with great care.

The most common type is the square-edge orifice plate, shown in Figure 18.

We must ensure that the flow entering the device is steady and free of eddies which would affect the accuracy of the meter. The orifice plate should, therefore, be placed at a point where temperature and pressure are constant. In addition, bends, valves and other fittings upstream of the orifice plate tend to disturb the flow pattern of the fluid approaching the plate. To avoid this, it is common practice to specify:

a minimum length of straight pipe both upstream and downstream of the orifice plate

or

a flow straightening vane to be fitted upstream of the plate

A flow straightening vane is a length of pipe with a set of fins running along the inside. As the fluid flows along this stretch of pipe, the fins straighten the flow and prevent swirling. Flow straightening vanes are also used upstream of turbine meters.

Figure 19, demonstrates how the pressure changes as fluid passes through an orifice plate. The differential pressure is measured between points P1 and P2. Point P2 is positioned in line with the vena contracta - the point at which fluid velocity is at its highest, and pressure at its lowest.

The differential pressure thus created will depend mainly upon

type of fluid pipe diameter orifice diameter flow rate inlet pressure

The differential pressure thus recorded may then be converted into a flowrate figure.

r

Figure 19 : Pressure Changes Across an Orifice Plate

Turbine Meters

Turbine meters are the most popular method of measuring produced oil. They are accurate, reliable and are easily proved and adjusted.

Turbine meters consist of a straight flow tube within which a turbine or fan is free to rotate. You can see this in Figure 20. The flowing stream causes the turbine to rotate at a speed proportional to the flowrate. If the flow increases, the turbine will spin faster. If the flow decreases the turbine will rotate more slowly.

In most units, a magnetic pick-up system senses the rotation of the turbine rotor. As each blade passes the pick-up coil, an electric pulse is generated. Each pulse is counted and, as each pulse represents a known volume of liquid, the total flow of oil can be calculated. In some cases, two pick-up coils are installed, so that the two separate pulse counts may be compared with each other as an additional check.

Figure 20 : Turbine Meter

One of the major advantages of a turbine meter is in its use for producing additional flow data. The electrical pulses generated can be fed into a computer system, which can then perform other, more complex, flow calculations. This additional information may be added to the final read-out.

It should always be remembered that the accuracy of a turbine meter depends almost entirely on the precision of the rotor and how consistently its speed of rotation can be related to flow. If the rotor becomes damaged, worn or dirty, then its capacity to measure flow accurately will suffer dramatically.

Metering Systems

The component parts of a typical turbine metering run are shown in Figure 21. These consist of

A manually operated Inlet block and bleed valve, which allows the metering run to be positively isolated from the rest of the process upstream. The bleed facility allows the space between the two valve seals to be de-pressurised, proving that no liquid is passing across the valve.

A filter, to remove any particles which may damage the measuring element. The filter is fitted with a differential pressure switch (PDS), which gives an alarm if the pressure drop across the filter gets too high (due to filter blockage).

Flow straightening vanes, to remove turbulence and any tendency for the fluid to swirl.

A measuring element, in this case a turbine meter fitted with a pulse transmitter. The electrical pulses produced may be transmitted to the flow computer. (In the case of an orifice plate metering system, the differential pressure across the plate produces an electrical signal, which may also be sent to the flow computer.)

Figure 21 : Meter Stream Components

A flow control valve, which controls the flow of liquid through the metering run. When there are two or more metering runs, a central metering controller will apportion flow between the different flow control valves to ensure that each meter run is operating within its limits.

A motor operated outlet block and bleed valve (MOV), which allows the metering run to be positively isolated from the rest of the process downstream. This isolation is required when the meter run is out of service, or when it is being proved by the meter proving system.

A second, motor operated block and bleed valve (MOV), which is opened when the meter run is being proved. When this occurs the flow is diverted through the second MOV to the meter proving system.

In practice, the pressure, temperature and density of the oil may change while the flowrate is being measured. To compensate for these changes, readings of the temperature, pressure and density are taken. This information is then fed, together with data from the flow measurement device, into the flow computer. Corrected values for volume flow rate, mass flow rate, etc., can then be computed and recorded.

Therefore, in many meter runs, but not shown in Figure 21, you will find

a thermometer, which measures the temperature of the stream being metered

a pressure transmitter

an on-line densitometer

Meter Proving

You saw, from Test-Yourself 9, that small inaccuracies in measurement of oil can result in considerable revenue losses. In order to minimise any errors the meters are proved at regular intervals. The term proving is used in the oil industry to refer to the calibration of oil meters.

The procedure involves comparing the indicated (recorded) volume of oil passing through the meter with the actual (true) volume as measured by a very accurate device known as a prover. From this comparison a correction factor can be obtained which is then used to convert the observed flow readings to true values.

This correction factor is known as the meter factor.

There are various types of meter prover, but the most common one is the pipe prover.

The basic principle on which a pipe prover works is as follows:

A slightly oversize, elastic sphere is installed in a special length of pipe. It is free to move within the pipe as it is pushed by oil flowing through. As it moves it forms a travelling seal against the inside of the pipe.

The prover is connected in series with the meter to be proved. So, the volume swept out by the sphere in a given time is identical to the volume passing through the meter.

Two detectors are installed in the special pipe near each end. These emit a signal when the sphere passes them, which is transmitted to the pulse counter of the meter. When the sphere reaches the first detector it starts the counter. When the sphere reaches the second detector it stops the counter.

The pulses, and therefore the volume, recorded by the meter should be the same as the true volume displaced by the sphere as it travels between the detectors. If it is not, the recorded volume and the true volume are compared, to arrive at the meter factor.

The meter factor then is

accurately calibrated volume of provervolume registered by meter

Pipe provers usually consist of a U-shaped or W-shaped length of pipe. Figure 22 is an illustration of a bi-directional U-shaped meter prover loop.

Figure 22 : A Bi-Directional Prover Loop


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Figure 23: Pig Designs

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Brush pig

Brushes

sphere

Foam Brush pig


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A bi-directional U-shaped meter prover loop, operates as follows;

The flow enters the meter prover through the meter under test.

In the position shown, the oil flow is holding the calibration sphere against the buffer. If the 4-way diverter valve is now turned through 90 degrees, the flow through the prover loop is reversed. This reversed flow picks up the sphere and carries it round the prover loop for the first pass. Two sphere detectors are mounted in the prover loop, and the internal pipe volume between these detectors is already known.

As the sphere passes sphere detector 'A', a signal to the flow computer records the flowmeter reading at that point.

When the sphere passes sphere detector 'B', a new flowmeter reading is recorded.

The difference between these two meter readings, representing the metered volume of the prover loop, is now computed and stored.

The calibration sphere, at the end of the first pass, is now held against the other buffer.

The flow computer now turns the 4-way diverter valve through another 90 degrees to start the second pass.

The second pass is now completed as above, but with the oil flow reversed.

The flow computer will then average the two metered volumes from the first and second passes and compare this average with the known volume. If the volume recorded by the meter under test is the same as the known volume then the meter has been proved.

If there is a discrepancy between the measured volume and the known volume, the flow computer will calculate a correction factor and then apply this to the meter under test. Another meter proving run will then take place.

When the flowmeter reading (including any correction factor) falls within 0.5% of the known volume, without adjustment, for at least five consecutive proving runs, it is classed as being accurate.

Sampling Systems

It is not only important that the crude oil is metered accurately. It is equally important to gather information on the nature of the oil being pumped. The chemical and physical nature of the oil may change with time, as may the level of contaminants, such as water or solids, still present after the separation process.

A sampling system must therefore be installed to determine the precise nature of the liquid being pumped.

Sampling systems have two main functions

• sampling for metering• sampling for analysis

Sampling for metering involves the use of an online density measuring system. This system continuously samples the fluid and passes the density results to the flow computer. The computer then combines values for density, pipeline pressure and temperature to calculate the mass flow.

Sampling for analysis is carried out by a second system. At regular intervals, a pump extracts a small amount of the fluid being metered, and these small samples are stored in a sample jar or similar vessel. Periodically, this combined fluid sample is taken away to be analysed in detail.

An on-line basic sediment and water (BS&W) system is also installed on most oil handling facilities. The BS&W analyzer ensures that the water and solids content of the crude does not exceed pre-set limits (typically "less than 1 %") without a warning being transmitted to the operator.

The automatic sampling systems described above are usually backed up by samples taken manually by the operator, as a check on the automatic systems.

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Oil Pumping and MeteringSection 4 – Pig Launching Facilities

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In previous sections, we have looked at the equipment used to pump the oil. I have described typical metering systems and how we prove that they are accurate. Sampling and analysis of the crude oil were touched upon.

In Figure 1 we saw that the last stage in a crude oil production facility is normally the pig launcher - the final item of equipment on the installation before the oil enters the main oil pipeline..The oil which flows through the pipeline may have a small amount of residual water in it. There may be traces of sand, or wax may be deposited from the oil as it cools down. All of these materials may settle out and affect the efficiency of the pipeline.

Devices called pigs may then be pumped through the pipeline, from the pig launcher, to remove the water or sediments which have settled out from the oil.

Pig should from a reasonably tight fit inside the pipeline, in order that they perform their cleaning duties effectively they are efficiently transported through the

pipeline by the fluid flow

By the way, there are two main explanations given for the name “pig” both of which are equally unlikely.

the first is that the original pigs were made from stuffed pigskins, send through water pipelines to clear them out

The second is that early pigs were made of wood, with metal bands around them to help withstand constant rubbing against the wall of the pipeline. As they travelled along the pipeline they "squealed like pigs" as the metal bands scraped along the pipe

I will leave you to choose which one you believe.

Types of PigPigs come in a variety of shapes and sizes depending on the service which they are intended to perform.

Figure 23 on page 43 illustrates a few of the designs available. Their main uses are as follows; the squeegee pig is often used for separating

different liquids or gases when pipelines are being filled or emptied, or when the same pipeline is being used for different products. It

may also be used for lightweight cleaning duties and for de-watering gas pipelines

the brush pig is used for cleaning and de-waxing pipelines. (Scrapers may also be included in the design). Brush pigs in liquid service often incorporate a series of pipes which provide liquid channels through the pig centre. Some of the liquid behind the-pig will pass through the pipes and, because of the angle at which these pipes are set, the pig rotates, thus improving the brushing effect. In addition, the jetting action this causes ahead to the pig stops a build up of debris at that point.

the sphere is used mainly to de-water gas pipelines but it is occasionally used for very light cleaning work on oil pipelines

the foam pig is most often used for the initial de-watering and cleaning of pipelines. Any welding rods, or other sharp objects which may have been left in the pipeline, embed themselves into the foam as the pig passes by

the foam brush pig is used in lightweight cleaning service, usually on gas pipelines

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A very specialised pig is shown in Figure 24. Thisis the Kaliper pig or Linalog pig.

As this type of pig travels along the pipeline, two wheels, positioned near the centre of the pig, press against the walls of the pipe and record how far the pig has travelled.

At the same time a series of fingers, mounted at the back of the pig, slide along the walls of the pipe and measure its diameter.

The information thus collected is recorded on a chart which is built into the pig. The chart can be analysed on arrival, to reveal variations in internal diameter (caused, perhaps, by dents or corrosion pitting) and precisely where these variations occur.

Pigs are becoming more sophisticated and, these days, are capable of measuring and recording a wide range of data related to the condition of the pipeline and contents.

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Pig Launchers

We will now take a look at Figure 25, which shows the basic layout of a pig launcher, and think about how it operates


Under normal conditions, the crude oil supply by-passes the pig launcher and flows through valve X directly into the pipeline.

To load a pig into the pig launcher:

valve B and valve C should be closed

the pig launcher must be de-pressurised and drained of liquid

when these steps are completed, the pig launcher door - door A - is opened and the pig placed inside the launcher

door A is then closed

the pig launcher is refilled with liquid and re-pressurised using the pressurising valve

the pig launch Indicator is re-set to record when the pig passes that point

valve B and valve C are then opened, and valve X slowly closed

the flow of oil diverted through the pig launcher and this flow forces the pig into the pipeline

as the pig passes the pig launch indicator it activates a “flag” which tells the operator that the pig is in the pipeline

the operator can now open valve X, and close valves B and C

Pig Launching Problems

It all looks pretty straightforward, so what can go wrong?

Well, some pigs are very reluctant to leave the pig launcher and it may take three or four attempts at loading, to get them far enough into the pig launcher for them to leave.

Again, pigs can break up as they traverse the pipeline. This may result in the non-arrival of a pig, and then damage to pigs which are sent down after it.

Pigs can stick in the pipeline. Some pig / pipeline combinations found onshore are so prone to sticking that the pig is fitted with a radio transmitter to assist in locating the sticking point. When a pig is stuck, the operator must decide whether to launch another pig in an attempt to shift the first one. If this doesn't work, you have two stuck pigs. Is it wise to try a third?

On occasion, foam pigs will 'leapfrog' each other inside the pipeline. Launched in the order 1,2,3, they arrive in the order 1,3,2.Pigs may leave the launcher and enter the pipeline without triggering the 'pig launched' signal; or arrive at the other end of the pipeline without trigge ring the 'pig received' signal.

In addition, it should be remembered that the operation of pig launchers and pig receivers is a major cause of explosions in the oil and gas industry. You will understand, therefore, why the launching and recovery of pigs is an

operation which must be treated with a great deal of respect.

Basic Rules for Pig Launching

Always bear in mind the following basic rules

stick closely to your own laid down procedures and do not take any short-cuts

as the pig passes the pig launch indicator it activates a "flag" which tells the operator that the pig is in the pipeline

during pig launching and receiving operations, do not assume that any event has occurred or not occurred until you have checked and double-checked thoroughly

always make sure that you are launching the correct size of pig

too narrow, and it may not travel

too wide, and it may stick, blocking the pipeline

too long, and it may jam on a bend, again (blocking the pipeline

too short, and it may hang on a bend allowing the flow to bypass it

always ensure that the pig is properly positioned in the launcher so that it will leave cleanly when the flow is diverted


always remember to re-set the 'pig launched' device before you launch the pig, otherwise you cannot tell whether it has entered the pipeline or not

As I have already emphasised, opening and closing pig launchers is potentially dangerous and, because of this, most of the launching facilities are fitted with safety systems. These prevent the operator from opening the wrong valve or, worst of all, opening the launcher door whilst the launcher is open to the pipeline.

Safety Systems

You will note from Figure 25 that a number of interlocks have been labelled. I do not intend to go into any detail on these -this topic will be covered extensively by other Units in the Petroleum Processing Technology Series.

As a simple illustration, however:

interlock A on the pig launcher doorInterlock B on valve B (inlet to the pig launcher) interlock C on valve C (outlet from the pig launcher) interlock D on the pig launcher low pressure switch

work together to ensure that the pig launcher door cannot be opened unless

valve B is closed valve C is closed the pig launcher pressure is low

Summary of Section 4

In this section we have looked at:

The reasons why we need to pig a pipeline

The different types of pig which may be used

A typical pig launcher and how to launch a pig

And, very briefly, the need for safety systems

We will now look at a typical Oil Pumping and Metering system and see how it compares with what we have learned so far. Before that, however, try the following Test Yourself:

?Test Yourself 11

1. Why do pig launchers systems present an explosion hazard?

2. What steps should always be taken before a pig launcher door is opened?

The answers are given in Check Yourself 11, which you will find on Page --.

Oil Pumping and MeteringSection 5- A Typical Oil Pumping and Metering System

In this section we will take a look at a typical oil pumping and metering system and see how it relates to what we have covered previously in this Unit.

You may like to refer back to Figure 1, which shows the general layout.

A few assumptions have been made in the design illustrated

the production operation is offshore and the main pipeline takes the oil to an onshore facility, where it is treated further

there is no crude oil buffer storage facility. Therefore, the separated crude oil is pumped directly from the second stage separator, through booster pumps and pipeline pumps into an export pipeline system

the crude oil metering facility is located between the booster pumps and the pipeline pumps. As previously explained, this location ensures that there is a stable flow to the metering system and that the pressure is sufficiently high to prevent any gas bubbles forming

Booster Pumps

If we look at Figure 26, on the next page, we can see how the booster pump system works.

The crude oil flows from the 2nd stage separator through an emergency shutdown

valve, ESDV 1. Valve ESDV 1 is common to the suction of all three pumps we are using here.

ESDV 1 will be closed by remote signals if an emergency occurs. Typical emergencies would be

a very low oil level in the 2nd stage separator (part of a process shutdown because only the oil process would be closed down if this occurred)

a fire in the wellheads area (part of an emergency shutdown, which would shut down all processes).

ESDV 1 also has an interlock (IL) which, if the valve is in the closed position will prevent any of the booster pumps from starting.

It should be noted that, after the pumps are running, the closure of ESDV 1 will not shut them down via the emergency shutdown system. It only acts as an inhibit to prevent the pumps starting in certain circumstances. If ESDV 1 closes while the pumps are running, then the low-low pressure switch on the discharge of the booster pump (PSLL) would shut down the pumps.

Downstream of ESDV 1, the line branches into three, which provide suction to each of the booster pumps. It is normal practice to specify that the piping configuration to the pumps is designed to distribute the oil flow evenly.

The first valve on the suction of booster pump A is HV 1. HV 1 is a hand operated valve and it is also interlocked as an inhibit, to prevent the starting of booster pump A when it is closed.

Downstream of HV 1 and just upstream of the inlet to the pump is a 'T' filter. This is usually a coarse screen, designed to prevent larger items of debris (gloves, helmets, spanners, etc.) from entering and damaging the pump.The filter is fitted with a differential pressure switch (PDS) which incorporates a high differential alarm. This arrangement will give an alarm in the event of a high differential pressure caused by filter blockage. It should be noted that a low or zero reading here may be caused either by a clean filter or a ruptured filter !

The discharge of booster pump A is fitted with a pressure switch low (PSL) and a pressure switch low-low (PSLL). PSL will give an alarm and PSLL will cause the pump to shut down in the event of low pressures.

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Figure 26 : A Typical Booster Pump System


After a shutdown, PSLL creates a potential problem. If the pressure at that stage is below the setting of PSLL, the pump cannot be re-started. A shutdown signal is still being sent from the Pressure Switch Low-Low. Something must be done to allow the pump to restart.

The problem is overcome by, automatically, bypassing PSLL for 30 seconds when the pump is started. This allows sufficient time to build up enough pressure to re-set the switch. If the increasing pressure does not re-set PSLL before the 30 seconds have elapsed, then the pump will shut down again. This system is called a time-pressure race, i.e., the pump is racing against time to generate sufficient pressure to re-set the switch.

The discharge of the pump is also fitted with a pressure switch high (PSH) and a pressure switch high-high (PSHH). PSH will give an alarm and PSHH will cause the pump to shut down in the event of high pressures, perhaps because of problems downstream.

The discharge of the booster pump is fitted with a minimum flow non-return valve (SV 1), which we have already described in Section 2, Page 31 and Figure 17. To prevent the continuously re-cycled oil from becoming progressively hotter, it is routed

all the way back to the 2nd stage separator via HV 2.

The discharge from pump A now passes through a hand-operated valve, before joining the flow from the other pumps. The combined flow then passes through level control valve LCV 2. This valve controls the oil level in the 2nd stage separator. The separator level controller will open this valve if the level rises, and close it if the level falls. We can see that, in the event of a failure of supply to the 2nd stage separator, the valve would close completely and the booster pumps would go on to minimum flow.

After passing across LCV 2 the oil flows to the sampling and metering systems.

You should note that the booster pump system is designed so that its discharge pressure is high enough to meet the required suction pressure at the main oil pipeline pumps, which we will look at later.

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Sampling System

Figure 27 shows the layout of a typical sampling system.

Figure 27 : A Typical Sampling Arrangement

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You will see that a side stream is removed from the inlet header to the metering system by one of two sample pumps, A and B.

This side stream is drawn through two.continuous sampling devices (A and B) where a small sample is removed and stored.

As an illustration of the sampling routine sample device A may take a composite

sample of five litres per day sample device B may take a composite

sample of 35 litres per week one litre spot samples may be taken

manually by the operator, as a back-up, at twelve hour intervals

After leaving the sample pumps, the sample stream flows to two densitometers (A and B) and a basic sediment and water (BS&W) analyzer before returning to the inlet header.

A densitometer is designed to measure the density of the sample stream fluid. It does this by comparing this fluid with a reference, whose 7density is known. The

result is then passed automatically to the flow computer.

A BS&W analyzer checks for the basic sediment and water contained in the crude oil flow. Most pipeline operations have a maximum specification for BS&W which, typically, may be "not more than1 %". This means that no more than 1 % of the total volume pumped into the pipeline should be sediment and water.

If an increased BS&W level occurs for any length of time, the pipeline pigging programme is readjusted to increase the rate of pigging. This is required to prevent the sediments and water from blocking and corroding the pipeline.

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Metering System

In the metering system shown in Figure 28, I have included just one meter run and a prover loop. The meter run, which we could designate run 'A', is from upstream of the inlet block valve (HV 1) to downstream of the outlet block valve (MOV 1). In a complete system there would be three or more parallel runs. I have indicated this in the drawing as additional runs'B' and'C'.A single prover loop is used and there are connections between each run and the prover, enabling it to be placed in series with any of the meters.

Figure 28 : A Typical Metering System

When meter run 'A' is in service, the normal flow pattern would be through

the inlet block valve (HV 1) the filter (F) the flow straightening vanes the turbine meter the flow control valve (FCV 1) the outlet block valve (MOV 1)

and from there to the pipeline oil pumps.

When the meter in run 'A' is being proved, the flow would be through

the inlet block valve (HV 1) the filter (F) the flow straightening vanes the turbine meter the prover loop block valve (MOV 2) the 4-way prover loop diverter valve

(MOV 3) the prover loop the 4-way prover loop diverter valve

(MOV 3) the prover loop flow control valve (FCV

2)

and from there to the pipeline oil pumps.

Note the flow computer in the drawing. You will remember from Section 3 that one of its jobs is to compare the volume indicated by the meter with the true volume of the loop to obtain a meter factor. In addition, it ensures that there is equal flow between each of the meters being used. It does this by altering the settings of the appropriate flow control valves. If meter run 'A' were in normal service this would be FCV 1. If meter'A' is being proved however, the flow would be controlled via FCV 2. The flow reading from each meter is fed to the computer via a flow transmitter (FT).

So, when the meter in run 'A' is being proved, the flow computer

closes MOV 1 opens MOV 2 transfers control of flow from FCV 1 to

FCV 2 allows flow to stabilise operates MOV 3 to start first proving run operates MOV 3 again, to reverse flow

through prover and start second (and any further) proving runs

performs necessary calculations to obtain meter factor

A few other points to note are

1) interlocks are fitted to MOV 1 and MOV 2 to ensure that these valves are at the right setting (open or closed) before the meter proving starts

2) pressure relief valve PSV 1 is located downstream of the filter and upstream of the flow straightening vanes. If HV 1, MOV 1 and MOV 2 are all closed for any reason, the pressure inside the meter run may rise due to any temperature increase. PSV 1 is fitted to relieve this pressure

3) to ensure the accuracy of the prover loop, the sphere is always oversized by 1-2%. This ensures a tight fit between the surface of the sphere and the walls of the prover loop. The sphere is replaced on a regular basis, and it is normally the first item to be changed if the accuracy of the prover loop is suspect

4) An independent contract company is often used to prove the prover loop, say, on an annual basis

Oil Pipeline Pumps

If you look at Figure 29, you can probably see how the oil pipeline pumping system works.

Figure 29 : A Typical Pipeline Pumping System

It is rather similar to the booster pump layout, so we will concentrate only on the important differences When the minimum flow system is

operating, crude oil is re-cycled from the discharge to the suction of the pump and is not routed back to a separator, as was the case in the booster pump layout. (The separators are upstream of the meters. Therefore, if the oil was re-cycled to the separators, it would pass through the meters twice, which, of course, would introduce errors into the flow measurements)

However, because the pipeline pumps are transferring a large amount of energy to the oil, this direct re-cycling would result in a rapid and substantial temperature rise. To prevent this from occurring, a re-cycle cooler is fitted to cool the crude before it is returned to the suction of the pipeline pumps. Offshore, the re-cycle cooler would often use seawater as a cooling medium (as shown in Figure 29) because it is cheap and plentiful

Fluid CouplingPipeline pumps have a variable speed drive. The speed at which they operate is determined by the pipeline pressure controller (which we will look at later). li the line pressure is too low, then the controller increases the pump speed; if it is too high, the pump speed is decreased.This speed variation may be achieved by a fluid coupling between an AC electric motor and the pump. Fluid couplings are also known as hydraulic couplings.

Figure 30: A Fluid Coupling

Figure 30 is a three dimensional cut-away drawing of the coupling assembly. You will see that the coupling comprises:

an inlet shaft, connected to the drive motor

an outlet shaft, connected to the main pump

The inlet shaft drives an oil circulating pump. The oil path is from the reservoir, via a cooler and small holding tank, into the circulating pump suction. From the pump discharge, the oil flows to the scoop chamber.

You should take particular note of the components labelled the runner and the Impeller. They are both of similar design and look like a ring of cups attached to a wheel. The runner is at the end of the inlet shaft, and the. impeller at the beginning of the outlet shaft. Each turns independently of the other within the casing. The only connection between them is made by the circulating oil when the unit is in operation - hence the term fluid coupling.

The basis of operation is as follows

the inlet shaft turns the runner, and drives the oil circulating pump. Note that the runner turns at 100% of the drive motor speed at all times

the cups on the runner pick up oil from the outer perimeter of the scoop chamber and throw it into the receiving cups of the impeller. The runner is therefore acting as a pump

the oil striking the impeller cups turns the impeller, which is acting as a turbine

the impeller then turns the main pipeline pump

Pump Speed Control

The amount of oil transferred between the runner and the impeller controls the output speed of the impeller and, therefore, the main oil pump.

Figure 31, on page 59, shows a series of cross sectional diagrams through a fluid coupling, which help us to explain this mechanism of speed control.

Figure 31 a, b and c : Speed Control Using a Fluid Coupling

The position of the scoop tube will determine how much power is transmitted across the coupling.

In Figure 31 a the scoop tube is at maximum extension, at a radius slightly greater than the outer boundary of the circulating oil. Therefore, all oil entering the scoop chamber is 'scooped' away by the open tip of the scoop tube and returned to the reservoir. The scoop chamber is virtually empty, and no oil remains for the runner to throw at the impeller. Power transmission is therefore nil, and the main pipeline pump is stationary.

At an intermediate extension of the scoop tube, (Figure 31 b), a ring of oil can accumulate in the scoop chamber between the tip of the scoop tube and the outer boundary. This limited volume of oil is now available for the runner to throw at the impeller. An intermediate level of power can now be transferred across the coupling to drive the main pump.

In Figure 31c, the scoop tube is at minimum radius, the oil retained within the scoop chamber is at a maximum, and full power transfer is taking place.

Pipeline Pumping Pressure

Returning to Figure 29 again, the oil pipeline pump speed is controlled by the speed controller (SC) which takes its signal from the pipeline pressure controller.

If the pipeline pressure is toe low. these controllers will speed up the oil pipeline pump by shortening the extension of the scoop tube.

If the pressure is too high, the controllers will slow down the main pump by increasing the radius of the scoop tube.

Pressure Transmitter

Finally, just upstream of the main outlet valve ESDV 2 is a pressure transmitter (PT) which sends a telemetry signal to the local control room, to the share (in offshore locations), and to other oilfields sharing the same pipeline facility.

This safety feature is required to prevent over-pressuring the pipeline.

Pig Launching

The pig launching facility is illustrated in Figure 32. It is similar to the-one I have described previously,

Normal flow through the system would be:

through ESDV 2

through MOV 1

through ESDV 3, and then

to the pipeline

ESDV 2 and ESDV 3 are two emergency shutdown valves which are interlocked with the ESD system to ensure that the pipeline pumps cannot be operated when these valves are closed.

On an offshore installation, ESDV 3 may be situated on the sea bed. It is designed to ensure that no oil can flow back to the installation in the event of platform malfunction. It is only operated in extreme emergencies such as a fire or largo oil leak.

Figure 32: A Typical Pig Launching System

Now, with reference to Figure 32 again, we can list the steps involved in launching a pig

1. check that the pig is undamaged, the correct size, and that the shape is undistorted. Spherical pigs may be passed through a sizing ring to make sure that they are the right size.

2. ensure that the pig signalling device (SX) has been re-set, ready to tell us when the pig has been launched

3. check that MOV 2, MOV 3 and HV 1 are closed so that we may de-pressurise the pig launcher

4. begin the de-pressurisation process by opening HV 3, allowing pressure in the pig launcher to blow the oil it contains to the drain system

5. as the pressure falls, the high pressure switch (PSH) will show that the pressure is not high. Then the low pressure switch (PSL) will show that the pressure is low

6. when this situation is reached, we can open HV 2 to the vent system and allow the pig launcher and vent system pressures to equalise. As this occurs, the remainder of the oil will drain to the drain system through HV 3

7. confirm that pressure is off the pig launcher by checking a pressure gauge (PG). Then close HV3.

8. Open HV4 to allow nitrogen (N2) to flow through the pig launcher to remove hydrocarbon gases. Close HV 4 and HV2

9. Open the pig launcher door

10. Load the pig, ensuring that it is past the inlet from MOV 2

11.close the pig launcher door and purge air from the launcher (with nitrogen) before re-pressurising. The reason for purging is to prevent an explosion when we bring the pressure up to normal operating level (in our example, the purging operation is carried out by re-opening HV 2 and then HV 4. This allows a small amount of nitrogen to displace air to the vent system via HV 2)

12. when all air has been displaced, close HV 4 and HV 2 and allow pressure to build up to the pipeline operating pressure by opening HV 1. As this

occurs, PSL will tell us that the pressure is not low and PSH will finally tell us that the pressure is high. When these two switches have given their indications, we will close HV 1

13. open MOV 3 and then MOV 2. We open MOV 3 first because we do not want a sudden flow of oil through the pig launcher to try to force the pig through MOV 3 as it is opening

14. when MOV 2 is fully open, close MOV 1 to divert the flow through the pig launcher. We keep closing MOV 1 until the flow launches the pig. When the pig enters the pipeline, it will hit the pig enters the pipeline, it will hit the pig signalling device (SX). This will then tell us that the pig has passed this point.

15. Re-open MOV 1, close MOV 2 and MOV 3, to return the system to normal.

You should note that a pig should never be launched without first ensuring that the pig receiver at the other end of the pipeline is ready to receive it.

During all pigging operations, you should follow the operational and safety procedures laid down specifically for your equipment and your installatio

Now, finally, try this Test yourself, which covers some of the topics we have discussed in Section 5.Summary of Section 5

In this section we have:

Looked at the main design features of a typical oil handling and metering system

Examined the laylout of a booster pump unit and, in particular, how it may be controlled

Discussed the key elements of a sampling system and noted that density and BS&W are measured automatically

Worked through the operation of a metering system and, in particular, a meter proving loop

Looked at a typical arrangement of the main pipeline pumps, and compared this arrangement with that for booster pumps

Discussed the main design features of a fluid drive system, and how it may be used to control pumping rate

Describe the procedure for launching a pig to the pipeline

?Test Yourself 2

1. What do you understand by a time-pressure race?

2. In pig launching operations, what does the flag do?

3. What do we mean by the meter factor?

4. In the case of the booster pumps, why does the minimum flow system re-cycle oil back to the second stage separator, and not directly to the booster pump inlet?

5. The minimum flow system for the main pipeline pumps re-cycles oil directly to the pump suction. Why does this arrangement differ from that for the booster pumps?

6. What types of analysis does out sampling system perform continuously on the oil flow?

You will find the answers to Test Yourself 12 on Page 65.

Unit Summary

In the course of this Unit on Oil Pumping and Metering, we have:

looked at some of the theor ies behind the operation of centrifugal pumps, including the behaviour of fluids, centrifugal force and energy.

Detailed the component parts of a centrifugal pump, and the role each, plays in its operation

Examined the main design features of a metering and sampling system, and how it is controlled and operated

Familiarised ourselves with the layout and operations of a pig launching facility

Discussed the main design and operational aspects of a typical oil pumping and metering system

Now go back to the Training Targets on Page 4 of this unit and satisfy yourself that you are able to meet those targets.

Check Yourself 1

Specific gravity of gasoline

= mass of one gallon of gasolinemass of one gallon of water (reference)

= 8.5 lbs = 0.8510 lbs

Specific gravity of brine

= mass of one gallon of brinemass of one gallon of water (reference)

= 11 lbs = 1.110 lbs

Check Yourself 2

Velocity of the car :

= 180 kph = 50 metres/ sec

Kinetic energy of the car:= ½ x 1000Kg x (50m/ sec x 50m/sec)= 1250000 joules

Velocity of the truck: =30 kph = 8.3 metres/sec

Kinetic energy of the truck:= ½ x 2000Kg x (8.3m/ sec x 8.3m/sec)= 688900 joules

Therefore, the car rigs 'he greater kinetic energy

Check Yourself 3

10 feet head of water exerts a pressure of 4.33 pounds per square inch,

S.G. of gasoline = 0.85

Head Pressure of 10 feet of gasoline = 4.33 x 0.85 = 3.68 pounds per square inch.

16 feet head of water exerts a pressure of 6.93 pounds per square inch,

S.G. of brine = 1.1

Head Pressure of 16 feet of brine = 6.93 x 1.1 = 7.62 pounds per square inch

Check Yourself 4

b. the static suction line pressurec. the NPSHa. the pressure at which gas or vapour is

released

The NP H represents the minimum design pressure to prevent gas or vapour release and should therefore be above this gas / vapour release pressure by a safe margin

The static suction head pressure would normally be maintained at about 10% above the NPSH.

Check Yourself 5

70 % differential pressure= 83.7% flow = 41.9 gals/ min

40% differential pressure = 63.2% flow = 31.6 gals/ min

Therefore the flow rate would fall by41.9. – 31.6 = 10.3 gals/ min

Check Yourself 6

When pumping 20 cubic metres per hour this pump will:

require a minimum of 3.4 metres head of liquid NPSH

develop 57 metres total head of liquid

consume 8 kilowatts of power

operate at 72% efficiency

approximately

Check Yourself 7

When pumping 40 cubic metres per flour this puma will ;

require a minimum of 3.9 metres head of liquid NPSH

develop 47 metres total head of liquid

consume 11.7 kilowatts of power

operate at 85% efficiency

approximately

Check Yourself 8

Your answer should look like the following:

Item Casing Impeller Bearing Seal

Shaft sleeve ‘O’ ring Shroud Lantern ring Wear rings Flush inlet Vane Slinger ring Balance holes Gland follower Volute Ball bearing race diffuser

Check Yourself 9

1.0% of 60,000 bbl/ day = 600 bbl/ day = 600 x 365 bbl/ year = 219,000 bbl/ year(assuming, of course, that the installation produces at that rate without interruption).

At $25 per barrel, this error is valued at about $5.5 million per year.

This example emphasises very effectively the importance of accuracy in the metering process. You should note that the error is equally undesirable, whether it involves an over-measurement or under-measurement of crude oil volume.

Check Yourself 10

1. densitometer An instrument, installed between booster pumps and metering system, to measure the density of the pipeline fluid.

7. Booster pumps Located upstream of the metering and sampling system (to discourage gas/ vapour breakout).

2. Flow straightening vanes

Installed upstream of a flow meter to smooth out flow and prevent swirling.

8. Pick-up coil Part of a turbine meter, used to sense and transmit speed of rotation.

3. 4-way diverter valve Part of a meter proving loop, allowing flow to be reversed for a second pass of the sphere

9. Orifice plate An essential part of the most common type of differential pressure meter

4. vena contracta This is cheating a little bit – the vena contracta is the point in the flow rate is highest and pressure lowest.

10. Sphere detector Part of a meter prover loop, and signals the beginning and end of a prover run, allowing the meter reading to be recorded at those points.

5. Prover loop A pipe loop of known volume in the meter proving system, which allows accurate calibration of the meter.

11. Turbine meter The most common type of oil flow meter, located downstream of booster pumps, filter and flow straightening vanes

6. BS&W analyser An instrument, installed between booster pumps and metering system, to measure basic sediment and water (BS&W) in the pipeline fluid.

12. Block and bleed valves

Located at various places in a metering run, allowing the run to be positively isolated from the rest of the process. The “bleed” facility allows the space between the two valve seals to be depressurised.

Check Yourself 11

1. They are the only par[ of the pipeline System which is regularly opened to the atmosphere.

2. The pig launcher must be -.

a) isolated born the pipeline b) drained of liquids c) depressurised

Check Yourself 12

1) When restarting the booster pumps after a shutdown due to low pressure, it will be necessary to by-pass the pressure switch low-low (PSLL - see Figure 26) for a short while. This gives the pump sufficient time to build up enough pressure to re-set PSLL.

2) The flag is part of the pig launch indicator mechanism, and signals that the pig has passed that particular point in the system.

3) The meter factor is a correction factor which allows us to convert observed flow readings to true values.

It is calculated during the meter proving procedure, by comparing the true value of liquid passing through the meter in a given time, with the volume registered by the meter in the same time:

meter factor = true volume of liquid passing through meter in a given timevolume registered by meter in the same time

4) Re-cycling directly back to the pump suction would cause the oil to become progressively hotter. Re-cycling to the separator will give the oil an opportunity to cool down.

5) The separators are upstream of the flow meters. If we re-cycled oil to the separators, it would pass through the meters twice and give us a false flow reading.

6) (i) density or specific gravity(ii) basic sediment and water (BS&W)

samples are also taken for more detailed laboratory analysis.

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