4 Separators

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Production and Test Separators

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Principles of separation

There are two necessary factors for separators to function which are:

1) The fluids to be separated must be insoluble in each other.2) One fluid must be lighter than the other.

Separators depend on the effects of gravity to separate fluids. If they are

soluble in each other, no separation is possible with gravity alone.

In the process of separating gas from liquid, we actually have two

separation stages:

1) Separate liquid mist from gas.2) Separate foamy gas from liquid.

Basic considerations

Separators are mechanical devices used for removing and collecting

liquids from natural gas or gas stream.

A properly designed separator will also provide the release of entrained

gases from the accumulated hydrocarbon liquids.

The objective of ideal separator selection design is to separate the

hydrocarbon stream into, liquid free of gas, and gas free of liquid.

Ideally, gas and liquid reach a state of equilibrium at the existing

conditions of pressure and temperature within the vessel.

Factors affecting separation

Fluids stream composition, operating pressure, and operating temperature

are the factors controlling separation.

Changes of any of them will change the amount of gas and liquid leaving

the separator.


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1.2 Classification of Separators:

Separators are Classified According to:

1) The configuration of the separator.2) The number of fluids to be separated.

1.2.1 Separator Configuration:

It is manufactured in three basic types:

a. Horizontal type.b. Vertical typec. Spherical type

Each configuration has specific advantages and the selection is based on which will

accomplish the desired results at the lowest cost.

Horizontal Separators

This type of vessel has a large interface area between liquid and gas, therefore results

in more separation. When the gas capacity is a design criterion, the horizontal vessel

is more economical in highpressure separation. However liquid level control is more

critical than that of vertical separator.

Vertical Separators

This type of vessel is capable of handling larger slugs of liquid without carrying over

to gas outlet. In this configuration, the action of level control is not critical. Due to

greater distance between liquid level and gas outlet, there are less tendencies to

evaporate. This type is most often used with fluid streams having more liquid than

gas. The vertical separator is more difficult and expensive to fabricate than a

horizontal separator.


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Spherical Separators

This type of vessel is cheap and compact. It has a limited surge space and liquid

settling section.

The placement of liquid level control is very critical in this type. This type of

separators are not popular today because of their limitations.

1.2.2 Classification According to the Number of Fluids to be

Separated

If the fluid stream inside the separator is separated into two fluids (gas and oil), the

separator is two phase.

If the fluid stream inside the separator is separated into three fluids (gas, oil, andwater), the separator is three phase separator.

Some well streams contain sand and other solid particles, which are removed in the

separator. Special internal devices are provided to collect and dispose of the solid

materials. See Fig. 7. Solids are not considered as a phase of fluid in the

classification of separators.

1.3 Flow Patterns

1- Two Phase Separator

Flow patterns in horizontal or vertical separators are the same. The crude oil stream

enters to the separator, the lighter fluid (gas) passes out to the top, and the heavier

fluid (oil) drops out to the bottom.


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Figure 1 Two Phase Horizontal Separator

Figure 2 Three Phase Horizontal Separator with Weir


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Figure 3 Three Phase Horizontal Separator with Bucket

Figure 4 Two Phase Vertical Separator


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Figure 5 Three Phase Vertical Separator


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Figure 6 Two Phase Vertical Centrifugal Separator


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Figure 7 Three Phase Vertical Separator with Sand Cone

2- Three Phase Separator

These type of separators are shown in fig. 2, 3, 5, 7.

In Horizontal separator, liquid flow is shown in fig. 2, 3.

In fig 2, oil and water settle down to the bottom in the left side of weir. Oil floats onwater and spills to the right side over the weir into oil chamber.

Oil is withdrawn using level controller.

Water at the left side of the weir is withdrawn using level controller.

The float of a level controller has a problem due to emulsion at the water oil interface.


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Fig. 3 shows the flow pattern with no interface. Oil spills in the bucket are

withdrawn using a level controller.

Water flows along the bottom of separator, where using a level controller.

Flow in the centrifugal separator Fig. 6 is somewhat different than that in theconventional type.

The centrifugal separator is vertical and depends on centrifugal action for separation

of fluids. The inlet stream is forced to flow around the wall of the separator in a

swirling motion. The liquid reaches the outside wall and drops down to the bottom.

Gas collects in the middle of the separator and flows up to the outlet pipe.

1.4 Separator Internals

Production equipment involving the separation of oil and gas usually have a wide

variety of mechanical devices that should be present in some of all separators,

regardless of the overall shape or configuration of the vessel. These mechanical

devices improve the separators efficiency and simplify its operation. The most

commonly used devices are:

Inlet configuration

Intermediate configuration

Outlet configuration

1.4.1 Inlet Configurations

In horizontal separatorsthe internal configuration can take many shapes as shown in

the Figures ( 8 and 9). The most commonly used are:

- Structural channel iron- Angle iron- Flat plates- Dished heads- Schopentoeter

The latter three shapes have been considered optimum for certainapplications. These shapes are used in gasliquid separators in front of

the inlet nozzle of the vessel, which serve two purposes:

1. To aid in the separation of entrained gas from the liquid.2. To divert the fluid flow downstream.


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In vertical separators, there is a centrifugal inlet device, it causes the primary

separation of the liquid and gas to take place. Here, the incoming stream is subject to

a centrifugal force as much as 500 times the force of gravity. This action stops the

horizontal motion of the liquid droplets together, where they will fall to the bottom in

the settling section.

Figure 8 Inlet Momentum Absorber Designs (All Views

Taken In Plan)


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Schoepentoeter

The Schoepentoeter (vane-type) is a Shell-proprietary inlet device and is commonly

used for introducing gas/ liquid mixtures into a vessel or column

It is used to absorb the initial momentum as the well fluid enters the separator. It tendsto deflect the direction of flow causing gas to rise and free liquid to drop that the flow

encounters. A drop in velocity as well as reduction in pressure.

Figure 9 shows schematically the typical outline of a Schoepentoter in a vertical

vessel together with its design parameters (for simplicity not all the vanes are shown).

The geometry of the Schoepentoter is largely standardised so that the choice of

dimensions to be made by the designer is limited to the following:

The number of vanes per side nv.

The vane angle, a which is 8 degrees o less.

The length of the straight part of the vanes, Lv, which shall be 75,100, 150 or 200 mm. The choice of Lvis also used to fix the vane

spacing.

The radius of the vanes, Rv, which shall be 50 or 100 mm.

With a Schoepentoeter, it is normal to specify a protruded nozzle, although this is not

essential.


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a = vane angle, angle made by straight part of vanes with centre line.

B. = edge angle, angle made by edge of the row of vanes with centre line.

D. = vessel inside diameter, mm.

d1. = inlet nozzle inner diameter, mm.

E = available space, mm.

Lv = length of straight part of vanes (normally 75, 100, 150 or 200 mm)nv = number of vanes per side.

Rv = vane radius, mm (normally 50 or 100 mm)

t = vane material thickness, mm (normally 3 mm, but typically 5 mm for heavy

duty, e.g slugs)

W1/0= width of vane entrance opening, mm.

Figure 9 Schematic Outline of the Schoepentoeter


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1.4.2 Intermediate Configuration

The most commonly used of these intermediate devices are:

Coalescing plates

Straightening vanes Weir

Horizontal baffles

These are commonly used in gravity separation sections and are as follows:

- Coalescing plates

Several configurations are available. They are used in gas-liquid vessels to remove

liquid from the gas and is not used where hydrate or paraffins are present.

- Straightening vanesThese are used to separate liquid mist from gas and used where hydrate or paraffins

are present. They are used when hydrate or paraffins prevent the use of pads.

- Weir

As illustrated in figures, it is a dam-like structure, which is controlling the liquid

level and keeps it at a given level. Maybe one or two weirs are used in one

separator, where one maintains the oil level and the other the water level.

- Horizontal Baffles

These are used in large gas liquid separators to prevent waves in the liquid phase.

1.4.3 Outlet Configuration

These mechanical outlet devices are sometimes used in horizontal and vertical

separators, and the most commonly used are the following.

- Mist pad or extractor (Figure 10 and 11)

Most frequently used in gas - liquid separators and normallylocated near the gas outlet that will coalesce small particles (mist)of liquid that will not settle out by gravity. It breaks oil-water

emulsion to help in segregating the two liquids. Not used where

hydrate or paraffin may be present. The stainless steel woven wire

mesh mist-eliminator of thickness 10 20 cm (4-8 inch) is

considered to be the most efficient type.


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It is held in place by a sturdy grid which prevents it from being swept out or torn by a

sudden surge of gas, and has been proven by removing up to 99.5% or ore of the

entrained liquids from the gas stream.

This type offers the greatest area for the collection of liquid droplets per unit volume

as compared to vane type.

Figure 10 Types of Mist Extractors


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Figure 11 Mist Extractors in Varius Types Vessels


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- Vane Type(Figure 12)

It consists of a labyrinth formed with parallel metal sheets with suitable liquid

collection pockets.

The gas passing between plates is agitated and has to change direction a number oftimes. Vane type mist eliminators have their applications in areas where there are

entrained solid materials in the gas phase.

Figure 12 Demister Types


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- Vortex BreakersThe liquid outlet should be equipped with anti-vortex devices to prevent a vortex from

forming, and gas from going out with the liquid. Several types are shown in the

figure.

Figure 13 Outlet Vortex Breaker

The designation of high or low gas-oil ratio is rather arbitrary. The following are

specific instances in which high or low GOR's usually occur:

Low Gas-Oil Ratio

Oil wellstreams.

Flash tanks in dehydration.and sweetening plants.

Fractionator reflux accumulators.

High Gas-Oil Ratio Gas wellstreams.

Gas pipeline scrubbers.

Compressor suction scrubbers

Fuel gas scrubbers.


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The terms Flash Tank, Accumulator and Scrubber are commonly used for specific

applications of separators. The vessels are gas-liquid separators.

1.5 Inspection & Maintenance

Reasons for Inspection

General:

The basic reasons for inspection are to determine the physical condition of the vessel

and the type, rate, and cause of deterioration.

All data should be recorded.

With such data on hand:

Safety can be maintained

Continuity of operation can be enhanced

Rate of deterioration can be reduced

Future repair and / or replacement can be predicted.

Periodic scheduled maintenance and inspection can reveal conditions that

if not discovered and corrected may result in hazardous leak or vesselfailures and unscheduled shutdowns.

These unnecessary start ups and shutdowns of equipment tend to be more hazard thanroutine operation.

Periodic inspection can lead to wellplanned maintenance.

Corrosion rates and remaining corrosion allowance determined by such inspection are

the normal basis for predicting replacement or repair.

These predictions provide the orderly planned maintenance and continuity of

operation.

Causes of Vessel Deterioration

Corrosion

Erosion

Metallurgical and physical changesExcessive mechanical forces.

Mechanical forces can cause a vessel to fail or to operate inefficiently.

Mechanical Forces Such as:

Thermal shock


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Cyclic temperature changes

Vibration

Excessive pressure surge

External loads

- Thermal shock is caused by a sudden change in temperature (eitherfrom cold to hot or from hot to cold). The stresses resulting from the

sudden unequal expansion or contraction of the different parts of a

vessel may cause distortion to these parts.

- Cyclic temperature changes may cause cracks as a result of thermalfatigue. Thermal fatigue is often found at locations where metals of

different expansion coefficients are welded together.

- Vibration forces may be transmitted to vessels through piping systems.These forces may cause undue loads on nozzles, internal piping, and

vessel walls.

- Pressure surge due to the failure of relief valves to open promptly atthe set pressure may result in internal pressures exceeding the

maximum allowable working pressure. This condition may cause

damage to the internals or bulging of the vessel walls.

- Excessive temperature in excess of the design limits during operationof the vessel (even without high pressure) may cause bulging of vessel

walls.

Methods of Inspection

External Inspection

External inspection can be carried out visually, and using nondestructive testing

methods while vessel is in service.

External inspection of pressure vessels should start with ladders, stairways, platforms,

or walkways connected to or bearing on them.

A careful visual inspection should be made for corroded or broken parts, cracks,

tightness of bolts, condition of paint and wear of external parts.

Foundation and supports should be inspected carefully for any deterioration as

spalling, cracking, and settling.

Internal Inspection

Internal inspection carried out on vessels in out of service conditions. The vessel

should be isolated completely, cleaned, freed of gases, and prepared for internal

inspection.


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All internals should be inspected carefully to detect any damaged or deteriorated

parts.

Vessel wall should be inspected ultrasonically, metallic lining should be inspected

carefully using dye penetrant test.

Non metallic lining should be inspected using holiday detector.

Fig. 14 shows measurements of a vessel.

Figure 14 Method of Obtaining Vessel Profile Measurements

Bracket


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Tools for Inspection of Vessels

- Portable lights (including a flash light)- Thinbladed knife- Chisel or scraper (to remove scales)- Hammer- Inside calipers and outside calipers.- Tape measuring tape- CRT ultrasonic flow detector- Thickness gauge- Pit depth gauge- Paint or crayon- Straightedge- Wire brush- Magnet

- Spirit level- Magneticparticle inspection equipment- Dyepenetrant inspection equipment- Temperatureindicating crayons- Radiographic equipment- Micrometer- Meger ground tester- Magnifying glass- Sandblasting equipment- Metal samplecutting equipment- Portable hardness tester

- Camera

Methods of Repair and Maintenance

Before any repairs are made to a vessel, the application code and standards under

which it is to be rated should be studied to ascertain that the method of repair will not

violate the rules.

Most repairs on the shell and heads of a vessel are made to maintain the strength and

safety of the vessel and will therefore require reinspection.

In case of replacement a section of shell plates, the calculated joint efficiency of the

patch should be equal or greater than the calculated efficiency of the original joints in

the shell.


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Heater Treaters


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Heater Treaters

The function of the heater treater is to provide further gas separation, free water

removal and coalescence of entrained water particles to ensure that the crude oil

produced meets pipeline specifications of 0.5% BS&W maximum.

The heater treater consists of the following:

1. Degassing Vessel, which is a two phase separator mounted on top of the mainbody of the heater treater.

2. The main body of the Heater Treater, which is divided into three sections:

a. Heating Section. The fire tubes for heating the oil are situated in this section.This is also where initial separation of free water and oil takes place.

b. Oil Chamber. The oil chamber separates the inlet section from the coalescingsection. It is separated from the inlet section by a weir and also contains the

inlet to the metered orifice distributors which control the flow into the

coalescing section.

c. Coalescing Section. High voltage positive (+) and negative (-) electrodes arefitted in the coalescing section. Two externally mounted high voltage

transformers provide power to these electrodes.

Pressure and incoming liquid level in the degassing vessel are controlled by:

a. A pressure valve located in the gas discharge to the flare header.

b. A level valve in the clean oil discharge to the crude oil coolers.

The pressure and level controllers work together to maintain a constant level in the

degassing vessel.

A rise in liquid level will increase the pressure in the degassing vessel causing the

pressure valve to open releasing excess pressure to the flare header. The level valve

will also open further to allow more clean oil to be discharged. A falling liquid level

will cause the level valve to close restricting the flow of oil to the coolers.


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Figure1Heater

TreaterCrossSection


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The heating section free water and the coalescing section treated water levels are

maintained by level valves located in the water discharge to the produced water

disposal system.

These level valves are operated according to the interface level of oil on water. As thelevel of free or treated water rises the interface controller initiates a signal to open the

level valves. The movement of the valves is proportional to the strength of the signal.

A flow element is fitted in the gas discharge to the flare header. This connects to a

two pen circular flow and pressure chart recorder.

The heater treater is protected from overpressure by a pressure safety valve.

Spectacle blinds are used to positively isolate the vessel.

Drain valves are fitted to allow draining of the heating oil chamber and coalescingsections of the heater treater. The drains are connected to the closed drain system.

An emergency shutdown will be initiated by a high high pressure or high high level

condition in the degassing vessel.

A low low liquid level in the heating section of the heater treater will cause the inlet

flow valve to shut.

The burner control panel is also fitted with system shutdowns which will be detailed

later in this section.

Alarms and shutdowns will be annunciated at the local shutdown panel and at the

control room annunciator panel.

Firetube Heater

The purpose of the firetube heater is to raise the oil temperature to the dehydration

temperature. This will cause additional gas to be released and aid in the coalescing

process.

The firetubes of the heater treater are heated by dual gas burners supplied from thefuel gas system.


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Fig

ure2HeaterTreater(V

206,

V

207,

V

301,

V

401).


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Figure3.3

H

eaterTreaterProcessFlow

Figure.4

Heater

TreaterFuelGasSystem

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4 Separators