Chapter 4 Separators

Production Engineering II

Separation Process

Learning Outcomes

At the end of this lecture, students should be able to :

1. Describe the different types of separator and their functions.

2. Understand the basic theory of separation process.

3. Describe the two phase separation process.

4. Describe the three phase separation process.

5. Perform separator sizing calculations.

Introduction

Crude/Gas Separation System-Overview

Introduction

Main Offshore Production Facilities (key components):

Wellhead Equipment

Separation

Waste Handling Pump/Compressor Gas utilities, flaring

Introduction The oil production system begins at the

wellhead, which includes at the least one

choke valve (percentage opening

determines the flowrate from the wells).

Most of the pressure drop between the well flowing tubing head pressure (FTHP) and

the separator operating pressure occur

across the choke valve.

Whenever there are two or more producing wells, a production manifold (as well as a

test manifold) is installed to gather fluids

prior to be processed.

The test manifold is provided to allow an individual well to be tested via a test

separator or a multiphase flowmeter.

Simple wellhead assembly including

casing spools and Christmas tree

Introduction

Manifold / Gathering Station

The Production Process

SEPARATORS form the HEART of the production process

SEPARATION MODULE

reservoir

well

wellhead

Wellhead

manifold FIRST STAGE

SECOND STAGE

To export

Disposal

Storage

tank final oil treatment

Water treatment

Water

Gas to gas scrubber

and gas

compression module

Oil

Introduction

Produced wellhead fluids are complex mixtures of different compounds of hydrogen and carbon, all with different densities, vapor pressures, and other

physical characteristics.

As a well stream flows from the reservoir, it experiences pressure and temperature reductions.

Gases evolve from the liquids and the well stream changes in character. The velocity of the gas carries liquid droplets, and the liquid carries gas bubbles.

The physical separation of these phases is one of the basic operations in the production, processing, and treatment of oil and gas.

In oil and gas separator design, we mechanically separate from a hydrocarbon stream the liquid and gas components that exist at a specific temperature and

pressure.

Introduction

Phase Diagram of a typical production system

Introduction

Proper separator design is important because a separation vessel is normally the initial processing vessel in any facility, and improper design

of this process component can bottleneck and reduce the capacity of the entire facility.

Separators are classified as the following

Two Phase if they separate gas from the total liquid stream

Three Phase if they also separate liquid stream into its crude oil and water components.

Introduction

What is a separator?

A separator is a pressure vessel designed to separate a combined

liquid-gas system into individual components that are relatively free of

each other for subsequent processing or disposition

Why separators are needed?

Downstream equipment cannot handle gas-liquid mixtures

Pumps require gas-free liquid

Compressor/ dehydration equipment require liquid-free gas

Product specifications has limits on impurities

Measurement devices (metering) for gases/liquids highly

inaccurate when the other phase is present.

Basic Separator Construction

Regardless of the size/shape of a separator, each gas-liquid

separator contains four major

sections :

I. Inlet Diverter Section

II. Liquid Collection Section

III. Gravity Settling Section

IV. Mist Extractor Section

Vertical

Separator

Schematic

Horizontal

Separator

Schematic

Basic Separator ConstructionI. Inlet Diverter Section

The inlet stream to the separator is typically a high-velocity turbulent mixture of gas and liquid.

Due to the high velocity, the fluids enter the separator with a high momentum.

Fluid phase at different densities have different momentum.

The Inlet Diverter abruptly changes the direction of flow by absorbing the momentum of the liquid and allowing the liquid and gas to separate.

Results in the initial gross separation of liquid and gas. Initial separation of gas phase from the free liquid phase.

Basic Separator ConstructionII. Liquid Collection Section

Located at the bottom of the vessel.

Provides the required retention time necessary for any entrained gas in the liquid to escape to the gravity settling section.

Also provide a surge volume to handle intermittent slugs.

After a certain period of retention time, phases become equilibrium with each other and separated naturally due to density differences

Degree of separation is dependent on the retention time available.

Retention time is affected by the amount of liquid the separator can hold, the rate at which the fluids enter the vessel, and the differential density of

the fluids.

Basic Separator ConstructionIII. Gravity Settling Section

As the gas stream enters the gravity settling section, its velocity drops.

Small liquid droplets that were entrained in the gas and not separated by the inlet diverter are separated out by gravity and fall to the gas liquid

interface.

The gravity settling section is sized so that liquid droplets greater than 100 to 140 microns fall to the gas-liquid interface while smaller liquid droplets

remain with the gas.

Liquid droplets greater than 100 to140 microns are undesirable as they can overload the mist extractor at the separator outlet.

Basic Separator ConstructionIV. Mist Extractor Section

Gas leaving the gravity settling section contains small liquid droplets, 100-140 microns.

This section uses coalescing elements that provide a large amount of surface area used to coalesce and remove the small droplets of liquid.

As the gas flows through the coalescing elements, it must make numerous directional changes.

Due to their greater mass, the liquid droplets cannot follow the rapid changes in direction of flow. These droplets impinge and collect on the

coalescing elements, where they fall to the liquid collection section.

Factors Affecting SeparationThe following factors must be determined before separator design :

Gas and liquid flow rates

Operating & design pressures and temperatures

Surging or slugging tendencies of the feed streams

Fluid physical properties (density, compressibility)

Desired phase separation (gas-liquid or liquid-liquid)

Desired degree of separation

Presence of impurities (paraffin, sand, scale)

Foaming tendencies of the crude oil

Corrosive tendencies of the liquids or gas

Separator Design Checklist (2P)

A primary separation section to remove the bulk of the liquid from the gas

Sufficient liquid capacity to handle surges of liquid from the line

Sufficient length of height to allow small droplets to settle out by gravity. Also a means of reducing turbulence in the main body to ensure proper settling

A mist extractor to capture entrained droplets

Back pressure and liquid level controls

Separators are designed and manufactured in horizontal, vertical, spherical and various other configurations.

Each configuration has specific advantages and limitations.

Selection is based on obtaining the desired results at lowest life-cycle cost

Separator Types (2P)

Gravity separators

Horizontal Vertical Spherical

Centrifugal separators

Venturi Separators

Double-Barrel Horizontal Separators

Horizontal Separator with Water Pot

Filter Separators

Scrubbers

Selection of separators is based on obtaining the desired results at the lowest cost

Horizontal Separators (2P)

Illustration of a Horizontal Separator


The fluid enters the separator and hits an inlet diverter, causing a

sudden change in momentum.

The initial gross separation of liquid and vapor occurs at the inlet diverter.

The force of gravity causes the liquid to fall to the bottom of the vessel and

gas to rise to the vapor space.

The liquid collection section provides retention time to let entrained gas evolve out of the oil and reach a state of equilibrium.

It also provides a surge volume, to handle intermittent slugs of liquid.

The level controller senses changes in liquid levels and controls the dump valve accordingly.


Gas flows over the inlet diverter and then horizontally through the gravity settling

section above the liquid.

Small drops of liquid, which were entrained in the gas and not separated by

the inlet diverter, are separated by

gravity-settling; they fall to the gas-liquid

interface.

Some small diameter droplets are not easily separated in the gravity-settling section.

Before the gas leaves the vessel, it passes through a coalescing section, or mist extractor.

This section uses elements of vanes, wire mesh, or plates to coalesce and remove the very small droplets of liquid in one final separation step.


The pressure in the separator is maintained by a pressure

controller.

The pressure controller senses changes in the pressure within

the separator and sends a

signal to the pressure control

valve accordingly.

By controlling the rate at which gas leaves the vapor space of the vessel, this system maintains the pressure in the vessel.

Normally horizontal separators are operated half full of liquid to maximize the surface area of the gas-liquid interface.

Vertical Separators

Illustration of a Vertical Separator

Vertical Separators

Inlet flow enters the vessel through the side.

The inlet diverter does the initial gross separation.

The liquid flows down to the liquid collection section of the vessel and continues to the liquid

outlet.

As the liquid reaches equilibrium, gas bubbles flow counter to the direction of the liquid flow and

eventually migrate to the vapor space.

The level controller and liquid dump valve operate in the same manner as in a horizontal separator.

The gas flows over the inlet diverter and then vertically upward toward the gas outlet.

Vertical Separators

In the gravity settling section, the liquid drops fall vertically downward counter-current to the upward

gas flow.

Gas goes through the mist extractor section before it leaves the vessel to capture smaller liquid

droplets.

Pressure and level are maintained as in a horizontal separators using pressure and level

controllers respectively.

Spherical Separators

Illustration of a Spherical Separator

Spherical Separators

The same four sections can be found in this separator too. (Inlet Diverter, Liquid

Collection, Gravity Settling and Mist

Extractor)

Fluid enters through the inlet diverter where flow stream is split into two.

Liquid falls to the liquid collection section.

Gases rising out of the liquids pass through the mist extractor and out of the separator through the gas outlet.

Liquid level and pressure are maintained by liquid dump valve and back pressure control valve respectively.

Not widely used because they have limited liquid surge capability and exhibit fabrication difficulties.

Centrifugal Separators

Illustration of a Centrifugal Separator

Centrifugal Separators Work on the principle that droplet separation can be

enhanced by the imposition of a radial or centrifugal force.

Consists of three sections ( inclined tangential inlet, tangential liquid outlet and axial gas outlet).

Fluids are introduced tangentially into the separator via inclined feed pipe.

The high-velocity swirling flow creates a radial acceleration field that causes the gas to flow to the axial core region due to differences in gas and liquid density.

The gas exits through an axial outlet located at the top of the separator, and the liquid leaves through a tangential outlet at the bottom.

Control can be achieved by a control valve on either liquid or the gas outlet lines.

Not suitable for widely varying flow rates since separation efficiency decreases as velocity decreases.

Centrifugal Separators The major benefits of using centrifugal separators are :

(i) No moving parts

(ii) Low maintenance

(iii) Compact (space and weight)

(iv) Insensitive to motion

(v) Lower cost

Not commonly used in production operations because :

(i) Too sensitive to flowrates

(ii) Require greater pressure drop than other conventional separators.

Venturi Separators

Like the centrifugal separator, the venturi separator increases droplet coalescence

by introducing additional forces into the

system.

Instead of centrifugal force, the venturi acts on the principle of accelerating the

gas linearly through a restricted flow path

with a motive fluid to promote the

coalescence of droplets.

Best suited for applications that contain a mixture of solids and liquids.

Not cost-effective for removing liquid entrainment alone, because of the high-

pressure drop and need for a motive fluid.

Motive Fluid

The venturi principle involves sending a motive stream horizontally

through a constricting nozzle.

This movement creates an area of low pressure at the expanding side of the

nozzle which pulls gas molecules into

the flow from an attached inlet.

Double-Barrel Separators

Illustration of a Double-Barrel Separator

Double-Barrel Separators The flow-stream strikes the inlet diverter and the free

liquids fall to the lower barrel through a flow pipe.

The gas flows through the gravity settling section and encounters a mist extractor en route to the gas

outlet.

Small amounts of gas entrained in the liquid are liberated in the liquid collection barrel and flow up

through the flow pipes.

Commonly used in applications where high gas flowrate and/or large liquid slugs are encountered

Single barrel horizontal separators can handle large flowrates but offer poor liquid surge capabilities compared to the double barrel separators.

Two-barrel separators are typically used as gas scrubbers on the inlet to compressors, glycol contact towers and gas treating systems in which the liquid flow rate is extremely

low relative to the gas flow rate.

Horizontal Separator with a Water Pot

Single barrel separator with a liquid water pot at the outlet end.

Small amounts of liquid in the bottom flow to the boot end

which serves as a liquid

collection section.

Less expensive than double barrel separators but has less

liquid handling capacity.

Used for productions with very low liquid flowrates

When liquid flowrates are minimal, the boot section can serve as a liquid-liquid separator as well.

Illustration of a Horizontal Separator with a Water Pot

Filter Separators

Illustration of a Horizontal Double Barrel Filter Separator

Filter Separators

Commonly used in high-gas/low liquid flow streams. Can be either horizontal or vertical in configuration.

Designed to remove small liquid and solid particles from the gas stream.

Typically used when conventional separators employing gravitational or centrifugal force are ineffective.

Filter tubes in the initial separation section cause coalescence of any liquid mist into larger droplets as the gas passes through the tubes.

A secondary section of vanes or other mist extractor elements removes these coalesced droplets.

The design of filter separators is dependent on the type of filter element employed. Some filter elements can remove 100% of 1-micron particles and

99% of 1/2-micron particles when they are operated at rated capacity and

recommended filter-change intervals.

Scrubbers

Is a two-phase separator that is designed to recover liquids carried over from the gas outlets of production separators or to catch liquids condensed due to

cooling or pressure drops.

Lower liquid loading compared to a conventional separator.

Typical applications :

Mechanical equipment (such as compressors) that could be damaged by free liquid

Equipment (such as coolers) that can cause liquids to condense from a gas stream.

Gas dehydration equipment that would lose efficiency if contaminated with liquid hydrocarbons

Selection Criteria

The geometry, physical and operating attributes give each separator type its own advantages and disadvantages.

Horizontal separators are normally more efficient at handling large volumes of gas than vertical separators ; less expensive compared to vertical separator for

a given gas capacity.

Since the interface area is larger in a horizontal separator than a vertical separator, it is easier for the gas bubbles, which come out of solution as the

liquid approaches equilibrium, to reach the vapor space.

Thus, from a pure gas/liquid separation viewpoint, horizontal separators would be preferred.

Selection Criteria

The following are the limitations of a horizontal separator which would require the usage of a vertical separator :

(i) Horizontal separators cannot handle solids as good as vertical separators.

The liquid dump of a vertical separator can be placed at the center of the bottom head so that, solids will not build up in the separator but continue to

the next vessel in the process.

(ii) Necessary to place several drains along the length of the horizontal separator.

In a horizontal vessel, it is necessary to place several drains along the length of the vessel.

The distance between the drains can be increased by using sand jets but is not cost effective.

Selection Criteria

(iii) Horizontal separators require more area to perform the same separation as

vertical separators.

Not critical for onshore development but very critical consideration for offshore development due to space constraint.

(iv) Lower liquid surge capacity compared to vertical separators.

Surge capacity of a separator is defined as the ability to absorb a slug of liquid.

The liquid level change is larger in liquid volume for horizontal separator compared to the vertical separator which is sized for the same flowrate.

Surges in horizontal vessels could create internal waves which can activate the high level sensor prematurely.

Selection Criteria Vertical separators also have some drawbacks which are not process-related

and must be considered in making a selection :

The location of the relief valves and other controls which would be difficult to access without scaffolding for maintenance activities.

More expensive than an equally sized horizontal separator.

Taller vertical separators are subjected to larger wind loads which

requires the wall thickness to be

increased

Vertical Separators are supported by bottom skirt, which requires the

walls of the vertical separator to be

much thicker than a horizontal

separator which is supported by

support saddles. Illustration of a the support structures of

vertical and horizontal separators.

Selection Criteria

Overall, horizontal separators are most economical for normal oil-gas separation, particularly where there may be problems with emulsions, foam, or

high gas-oil ratios (GOR).

Vertical separators work most effectively in low-GOR applications.

Vertical separators are used in some very high-GOR applications, such as scrubbers in which only fluid mists is removed from the gas and where extra

surge capacity is needed (particularly for compressor suction scrubbers)

Comparison Summary of Different Gravity Separators


1.Can handle much higher gas-

oil ratio well streams because

the design permits much higher

gas velocities

2.Cheaper than the vertical

separator

3.Easier and cheaper to ship

and assemble

4.Requires less piping for field

connections

5.Reduces turbulence and

reduces foaming (thus, it can

handle foaming crude)

6.Several separators may be

stacked, minimizing space

requirements

1.Easier to clean

2.Saves space

3.Provides better surge control

4.Liquid level control is not

critical

5.Less tendency for re-

evaporation of liquid into the

gas phase due to the relatively

greater vertical distance

between liquid level and gas

outlet

1.Good for low or

intermediate gas-oil ratio

2.Very compact and easy

to ship and install

3.Better clean-out.

Comparison of different

gravity separator types

Advantages

Comparison Summary of Different Gravity Separators


1.Greater space requirements

generally

2.Liquid level control more

critical

3.Surge space is somewhat

limited

4.Much harder to clean (hence

a bad choice in any sand

producing area

1.It takes a longer diameter

separator for a given gas

capacity as compared to

horizontal separator

2.More expensive to

fabricate

3.Difficult and more

expensive to ship

(transport)

1.Very limited liquid

settling section and rather

difficult to use for three

phase separation

2.Liquid level control is

very critical

3.Very limited surge space

Disadvantages

Vessel Internals

Vessel Internals

Inlet Diverter

Wave Breaker

DefoamingPlates

Vortex Breaker

Mist Extractor

Sand Jets and Drain

Vessel Internals

Inlet Diverter

Functions to :

(i) To impart flow direction of the entering stream

(ii) To provide primary separation of liquid and vapor

There are many types of inlet diverters. The three main types are

(i) Baffle Plates

(ii) Centrifugal Diverters

(iii) Elbows.

Inlet Diverter

(i) Baffle Plates

Can be a spherical dish, flat plate, angle iron, cone or any shape that will accomplish a rapid change in direction and velocity of the fluids which will disengage the gas and

liquid.

Liquid strikes the diverter and falls to the bottom of the vessel

Gas tends to flow around the diverter.

Inlet Diverter

(ii) Centrifugal Diverters

Uses centrifugal force to disengage oil and gas rather than mechanical agitation.

Can be designed to efficiently separate the liquid while minimizing the possibilities of

foaming or emulsification of oil

Design is rate sensitive. They dont work properly at low velocities. Hence not

recommended for normal operations since

the rates are not expected to be steady.

Inlet Diverter

(ii) Elbows

Similar theory as the baffle plates ; instead of plates, an inlet in the shape of an elbow pipe is used

Wave Breakers Function of wave breakers are to dampen any wave action that is caused by incoming

fluids.

Wave breakers are perforated baffles or plates that are placed perpendicular to the flow which is located in the liquid collection section.

Waves are resulted from surges of liquids entering the vessel.

Why eliminate wave?

To ensure liquid level controllers, level safety switches, and weirs

perform properly.

Waves results in reduced separation

Defoaming Plates

Function is to aid in coalescence of the foam bubbles.

Foam at the interface may occur when gas bubbles are liberated from the liquid.

Foam can degrade the performance of a separator but can be stabilized with the

addition of chemicals.

However, the most effective way would be to force the foam to pass through a series of

inclined parallel plates or tubes.

This will break up the foam and allow the foam to collapse into the liquid layer.

Vortex Breaker

Liquid leaving the separator may form vortices which can pull gas down into theliquid outlet. This may result in re-entrainment of gas in the liquid outlet.

Separators are equipped with vortex breakers to prevent the formation of vortexwhen the liquid line is open.

A vortex breaker is a covered cylinder with radially directed flat plates.

When a liquid stream passes through the vortex breaker, the circular motion isprevented by the flat plates.

Sand Jets and Drains Accumulation of sand and solids

at the bottom of the vessel is a

common operational problem.

If build up of solids is not controlled, the separator

operations will not be efficient as

there is less volume available.

To remove the accumulated solids, the sand drains are

opened in a controlled manner

and then high pressure fluid

(usually water) is pumped

through the jets to agitate the

solids an flush them down the

drains.

Mist Extractor

Designed to remove the liquid droplets and solid particles from the gas stream.

The impingement-type of mist extractor is the most widely used type as it offers good balance between efficiency, operating range, pressure drop requirement

and installation cost.

There are three main types of impingement-type of mist extractors :

i. Baffles

ii. Wire Meshes

iii. Micro Fiber Pads.

Mist Extractor

i. Baffles

This type of impingement mist extractor consists of a series of baffles, vanes or plates between which gas must flow.

The most common is the vane shaped mist extractor.

The vane forces the gas flow to be laminar between parallel plates coupled with directional changes.

The surface of the plates serves as target for droplet impingement and collection.

As gas flows through the plates, droplets impinge on the plate surface.

The droplets coalesce, fall and is routed to the liquid collection section of the vessel.

Mist Extractor

i. Baffles (cont)

Mist Extractor

ii. Wire Meshes

The most common type of mist extractor found in production operations is the knitted-wire-mesh type

Has high surface area and void volume.

Effectiveness depends on the gas being in the proper velocity range. If the velocity is too high, the liquids knocked out will be re-entrained. If the velocity is

too low, the vapor will just drift pass the wire mesh without the droplets

impinging or coalescing.

Although it is not expensive compared to the other types, they are more easily plugged that the others. Not the best choice if solids can accumulate and plug

the mesh.

Mist Extractor

ii. Wire Meshes (cont)

Mist Extractor

iii. Micro Fiber Pads

Use very small diameter fibers to capture very small droplets (>0.02mm).

Since it is manufactured from densely packed fiber, the drainage by gravity inside the unit is limited.

Most of the liquid is eventually pushed through the micro-fiber and drains on the downstream face.

The surface area can be 3 to 150 times that of a wire mesh unit of equal volume.

Mist Extractor

The table below illustrates the major parameters which should be considered when selecting a mist extractor.

Potential Operational Problems

The following are the potential operating problems which

can apply to two-phase and three-phase separators

(i) Foamy Crude

(ii) Paraffin

(iii) Sand

(iv) Liquid Carryover

(v) Gas Blowby

(vi) Liquid Slugs


i. Foamy Crude

Foam is caused by the impurities in the crude oil which is not possible to removed before the stream reaches the separator.

Foaming in a separator results in :

Aggravated mechanical control of liquid level because the control device must deal with essentially three phases instead of two.

Reduced space for liquid collection or gravity settling as foam has a large volume-to-weight ratio (it occupies a large amount of the vessel

space)

Difficulties in removing separated gas or degassed oil from the vessel without entraining some of the foamy material in either the liquid or gas

outlets.


Foaming tendencies of an incoming stream can be determined via laboratory tests.

Foaming cannot be predicted ahead of time without laboratory tests.

By comparing the foaming tendencies of a known oil to a new one, the operational problems which may be expected with the new oil can be analyzed.

Foaming can be expected where CO2 is present, even in small quantities. (one percent to two percent).

The amount of foam is dependent on :

(i) Pressure drop to which the inlet liquid is subjected.

(ii) Characteristics of the liquid at the separator conditions.


Changing the temperature at which a foamy oil is separated has two effects on the foam.

a) Change in viscosity

b) Change in oil-gas equilibrium

It is difficult to predict the effects of temperature on foaming tendencies, but some general trends can be identified.

For heavy oils with a low GOR, an increase in temperature will typically decrease foaming tendencies.

Similarly, for light oils with a high GOR, temperature increases typically decrease foaming tendencies.

However, for light oils with a low GOR, a temperature increase may increase foaming tendencies. (because it is rich in intermediates which

have tendency to evolve to the gas phase as temperature is increased)


Foam-depressant chemicals can be utilized to increase the capacity of a given separator.

In sizing a separator to handle a specific crude, the use of an effective depressant may not be of the same type as characteristics of the crude and of

the foam may change during the life of the field.

The cost of foam depressants for high-rate production may not be cost economical.

During the design phase, sufficient capacity should be provided in the separator to handle the anticipated production without use of a foam depressant or

inhibitor.

Once the foam depressants are used in the operation, it may allow more throughput than the design capacity.

Potential Operational Problemsii. Paraffin Wax

The accumulation of paraffin wax in the separator can adversely affects its operation.

Coalescing plates in the liquid section and mesh-pad mist extractors in the gas section are particularly prone to plugging by accumulations of paraffin wax.

Vane-type or centrifugal mist extractors should be used in events where it is determined that paraffin is an actual or potential problem.

Manways and nozzles should be provided to allow steam, solvent or other types of cleaning of the separator internals.

In general, paraffinic oils are not a problem when the operating temperature is above the cloud point of crude oil (temperature at which paraffin crystals begin to form).

Potential Operational Problemsiii. Sand

Sand causes plugging of separator internals and accumulation in the bottom of the separator.

Accumulations of sand can be minimized by periodically injecting water/steam in the bottom of the vessel to suspend the sand during

draining.

Plugging of the separator internals is a problem that must be considered during the design stages of the separator.

A design that will promote good separation and have minimum traps for sand accumulation may be difficult to attain.

This is because the design that provides the best mechanism for separating the gas, oil, and water phases probably will also provide areas for sand

accumulation. A practical balance for these factors is the best solution.


iv. Liquid Carryover

Occurs when free liquid escapes the gas phase which results in :

Indication of high liquid level Damage to vessel internals Foam Plugged liquid outlets Flowrates which exceeds the vessels design rate

Can usually be prevented by installing a level safety high (LSH) sensor that shuts in the inlet flow to the separator when liquid level exceeds the normal

maximum liquid level by 10-15% (usually).

Potential Operational Problemsv. Gas Blowby

Gas Blowby occurs when free gas escapes with the liquid phase which can be an indication of :

Low liquid level Vortexing Level control failure

If there is a level control failure and the level dump valve is open, the gas will exit the liquid line and will have to be handled by the next equipment in the process.

Unless the next equipment is designed for gas blowby conditions, it can be over pressured.

Can be prevented by installing a level safety sensor (LSL) tat shuts the inflow when the liquid level drops 10-15% below the lowest operating level.

Downstream equipment should be equipped with PSH sensor/ PSVs sized for gas blowby


vi. Liquid Slugs

Two phase flow lines tend to accumulate liquids in low spots in the lines.

When the level of liquid in these low spots rises high enough to block the gas flow then the gas will push the liquid along the line as a slug.

Depending on the flow rates, flow properties, length and diameter of the flow line, and the elevation change involved, these liquid slugs may contain large

liquid volumes.

Situations in which liquid slugs may occur should be identified prior to the design of a separator.

The normal operating level and the high-level shutdown on the vessel must be spaced far enough apart to accommodate the anticipated slug volume.


If sufficient vessel volume is not provided, then the liquid slugs will trip the high-level shutdown.

The separator size must then be checked to ensure that sufficient gas capacity is provided even when the liquid is at the high-level set point.

This check of gas capacity is particularly important for horizontal separators because, as the liquid level rises, the gas capacity is decreased.

For vertical separators, sizing is easier as sufficient height for the slug volume may be added to the vessel seam-to-seam length.

Two Phase Separation Theory

i. Liquid Droplet Settling

ii. Droplet Size

iii. Liquid Retention Time

iv. Liquid Re-Entrainment

Separation Theory

i. Liquid Droplet Settling

In the gravity settling section of a separator, liquid droplets are removed using the force of gravity. Liquid droplets, contained in the gas, settle at a terminal or settling velocity.

At this velocity, the force of gravity (or negative buoyant force) on the droplet equals the drag force exerted on the droplet due to its movement through the continuous gas phase.

The drag force on a droplet is determined using the following equation:

=

2

2Where, FD = drag force, lb

CD = drag coefficient, dimensionless

Ad = cross sectional area of droplet, ft2

Dm = oil droplet diameter, ft

= density of continuous (gas) phase, lb/ft3

Vt = settling velocity of the oil droplet, ft/s

g = gravitational constant, 32.17 ft/s2

(1) =

4

2 2

2

Separation Theory

The buoyant force, FB, on a spherical oil droplet from Archimedes principle is :

Where, FB = gravitational or buoyant force, lb

V = volume of spherical oil droplet, ft3

Dm = oil droplet diameter, ft

= density of continuous (gas) phase, lb/ft3

= density of oil, lb/ft3

Vt = settling velocity of the oil droplet, ft/s

(2)

=

=

6

3

Separation Theory

=

4

2

2

2=

6

3

The oil droplet will accelerate until the frictional resistance of the fluid (gas) drag force, FD, approaches and balance the buoyancy force FB. Under this condition, the oil

droplets acceleration is zero so that it falls at a constant velocity known as the terminal or settling velocity (Vt). Therefore,

The oil droplet diameter Dm is normally expressed in microns (1 m is equal to 3.280810-6 ft). Let dm be the droplet diameter in m. Now, the above equation can be reduced for the settling velocity as:

2 =

4

3

= 0.01186

1/2

(4)

(3)

FD

FB

Separation Theory

(7)

The CD is a function of Reynolds number. For low Reynoldss number flow, i.e. NRe < 1,

Unfortunately, Stokes Law (creeping flow) doesnt govern for production facilities design. Hence the following drag coefficient formula can be used for practical application:

=24

=24

+

3

+ 0.34

Here, Reynolds number,

Where = density of gas, lb/ft3

dm = oil droplet diameter, m Vt = terminal velocity, ft/s

= viscosity of gas, cP

= 0.0049

(6)

(5)

Separation Theory

Determining CD

1. Determine oil-gas properties (o, g, ) and gas compressibility, Z if required 2. Assume CD = 0.34 considering high Reynolds number 3. Evaluate Vt using equation (4)

4. Calculate NRe using equation (7)

5. Calculate CD using equation (6)

6. Go to step 3 and iterate until convergence is obtained

= 0.01186

1/2

= 0.0049

=24

+

3

+ 0.34

(4)

(7)

(6)

Separation Theory

Example 1

Determine drag coefficient using the following operating conditions:

- Gas specific gravity: 0.6

- Oil gravity: 35 oAPI

- Operating pressure: 1000 psia

- Operating temperature: 60 oF

- Gas compressibility: 0.84

- Viscosity of gas: 0.013 cP

- Diameter of oil droplet: 100 m

Separation Theory

Tabulate the Values

Iteration Step

CD Vt NRe CD % error Remarks

1.

2.

3.

4.

5.

6.

7.

8. Convergence

Separation Theory

Tabulate the Values

Iteration Step

CD Vt NRe CD % error Remarks

1. 0.3400 0.7419 103.7142 0.8660 154.7013

2. 0.8660 0.4649 64.9864 1.0815 24.8811

3. 1.0815 0.4160 58.1533 1.1461 5.9782

4. 1.1461 0.4041 56.4893 1.1640 1.5626

5. 1.1640 0.4010 56.0530 1.1689 0.4173

6. 1.1689 0.4001 55.9364 1.1702 0.1120

7. 1.1702 0.3999 55.9051 1.1705 0.0301

8. 1.1705 0.3999 55.8967 1.1706 0.0081 Convergence

Separation Theory

ii. Droplet Size

The purpose of the gravity settling section is to condition the gas for final polishing by the mist extractor.

In the designing phase of a separator, the liquid droplet sized to be removed must be selected.

From field experience, if 140 micron sized droplets are removed, the mist extractor will not be flooded and is able to removed droplets of sized between 10 to 140 micron

diameters.

The design calculation for separators in this module is based on 140 micron sized droplets removal.

Separation Theory

iii. Liquid Retention Time

The average time a molecule of liquid is retained in the vessel is termed as retention time.

Sufficient retention time would ensure that the liquid and gas reach equilibrium at separator pressure.

The retention time is represented by the volume of the liquid storage in the separator divided by the liquid flow rate.

In normal operations a retention time of 30s to 3 mins is sufficient for separation operations. However, retention times of 4 times the normal amount is required in cases

where foaming crude is present.

Separation Theory

iii. Liquid Retention Time (cont)

The table below illustrates the typical retention times required for two phase separators from field data.

Separation Theory

iv. Liquid Re-Entrainment

Caused by high gas velocity at the gas-liquid interface in a separator.

The momentum which is transferred from the gas to the liquid causes waves and ripples in the liquid which results in droplets being broken away from the liquid phase.

The general rule of thumb to minimize the liquid re-entrainment is to limit the slenderness ratio to a maximum of 4 or 5 for half full horizontal separators.

Is more prominent for high pressure separators sized on gas-capacity constraints and also for applications with higher oil viscosities (

Separator Design - Horizontal

Separator Design Horizontal Separators Sizing (Half Full)

i. Gas Capacity Constraint

ii. Liquid Capacity Constraint

iii. Seam-To-Seam Length

iv. Slenderness Ratio

When sizing a horizontal separator, it is necessary to choose a seam

to seam vessel length and a diameter that satisfies all the conditions

for gas capacity that allows the liquid droplets to fall from the gas to

the liquid volume.

It must also provide sufficient retention time to allow the liquid to

reach equilibrium.


HORIZONTAL SEPARATOR

Liquid capacity (50%)

Gas capacity (50%)

Seam-to-seam Length Lss

Effective Length LeffInlet Liquid Outlet

Gas molecule flowing at average gas velocity, Vg

Liquid droplet dropping at settling velocity Vt relative to gas phase

Gas-oil interface

Diameter d

Gas outlet

Separator Design - Horizontali. Gas Capacity Constraint

Based on setting the gas retention time equal to the time required for a droplet to settle to the liquid interface.

For a separator 50% full of liquid and separation of 100 micron liquid droplets from the gas, the following equation can be derived :

Where

d = vessel internal diameter, in.

Leff = effective length of the vessel, ft

T = operating temperature, oR,

Qg = gas flow rate, MMscfd,

P = operating pressure, psia ,

z = gas compressibility,

CD = drag coefficient,

dm = liquid droplet to be separated,

g = density of gas, lb/ft3

l = density of liquid, lb/ft3

= 420

1/2

(8)

Separator Design - HorizontalEquation 8 is derived as the following :

=

=1

2

42

=1

2

4

2

144

=2

367

= 106

24

1

3600 14.7

520

= 0.327

=(0.327

(367)

2

=120

2 (9)

Separator Design - HorizontalSetting the residence time (tg) equal to time required for droplet to fall to the gas liquid

interface (td) :

=

=

2=

24

=

1202

(10) (11)

Combining 9 and 10 Combining 4 and 11

=

(24)(0.0119)

1/2

Equating tg to td :

1202

=

(24)(0.0119)

1/2

= 420

1/2

(8)


ii. Liquid Capacity Constraint

Separators must be sized to provide some liquid retention time so the liquid can reach phase equilibrium with the gas

For a separator 50% full of liquid, with a specified flow rate and retention time, the following equation is used to determine the vessel size :

Where

tr = desired retention time for the liquid, min,

Ql = liquid flow rate, bpd

2 =0.7 (12)

Separator Design - HorizontalEquation 12 is derived as the following :

=

=1

2

24

= 2.73 1032

= 5.62 3

24

1

3600

= 6.5 105

(12)

=21152

= 422

2 =0.7

*t = 60 tr (Assuming retention time of 60 seconds)

Retention time of between 30 seconds and 3 minutes

have been found to be sufficient for most applications.


iii. Seam-To-Seam Length

From the effective length calculated from equations 8 and 9 the vessels seam to seam length can be determined.

For vessels sized on a gas capacity basis, some section of the vessel length is

required to distribute the flow evenly near

the inlet diverter.

Another portion is required to place the mist extractor.

The length of separator between the inlet diverter and the mist extractor with evenly

distributed flow is the Leff (calculated from

Equation 8).


iii. Seam-To-Seam Length (cont)

As the diameter increases, more length is required to evenly distribute the gas flow.

The seam to seam length of a separator can be calculated using the following formula (from whichever is larger) :

= +

12

For separators sized on liquid capacity basis, the seam to seam length of a separator should not exceed the following :

(13)* For gas capacity

=4

3

(14)* For liquid capacity(or)

(15)

= + 2.5

If d < 36 ft If d 36 ft

Separator Design - Horizontaliv. Slenderness Ratio

Equation 8 and 12 allows for various options of diameter and length.

The smaller the diameter, the less the vessel will weigh and therefore lower cost.

However, there is an equilibrium point where further decrease in diameter increases the possibility that high velocity in the gas flow which will create waves and/or re-entrainment

of liquids.

Slenderness ratio is the ratio between length and diameter. Its calculated using the formula : 12Lss/d

Generally, most two phase separators are designed for slenderness ratios between 3-4.

Field data indicates that slenderness ratio greater than 4 or 5 will result in liquid re-entrainment.

For designs of slenderness ratios outside the range of 4, the designs should ensure that liquid re-entrainment does not take place.

General Horizontal Separators Sizing Procedure Half Full

1. Firstly the design basis has to be established. The maximum and minimum flow

rates, operating pressure and temperature, droplet size to be removed, etc has

to be specified.

2. A table with calculated values of Leff for selected values of d that satisfy

Equation 8, and the gas capacity constraint. Lss is calculated using Equation 13.

3. Using the same values of d, the values of Leff is calculate using Equation 12 for

liquid capacity and is listed in the same table. Lss is calculated using Equation

14 or 15.

4. For each d, the larger Leff should be used.

5. The seam to seam length (Lss) is calculated using the equation (12Leff/do or

1000Leff/do) and is listed for each d. A combination of d and Lss that has a

slenderness ratio between 3 and 4 is selected.

Sizing Horizontal Gas-Oil Separator

Horizontal separator sizing procedure

1. Determine CD using iterative procedure

2. Calculate dLeff for gas capacity constraint

3. Calculate d2Leff for liquid capacity constraint

7.0

2 lreff

QtLd

2/1

P420

m

d

CTZQdL D

gg

eff

gl


Horizontal separator sizing procedure (cont)

4. Set retention time tr to be 1, 2 and/or 3 minutes (usual case)

5. For each tr , calculate and tabulate values of

a) d

b) Leff for

Gas capacity from equation Step 2

Liquid capacity from equation Step 3



c) Lss for

Gas Capacity

Liquid capacity

d) Slenderness ratio (SR), (12)Lss/d

12

dLL effss

effss LL3

4 (or) = + 2.5



From table, compare the values of Leff for each gas and liquid capacity that governs the design of the separator

The one with larger required length governs

Then, select possible choices of separator size (d x Lss) based on the values of SR

Select SR values range 3 5

Lss values selected are the one that governs the design


Example of Separator Selection

tr

d Gas Leff

Liquid

Leff

Gas Lss

Liquid

Lss

SR

16 2.5 33.5 44.7 33.5

20 2 21.4 28.5 17.1

24 1.7 14.9 19.9 9.9

3 30 1.3 9.5 12.7 5.1

36 1.1 6.6 9.1 3

42 0.9 4.9 7.4 2.1

48 0.8 3.7 6.2 1.6

Horizontal Separator Example

Diameter vs. Length

Liquid capacity constraint governs since it has the largest required length

Use the liquid Lss values

to select separator size

Possible size

36 X 10

Example - Sizing Horizontal Gas-Oil Separator

Example 1

Given

Gas flow rate: 10 MMscfd (0.6 specific gravity)

Oil flow rate: 2,000 bopd (40API)

Operating pressure: 1,000 psia

Operating temperature: 60F

Droplet size removal: 140 microns

Retention time: 3 minutes

Gas Compressibility Factor = 0.84

Viscosity of gas = 0.013cP


Solution

1) Calculate CD

CD = 0.851

2) Gas Capacity Constraint

= 420

1/2

= 420(520)(0.84)(10)

1000

3.71

51.5 3.71

0.851

140

1/2

= 39.852


3) Liquid Capacity Constraint

4) Compute combinations of d and Lss for gas and liquid capacity.

5) Compute seam-to-seam length for various d . Use liquid separator capacity

basis since its greater than the gas capacity basis.

2 =0.7

2 =(3)(2000)

0.7

2 = 8571.43

=4

3 = + 2.5

If d < 36 ft If d 36 ft

or


6) Compute slenderness ratios, 12Lss/d. Choices in the range of 3 to 4 are

common.

7) Choose a reasonable size with a diameter and length combination above both

the gas capacity and the liquid capacity constraint lines. A 36-in10-ft separator provides about 3 minutes retention time.

d (ft) Gas Leff (ft) Liquid Leff (ft) Lss (ft) 12Lss/d16 2.5 33.5 44.6 33.520 2.0 21.4 28.6 17.124 1.7 14.9 19.8 9.930 1.3 9.5 12.7 5.136 1.1 6.6 9.1 3.042 0.9 4.9 7.4 2.148 0.8 3.7 6.2 1.6

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Chapter 4 Separators

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