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Principles and Equipment of Gas-Liquid Separation

Separation Core

Learning Objectives

By the end of this lesson, you will be able to:

Describe separator applications and common types ofseparators

List the sizing criteria for 2-phase and 3-phase separators

Discuss the principles of gas-liquid separation and how they areapplied in separator design

Describe the effect of inlet piping size and inlet devices onseparator sizing

List the types of mist extractors and describe typical applications

Estimate separator size based on gas-liquid separation criteria

By the end of this lesson you will be able to:

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• Bulk separation of produced fluids• Gas scrubbing upstream of compressors, dehydrators and amine

systems• Removal of entrained chemicals downstream of glycol and amine

contactors• Removal of fines/dust downstream of solid desiccant dehydration

vessels• Provide retention time to reduce flowrate fluctuations upstream up

pumps and distillation columns and process facilities• Meet product sales specifications

Why Separation Equipment?

Applications

Separators are a critical, but often overlooked, component in aprocessing facility

Poor separator performance can significantly impair theeffectiveness and availability of downstream process equipmentwhich in turn reduces profitability

To water treating

Electrostatic Coalescer

Surge Tank

TEG Contactor

Degasser

LACT

HP

IP

LP

150°F4 psig

Oil export 1850 psig

150°F50 psig

130°F180 psig

120°F500 psig

120°F1200 psig

110°F1200 psig

Gas export2000 psig

To FuelGas System

CM

CMCM

CM

HM

CM

CMCM

Where Do We Use Separators?

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Production Separators

Can be 2-phase (gas-liquid) or 3-phase(gas-hydrocarbon liquid-water)

Fluctuating flows of gas and liquidincluding slugs

Solids, e.g. sand, paraffin, asphaltenes,corrosion products

Low to high vapor-liquid ratios

Can be vertical or horizontal• Vertical usually preferred in higher vapor-

liquid ratio applications

• Horizontal usually preferred in lower vapor-liquid ratio applications

Typical quality of separated streams• Liquid in gas: 0.013-0.27 m3/106 sm3

[0.1 to 2 US gal/MMscf]

• Water in oil: 2-3 vol% or greater

• Oil in water: 500-2000 ppmv

Not typically designed to meetexport/sales specifications

Scrubbers

Reciprocating Compressor

Suction Scrubber

Example ScrubberInternals

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Scrubbers

Flow rate is typically gas with a small amount of entrained liquid

Large fluctuations in flowrate are not common

Often prevent damage to downstream equipment due to liquid carryover

High separation efficiency is critical

Often use high separation efficiency internals to remove liquid from gas

Typically vertical orientation

Very little liquid retention capacity

Typical quality of separated streams

• Liquid in gas: less than 0.013 m3/106 sm3 [0.1 US gal/MMscf]

•

Inlet Separation Chamber

Gas In

Final Mist Extractor

Gas Out

Second Stage Liquid Reservoir

Liquid OutFirst Stage

Liquid Reservoir

First Coalescing Chamber

Quick Opening Closure

Horizontal Filter Separators• High efficiency removal of small amounts of liquid from gas

• Gas flows radially from outside to inside of filters and enters a perforated tube in themiddle of each filter element

• Gas flows to right side of the vessel and through a vane-type mist extractor


Filter Separators

•Courtesy Pall

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Gas In


Gas Out



Liquid Reservoir







Filter Separators

•Courtesy Pall

Liquid Drain

Liquid Drain

Clean Gas Outlet

Dirty/WetGas Inlet


Gas In


Gas Out



Liquid Reservoir







Filter Separators

•Courtesy Pall

Vertical Coalescing Filters• Very high efficiency removal of

small amounts of liquid from gas

• Flow enters bottom of vessel andup through the filter elements in top of vessel

• Gas flows radially from inside tooutside of filters

• Liquid may be collected in bothbottom and top sections

• Liquid in gas: less than 0.0013m3/106 sm3 [0.01 US gal/MMscf]

Liquid Drain

Liquid Drain

Clean Gas Outlet

Dirty/WetGas Inlet

Upper Sump

Lower Sump

Coalescer Filter Cartridges

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Typical Governing Criteria for Sizing Separators

Typical governing criteria for sizing of various separation equipment:

Droplet Removal from Vapor • Primary sizing criterion for mostseparation applications

• In scrubbers and coalescingfilter separators, it is critical toremove liquid droplets from thevapor stream

• Liquid degassing and reductionof liquid flow variation are notcritical

• Liquid-liquid separation isalmost never done



Droplet Removal from Vapor

Liquid Degassing

• The removal of entrainedbubbles in the liquid phase

• Seldom the primary separationcriterion

• Important in high viscosity liquidphase or when “carry under” ofbubbles interferes withperformance of downstreamequipment

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Liquid Degassing

Separation of Liquid Phases

• Important criterion in 3-phaseseparation

• Controls the size of theseparator

• Liquid-liquid separation typicallyrequires a large interfacebetween liquid phases, sohorizontal separator is preferred

• Requires longer liquid retentiontimes, especially with highviscosity hydrocarbon phase




Liquid Degassing


Flow Smoothing / Slug Handling

• Slug catchers– Used at the end of multiphase

pipelines and in gathering systemswhere slugging is prevalent due toelevation changes, variations inflowrates, or in systems that operatein a slug flow regime

– The main sizing criterion is the abilityto store the volume of liquid thatarrives with a slug and deliver steadyflowrate to downstream equipment

• Surge vessels– Designed to store liquid and

attenuate flow variations

– This is often the primary sizingcriterion in vessels upstream ofpumps and process units that aresensitive to flow variations such asfired heaters and distillation columns

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Liquid Degassing



Other

• Foaming

– Increased carryover

– Interference with separatorcontrols

• Solids

– Sand can accumulate in thebottom of the separator reducingliquid retention volume

– Can cause failure in level controlvalves due to erosion around thevalve plug and seat




Liquid Degassing



Other

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Most separators rely on several mechanisms to achieveseparation:

• Gravity settling

• Centrifugal forces

• Impaction

• Coalescence

Principle of Gas-Liquid Separation

Force Balance:FGravity = FDrag

0.5

4

3O gP

td g

gDv

C

Red PC f Re P t fP

f

D v

Drag Force of Gas on Liquid Droplet

Dp = Droplet sizeCd = Drag coefficientRep = Reynold’s Numberμf = Fluid viscosity

Where:vt = Terminal velocityρ = Densityg = Gravitational acceleration

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Typical Separation Application Settling Laws

Smaller droplets are more difficultto separate

• Minimize formation of entraineddroplets

• Provide conditions favorable todroplet coalescence

• Minimize shear and turbulence

Assumptions• Spherical droplets

• Unhindered settling

• Uniform gas velocity profile

Common-Practice vs Theoretical Methods

The theoretical approach requires knowledge of the followingvariables which are difficult to determine

a) Droplet size distributions, which typically change due toshear/coalescence effects

b) The amount of entrained dispersed phase droplets in thecontinuous phase

c) Velocity profile distributions of the continuous phase

d) Details concerning the settling trajectories of the dispersed phase

Because of this limited information, the “common-practice”methods are often applied instead of the more “theoretical”approaches

• The use of an empirical sizing coefficient, KS

0.5 0.54

3O g P

t S Sg d

gDv K where K

C

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Common-Practice vs Theoretical Methods

The theoretical approach requires knowledge of the followingvariables which are difficult to determine

a) Droplet size distributions, which typically change due toshear/coalescence effects

b) The amount of entrained dispersed phase droplets in the continuous phase

c) Velocity profile distributions of the continuous phase

d) Details concerning the settling trajectories of the dispersed phase

Because of this limited information, the “common-practice” methods are often applied instead of the more “theoretical” approaches

• The use of an empirical sizing coefficient, KS

0.5 0.54

3O g P

t S Sg d

gDv K where K

C

Where:vt = Terminal velocityKs = Sizing coefficientρ = Densityg = Gravitational

accelerationDp = Droplet sizeCd = Drag coefficient

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Vertical and Horizontal 2-Phase Separator

Vertical Horizontal


Vertical Horizontal

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Vertical Horizontal


Vertical Horizontal

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Vertical Horizontal

Mandane, et.al.

Horizontal Flow

Stratified Flow

Wave Flow

Annular Mist Flow

Slug Flow

Bubble, Elongated

Bubble Flow

Annular Mist Flow

Stratified Flow

Flow Pattern Map

Wave Flow

Dispersed Flow

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Effect of Feed Pipe Velocity on Liquid Entrainment

The horizontal flow patterns and flow pattern map assume that theflow conditions in the feed pipe have reached a well-established,“stabilized” state

This will not be true if the flow has changed direction• Vertical runs, elbows, fittings, valves, or other flow pattern disruptions

Large Diameter Inlet Pipe

Small Diameter Inlet Pipe

Provide 10 diameters of straight pipe upstream of the inlet nozzlewithout valves, expansions/ contractions, or elbows

If a valve in the feed line near the separator is required it shouldpreferably be a full port gate or ball valve

Sometimes straightening vanes are used

Effect of Feed Pipe Velocity on Liquid Entrainment

Large Diameter Inlet Pipe

Small Diameter Inlet Pipe

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Various Separation Equipment Inlet Devices

Vane-Type and Cyclonic Inlet Devices

Vane-Type

Cyclonic-Type

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Comparison of Inlet Devices

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Wire Mesh Mist Extractor in a Vertical Separator

Mist extractors (eliminators)are used to remove smalldroplets from the vaporstream. These droplets aretoo small to be economicallyremoved in the gravityseparation section

The primary issues that affectmist extractor selection are:

1) Capacity

2) Separation performance

3) Fouling tendency

4) Turndown performance

1)

2)

3)

4)

Mesh Pad Examples

Mesh pads are most commonlyutilized in vertical separators

Typically installed horizontally(vertical gas upflow)

Better at removing small droplets

Possess a better turndown ratio

Have a lower gas handling capacity

Are not recommended for dirty/fouling service

Require capacity derating athigh pressures

Courtesy of Koch-Otto York

Courtesy of ACS

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Single and Double Pocket Vane Mist Extractor

Courtesy Koch Glitsch

Vertical Gas Separator

Vane packs capturedroplets primarily byinertial impact andcollection in “pockets”

Vanes packs are bettersuited for dirty/foulingservice

Have a higher gashandling capacity andable to tolerate higherentrained liquid loads

Droplet removal efficiencytends to be lower

Require capacity deratingat high pressures

Examples of Demisting Cyclone Configurations

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Examples of Demisting Cyclone Configurations

Have the highest gashandling capacity highliquid handling capacity,and excellent dropletremoval performance

Separation efficiency isinsensitive to highpressures

Tolerant of entrained solids

Most commonly installed invertical flow orientation

Sometimes a wire meshpad is installed below thecyclones to improveremoval efficiency

Comparison of Mist Extraction Devices

Table 11.10 (Pg. 24)

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Droplet Settling in Vertical and Horizontal Separators

Droplet Settling Relationships

The gravity separation section of a separator has two main functions:

1

2

Reduction of entrained liquid load not removed by inlet device, and

Improvement or straightening of gas velocity profile

In low liquid loading applications, pre-separation of liquid dropletsmay not be required if the mist extractor can handle theentrainment entering the vessel




1

2



Even in this scenario, a relatively uniform gas velocity distributionshould be delivered to the mist extractor to achieve its intendedperformance

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1

2



Pre‐conditing of fluids upstream of mist extractor

Two approaches for sizing the gravity separation section to remove liquid droplets from the gas:

Ks method

Droplet settling theory




1

2



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Two approaches for sizing the gravity separation section to remove liquid droplets from the gas:

Ks method





1

2



12


• Involves sizing the gravityseparation section to remove atarget liquid droplet size (and alldroplets larger than the targetsize) using the equationspresented later in this module

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Ks for Horizontal Vessels

Vt

Vghg

Le

L

D


3-Phase Separator Internals(Courtesy of KIRK Process Solutions)

Inlet Distribution BafflesTop: Vapor Baffle

Bottom: Liquid Baffle

Copak Coalescer Vortex Breakers

Submerged Weir

MistEliminator

Gas FlowStraightening

DeviceFoam Breaker

Inlet Deflector

Sand Jetting System

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Vt

Vghg

You may want to pause a moment to review the equations and terms.PAUSE

Ksh = Ksv (Le/hg)

Vt

Vghg

Le

L

D

It is recommended that Ksh be limited to a maximum value of 0.21 m/s or 0.7 ft/sec

Le = L-D

3-Phase Separator Internals

(Courtesy of KIRK Process Solutions)

Inlet Distribution BafflesTop: Vapor Baffle

Bottom: Liquid Baffle

Copak Coalescer Vortex Breakers

MistEliminator

Gas FlowStraightening

DeviceFoam Breaker

Inlet Deflector

Sand Jetting System

Submerged Weir

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Fractional Area Available for Liquid and Gas Flow

Figure 11.17(Pg. 17)

Horizontal Separator

For a vertical separator Fg is 1.0

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Learning Objectives

Describe separator applications and common types of separators

List the sizing criteria for 2-phase and 3-phase separators

Discuss the principles of gas-liquid separation and how they areapplied in separator design

Describe the effect of inlet piping size and inlet devices onseparator sizing

List the types of mist extractors and describe typical applications

Estimate separator size based on gas-liquid separation criteria

You are now able to:

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Emulsions and Oil Dehydration Equipment

Separation Core

Learning Objectives

By the end of this lesson, you will be able to:

Describe emulsions, how they form and how they influenceseparator design

Discuss how emulsions can be destabilized and eliminated

Estimate the size of an oil dehydrator based on liquid-liquidseparation criteria

By the end of this lesson you will be able to:

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Emulsions Definition

A mixture of two immiscible liquids, one of which is dispersed asdroplets (dispersed phase) in another liquid (continuous phase)

Two main types:1. Water in oil (WIO, W/O) also known as a “normal” emulsion

• Oil is the continuous phase and water is the dispersed phase

2. Oil in water (OIW, O/W) also known as a “reverse” emulsion• Water is the continuous phase and oil is the dispersed phase

From a practical standpoint, WIO emulsions are more frequentlyencountered in production operations and more difficult to resolvethan OIW emulsions

Emulsifying compound

Water-in-Oil

Water Phase

Oil Phase

Emulsifying compound

Oil-in-Water

Oil Phase

Water Phase

Water in Oil and Problems Cause by Emulsions

Oil must meet a water content (or BS&W) specification before itcan be transported or sold

• Typical BS&W specifications range from 0.3 to 3% by volume

• Water entrained in oil increases transportation costs

• Water entrained in oil can cause corrosion in pipelines andassociated equipment

• If the entrained water has a high salinity, a lower BS&W specificationmay be required to meet the salt specification

Problems cause by emulsions• Emulsions make the dehydration of crude oil and the deoiling of

produced water more difficult because:– Dispersed droplets do not coalesce and separate from the continuous

phase

– The viscosity of the emulsion can be much higher than the viscosity ofthe continuous phase

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Conditions Required to Form Emulsions

1

Twoimmiscible

liquids(oil and water)

2

Agitation to disperse one liquid as droplets in the

other

3

Compounds which stabilize the emulsion thereby inhibiting

coalescence and increasing the time required for

separation

There are three requirements for forming an emulsion:

When we use the word “stable” in talking about emulsions wemean how difficult is it to separate the two phases

Example of Normal Emulsion

Water-in-oil (normal) emulsion:

OIL

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Example of Normal Emulsion

Water-in-oil (normal) emulsion:

OIL

Some Common Household Emulsions

Salad Dressing• Type: generally oil in water• Emulsifying compound: mustard

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Mayonnaise• Type: oil in water• Emulsifying compound: egg yolk lecithin

or egg white proteins





Homogenized milk• Type: oil in water• Emulsifying compound: proteins in the milk

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Butter or Margarine• Type: water in oil• Emulsifying compound: proteins in the cream






Butter or Margarine• Type: water in oil• Emulsifying compound: proteins in the cream

Latex Paint• Type: oil in water• Emulsifying compound: various surfactants

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Sources of Agitation

Bottomhole pumps

Flow through tubing, wellheads,chokes, flowlines, production manifolds

Ineffective or poorly designed separatorinlet devices

Process pumps, control valves, flowthrough process piping

Emulsifying Compounds

There is normally no shortage of emulsifying agents present!

A surface-active compound that alters the characteristics of theoil-water interface

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Emulsifying Compounds

Types of emulsifying compounds1. Indigenous surface active compounds (surfactants)

– Asphaltenes, resins, naphthenic acids, etc

2. Finely divided solids– Formation fines, e.g., sand, silt, clay

– Drilling muds/workover fluids

– Mineral scales, corrosion products, wax

3. Added chemicals– Corrosion inhibitors, paraffin dispersants, stimulation chemicals, etc.

There is normally no shortage of emulsifying agents present!

A surface-active compound that alters the characteristics of theoil-water interface

• Migrates to the oil-water interface and concentratesthere

• Forms a barrier that prevents droplets from coalescing

• Lowers system interfacial tension (IFT) allowingformation of smaller droplet sizes

Rigid Film Surrounding Water Droplets in WIO Emulsion

An emulsifying agent forms a viscous barrier that inhibits dropletcoalescence

Emulsifying agents surround thewater droplet and form a “skin”

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Typical Emulsion Droplet Size Distributions

Droplet Diameter (microns)

Dis

trib

uti

on

Fu

nct

ion

1 10 100

Tight (Difficult)Small dropletsMore stable

Loose (Easier)Larger droplets

Less stable

Modelling Oil-Water Separation

FPS SI

vt, terminal settling velocity ft/sec m/s

g, gravitational acceleration 32.2 ft/sec2 9.81 m/s2

Dp, droplet diameter ft m

ρw, water density lb/ft3 kg/m3

ρo, oil density lb/ft3 kg/m3

µo, oil viscosity lb/ft-sec kg/m-s

Note: 1cP = 0.001 kg/m s = 6.72x10-4 lbm/ft-sec

Design of oil dehydration equipment is complex and is very muchbased on experimental data

o

owpt

gDv

18

)(2

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Modelling Oil-Water Separation

Droplet size, Dp

• Droplet sized is the most important parameter in oil-water separation

• Doubling the droplet size increases the settling velocity by a factor of 4

• Larger droplet sizes are achieved by:– Reducing shear in the production system

– Increasing the interfacial tension

– Modifying the effect of the emulsifying agent

– Using separator internals that promote coalescence

Oil viscosity, µo

• Oil viscosity is the second most important parameter in oil-water separation

• Halving the oil viscosity increases settling velocity by a factor of 2

• Lower oil viscosity is achieved by:– Increasing separation temperature

Density difference, ρw – ρo

• The density difference between oil and water is the third most importantparameter in oil-water separation

• Typically we have little control over the fluid densities although increasing thetemperature may have a small effect on the density difference

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Three Main Steps

What equipment or means do we use to accomplish the above ?

Heat

Chemical demulsifiers

Mechanical devices to promote coalescence

Electricity to promote coalescence

Retention time/cross sectional area

1

Destabilization

Weaken the film surrounding the

small water droplets

2

Flocculation/Coalescence

Get the small droplets to collide, coalesce, and

grow into larger droplets

3

Gravity Separation/Sedimentation

Allow time for the coalesced water droplets to settle out of

the oil due to density difference

Heat

Benefits of heating:• Reduces oil viscosity

• Increases movement of droplets due to convection currents whichaids coalescence

• Destabilizes the interfacial film/skin around the droplets

• Increases solubility of waxes and asphaltenes (emulsifying agents)

• May increase the density difference

Disadvantages of heating:• Oil shrinkage due to loss of light components

• Reduction of API gravity

• Increased water solubility in oil

• Scale deposition

• Fuel cost

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Example Oil Dehydration Temperatures

Emulsion Type

oAPI Gun Barrels Wash Tanks

ºF (ºC)

Heater

Treaters

ºF (ºC)

Electrostatic Treaters

ºF (ºC)

Loose >35 80 – 100

(27 – 38)

100 – 120

(38 – 49)

85 – 105

(29 – 41)

Moderate 25 – 35 100 – 120

(38 – 49)

120 – 180

(49 – 82)

105 – 140

(41 – 60)

Tight 15 – 25 120 +

(49 +)

140 – 200

(60 – 82)

120 – 160

(49 – 71)

Very viscous

10 – 15 150 +

(66 +)

180 – 250

(82 – 121)

160 – 230

(71 – 110)

Use of electricity can reduce required temperature and heat input

Chemical Demulsifiers

What are they?• A wide range of surface active chemicals used to destabilize oilfield

emulsions and promote solids removal

• WIO demulsifiers are highly oil soluble

• OIW (reverse) demulsifiers are highly water soluble

What do they do?1. Strong attraction to the oil/water interface

2. Deactivate emulsifying agents by dissolving them in one of thephases

3. Promote flocculation and coalescence by weakening the filmaround the water droplet

4. Solids wetting – remove solids from the oil-water interface bymaking them migrate to the water phase, e.g. iron sulfide andreservoir fines or making them migrate to the oil phase, e.g.paraffins and asphaltenes

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Demulsifiers

•Emulsion BreakerWithout Demulsifiers With Demulsifiers

Emulsion Breaker = EB

Demulsifiers


Without demulsifier treatment,the film around the waterdroplet remains intact

With demulsifier treatment,the emulsifying agents areinto one of the two phases(usually the continuousphase)

Without demulsifier treatment,the pliable film around thewater droplet remains intactwhen a collision occurs

With demulsifier treatment,the film becomes brittle andruptures when a collisionoccurs

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Demulsifiers







Demulsifiers






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Demulsifiers







Chemical Demulsifiers – Selection

Different demulsifier compounds have different properties• Water drop: effective at coalescing water droplets

• Dehydration: flocculate submicron water droplets

• Wetting agents: interact with solids to change wettability of their surfaces

• Interface quality and water clarity

Normally screened/selected based on bottle tests

Typically use a tailored blend of chemicals to achieve the desired performance

Electrostatic bench tests• Chemical effectiveness can be different in the presence of an electric field

Concentrations of 10-60 ppm are typical (overdosing can make emulsions worse)

Injection point

What type of emulsion is to be treated

What is the water cut

What is the temperature range and can the system be heated

Is the feed composition constant or variable

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Internals to Promote Droplet Coalescence

Coalescing Plate Pack(Courtesy Koch Glitsch)

Natco® Horizontal® PERFORMAXTreater Coalescing Matrix Plates

Internals designed to promote coalescence of dispersed phasedroplets are sometimes installed in the liquid holding sections ofthree-phase separators

Internals to Promote Droplet Coalescence

o

owpt

gDv

18

)(2

Stokes’ Law

Internals designed to promote coalescence of dispersed phasedroplets are sometimes installed in the liquid holding sections ofthree-phase separators

•6/21/2017

•7

Electricity to Promote Droplet Coalescence

Electrostatic treaters (coalescers) apply a high voltage electric field toan emulsion to enhance separation

Two main types:• Alternating current (AC)

• Alternating/direct current (AC/DC)– Voltage modulation

– Dual frequency

Typical voltage levels: 12,000 – 30,000 V

How does it work?

Electricity to Promote Droplet Coalescence

Ratio of electrostatic to gravity forces is ~ 1,000for 4 microns diameter water drops in 20o API crude

Free Water Knockout (FWKO)

Long residence time (2-20 min)

May include a gas “boot” if gas bubbles interferewith separation efficiency

Pressure about 50 psig (350 kPag) or lower

Can be horizontal or vertical

Free Water Knockout (FWKO)

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Gunbarrel or Wash Tank

Gas Separating Chamber Gas Equalizing Line

Weir Box

Adjustable Interface Nipple

Oil SettingSection

Well Production Inlet

Water WashSection

OilOutlet

WaterOutlet

Gas Outlet

Produced Fluid

Gas

Emulsion

Separated Oil

Water Out



Weir Box


Oil SettingSection


Water WashSection

OilOutlet

WaterOutlet

Gas Outlet

Produced Fluid

Gas

Separated Oil

Water Out

API 421 Recommends short circuiting factor of 1.75, so…• For a retention time of 8 hours, design for

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HEXT

=HO

=HW


Weir Box


Oil SettingSection


Water WashSection

OilOutlet

WaterOutlet

Gas Outlet

HEXT=(SGO/SGw)HO+HW

HEXT


Cutaway of a Vertical Heater Treater

1. Emulsion in at top

2. Gas leaves from top

3. Drop to FWKO section

4. Oil (lighter fluid)moves upward throughperforated baffles

5. Hot dehydrated oil outheat exchange withemulsion feed

6. Water leaving thebottom of the treaterthrough the dumpvalve

7. Maximum capacitytypically 10,000Bbls/day [1590 m3/h]

8. Very common onshoremature field

Direct Fired

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Cutaway of a Horizontal Heater Treater

•Coalescing•sectionG

asFree W

ater

Dehydrated Oil

Separated

Water

Gas

Electrostatic Treater

Courtesy Natco

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Typical Liquid Residence Times

Type of TreaterTypical Liquid – Phase

Residence Time

Gun Barrels or Wash

Tanks (Settles via Stokes’ Law)

8 – 24 hrHeavy crudes or low volume

Vertical Heater–Treaters 0.5 – 4 hr

Horizontal Heater–Treaters 0.5 – 4 hr

Electrostatic Treaters5 min – 0.75 hr

Offshore and heavy crudes

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Oil-Water Separation

Well fluid production facilities and in the gas conditioning andprocessing facilities, such as hydrocarbon dew point control plant,we encounter separation of oil, water and gas phases

Similar to degassing of a liquid phase, two methods are used tosize the liquid-liquid separation section:

• Residence Time Method

• Droplet Settling Theory

Horizontal 3-Phase Separator

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Water-in-Oil and Oil-in-Water Separation Criteria P 34

Gas-oil and Oil-water level control arrangements for 3-phaseseparators

• Overflow Weir

• Submerged Weir

• The Bucket and Weir

• Submerged Weir with Boot

Three-Phase Separator Configurations

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Overflow Weir Gas-oil contact is fixedby the weir, so no liquidlevel control is required

• It is more difficult toadjust the gas-oilinterface tocompensate forchanging gas-liquidrequirements

• Any slugs/surgesentering the separatormay spill over into theoil compartment

• For viscous oils, thereis increased possibilityof entrainment of gasinto the oil due to the“waterfall” effect


Submerged Weir Requires level control atgas-oil interface butallows more flexibility

Better able toaccommodate slugs& surges

Allows for more stable oilflow out of separator

Ability to adjust oil-waterinterface may be limiteddue to shorter weirheight

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Bucket and Weir designis sometimes favored insmaller separatorsbecause it does notrequire interface levelcontrol

Disadvantages include:• Increased complexity

• Limited retention timein the oil and watercompartments

• Limited flexibility toadjust levels as watercuts and GOR changeover the field life

Bucket and Weir

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•6/19/2017

•1

Learning Objectives

Describe emulsions, how they form and how they influenceseparator design

Discuss how emulsions can be destabilized and eliminated

Estimate oil dehydrator size based on liquid-liquid separationcriteria

You are now able to:

PetroAcademyTM Gas Conditioning and Processing Core

Hydrocarbon Components and Physical Properties Core

Introduction to Production and Gas Processing Facilities Core

Qualitative Phase Behavior and Vapor Liquid Equilibrium Core

Water / Hydrocarbon Phase Behavior Core

Thermodynamics and Application of Energy Balances Core

Fluid Flow Core

Relief and Flare Systems Core

Separation Core

Heat Transfer Equipment Overview Core

Pumps and Compressors Overview Core

Refrigeration, NGL Extraction and Fractionation Core

Contaminant Removal – Gas Dehydration Core

Contaminant Removal – Acid Gas and Mercury Removal Core

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Documents

Separation Core COPYRIGHTcloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · TEG Contactor Degasser ... top of vessel • Gas flows radially from inside to outside