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“Scaled Solutions Production Chemistry
Short Course - 2016”
Separation and Demulsifiers
Dr Neil Goodwin;
Technical Manager - Scaled Solutions Ltd, Livingston
30/09/2016
Presentation Content
Introduction
Why Separation?
Gas/liquid separation
• Foaming/De-foaming
Oil/Water Separation (Crude Dehydration)
Theory
Methods
Natural/Mechanical
/Electrical/Thermal/Chemical
Oil Removal from Water (eqpt. overview)
Future Trends
Production Chemistry
Course Scaled Solutions (c) 2016
Typical Production System
Gas
Manifold 1 Processing
Sep 1
Gas
W Manifold 2
Export
+ Gas Lift
+ Fuel
e Sep 2 Gas
l
Test Manifold
l Test
Sep
s
Oil
Export
Produced Water
Processing
Disposal, Overboard
discharge
Production Chemistry or re-injection
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Why Separation?
Most oil wells also produce gas and (eventually) water
Gas and oil are marketed separately
Oil and gas processing requirements are very different
Gas, oil must meet strict commercial specifications
Water is a waste product – no value, but must still be processed for
disposal
First stage of processing - separate the gas, oil and water
Production Chemistry
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Typical Three Phase Separation Vessel
Production Chemistry
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Gas/Oil Separation Problems -
Foaming
Foams = colloidal systems - liquid continuous phase and dispersed gas
phase
Foaming in separators occurs when gas can not easily escape from the
liquid due to surfactants that affect the liquid surface tension
Foaming tendency is crude specific … different surfactants
Foam stabilisers include soaps of organic acids, other chemicals, bio-
solids etc.
Foaming can result in:
liquids carryover into gas treatment train
Requirement to reduce throughput/cut production
System ‘trips’
Foaming can be controlled with defoamer chemicals
incl. silicones, fluoro-silicones, polydimethylsiloxane, EO/PO, alkyl
polyacrylates
Production Chemistry 6
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Foaming in a Separator
No foaming
Severe foaming
Liquid carryover
results in
Gas out compressor trips
Live crude Live crude
oil in Gas oil in Foam
Crude Crude
Stabilised Gas carry under results in
crude oil out vapour pressures exceeding
specifications
Production Chemistry
Course Scaled Solutions (c) 2016
Structure of Gas/Oil
Foams
Typical Lamellar
structure of gas/oil
foam gas bubbles are
stabilised by
indigenous surfactants
resins, asphaltenes,
etc.
or added surfactants in
other treatment
chemicals
Gas Phase Volume
Gas Dispersions Polyhedral Foams
Gas Liquid
Gas
Liquid
Low Gas Phase volume High gas Phase Volume
Individual bubbles rise by Interfacial films need to drain to
gravity allow gas bubble coalescence
Little intervention needed Assistance may be needed
Production Chemistry
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Foam Stability – An Analogue
Releasing the pressure
on the liquid has
created millions of little
gas bubbles (CO2
coming out of solution)
Transient foam forms
But after a minute or Proteins
two the foam has gather around
collapsed. The foam the gas
in Coke is unstable bubbles and
The bubbles flow
down the insides of the stop them
glass before gradually from
rising to the top of the collapsing
glass.
The head (foam)
remains stable for an
extended period of
time.
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How De-foamers Work
Consider oil film between two gas
bubbles in the foam
The de-foamer chemical must be
insoluble in the crude oil..
...and it must be able to spread at
the gas/oil interface..
As it spreads it thins the film until
it breaks..
Adding too much chemical means
there is no thinning effect, and it
may even stabilise the foam!
Production Chemistry
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Oil/Water Separation - Crude Oil
Dehydration
Why Dehydrate Crude?
Water is a waste product of oil production
Water production increases as fields mature – e.g. North Sea wells
now average > 70% water cut – some > 95%!
PW discharge quality requirements increasingly more
stringent/costly
Reduce the oil capacity of transport and storage facilities
Enhance corrosion pipelines, pumps etc.
Can enhance viscosities – reduced throughput/increased
energy/cost
Can cause scale problems
Can enable biological activity (corrosion/blockages/H2S)
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Oil/Water Separation Fundamentals
Oil and water are immiscible
Oil/water emulsions “should” separate by density difference
This separation is governed by Stokes Law
Emulsion definitions
A dispersion of two immiscible (or partly miscible) phases
Water or oil external (ie Oil in Water or Water in Oil)
In producing developments unless water cuts are +/- >60% oil is
external
Emulsions possess an oil/water interface – key to separation
Focus here is on water in oil
Production Chemistry
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Types of Emulsion
Water in Oil
Oil continuous phase
Low water cut
Early field life scenario (hopefully!)
Oil in Water
Water continuous phase
Water cut > 40% (field specific)
Late field life scenario (hopefully!)
Transition from WiO to OiW know as the “Inversion Point”
Treating requirements can be significantly different (esp.
chemicals) depending on continuous phase
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Natural Separation of Oil and Water
Stoke’s Law determines rate of fall of water droplets in oil
v = 2gr2(Dr)/9η
where, v = velocity of rise (or fall) of droplets
g = gravitational constant
r = droplet radius (note square relationship!)
Dr = density difference
η = viscosity of continuous phase
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Inherent Barriers to Separation
Natural surfactants
• Low molecular weight molecules (<~500) containing polar
functional groups
• Asphaltenes: - high molecular weight condensed
aromatic/aliphatic molecules containing S, O, N, metals
• Resins: - similar to asphaltenes but lower molecular weight and
less polar (little effect on g)
Other ‘stabilisers’
• Wax & naphthenate soaps
• Solids – scale/sand/corrosion debris
• Droplet size distribution
o Small droplets and a narrow size distribution reduce
collisions
Time
• Interfacial films become stronger as more surfactants migrate
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How to Speed Up Oil Water Separation?
Assisting Stokes Law v = (2gr2(Dr))/9h
Increase gravity
Apply centrifugal force
Increase the size of the water droplets = Minimise System Energy (IFT)
Flocculate water droplets - chemicals
Coalesce water droplets – electric fields
Increase the density difference
De- gas oil
‘Salt’ water (not typical)
Reduce the viscosity of the oil
Apply Heat
Temperature is key as it reduces oil viscosity
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Minimize System Energy (1)
The driving force to separation is a reduction in free energy (G) of
the oil water system
G = γA where G = interfacial tension and A = interfacial area
Therefore Separation is enhanced by:
Reducing the interfacial area (A)
Reducing the interfacial tension (G)
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Reduce Surface Area
Adding energy to oil and water creates small droplets i.e. large surface
area
e.g. turbulence across downhole perforations and across topside valves/pumps
Consider a 1% water in oil emulsion e.g. 990ml oil and 10ml water
If all droplets are 1 micron diameter
number of droplets = 1.91 x 1013
total area = 600,000cm2 (ie 60m2)
So - to aid separation, the large surface area must be reduced: ie we
need coalescence to reduced free energy
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Oil/Water Separation Fundamentals
Flocculation
Coalescence
Original
dispersion
Breaking
To separate water from oil the water droplets must be:
1. Flocculated
2. Coalesced
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Flocculation
Particles collide by:
Brownian motion
Thermal motion
Mechanical agitation
Greater chance of collision with
Larger particles
More particles
There is a natural desire for all systems to achieve minimum energy
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Separation Enhancing Methods
Mechanical
Provide residence time and ‘quiescence’ using baffles, etc.
Exploit density differences by centrifugation (less common in
oilfield)
Thermal
Electrical
Chemical
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Three Phase Separation Vessel (G/O/W)
Production Chemistry
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Separator Internals
Weir Plate
Plate Pack
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Centrifugation
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Separation Enhancing Methods
Mechanical
Thermal/ Heating
Reduce the viscosity of the oil allows water to drop
faster
Reduces interfacial viscosity
Re-melts wax particles
Electrical
Chemical
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Effect of Temperature
Separated Typical lab bottle tests
Water (%)
Common oil/water
100
separator temperatures
80 are 50-80C
However, subsea can
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reduce to < 30C
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20
0
20 30 40 50 60 70 80
Temperature (°C)
Temperatures > 50°C dissolve many indigenous species (e.g. wax) that enhance
the mechanical barrier to coalescence
There may be sufficient natural temperature or heat may be added
• Long subsea tiebacks may require additional heat
Even at high temperatures a chemical demulsifier is usually required
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Heat Exchangers
(Heating or Cooling)
Plate Type Heat Exchanger
Tube/Shell Type Heat Exchanger
Production Chemistry
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Separation Enhancing Methods
Mechanical
Thermal
Electrical
Achieve droplet coalescence by applying an electrical field
Chemical
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Electrostatic Coalescence
No field Electrostatic field:
+ -- a dipole is created
+
+ - droplet is elongated
++
-
- surface area is increased
+ - interfacial film weakened
Attractive Force, F = (6kE2a6)/d4
where, k = dielectric constant
E = field gradient
a = droplet radius
d = distance between
centres
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Typical Electrostatic Coalescer Unit
Production Chemistry
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Separation Enhancing Methods
Mechanical
Thermal
Electrical
Chemical – complex organic compounds with
surfactant properties
Reduce interfacial tension and promote coalescence/flocculation
Alter wettability of solids - remove from interfacial/emulsion zone
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Chemical Demulsification Theory
Film of oil surfactant molecules
Added chemical migrates to interface
with the indigenous surfactants
The film distorts, expands,
reducing its strength and
lowering interfacial tension
The film contracts, and indigenous
surfactants are removed/replaced by
demulsifier molecules
Ironically - overdosing can cause demulsifiers to
Concentrate at the interface and stabilise emulsions
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Typical Demulsifier Chemistry
(OCH2CH2)xOH Tertiary butylphenol
formaldehyde resin ethoxylates
Hydrophobic chains of ethoxylates
Hydrophilic groups of sulphonates, amines
and acids
Polyglycols
n
C(CH3) Generally in aromatic solvents
Production Chemistry
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Typical Demulsifier Chemistry
Tertiary butylphenol formaldehyde resin
ethoxylates
Hydrophobic chains of ethoxylates
Hydrophilic groups of sulphonates, amines
and acids
Polyglycols
Generally in aromatic solvents
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Biodegradable Demulsifier Chemistry
As many demulsifies are large molecules they have limited toxicity. However,
residual monomers or degradation products can have high toxicity . Therefore ,
use of less toxic / more biodegradable monomers have been developed
including alkoxylated alkyl ployglycosides
Others are based on polyglcerol, or branched polyesters or polyamides
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Demulsifier Selection Procedures
Service companies supplied
with crude oil samples,
formation water chemistry and
likely emulsion characteristics
(droplet size etc.)
Service companies supply small
samples of their best
formulations (bottle tested) for
comparative bottle testing by
independent lab
Candidate demulsifier
formulations ranked and the
best two or three identified for
field trial
Sometimes bottle test results
bear no relation to field
performance!!
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Optimum Demulsifier Injection Point
Water Content
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(%v/v) Separator Separator
K1 K2
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Site B
10
Site A
0 10 20 30 40 50 60 70 80 90 100 110
Injection Point A Injection Point B Time (minutes)
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Summarising - Factors Influencing
Separation
Increased Temperature
• Increases the number of droplet collisions
• Reduces viscosity of external phase
• Increases the rate of film drainage between droplets
Increased water phase volume
• Increase rate of coalescence
Chemicals
• Reduce the interfacial tension (lower free energy)
Electrostatic Fields
• Can be used to increase number and rate of droplet collisions
Time
• Maximise time to minimise Oil BS&W and oil content in water
• Minimise time for separator size
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Slide 40
Thank You
Questions?
www.scaledsolutions.com
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