2010 npra seminar, fundamentals of desalter operation

© 2010 Baker Hughes Incorporated. All Rights Reserved.Confidential. No portion of this material may be copied, reproduced, transferred or stored without the express written permission of Baker Hughes Incorporated.
Fundamentals of Desalter Operation
Baltimore Marriott Waterfront Hotel
October 13, 2010
Presenters:
Kerlin Lobo
Larry Kremer
Simon Cornelius
Baker Hughes Incorporated
© 2010 Baker Hughes Incorporated. All Rights Reserved. Confidential. No portion of this material may be copied, reproduced, transferred or stored without the express written permission of Baker Hughes Incorporated.
Outline
•Process overview
•Common designs
•Design variables and performance expectations
•Operating variables
•Chemical treatment programs
•Performance monitoring
•Desalting system troubleshooting
•Crude oil quality issues
•Crude storage tank issues
•Slop oil reprocessing
•Wastewater treatment

Process Overview
© 2010 Baker Hughes Incorporated. All Rights Reserved. Confidential. No portion of this material may be copied, reproduced, transferred or stored without the express written permission of Baker Hughes Incorporated.4
How Does the “Desalter” Process Work?
•Mix crude oil with water
•Use “mix valve” to agitate
•Use an electrical field and chemical
to help break the emulsion
•Wash contaminants out of oil (into
the water)
•Clean oil is pulled off the top
•Water is drawn off the bottom
Using the right
equipment for the
right job

Crude
Offloading
Refinery
Tank Farm
Tank 1
Tank 3
Desalter
Effluent
Water Pump
Cold Crude
Preheat Exchangers
Crude
Charge Pump
Pipeline Crude
Storage
Terminal
Mix
Valve
Tank 2
Crude Oil Desalter
To Hot Crude
Preheat Exchangers
Desalter
Wash Water
Emulsion
Breaking
Chemical
Tank Farm
Crude PumpCrude
Booster
Pump
Pipeline
Crude Oil
Interface
Level
Controller
Refinery Crude Oil Handling System
•Dissolved salts:
NaCl (~70 - 75%)
MgCl2 (~15 -20%)
CaCl2 (~10%)
– Crude preheat fouling
– Crude unit corrosion
– Downstream catalyst deactivation
– Product quality concerns (coke, heavy fuel oils)
•Metals (Fe, V, Ni)
– Downstream catalyst deactivation
– Product quality concerns (coke, heavy fuel oils)
Typical Crude Oil Contaminants & Effects

•Solids
– Sand/silt/clays/scale
– Corrosion products (iron sulfides, iron oxides)
• Emulsion stabilization
• Crude preheat fouling
• Downstream unit fouling (coker, visbreaker, RHDS, RFCC)
• Product quality concerns (coke, heavy fuel oils)
•Organics (asphaltenes, paraffins)
– Emulsion stabilization
– Crude preheat fouling
Typical Crude Oil Contaminants & Effects
Desalting Purpose and Benefits
•Remove excess water, contaminants from crude oils
•Reduce:
– Fouling in crude unit preheat exchangers, furnaces,
distillation columns
– Corrosion in crude unit distillation columns and overhead
condensing systems
– Potential unit damage, excessive energy costs due to
presence of water in crude
– Impact of contaminants on downstream processes
– Impact on product (coke, heavy fuel oil) quality
Bottom Line – Refineries Desalt to Decrease Operating and
Maintenance Costs

•Reduce crude preheat system fouling
– Salts and solid particles can deposit in crude unit preheat
exchangers or furnace tubes
– These deposits reduce heat transfer rates and/or cause
plugging of the tubes
– Sodium also acts as a catalyst for coke formation in heat
exchangers, furnace tubes and transfer lines
A good desalting operation will reduce fouling potential by
removing a high percentage of crude oil salts and solids,
and by minimizing the amount of sodium in desalted
crude.
•Reduce crude unit corrosion
– Salt hydrolyze at temperatures found in crude unit
atmospheric and vacuum furnaces:
Heat
MgCl2 + 2H2O Mg(OH)2 + 2HCl
Heat
CaCl2 + 2H2O Ca(OH)2 + 2HCl
– HCl gas dissolves in condensing water to form highly
corrosive hydrochloric acid
– Found in overhead condensing systems of distillation
towers
Proper desalting will minimize the HCl generated and will
greatly reduce corrosion potential in the crude unit

Examples of Crude Unit Corrosion Damage
Stainless Steel Distillation Tray
Damage from Exposure to Amine
Hydrochloride Salts
Overhead Vapor Condensing
System Pipe Damaged by Liquid
Hydrochloride Salts
Refinery Corrosion Costs
• 50% of plant maintenance costs
• 4% of plant revenue
•Desalting is the 1st defense for
refinery corrosion control for the crude
unit and downstream processing units.
•Poor desalting will impact refinery
reliability and costs

•Reduce the amount of water in crude oil
– Excessive water in crude (“water slugs”) can cause
damage in the crude distillation tower
• Pressure surges when water is vaporized to steam often
damage tower internals
– Excess water in the desalted crude oil also requires more
fuel to heat crude oil to the desired atmospheric column
approach temperature
A good desalting operation will reduce the impact of
water slugs from the tank farm on crude unit operations
and improve energy efficiency
•Reduce impact of contaminants on downstream
processes
– Catalyst deactivation, especially if residual materials are
fed to the RHDS, RFCC or FCCU
– Increased slagging in furnaces burning refinery fuel oil
•Improve market value of refinery products
– Contaminants can increase coke conductivity, making it
unsuitable for anode grade
– Contaminants can increase metals, ash content of heavy
fuel oils
• New ISO-8217 specs includes maximum Ca levels in HFO

Common Designs
Petreco Low Velocity Desalter
MUD WASH
CRUDE OUTLET
HEADER
MUD WASH
DESALTED
CRUDE
CRUDE
INLET
DISTRIBUTOR
GROUND
GRID
TRANSFORMER
WASH
WATER
EFFLUENT
WATER
MIX VALVE
( + )
( )_
WASH WATER
MIX VALVE
HOT
GRID
END VIEW SIDE VIEW
H2O LEVEL
EFFLUENT WATER
H2O LEVEL
EFFLUENT
WATER HEADER
HEADER
MUD
WASH
RAW
CRUDE
DESALTED
CRUDE
RAW
CRUDE
CRUDE OUTLET
HEADER
MUD WASH
DESALTED
CRUDE
CRUDE
INLET
DISTRIBUTOR
GROUND
GRID
TRANSFORMER
WASH
WATER
EFFLUENT
WATER
MIX VALVE
( + )
( )_
WASH WATER
MIX VALVE
HOT
GRID
END VIEW SIDE VIEW
H2O LEVEL
EFFLUENT WATER
H2O LEVEL
EFFLUENT
WATER HEADER
HEADER
MUD
WASH
RAW
CRUDE
DESALTED
CRUDE
RAW
CRUDE
Optimum interface level: 6” (15 cm) above inlet

Howe Baker Low Velocity Desalter
CRUDE OUTLET
HEADER
WASH WATER
DESALTED
CRUDE
CRUDE
INLET
HEADER
H2O
LEVEL
HOT
GRID
TRANSFORMER
MIX VALVE
( )_
WASH
EFFLUENT WATER
END VIEW
SIDE VIEW
MUD WASH
EFFLUENT WATER
( + )
EFFLUENT WATER
HEADER
MUD WASH
HEADER
DESALTED
CRUDE
RAW
CRUDE
MUD
WASH
RAW
CRUDE
Optimum interface level: 6-12” (15-30 cm) below crude inlet
Cameron-Petreco Cylectric Desalter

Cameron-Petreco
Bilectric Desalter
WASH WATERWASH WATER
DESALTEDDESALTED
CRUDECRUDE
EFFLUENTEFFLUENT
WATERWATER
MIXMIX
VALVEVALVE
LCLC
END VIEWEND VIEW
DESALTED CRUDEDESALTED CRUDE
EFFLUENT WATEREFFLUENT WATER
SIDE VIEWSIDE VIEW
Flow BaffleFlow Baffle hot gridshot grids
Wash WaterWash Water
Mix ValveMix Valve
RawRaw
CrudeCrude
MudwashMudwash
HeaderHeader
MudwashMudwash
PumpPump
RawRaw
CrudeCrude
Mud WashMud Wash
HeaderHeader
TransformerTransformer
Flow BaffleFlow Baffle
MudMud
WashWash
TransformerTransformer TransformerTransformer TransformerTransformer
LCLC
Distributor HeaderDistributor Header
Crude Outlet Header
Orifice Plate
Upper Grid
Lower Grid
Crude oil
Emulsion
Middle Grid
Optimum level: 12-24” (30-60 cm) below grids
Three
distributors are
typically used to
meter crude oil
into the two
electrical fields
of the desalter
vessel.
BILECTRIC is a registered trademark of Cameron - Petreco
Design Variables and Performance Expectations

Desalter Design Variables
•Each desalter has a design basis
– Crude rate
– Gravity
– Viscosity
– Temperature
– Raw crude BS&W (basic sediment and water) and salt
Lower Electrode
690
15001500
1750
250
1
2
3
4
5
200
125
200
290
200
CL
Internal Dimensions:
• Center line
• Tri-cock spacing and location
• Electrode position
• Levels
• Manifolds
Desalter Performance Expectations
•Performance predicted for design conditions
– 90 – 95% salt removal for single stage desalting
– 98% for two stage desalting
– If raw crude salts <10 PTB, desalted crude salts <1 PTB
•If operations are outside of design conditions,
performance may be affected

Desalter Design & Capacity
•Desalter Size
– Oil Residence Time affects emulsion resolution and
dehydration
– Water Residence Time affects brine quality
• Desalter diameters range from 10’ to 14’
• Spherical desalters provide more residence time
– Higher capital costs
– Typical residence times
Crude Gravity Oil Residence
Time (min)
Water Res
Time (min)
15-18o
API 30 - 60 120 – 140
18-22o
API 20 – 30 80 – 120
22+o
API 15 - 20 60 - 80
Desalter Design & Capacity
•Grid design and voltage
– Petreco claims Bilectric design has about 1.75 times the
treating capacity as low-velocity desalters of the same size
– In Bilectric desalters residence time between the grids is the
critical variable
– Grid voltage
• Function of grid area and transformer size
• Step up transformer voltage can be adjusted based on
operation
WASH WATERWASH WATER
DESALTEDDESALTED
CRUDECRUDE
EFFLUENTEFFLUENT
WATERWATER
MIXMIX
VALVEVALVE
LCLC
END VIEWEND VIEW
DESALTED CRUDEDESALTED CRUDE
EFFLUENT WATEREFFLUENT WATER
SIDE VIEWSIDE VIEW
Flow BaffleFlow Baffle hot gridshot grids
Wash WaterWash Water
Mix ValveMix Valve
RawRaw
CrudeCrude
MudwashMudwash
HeaderHeader
MudwashMudwash
PumpPump
RawRaw
CrudeCrude
Mud WashMud Wash
HeaderHeader
TransformerTransformer
Flow BaffleFlow Baffle
MudMud
WashWash
TransformerTransformer TransformerTransformer TransformerTransformer
LCLC
Distributor HeaderDistributor Header
Crude Outlet Header

Operating Variables
Desalter Operating Variables
• Desalter type
• Wash Water System
• Level control
• Mix valve setting
• Temperature
• Mud wash

Desalter Wash Water
•Common Sources
– Process water
• Preflash overhead water
• Atmospheric column overhead water
• Vacuum condensate
– Stripped sour water
– Municipal, well or filtered surface water
– Boiler blowdown
– Cooling water blowdown (scale, bio)
– Brine recycle
• Normal injection is prior to mixing device
• Can inject some water prior to preheat exchangers (10-100%)
– Longer contact to dissolve salt crystals
– Reduce exchanger fouling
• Do not inject to suction of pump (can make difficult emulsion)
Desalter Wash Water: Injection Location
Desalter Effluent Water to
Waste Water Treatment Plant
Wash Water to Cold
Crude Preheat Exchangers
Crude Oil
Storage Tank
Emulsion Breaker
Mix Valve
Wash Water
to Mix Valve Desalter
Wash Water
Crude Oil to Hot Crude
Preheat Exchangers

•Best Practice – Water Rate
– Target:
• 4 – 6% (Light to Medium Crude Oil)
• 6 – 9% (Heavy Crude Oil)
– Lower crude oil gravity = higher wash water rates for
optimum performance
Desalter Wash Water
Wash Water Impact on % BS&W
0.2%0.8%0.8%1.2%
Desalted
Crude BS&W
8.0%5.5%3.7%1.7%30 min
8.0%4.5%3.4%1.2%20 min
9% Water7% Water5% Water3% Water
Settling
Time
Heavy Canadian crude oil

•Best Practice – Water Quality
– pH (5 - 8)
– Hardness (< 175 ppm as CaCO3)
• Scale in brine effluent/wash water feed exchangers
– Suspended solids (< 30 ppm)
– Ammonia (< 50 ppm)
– Phenols and organic acids (< 1 ppm)
Wash Water Quality
Wash Water Source Concerns
•High pH (normal 5 - 8)
– Best practice pH around 7
– High pH can stabilize
emulsion
– Potential sources of high pH
• Spent caustic
• Caustic added at SWS to
improve stripping
• Tramp amine/ammonia
– Is it the desalter effluent pH
that is critical?

Desalter Operational Variables
• Desalter type
• Wash water system
• Level control
• Temperature
• Mud wash
Interface Level Settings
Determined by desalter design:
•Howe-Baker
– 5-30 cm (6-12”) below crude inlet
•Petreco Low Velocity
– 15 cm (6”) above inlet
•Petreco Bilectric & Cylectric
– 30-60 cm (12-24”) below bottom grid

Interface Level Monitoring
Tri-cocks, trylines and/or swing arms
1
2
3
4
5
EMULSION
0
1
2
2 1/4
1
2
2 1/4
Tri‐cocks:
separate lines and valves
samples vessel (desalter) typically at
five (5) heights
bottom #1, top #5
<-----OR ---->
DESALTER LEVEL SAMPLING DEVICES
Swing Arm:
sampling pipe rotates 180 degrees ,
enabling sample collection at any point
{MUST DETERMINE SWING ARM SETTING
vs. ACTUAL HEIGHT IN UNIT}
These numbers are only guides
"Arm" swings or rotates 180 degrees
straight up and down
bottom grid
C
OIL
WATER
EMULSION
Interface Level Monitoring
•Use tryline or swing arm to establish level
•Use instrumentation to monitor (not absolute)
•Collect samples in centrifuge tubes from swing arm or
trylines
•Centrifuge samples to determine BS&W at various levels

Interface Level Controllers
•Floats/Displacers
– Based on density differential
– Less effective with higher density/low gravity crudes
– Ineffective with emulsion pad
•Capacitance probe
– Measure differences in electrical capacitance
•Agar probes
– Measure differences in energy absorption
•TRACERCO
– Gamma ray technology
Level Control – Capacitance Probe
Middle Energized Electrode
Lower Grounded Electrode
Upper Grounded Electrode
Mud Wash
8“
8“
72“
Active Area 56”
10”
79”
69”
59”
49”
39”
Capacitance Probe
4TH & 5th Tricock -
Emulsion
Water Level
Rag layer
Desalted crude
Effluent Water
Low Level Safety Float Switch – Will cut power
to the middle grid if the float & Oil level drops
4 Ma = 0% @ 10”
20 Ma = 100% @ 66”
12 Ma = 50% @ 38”
8 Ma = 25% @ 24”
16 Ma = 75% @ 52”
51.8%
87.5 %
69.4%
105 %
123%
12.288mA
15.1mA
18mA
20.8mA
Inlet
Distributor
Middle Energized Electrode
Lower Grounded Electrode
Upper Grounded Electrode
Mud Wash
8“
8“
79”
69”
59”
49”
39”
4TH & 5th Tricock -
Emulsion
Water Level
Rag layer
Desalted crude
Low Level Safety Float Switch – Will cut power
to the middle grid if the float & Oil level drops
51.8%
87.5 %
69.4%
105 %
123%
12.288mA
15.1mA
18mA
20.8mA
Inlet
Distributor

• Desalter type
• Level control
• Temperature
• Mud wash
Mix Valve Setting
•No absolute best setting
– Will vary with type of crude, throughput, and type of
chemical used
•For most efficient salt and solids removal
– Increase mixing energy until BS&W begins to increase
– Changing chemical can improve dehydration and allow
more mixing

Adjust the Mix Valve to Optimize
Salt and BS&W Removal
SALT CONTENT
BS & W
}
OPTIMUM
MIXING
PRESSURE
INCREASING MIXING PRESSURE
100
80
60
40
20
0 0
0.2
0.4
0.6
0.8
1.0
%BS&WINDESALTEDCRUDE
%SALTINDESALTEDCRUDE Desalter mix valve ΔP vs. desalted crude salt and BS&W
• Desalter type
• Wash water system
• Level control
• Temperature
• Mud wash

Desalter Temperature
•Typical range 165 – 295°F
•Higher temperatures decrease crude oil viscosity
– Emulsion breaks more easily
•Water more soluble at higher temperatures
•Conductivity increases with temperature
Crude Oil
Deg API
Typical
Temperature
>36 220-250
36-30 235-265
30-24 250-280
24-18 265-295
18-12 280-310
2.52.5
5.55.5
20.020.0
12001200
450450
120120
80.080.0 100100 130130 210210 300300
TEMPERATURE - ºF
36º API
30º API
22º API
16º API
12º API
10º API
50005000
20002000
45.045.0
60.060.0
100100
200200
500500
10001000
35.035.0
Characteristic Temperature – Viscosity
Relationship for Crude Oils
VISCOSITY-CENTISTOKES
VISCOSITY-SAYBOLTSECONDS

• Desalter type
• Level control
• Temperature
• Mud wash
TO WWTPTO WWTP
MUDWASH HEADER
&
NOZZLES
INTERFACE
LEVEL
IN VESSEL
DESALTER EFFLUENTDESALTER EFFLUENT
WATER HEADERWATER HEADER
MUD WASH PUMPMUD WASH PUMP
LEVELLEVEL
CONTROLLERCONTROLLER
ALTERNATEALTERNATE
WATER SOURCEWATER SOURCE
Purpose: solids
accumulate in the bottom
of the vessel - forming
mud or oily sludge. The
sludge may plug parts of
the effluent water header
or significantly decreases
water phase residence
time in the vessel.
Howe-Baker recommends mud washing a minimum of three minutes per day
for a typical mud washing system, while Petreco suggests mud washing for
one hour once per week. However, the frequency and duration of mud
washing is best determined through operating experience. [ALL DEPENDENT
ON SOLIDS LOADING]
Desalter Components - Mud Wash

Mud Wash Practices
•Nozzles placed 0.3 – 0.5 m off bottom
•Velocity and time are critical parameters
•Mud wash until brine turns clear
•Best to use recycled effluent water
– Need mud wash pump
– Don’t starve wash water
Chemical Treatment Programs

Chemical Treatment Program Types
•Conventional emulsion breaking chemicals (demulsifiers)
– Injected into the suction of crude unit crude pump
• Used to control interface growth and improve effluent water
quality
• Can also have an effect on dehydration efficiency
• Sole chemical used in majority of desalter operations
•“Adjunct” chemical applications
– Solids wetting agents
• Used to improve solids handling capability
• Typically injected into desalter wash water
– Polymers
• Used to shrink interface size, reduce effluent water oil content
• In many cases used for upset recovery only
• Typically injected into desalter wash water
Chemical Treatment Program Design
•Feedstock evaluations
– Service companies can pre-screen blends and/or individual
crudes in the lab to assess and predict:
• Asphaltene stability
• Feedstock compatibility
• Emulsion resolution speed, efficiency
• Best chemical treatment regimes
•Chemical treatment program development
– Based on feedstock pre-screening results
– May be modified based on prior field experience
•Adjust/optimize program on site
– Good data collection, optimization protocols are key

Desalter Operating Variables: Summary
•To optimize desalter operations:
– Use an adequate amount of a good quality wash water
– Maintain good level control
– Use proper mix valve pressure drop settings
– Use an effective chemical treatment program
– Monitor desalting performance on a regular basis
Performance Monitoring

Monitoring to Ensure Performance
•Major KPIs are measurable and reflect true performance
•Some KPIs may be tied to the contract as performance
conditions
•Suggested minimum KPIs for
desalter operations
– Raw & desalted crude analyses
• Salt, BS&W and Filterable Solids
– Calculated % salt removal and %
solids removal efficiencies
– Brine quality measures
• pH
• O&G in refinery lab or TD500 (or
other method)
• Visual
• Percentage oil by graduated cylinder
TD500 Oil in Water Meter

•Basic process data monitoring recommendations
– Crude rate
– Crude type
– Crude tankage operational status
• Water slugs
• Crude tank levels
• Individual crude tank BS&W or filterable solids contents
– Slop oil addition
• Addition rate and quality (BS&W, solids content)
•Special application KPI monitoring
– Calcium removal efficiency
– Tramp amine or ammonia removal
– Iron removal efficiency

Additional Process Monitoring
•Monitoring of operational variables that impact
performance but are not KPIs
– Temperature & pressure
– Mix valve ΔP
– Level; tri-cock analyses
– Grid volts/amps
– Sludge levels
– Mud wash frequency, duration & efficacy
– Wash water rate and quality
– Flash drum bottoms temperature
– Atmospheric column overhead accumulator water make
•Other KPIs related to desalting
– Crude column overhead condensate chloride content
• Monitor caustic strength and addition rates, if used
• Best practice: 5 °Baume strength, ≤5 ptb addition rate
– Chemical dosage and consumption history
– Slop oil generation
– Downstream unit – specific KPIs
• Benzene stripper
• Coke sodium content (anode grade coke)

Desalting System Troubleshooting
•Agenda
– Common causes of
• Poor performance
• Upsets
– Crude oil quality and its impact on desalter operations
• Solids
• Asphaltenes
• Calcium naphthenates
– Crude oil storage tank condition and operation
– Slop oil reprocessing

•What are the most common causes of desalter
performance problems?
– Equipment problems
– Operating conditions
– Crude unit feedstock characteristics
•Identifying and correcting performance problems
– Operational and mechanical solutions
– Chemical treatment programs
– Combinations
•Typical equipment problems
– Treatment chemical pump malfunction
– Level control indication or control system malfunction
– Loss of electrical grid(s)
– Sludge buildup in vessel/plugged effluent water header
•Typical operating condition deficiencies
– Wrong interface level setting
– Low desalter temperature
– Insufficient wash water rate
– Incorrect mix valve setting
– Ineffective chemical treatment program
•Desalter feedstock characteristics
– Most common cause of desalter upsets

•Most desalter upsets related to desalter feedstock
characteristics
– Crude oil quality
• Individual crudes
• Properties of crude blends
– Impact of crude storage tank operating practices
– Slop oil re-processing
• Characteristics of re-processed slop
• Slop injection practices
– Wash water quality
• pH
• Solids content
Crude Oil Quality Issues

Crude Quality Issues
•Crude oil characteristics
– BS&W of raw crude
– Filterable solids content of raw crude
– Stability of asphaltenes in crude blends
– Other crude oil “contaminants”
• Surfactants
• Ammonia, tramp amines
• Naphthenic acids
• Calcium naphthenates
COQG
66
Crude Oil Supply System
Salt Dome
Storage
Refinery
Tankage
Marine
Terminal
Tankage
Pipeline
Tankage
MARINE
ONSHORE
REFINERY
Lease
Tankage
OFFSHORE
BARGE
TANKER

Filterable Solids
•Inorganic solids, > 0.45µm in diameter
– ASTM D-4807-88 (using toluene wash step)
•Not typically included in assays
•Wide variation in solids content
•What is high?
– Systems vary in their tolerance to solids
– Typical solids levels where emulsion stabilize >80 PTB
•Desalter problems caused
– Stabilized emulsions
– Oil in brine
•Specialty surfactants can help
Solids / Asphaltene Stabilized Emulsion
(5% Wash Water Added)
100 X

Filterable Solids Variations (Three Months)
0
50
100
150
200
250
300FilterableSolids(PTB)
For some crudes oils there can be substantial daily filterable solids variation
0.0
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
FilterableSolids -Lease Samples
Filterable Solids: Individual Lease Samples
Blended and Sold as Single Crude Oil
Solids in crude oil blend vary depending on which wells are producing

0
20
40
60
80
100
120
140
3/8/2000 3/16/2000 3/25/2000 4/15/2000 4/25/2000 5/8/2000 5/15/2000 5/26/2000 6/3/2000 6/9/2000
poundsper1000bbls
Combined Raw Crude Filterable Solids
Wetting Agents can Mitigate Problems
Wetting Agent
Solid shading indicates
desalter upset
Asphaltenes
• Stressing asphaltenes causes agglomeration
– Paraffinic vs. asphaltenic crude oil
– Temperature
– pH
• Can cause multiple problems
– Sludge precipitation in tankage
– Fouling
– Foaming
– Emulsion stability – desalter problems
• Effluent water quality
• Wastewater treatment plant upsets

Theoretical Asphaltene Structure
Gray, M. R., Energy & Fuels 17(6), 2003, 1566
Resins
Asphaltene Core
Asphaltene Micelle
Bulk oil

Asphaltene Destabilization
Stress
(destabilizes resins)
Disruption of resins → Agglomeration
(“stacking” of Asphaltenes)
ASIT Asphaltene Stability Index Test
•ASIT TM Principle
– Measures the onset of the flocculation of the asphaltenes
with high accuracy by inducing the asphaltene precipitation
via titration with a paraffinic solvent
Titrant
Light
source
1
2
Intensity
ASI
Onset Flocculation
Point of Asphaltenes
3
Titrant
Light
source
1
2
Intensity
ASI
Onset Flocculation
Point of Asphaltenes
3
ASIT is a trademark of Baker Hughes Incorporated

ASIT Test Case History 1
• Introduction of Crude 2 caused formation of rag layer
shorting out bottom grids
• Oils were found to be incompatible
• Blend had ASI in unstable region
# Oil / Blend ASI %Asphaltenes %Resins Asph/Res
1 Crude 1 1.75 3.4 7 0.49
2 Crude 2 0.96 5.4 10.8 0.50
3 Crude 3 1.5 6.53 27 0.24
4 55%(1) 20%(2) 25%(3) 1.24 - - -
EDDA Demulsification Test %Water Drop %Water Drop %Water Drop BS&W
5 min 10 min 15 min
# 4 0 0 0 0.6
# 4, Stabilizer & Demulsifier 3.3 3.8 4.5 0.14
0
20
40
60
80
100
120
0 0.5 1 1.5 2 2.5
ASI
Intensity
# 1
# 2
# 3
# 4
# 4 & Additive
Asphaltene stabilizer
increases stability of
blend
ASIT Test Case History 1

Mitigation Strategy for Case History 1
• Crude oil blending aid added to crude 2 as it was
transferred to storage tanks
• Wash water rate increased from 4% to 5.3%
– Increases droplet population
– Increases oil-water interfacial area, effectively diluting
asphaltene surface concentration
• Wetting agent added
– Control solids that increase asphaltene destabilization
Crude Oil Blending Aid Case History 2
•Refinery’s ability to process heavy Canadian crude limited
– Poor dehydration
– Poor brine quality
•Asphaltene stabilization determined to be the problem
•Tested crude blend samples to select best chemical
treatment program
– Crude oil blending aid (new)
– Oil-soluble emulsion-breaking chemical (already in use)
– Solids wetting agent in wash water (already in use)

Crude Oil Blending Aid Case History 2
•Results:
– More than doubled the amount of heavy Canadian crude
being processed
• 7.5 KBPD to 17.5 KBPD
– Maintained salt removal efficiency
– Dehydration performance maintained
Field ASIT ServicesTM Technology
Field ASIT ServicesTM is a trademark of Baker Hughes Incorporated

•Tank Farm problems
– Calcium naphthenates are natural emulsion stabilizers
• High BS&Ws in oil charged to crude unit
•Desalting problems, when metals are present as
naphthenate salts or fine particulates
– High conductivity causes voltage loss
– Emulsion stabilization
– Water carryover
– Poor effluent water quality (high O&G)
•Desalter effluent water exchanger scaling
– Calcium deposits
Other Contaminants: Calcium Naphthenates
84
Chemical Treatment Programs To Mitigate
Calcium Naphthenate Problems
Desalter
Effluent Water
to Waste Water
Treatment Plant
Wash Water to
Desalter
Treated Crude Oil
to Hot Preheat Train
Desalter
Crude Oil
Storage
Baker Petrolite Emulsion
Breaking Chemical
EXCALIBUR™ Contaminant
Removal Additive
Mix Valve
Baker Petrolite
Calcium Scale Inhibitor

Case History 1: Refiner Processing 20%
High Ca Naphthenate Doba Crude Oil
•Contaminant removal additive application reduced desalter
effluent water oil content vs. previous, non-Doba
operations
•Doba processing had no significant effect on effluent water
COD levels
•Phenol levels also reduced
Oil in Effluent
Water, mg/L
Chemical Oxygen
Demand, mg/L Phenol, mg/L
Before Doba
Processing 243 2,002 12.3
Average Values
During Doba
Run 34 2,870 2.3
Case History 1: Calcium Removal
Efficiency Over 90%

Case History 2: Desalter Contaminant Removal
•Background:
– Refinery processing up to 20% high Ca naphthenate Doba crude
– Concerns with Ca impact on FCCU catalyst
– Two stage desalting with minimal (2.5%) wash water
•Results:
– Limited metals removal without contaminant removal program
Metal Raw Crude
(ppm)
Desalted Crude
(ppm)
% Removal
Calcium 46.1 45.0 2
Iron 7.4 7.2 3
Barium 1.4 0.6 57
Magnesium 1.0 0.6 40
Manganese 1.0 1.0 0
•Results:
– Metals content of desalted crude monitored daily
– Contaminant removal program showed much greater
calcium, iron and other metals removal performance
Metal Raw Crude Desalted Crude % Removal
Calcium (ppm) 53 4 92
Iron (ppm) 8 2 75
Barium (ppm) 2 0.1 95
Magnesium (ppm) 2 0.1 95
Manganese (ppm) 1.0 0.34 66
Case History 2: Desalter Contaminant Removal

© 2010 Baker Hughes Incorporated. All Rights Reserved. Confidential. No portion of this material may be copied, reproduced, transferred or stored without the express written permission of Baker Hughes Incorporated.89 © 2010 Baker Hughes Incorporated. All Rights Reserved.89
Contaminant Removal Program Benefits
• Metals removal from crude oil
– Reduces downstream catalyst deactivation
– Improves coke, heavy fuel oil quality
• Improves desalter stability
• Reduces effluent brine downstream impacts (WWTP)
• Provides a key tool for overhead salt formation and
corrosion strategy
– Also removes alkaline materials (ammonia, amines)
• Minimizes crude preheat fouling
Crude Storage Tank Issues

Crude Storage Tank Issues
• Crude oil handling impacts
– Tank stratification
– Tank switches
– Tank sludge issues
– Water slugs
Crude Storage Tank Handling Practices
• Storage tank stratification
– Salts and water content vary as function of height
– Can form water lenses
– Results in varying crude quality to crude unit
– Can result in abrupt quality change during tank switch
– Can result in water slugs to crude unit
• Desalter cannot drain water fast enough
• High salt levels in and out of desalter
• Loss of grids
• Operators cannot respond fast enough

Mitigation Plan for Tank Switches
• Many desalter upsets occur during tank switch
• Switch from best of old tank to worst of new tank
• Improve communication between Oil Movements and
Crude Unit
• Slow transition during switch
• In line water sensor to alert operators of problems
• Chemical pre-treatment can reduce impact
Crude Oil Pretreatment
•Treat crude oil in the tank farm
– Long contact time between surfactants and solids, sludge
– Improves solids control
– Stabilizes asphaltenes
– Helps resolve desalter emulsions
– Reduces oil under-carry
Pretreatment
Chemical
Crude Oil
Storage Tanks
PIER
COMPOSITE SAMPLER
Pretreatment
Chemical
Crude Oil
Storage Tanks
PIER
COMPOSITE SAMPLER
Crude Oil
Storage Tanks
PIER
COMPOSITE SAMPLER
Crude Oil
Storage Tanks
PIER
COMPOSITE SAMPLER

1 3 6 8 9 122
231
339
420
460
500
0
100
200
300
400
500
600
0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96
Settling Time (Hrs)
DrainedWater(Barrels)
Untreated T-41
Baker Petrolite Treated T43
Marlim Crude Tank Treatment Trial - Total Drain Water(Bbl)
Crude Oil Pretreatment Case History 1
Treated Water DrawUntreated Water Draw
Untreated Tank Settling
0
20
40
60
80
100
120
0 24 30 48 72 96
Hours
Salt(PTB)
Top
Middle
Bottom
Top
Middle
Bottom

Treated Tank Settling
0
20
40
60
80
100
120
0 24 30 48 72 96
Hours
Salt(PTB)
Top
Middle
Bottom
Top
Bottom
Series7
Crude Oil Pretreatment Case History 2:
Improve Heavy Oil Handling Capabilities
•Desalter upsets when processing heavy oil sands crude oil
– Up to 3,000 ppm oil in desalter effluent water
– Caused problems in WWTP
•Implemented crude oil pretreatment program
– With pretreatment, effluent water oil content decreased to
an average of 140 ppm
– Improved WWTP operation
– Odor emissions reduced
– Filterable solids removal efficiency increased from 27% to
42%

Heavy Oil Pretreatment Case History 2
Desalter Effluent Water Quality Before and After Pretreatment Program
In Line Water Sensors
• Measure water in crude oil
• Give operators 10 to 30 minutes to react to water slug
– Reduce wash water
– Drop level in desalter
– Reduce mix valve ΔP
Crude
Charge
Pump
Wash Water to Cold
Transformer
Crude Preheat Exchangers
Crude Oil
Storage Tank
Emulsion Breaker
Mix Valve
Wash Water
to Mix Valve
Desalter Effluent Water to
Waste Water Treatment Plant
Desalter
Wash Water
Interface
Level
Controller
Crude Oil to
Hot Crude
Preheat
Exchangers

Sludge in Crude Tank
Visible Light Micrograph of
Sludge From Tank I

Schematic of a Complex Emulsion
WaterWater
WaterWater
OilOil
Problems - Solution
• Problems
– Sludge can lead to water slugs
– Complex emulsion difficult to resolve in desalter
• Solution
– Water slug alarm
– Chemical treatment to reduce sludge

Average Sludge Depth in Tank Farm
with 3 Years Chemical Treatment
0
5
10
15
20
25
30
35
40
0 10 20 30 40
MONTHS OF TREATMENT
DEPTH(cm)
Slop Oil Reprocessing

• Why is slop oil a problem?
• Should all slop go into the desalter?
• What can be done to manage slop oil?
Why is Slop Oil a Problem?
• High water content
• Inconsistent quality
• Can destabilize crude oil
• Solids can stabilize emulsions
– Coke fines causes desalter upsets
– Sand, clay, dirt
• Iron sulfide can affect product quality

Problems Associated with
• Cost of reprocessing
– Direct costs
– Opportunity costs
• Desalter upsets
– Stable emulsions
– Grid loss
– High BS&W
– Effluent water quality
• Catalyst poisons
– Heavy metals
– Alkali metals
• Corrosion
• Fouling
– Inorganic solids
– Organic materials
• Pressure surges
– Tray damage
– Throughput reductions
• Environmental releases
– Waste water system
– Hazardous gases
– Nuisance odors
Should All Slop Go To The Desalter?
• No-Nos
– Coke fines
– Catalyst fines
– Biological waste
– Cleaning waste
– Paraffinic material
• If no water and salt, it does not need to be desalted
• Some slop should be treated before desalting

© 2010 Baker Hughes Incorporated. All Rights Reserved. Confidential. No portion of this material may be copied, reproduced, transferred or stored without the express written permission of Baker Hughes Incorporated.This slide contains the proprietary information of Baker Petrolite Corporation.
By reading this Slide the reader agrees not to disclose any information
What Can Be Done?
• Segregate slop oil to better recycle
• Continuous feed versus batch feed
• Enable operators to back out slop
• Chemically treat slop oil
– Drops out oil and water
– Improves quality and consistency
Troubleshooting Crude Quality Issues:
Summary
• Understand factors affecting quality of feed to desalter
• Minimize variations in quality
• Alert operators to problems and enable them to respond
• Consider chemical treatment to solve some problems
– Wet crude oils
– High solids crude oils
– Incompatible crude oils
– High metals crude oils
– Emulsions and sludge in storage tanks
– Slop re-processing

Wastewater Treatment
Agenda
•Introduction
•Wastewater treatment overview
•Chemical treatment strategies
•Examples
•Post – desalter strategies

Brine Treatments
•Today, more and more emphasis is being put on brine
quality (solids and oil content) and its effects on
downstream processes (e.g. NESHAP, BRU – Benzene
Reduction Units ) – and the WWTP
•Many sites processing heavier crudes see desalter
emulsions (and possible upsets, mudwashings)
contributing to brine quality problems, plus potentially the
accumulation of sludge in “BRU” tanks
Filtration or Lime Softening
Refinery
Corrugated Plate Interceptor (CPI)
American Petroleum Institute (API)
Separators
Equalization Basin
Dissolved Air Flotation (DAF)
Induced Air Flotation (IAF)
Thickener
Dewatering
Landfill
Clarifiers
Filtration/Activated
Carbon Adsorption
Aeration
Basin
River/Sewer
Sludge
Solids
Filtrate
Digester

Wastewater Treatment Process Overview
•Primary
•Secondary
•Tertiary
•Dewatering
Primary Treatment
•Removal of relatively large, heavy suspended solids
and/or free oil
•Process involved:
– Equalization
– pH adjustment
– Chemical oxidation
– Precipitation
•Equipment involved:
– API Separators
– Corrugated Plate Interceptors (CPI)
– Parallel Plate Separators (PPS)
– Induced Air/Gas Flotation Units (IAF)
– Dissolved Air/Gas Flotation Units (DAF)
– Steam strippers
– Clarifiers
– Filtration units (sand, gravel, nutshell media)

Secondary Treatment
•Removal of colloidal and dissolved organics by a biological
system
– Equalization Basin
– Aeration Basin
– Waste Activated Sludge
– Rotating Biological Contactors (RBCs)
– Secondary Digesters (aerobic or anaerobic)
– Fixed Film Bioreactors
– Secondary Clarifiers
– Biosludge Thickeners
– Thickened Sludge DAFs
Tertiary Treatment
•Any form of advanced treatment of secondary effluent,
such as media filtration, nitrogen removal, carbon
adsorption, etc.
•Produces high quality water for reuse or discharge
– Oxidation systems:
• Chlorine dioxide, ozone generators
• Hydrogen peroxide (possibly catalyzed)
• Sodium hypochlorite, gaseous chlorine
– Powdered activated carbon adsorption
– Granular activated carbon
– Nutrient removal (nitrogen, phosphorus)
– Ultra filtration

Sludge Dewatering
•The removal of water from sludge to further concentrate
solids
– Plate and frame press
– Rotary vacuum filtration
– High speed centrifuge
– Vacuum belt filter
– Belt filter press
– Dewatering box
Heavy Oils Present Operating Challenges
•Crude quality issues
– Filterable solids
– Asphaltenes
– Non desaltable chlorides
•Observed problems
– Stable emulsions
– Water carryover
– Oil and solids in effluent water
– Mud build up in desalters and brine separators
– WWTP performance problems

1 2 3 4 5
Typical Desalter Effluent Brine Quality Variations
Based On Filterable Solids Estimates in Raw Crude Slate
30 - 60 PTB 100 - 130 PTB60 - 100 PTB 130 - 150 PTB 150 + PTB
Brine Treatment Unit
Brine Quality Cycle
Pre mud wash 15 minutes after
starting mud wash
2 hours after
mud wash
1 hour after
starting mud wash
2 hour after
starting mud wash
15 minutes after
stopping mud wash
O&G- 127 mg/l
TSS- 43 mg/l
O&G- 40,441 mg/l
TSS- 10,382 mg/l
O&G- 11,640 mg/l
TSS- 2849 mg/l
O&G- 2,031 mg/l
TSS- 658 mg/l
O&G- 343 mg/l
TSS- 92 mg/l
O&G- 22 mg/l
TSS- 16 mg/l

Heavy Oil Case History 1
•Refinery upgraded desalter for heavy Canadian crudes
– Poor desalter effluent water quality
– Low dissolved oxygen in WWTP
•Pre-screened crude blend samples to select chemical
treatment program
– Oil soluble emulsion breaking chemical
– Solids wetting agent in wash water
– Polymer when needed
•Desalter operating variables optimized in the field
Heavy Oil Program Results: D.O. in WWTP
Waste Water Treatment Plant Dissolved Oxygen
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
Daily
DissolvedOxygen,ppm
dissolved O2
Competitive average
Baker Petrolite Average
Before Baker Petrolite After Baker Petrolite

Heavy Oil Program Case History 1: Results
•Can run 250 PTB solids in crude charge
– Salt removal and dehydration maintained
•Filterable solids removal remains at 80%
•WWTP operation improved
– COD reduced
– DO increased
– No longer affected by oily brine
•Overall chemical usage dropped nearly 50%
Polymer Use Reduces
Desalter Effluent Water Oil Content
• Single stage BILECTRIC® high velocity desalter
• Heavy Canadian crude
– 0.91 Kg/L (24°API)
– 200 to 450 ppm solids
• 2 – 5% oil in desalter effluent water
• Injected dispersion polymer into wash water
– Oil and grease dropped to < 100 ppm
– Solids removal remained 66 – 73%
– Dehydration improved

Dispersion Polymer Application
Improves Desalter Effluent Water Quality
This is Not Good Enough
•Still have solids to contend with
•High levels of oily solids during mud wash
•Upsets can send oil to WWTP
•Solids and oil tend to accumulate in Equalization Tanks
The solution is to treat the effluent brine!

•Gas Flotation
•Hydrocyclones
•Centrifuges (2 and 3 Phase)
•Membranes
Advanced Separation Technologies
Desalter Effluent Brine Treatment
Recommended Flow Scheme
Desalter
Cone Bottom Tank
Or
API
Induced Static Floatation
Dissolved Nitrogen Floatation
Induced Gas Floatation
Equalization Tanks
Primary Refinery API
Waste Water Treatment
Plant

Primary Treatment Equipment
•Designated desalter effluent API or heated cone bottom
break tank advantages
−Provides for initial three phase separation of oil, solids and
water prior to chemical addition
− Enhances recovered “free” oil quality by not tying solid and
oil together with a polymer or flocculant into one phase
− Reduces overall slop oil production
− Breaks the internal refinery solids cycle
Heated Cone Bottom Tank Operation
Desalter
Effluent Brine
Free Oil to API or Slop
Solids
To Deoiler ISF, DNF or IGF
Optional
Emulsion Breaker
Or Wetting Agent
if needed or treat
only during mud wash
OIL
Solids
Emulsion
Note: Agar Probes can be installed in tank
to better monitor oil/emulsion interface
Max Oil: 500 ppm
Max BSW: 0.5%
Cationic Flocculant
(Spectrafloc Product)
Solids to Roll off box
Or Coker
Centrifuge

(ISF, DNF, or IGF)
Reverse Emulsion
from Cone Bottom Tank
Cationic Coagulant
Blend
BPW 76030
Anionic Flocculant
(Spectrafloc Product)
Solids to Centrifuge
Max Oil: 25 ppm
Effluent to API
or Equalization
Skim oil to Oily Sludge Thickener
then Centrifuge Feed Tank
•Designated desalter brine effluent flotation vessel
advantages
– Effluent can the be sent to benzene stripper for NESHAP
conformance with little to no fouling potential
– Reduces insoluble COD/BOD
– Reduces overall organic loading to wastewater treatment
plant
– Excellent point source control measure
– Treats only the emulsified portion of the desalter brine

Desalter # 3 Brine Testing
Blank
O&G 776 ppm
BPW 76030
@ 20 ppm
O&G 32 ppm
BPW 76091
@ 20 ppm
BPW 76453
@ 20 ppm
3 minutes Rapid Mix
5 Minutes 40 RPM
5 Minutes Settle
Note: 1.0 ppm SPC-880 added @ start of slow mix
Typical Refinery
Wastewater Treatment Layout
CPS ISF AERATION
“A”
AERATION
“B”
AERATION
“C”
CLARIFIER
CPS ISF
EQ
EQ
Process/Storm
Water
Deoiler
ISF
Desalter Effluent
OILY WATER ( 400 gpm)Coagulant
@ 30 - 50 ppm
Flocculant
@ 3.0 ppm
CLARIFIER
CLARIFIER
WASTE
TO SLUDGE
THICKENER
PST
SKIM
Reroute PST
supernatant
Deoiler
Break
Tank

BLANK BPW 76030
@ 20 ppm
BPW 76030
@ 30 ppm
BPW 76030
@ 40 ppm
WEST COAST REFINERY
WWT JAR TESTING
DEOILER ISF
3 MINUTES @ 100 RPM
5 MIN. 40 RPM
5 MIN. SETTLE
Note:All jars treated with 0.5 ppm SPC-880 during slow mix
WEST COAST REFINERY
Brine and WWT ISF Trial Samples
5600 NTU 337 NTU 125 NTU 7.6 NTU
Break Tank
Effluent
Desalter ISF
Effluent
Equalization
Effluent
WWT ISF
Effluent To Bioreactors
Polymer Treatment Level
BPW 76030 @ 120 ppm
Spectrafloc 880 @ 7.0 ppm
Polymer Treatment Level
BPW 76030 @ 50 ppm
Spectrafloc 880 @ 5.0 ppm

WASH WATER TARGETS
KPI's DESALTED CRUDE TARGETS
#N/A BPD BPD KPI's
#N/A % % SALT: #N/A PTB PTB
#N/A pH: pH: BS&W: #N/A % %
SALT REMOVAL: #N/A % %
CRUDE RATE CHARGE
KPI's
CHARGE RATE: #N/A BPD
API GRAVITY: #N/A
SALT: #N/A PTB
FILT SOLIDS: #N/A PTB
BS&W: #N/A %
EFFLUENT TO BIOREACTORS TARGETS
KPI's
EFFLUENT BRINE TURBIDITY #N/A NTU's NTU's
KPI's O&G #N/A ppm ppm
Visual Quality Index #N/A 1 - 5 TSS #N/A ppm ppm
O&G #N/A ppm COD #N/A ppm ppm
TSS #N/A ppm
DE-OILER EFFLUENT TARGETS
KPI's
TURBIDITY #N/A NTU's NTU's
O&G #N/A ppm ppm
TSS #N/A ppm ppm
#REF!
BRINE DE-OILER AND WWT ISF
Polymer Dosage Model
DESALTER
CPS ISF
ISF
EQ
MIXED
EQ
MIXED
Deoiler
CPS
Deoiler
ISF
PST
SKIM
Process
& Storm water
1200 GPM
CPS
1 2 3 4 5
Brine Effluent Visual Quality Index
Desalter Brine Effluent 400 gpm
Advanced Brine Treatment Unit
Raw Crude
Fresh Washwater
Desalted Crude
Effluent Brine
Floatation Units
Three Phase
Centrifuge
Off Spec
Tank
Off Spec
Tank
BPW 76001
During mud wash
BPW 76001
BPW 75850
(Metals Removal)
Spectrafloc 875
Effluent to API
BPW 76453
Float
Target
> 500 mg/l O&G
> 500 mg/l TSS
Solids to thermal
desorption
Dirty Brine
3000-4000 mg/l O&G
250-500 mg/l TSS
Mud Wash Brine
1.5 – 2.0 % O&G
2000 - 3000 mg/l TSS
Oil to slop
Water to API
2nd stage effluent brine to 1st stage
Spectrafloc 875

D200 Brine Vanadium Removal Testing
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04
0.045
0 1 2 3 4 5 6 7 8 9 10
Samples
mg/L
Total V Dissolved V
Brine Treatment Unit Metals Removal Test Results
Sample Products
Dose of Metals
Precipitant
Total
Vanadium
Dissolved
Vanadium
Numbers Samples mg/L mg/L mg/L
1 Blank 0 0.041 0.027
2 Polymer 0 0.0092 0.0074
3 TR6 50 0.0013 0.0016
4 TR6 100 0.0018 0.0012
5 TR6 200 ND ND
6 75850 50 0.0011 ND
7 75850 100 0.0058 0.0039
8 75823 50 0.0029 0.0023
9 75823 200 0.0018 ND
Blank
Polymer
Only
Raw Data
Polymer
& TR6
Polymer
& BPW 75850
Polymer
& BPW 75823
Conclusions
• Heavy crude oils typically produce poorer quality brine
• Solids and asphaltenes affect
– Emulsions in desalter
– Oil carryunder
• Optimize desalter to improve effluent quality
• Chemical treatment to minimize oil carryunder
• Brine requires treatment prior to equalization

Baltimore Marriott Waterfront Hotel
October 13, 2010
Presenters:
Kerlin Lobo
Larry Kremer
Simon Cornelius
Baker Hughes Incorporated

Our Baker Petrolite XERIC heavy oil program enables you to process
higher rates of heavy, high solids and high asphaltene crude oil blends
for improved feedstock flexibility and plant profitability.
 Maintains desalter operational stability while providing desired
dehydration and salt/solids removal efficiency
 Reduces oil recovery costs by reducing the amount of oil loss from
desalter operations
 Prevents wastewater treatment plant upsets by lowering desalter
effluent water oil content
 Controls expenses related to wastewater plant chemical treatment
by improving influent water quality
✓✓ = check first ✓ = check second
*Water level should be kept as high as practical, generally 1-2 ft below the bottom grid for PETRECO®
desalters.
Baker Petrolite Desalter Operating Guidelines
Feedstock flexibility equals refining profitability
©2010 Baker Hughes Incorporated. All Rights Reserved. 28888
XERIC is a trademark of Baker Hughes Incorporated.
High BS&W
in Desalted
Crude
High Oil
Undercarry
Wide
Interface
High Amps,
Low Volts
High Salt
Carryover with
High Water
Carryover
High Salt
Carryover with
Normal Water
Carryover
Items to Check
Typical
Range
✓ ✓✓ ✓✓ ✓✓ ✓✓ ✓ Crude change/crude tank switch?
✓ ✓ ✓ ✓ ✓ Poor wash water quality/high pH? pH 6.0-7.5
✓ ✓ ✓✓ Low wash water rate? 4-8%, typ. 5%
✓ ✓✓ ✓✓ ✓ ✓ Poor quality/high quantity of slop oil?
✓✓ ✓✓ ✓✓ ✓✓ ✓✓ Desalter mix valve DP high? 2-25 psig
✓✓ ✓✓ Desalter mix valve DP low? 2-25 psig
✓ ✓ ✓ ✓ Demulsifier rate high?
✓ ✓✓ ✓ ✓ ✓ Demulsifier rate low?
✓ ✓✓ ✓✓ Water level high? *
✓✓ ✓
Water level low?
Water residence time low?
125-165
minutes
✓✓ ✓✓ ✓✓ ✓✓ Desalter level controller operating OK?
✓ ✓ ✓ ✓ Desalter back pressure fluctuating?
✓ ✓ ✓ ✓ Cycletric®
desalter distributor DP OK? 3-7 psig
✓ ✓ ✓ ✓ ✓ Desalter temperature OK? 240-300ºF
✓ Desalter pressure low?
✓ ✓ ✓ Crude rate increased?
✓✓ ✓✓ ✓✓ Electrical system OK?

Reprinted from HYDROCARBON ENGINEERING AUGUST 2004
A
s an oil refinery repeatedly fills and empties crude stor-
age tanks, over time paraffin wax, asphaltenes, emul-
sified water and solids settle in the storage tank as
sludge. Depending on the quality of the crude oils and the
length of time the tank has been in storage, this sludge accu-
mulation can be from several centimetres to over one metre
deep.
Baker Petrolite has developed crude oil tank pretreatment
programs that recover trapped oil in
the accumulated sludge and reduce
the sludge volume by as much as
90%. The treatment program can
reduce a refinery’s total cost of oper-
ation by several millions dollars, pro-
viding the following benefits:
Reduced tank turnaround time
for inspection and maintenance.
Increased usable storage capac-
ity.
Recovery of unusable hydrocar-
bon inventory.
Reduced storage tank cleaning
and maintenance costs.
Reduced sludge disposal costs.
Fewer crude unit desalter
upsets.
These chemical treatment programs are conducted while
the crude storage tanks are in use, so no service interruptions
are necessary to achieve reductions in tank sludge levels.
Crude characteristics and tank farm
sludge formation
Crude oil is a mixture of hydrocarbons with boiling points rang-
ing from -100 ˚C to 800 ˚C. There are hundreds of different
crudes produced in the world today. The distillation character-
istics and contaminant levels vary from crude to crude.
Crude oil is most often produced as a water-in-oil emul-
sion containing large quantities of dissolved salts and sus-
pended solids. The salts are mostly chloride, sulfate and car-
bonate salts of calcium, magnesium and sodium. The solids
are typically silt, sand, clay, iron oxides, and iron sulfides.
Crystalline salts may also be present.
These contaminants frequently
arise from several sources:
Brine contamination as a result
of the brine associated with the oil in
the formation.
Most minerals, clay, silt, and
sand found in the formation around
the oil well bore.
Iron sulfides and oxides as a
result of corrosion during produc-
tion, transport and storage.
Polar molecules in the oil can
act as emulsifiers, adsorbing to the
oil/water interface. These polar
compounds may include
asphaltenes, resins, oxygenated
sulphur and nitrogen compounds,
porphyrins, waxes, organo-metallic salts and organic acids.
They have a lipophilic (oil loving) portion which tends to be
soluble in hydrocarbons such as crude oil, and a hydrophilic
(water loving) portion that tends to be soluble in water.
These stabilisers, when concentrated, have a mutual
attraction, which results in an elastic and sometimes tough
and viscous film around the water drop. Figure 1 shows how
the polar molecules are oriented in the interfacial area sur-
rounding a water droplet suspended in a continuous oil
Crude Oil Tank
Sludge Treatment
Mark Preston, Paul Martin and Scott Bieber, Baker Petrolite, USA, discuss a chemical
treatment program for reducing the amount of sludge accumulation in tank storage.
Figure 1. Graphical depiction of an
emulsified water droplet in crude oil.
77-80 30/9/04 8:52 Page 77

phase. Finely divided solids also collect at the liquid-liquid
interface leading to a minimum interfacial area and further
stabilisation of emulsions.
Crude can also become contaminated during shipping.
For example, solids can be picked up in pipelines and termi-
nal storage facilities or the oil can become
contaminated with sea water ballast in
ocean-going vessels. Waste oils and other
unknown chemicals can also be added to
the crude at the production site or during
transportation without the refinery’s knowl-
edge.
As crude oil is pumped into refinery stor-
age facilities emulsified water, solids, paraf-
fin wax and destabilised asphaltenes start to
settle to the bottom of the crude tanks. Even
if crude oil is low in BS&W (basic sediment
and water), large amounts of sludge can be
formed. For example, 1 million bbls of crude
containing only 0.01% BS&W could repre-
sent over 10 t of potential sludge.
The final composition of
storage tank sludges varies
widely, but typically contains
tightly emulsified oil and water,
stabilised by solids. Sludges
can contain both oil in water
and water in oil emulsions.
Solids that stabilise such emul-
sions include inorganic materi-
als such as sand, silt, clay,
metal oxides, metal sulfides
and organic materials such as
precipitated asphaltenes and
insoluble paraffins.
The amount of sludge that
accumulates in the tank bot-
tom depends on several fac-
tors:
Amount and nature of
solids in the crude.
Compatibility of crudes blended in the storage tank.
Degree of emulsification of water in the crude oil.
Transfer activity and residence time of crude oil in the tank.
Number, condition and operational practices for any tank
mixers.
Tank water draining practices.
Sludge profiles of crude tanks show sludge levels from
several centimeters to over a metre in depth. This translates
into hundreds and thousands of tonnes of sludge. Over time
the trapped hydrocarbon can undergo oxida-
tion and polymerisation reactions, forming
very viscous tank bottom deposits.
During receipt of a new crude some of the
sludge sloughs off and is suspended into the
crude phase. If the tank is fed to the crude unit
without sufficient settling time, the suspended
tank bottom sludge is also fed to the crude
unit. This disturbance of the sludge layer can
cause desalter upsets and can even con-
tribute to episodes of water carryover out of
the desalters.
Figure 2 shows untreated crude oil, high in
emulsified water and solids. Solids can be
seen adhering to the sample bottle surface
above the crude oil.
Tank sludge
reduction
Sludge reduction involves
chemical treatment of the
sludge to achieve removal,
rupture, or counteraction of the
emulsifiers, coalescence of the
emulsified water droplets, and
gravitational separation of the
oil and water phases. Figure 3
shows a crude oil sample
viewed through a microscope
with water droplets emulsified
into oil. Notice the solids
adhered to the water droplets’
surface.
Baker Petrolite has devel-
oped a range of chemistries
that water wets the solids and
adsorb at the oil-water interface, where the chemicals spread
with sufficient pressure to displace the natural emulsifying
agents from the interfacial area. This leaves an interface cov-
ered or partially covered with a very thin film which offers little
resistance to coalescence and break out of free water and
Figure 4. Typical sludge reduction chemical injection system.
Figure 2. Untreated crude
oil containing dispersed-
solids and water droplets.
Figure 3. Photomicrograph of solids-stabilised
water droplets in crude oil.
77-80 30/9/04 8:52 Page 78

release of trapped hydrocarbon. The zeta potential on the
water droplets is reduced, allowing the water droplets to coa-
lesce and eventually separate from the oil phase.
The application of a Baker Petrolite chemical program for
tank sludge reduction is very straightforward. Sludge reduc-
tion chemical is typically injected into the crude being dis-
charged into the refinery crude (Figure 4). Several different
additive injection methods have been
implemented that automate the control of
chemical dosing into the crude oil being
transferred.
As the treated crude enters the tanks,
sludge is picked up by the shearing force
of the incoming crude and is mixed with
the chemically treated crude oil.
Figure 5 shows a crude sample taken
from the bottom of a refinery tank
untreated in the left hand tube and treated
in the right hand tube. The sludge content
of the untreated sample was 12%.
Chemical treatment separated approxi-
mately 6% hydrocarbon, 6% water and
0.05% solids from the crude oil.
When incoming crude oils are treated
to reduce tank sludge levels, the sepa-
rated water and mostly inorganic solids
settle to the bottom of the tank. The
released water and some of the solids
are then removed via the tank bottom
drains. Recovered hydrocarbon is
absorbed into the crude oil. Exposure of
tank bottom sludge to this treated crude
oil slowly reduces the level of sludge in
the tank. Over a period of weeks to
months, significant reductions in sludge
volume can be achieved.
Economic benefits
Proper management of the crude oil stor-
age system, including the use of a crude
oil pretreatment program, can have sig-
nificant impact on refinery profitability and
the efficiency of downstream operations.
Reduced tank bottoms sludge
accumulation
Reducing the amount of sludge in the
bottom of crude oil tanks provides sev-
eral direct benefits for tank farm man-
agers:
Reduced tank turnaround time for
inspection and maintenance.
Increased usable storage capacity.
Recovery of unusable hydrocarbon
inventory.
Reduced storage tank cleaning and
maintenance costs.
Reduced sludge disposal costs.
Case history one: Asia Pacific
refinery
Application
Baker Petrolite conducted a trial using a chemical surfactant
to pretreat the sludge in tank T-1 prior to this tank being taken
out of service for maintenance. Tank sludge level measure-
ments were made on 8th
November prior to treatment and
then measured again on 25th
May prior to coming out of ser-
vice for maintenance. It was found that the quantity of sludge
had been reduced from 322 to 46 t. Treatment was via injec-
tion of chemical into crude receipts charged to T-1.
Results
In the past, sludge removal took up to 30 days per tank. By
treating the tank with Baker Petrolite demulsifier, the quantity
of sludge that needed to be removed
from the tank, treated and disposed of
was reduced by 86%. The cost savings
for this treatment are broken down as
follows:
Cost to remove sludge from the tank:
US$ 500/t
Cost for disposal:
US$ 90/t
Total cost of sludge removal:
US$ 590/t
Untreated tank sludge removal/dis-
posal:
322 t x US$ 590/t =$US 189 980
Treated tank sludge removal/disposal:
46 t x US$ 590/t = $US 27 140
Cost savings to refinery by chemically
treating tank T-1:
US$ 162 840
The total cost of chemical treatment
was less than 10% of the cost savings
due to sludge reduction. Additionally,
the time required to remove the remain-
ing solids from the bottom of the tank
after treatment was reduced from
approximately 30 days to 5 days.
Other benefits within the tank
farm area
Reduced oil loss from tank
draining operations
When water is drained from an
untreated crude tank there can be large
oil losses, as the oil/water interface can
be very indistinct, with water emulsified
into the crude oil phase and oil emulsified
into the water phase. Tank farm pre-
treatment resolves these emulsions pro-
ducing a sharp oil/water interface and
relatively oil free water. This reduces the
hydrocarbon loading in the refinery
waste water treatment system.
Figure 6 shows water drained from
storage tanks containing the same ship-
ment of crude oil, with one crude tank
untreated and the other treated with a
Baker Petrolite crude treatment chemical
program (Figure 4).
Improved custody transfer measurements
Crude pretreatment programs provide faster and more com-
plete separation of oil and brine in the crude storage tanks. As
a result, crude pretreatment has been used successfully to pro-
vide more accurate gaugings of tank inventories when custody
transfer volume measurements are made. This program fea-
ture can significantly reduce the refinery’s payments for crude
receipts that are based on these measurements, since emulsi-
fied water that can be separated in tankage will not be counted
as oil.
For example, if an extra 0.05% of crude oil water
Figure 5. Untreated (left) and
treated crude tank bottom sludge.
Figure 6a. Crude tank water draw,
untreated.
Figure 6b. Crude tank water draw,
treated.
77-80 30/9/04 8:52 Page 79

content can be released from a
1 million bbl shipment of crude
oil valued at US$ 35.00 per bbl,
the price for this shipment would
be decreased by 1 000 000 x
35.00 x 0.0005, or US$ 17 500.
Improved crude unit
operations
Proper crude oil pretreatment pro-
grams can also reduce the fre-
quency of water slugs in the feed
to the crude unit. These applica-
tions will also help reduce the raw
crude salt, solids and sludge con-
tent. This enables the crude unit
desalter to be run at optimum con-
ditions with higher mix valve settings, reduced desalter chemi-
cal dosage and higher interface levels. The end result is often
improved system salt removal efficiency, less oil in the desalter
effluent and reduced desalter chemical costs.
Case history two:
Tank pretreatment improves
desalter operation
Application
A US refinery processing 16˚ API San Joaquin Valley (SJV)
crude was experiencing several percent oil under-carry in the
crude unit desalter operation. It was determined that solids
coming in from the crude oil storage tanks were insufficiently
water wetted, so that the oil laden solids in the emulsion were
being carried into the desalter effluent water. It was determined
that by injecting a tank pretreatment chemical into the SJV
receipts going to the storage tanks,
and by providing continuous mixing
on the tanks, the solids could be
preconditioned so that they could
be more easily removed in the
desalter, without causing oil carry
under.
Results
The reduction in oil carry under
achieved with the tank pretreat-
ment program was dramatic. The
improvement in tail water quality
was immediately apparent by
visual comparison of brine samples
from the desalter. Without treat-
ment the desalter tailwater typically
had 2 - 5% oil. When the tank farm pretreatment program was
in use, the brine typically had a trace to 0.5% oil. Results are
shown in Figure 7.
This treatment program greatly reduced the loading on the
refinery waste water treatment system and slop oil recovery
system. In addition, it has also reduced the demand for chem-
ical emulsion breaker used at the desalter.
Conclusions
Chemical treatment programs have been developed that
reduce sludge levels in crude oil storage tanks while they
are in service. Chief economic benefits include reduced
time for tank maintenance, lower sludge disposal costs
and better quality raw crude charged to the crude unit.
Crude tank pretreatment provides many potential sec-
ondary benefits, including fewer crude unit upsets, better
desalter operation, less crude unit preheat system fouling
and improved crude unit corrosion control.____________
Figure 7. Pretreatment of SJV crude oil
reduces desalter effluent water oil content.
World Headquarters
12645 West Airport Blvd.
Sugar Land, TX 77478
P.O. Box 5050
Sugar Land, TX 77487-5050
Tel: +1-281-276-5400
Toll: +1-800-231-3606
Fax: +1-281-275-7395
Eastern Division
Kirkby Bank Road
Knowsley Industrial Park
Liverpool L33 7SY
United Kingdom
Tel: +44-151-546-2855
Fax: +44-151-549-1858
77-80 30/9/04 8:52 Page 80

T
he biggest variable input into the
refinery process is the variation in
crude oil quality. Variations in
crude oil quality can affect finished
product quality, environmental dis-
charges, corrosion, heat balance on the
units, catalyst performance, potential
safety issues, and the time before
required maintenance. Yet, most crude
oil is bought and sold on the basis of
density (API gravity), sulphur content,
and water content (BS&W, or basic sedi-
ment and water), which are insufficient
to predict most of these problems.
The definition of what constitutes
crude oil can vary widely. Crude quality
refers to the properties and components
of the crude oil that affect processing
and the products that can be refined
from the crude oil. Numerous standard
and non-standard tests have been devel-
oped to measure various aspects of crude
oil quality. The impact of these quality
characteristics can vary widely depend-
ing on the design of the units and the
robustness of the processes. For example,
some but not all crude units are
designed to handle sour crude oil. It is
important to identify crude oil quality
standards suitable for a specific refinery,
monitor these characteristics and design
and implement strategies to handle vari-
ations from the quality standards.
While it is critical to fully characterise
any new crude oil brought into the
refinery, the discussion of the oil supply
chain will show that there are many fac-
tors introducing variation into the crude
oil that the refiner may have been pur-
chasing for years. For example, gravity
may vary by one or two API units from
the last published assay. Published
assays may be based on pilot plant data
or test well samples. With time, the
quality of oil flowing from a well may
deteriorate. In addition new producing
oil wells may be put on line, which are
then blended into the currently pur-
chased crude oil.
The published assays should be
viewed as typical properties. In addition,
the standard assays do not list many of
the operational characteristics, such as
fouling tendency, corrosivity, emulsion
forming tendency, or environmental
impact.
Crude oil supply chain
There are many parties involved in the
supply of crude oil to the refining
industry. Producers are primarily inter-
ested in minimising their exploration
and production (E&P) costs and maxi-
mising their production. They are not
primarily interested in meeting the
quality expectations of the refinery.
Rather, they must meet the quality stan-
dards set by the shipper and the trader
who purchases the crude oil. Crude
quality issues are often negative for
crude oil traders, who may have to
reduce the price of the crude oil to the
refinery because of quality issues, or in
some cases “fix”" the crude oil before a
suitable buyer can be found.
The shipper often finds itself in the
middle of disputes between producer
and refinery. For this reason it often has
extensive quality control (QC) pro-
grammes to protect itself. Shippers also
set specifications on crude oil that they
will accept. For example, ships and
barges often set limits to the amount of
hydrogen sulphide (H2S) in the crude oil
and pipelines often set specifications on
viscosity, pour point and water content
(BS&W). In any case, refineries need to
set quality expectations suitable to their
operation.
The crude oil processed by the refin-
ery is necessarily a blend of crude oils
from different wells, from different for-
mations, and often different geographic
locations. Many production facilities
have such low rates that they must
blend their crude oil with production
from other areas to form a marketable
crude oil with a name recognisable by a
refinery. As crude oil is transported it
may be placed in temporary storage in
tanks at terminals in the supply chain.
There is always a heel in the tanks from
previous cargoes that is then blended in
with the current batch.
For handling purposes, a shipper may
have gravity or viscosity specifications
on crude oil that it transports. To meet
these specifications, producers will cut
the crude oil with diluents to lower the
viscosity and density of the crude oil.
Condensate is a commonly used dilu-
ent. However, in some regions, conden-
sate has become so scarce that other
diluents such as refinery cracked stock
and butane have been used. The cracked
stock can contain olefins that could
cause fouling or quality problems with
straight-run products. The butane pro-
duces so-called dumbbell crudes that
have larger-than-expected light ends
and residual material and lower-than-
expected middle cuts.
Changes during transportation
Several factors can change crude oil
quality during transportation. For this
reason the quality of the crude oil
received by the refinery may differ from
the quality of the oil produced in the
field. Degradation during normal hand-
ling can affect quality. As previously
mentioned, tank heels from previous
cargoes can contaminate new crude oil
placed in a tank. Small amounts of
material are left on the walls of
pipelines, and subsequent cargoes can
pick up these contaminations.
Pipelines transport crude oil in batches.
Some mixing at the interface between
two pipeline shipments is inevitable.
One estimate of the interface size is
1500 barrels, provided there are no
problems with the shipment. To min-
imise this cross contamination,
pipelines prefer to schedule large vol-
ume shipments and try to keep similar
cargoes back-to-back.
Some corrosion is inevitable in the
handling of crude oil and this too can
be incorporated into shipments, pri-
marily as particulate iron oxide and
iron sulphide. Crude transported by
ships or barges can become contaminat-
ed with various brines and slops. Ship-
pers try to minimise all these forms of
degradations.
Altering crude before receipt
There are many additives that are used
Crude oil and quality
variations
An assessment of the impact of crudes on operational and product quality, with
an explanation of the way in which the crude oil supply chain, combined with
the sources of many crude constituents, affects production
Larry N Kremer
Baker Petrolite Corporation
REFINING
P TQ AUTUMN 2004
w w w. e p t q . c o m
1
Crude Oil article4.qxd 9/15/05 8:01 AM Page 1

2010 npra seminar, fundamentals of desalter operation

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