Confidential 1
Chemical Foamers For Gas Well Deliquification
Training Workshop
Presented by: Duy Nguyen
Martin J Willis
European Gas Well Deliquification Conference
Groningen, Netherlands, Sept 2009
Essential Expertise for Water, Energy and AirSM
Workshop Contents
�Theory of Foam
�Foamer Chemicals
�Laboratory Testing
�Application in the Field
�Summary
Confidential 2
Basic Foam Theory
� Physics of foam
� in “close-up”
� at a molecular level
� How foam is stabilised
� Role of surfactants
Foam
�Why is High Foam Desirable ?
� Seen as evidence product is working
� ie. Shampoo, dishwashing liquid
� Indicates where product has been applied
� ie. Shaving foams, abattoir cleaners
� High expansion ratio
� Fire fighting foams
� Reduced liquid density and reduced surface tension
� i.e, gas well deliquification
Confidential 3
Soap – We Use It Everyday!
�Daily used surfactant
�Definition:
�Foam is a dispersion of gas in liquid and is caused by agitation and surfactant
Images courtesy of “google images”
Foamer Chemicals
� Surfactants typically applied to aqueous systems
� Reduce surface tension
� Decrease relative density
� Increases elasticity
� Allows gas/liquid dispersion at a lower gas pressure.
� In the lamellar condensate is trapped
� The benefits
� Reduces the critical velocity of the well
� Enables liquid unloading with low set-up cost
� Customised for local environment
� Facilitates continuous production
� Reduces well decline curve
LIQU
ID
GA
S
GA
S
Confidential 4
Dynamic Surface Tension Apparatus
2)( max rPP
o−
=γ
Dynamic Surface Tension Data
10.2% NaCl and 3.7% CaCl2.2H2O
20.00
25.00
30.00
35.00
40.00
45.00
50.00
55.00
10 100 1000 10000 100000Time (milliseconds)
Su
rfa
ce
Te
ns
ion
(m
N/m
)
Betaine at 400 ppm
Alkyl Ether Sulfate at 400 ppm
Olefin sulfonate at 400 ppm
Confidential 5
Correlation Between Max DST Reduction Rate & % Liquid Unloading
R2 = 0.95
40
45
50
55
60
65
70
75
80
400 500 600 700 800 900 1000
DST Reduction Rate, dyne/cm.s
% U
nlo
ad
ing
Olefin sulfonate
Alkyl ether
sulfate
Betaine
Conditions: 400 ppm active surfactant in 10.2% NaCl and 3.7% CaCl2.2H2O, 0% condensate
Foam Life Cycle
� Gas forms spheres in
liquid.
� Honeycomb with thick
lamellae between cells.
� Liquid drains into
junctions leaving thin
lamellae between cells.
Surfactant Properties - Foam
Formation
Confidential 6
Pure Liquids Don’t Foam
Gas
Gas
Liquid
Gas
Gas
Liquid
Gas
Liquid
. . .
When the Bubbles Collide .....When the Bubbles Collide .....
Film stabilisation
Foam drainage
.... .... they “unload” waterthey “unload” water
Confidential 7
Low Gas VolumeLow Gas Volume
Foam
Drainage
High Gas VolumeHigh Gas Volume
Polyhederschaum
Two Types of Foam
Foam Drainage Leads to Collapse
Caused by
Plateau
Border
Lamella
PolyhederschaumKugelschaum
� Gravitational force
� Capillary pressure
� Diffusion of gas
� Bursting of bubbles
� Rearrangement of lamellae
drainage
Confidential 8
Gas Permeability & Bubble Growth
Gas
Gas
Liquidr1
r2
. . . Also leads to foam collapse
Film Elasticity .......
...... makes them stretchy!...... makes them stretchy!
Confidential 9
FOAM STABILIZATIONFOAM STABILIZATIONFOAM STABILIZATION
PLATEAU BORDER FORMED FROM INTERSECTION OF 3 OR MORE FOAM CELLS
PLATEAU BORDER FORMED FROM INTERSECTION OF 3 OR MORE FOAM CELLS
SURFACTANT STABILIZATION OF FOAM LAMELLAE
SURFACTANT STABILIZATION OF FOAM LAMELLAE
Liquid flows
Liquid flows
Liquid flows
Marangoni Effect
-
-
-
-
- -- -
- -
- -- -- -
Viscous drag
Liquid flow
Viscous drag
Liquid flow
Surface tensionrestoring force
����
--
-
-
-
-
-
Micellarreservoir
Drainage -
The dynamics of rapid diffusion needed to restore and maintain film elasticity . . .
Confidential 10
Foam Stability: Area per molecule
Packing at the air-liquid interface
Air Air
Liquid Liquid
• Unstable foam
Loosely packed film Tightly packed film
- High area per molecule - Small area per molecule
- Low degree of packing - High degree of packing
• Stable foam
Area
FOAMFOAM
ElasticityElasticity Degree of packingDegree of packing
Confidential 11
Foam
�Foam stabilisation is thought to occur via the following mechanisms:
� Increasing elasticity of the foam film
�Slowing drainage of liquid in the lamellae
�Decreasing the diffusion of gas across the lamellae
� Increasing the thickness of the electrical double layer
� Increasing the surface and bulk viscosity of the foam film
Foam Inhibition
�Disruption of interfacial film structure
�Displacement of stabilising surfactant
�Poor interfacial orientation
�Spontaneous spreading of oils
�Low surface tension liquids
�Positive spreading coefficient
�Physical rupture of lamellae
�Waxy or hydrophobic particles
�Oil droplets and inverse micelles
Confidential 12
Configuration of Oil at the Air-liquid Interface
Oil Water
Air
Oil drop inside the solution
Oil
Pseudoemulsion Film
Oil drop at the surface separated by a pseudo-
emulsion film from the air
Oil
Oil drop enters the gas phase and forms lensOil spreads at the solution surface
and ruptures the bubble
Mechanisms of Foam Break Degradation
� Coalescence
� The flocculated foam cells form larger bubbles due to thinning and
rupture of the lamellae separating the bubbles. Usually occurs as a result of thinning due to prolonged drainage
� Gravitational separation
� Rise of bubbles through foam mass, while liquid is draining due to gravity through lamellae and plateau borders between bubbles
� Disproportionation
� The gas inside the bubbles diffuses across the foam lamellae, from areas of high pressure - small bubbles to areas of lower pressure -large bubbles
Confidential 13
Foam
�What does a foam modifier/booster do ?
�Product that acts synergistically with another product to increase volume of foam
�Product that stabilises the foam to prevent breakdown of the foam structure
� Improves appearance of a foam
� i.e. creamier appearance
Foam
�Additives for foam stabilisation
�Organic compounds
� Polymers
� Surface active materials
� Biopolymers
�Electrolytes
�Finely divided particles
Confidential 14
Foam
�Effect of addition of foam stabiliser
� Increases packing density at air/water interface
�Cause charge shielding of charged surfactant
�May interact with charged surfactant
�May reduce the CMC
Foam
�Commonly used foam stabilisers
�Fatty alcohols
�Amine oxides
�Betaines
�Alkanolamides
Confidential 15
Typical Chemicals
� Nonionic � More soluble at lower temperature
� Increase temperature &/or salt concentration reduces solubility – lowers cloud point
� Good for wells with unknown water chemistry
� Anionic� Excellent aqueous foamers
� Highly polar
� Can be affected by high brine solutions
� At elevated temperatures can degrade
� Cationic � Good for foaming water/oil mixtures
� Efficacy dependant on molecular weight
� Can be prone to emulsion issues
� Amphotheric� Very versatile
� Good high temperature performance and stability
� Effective in high salt content brines
R
SO3Na
α-olef in sulfonate
R
O
SO4Nan
Alkyl ether sulfate
R
SO3Na
α-olef in sulfonate
R
SO3Na
α-olef in sulfonate
R
O
SO4Nan
Alkyl ether sulfate
R
O
SO4Nan
Alkyl ether sulfate
R NH
NO Na
OCH3
CH3 O
-+
Cocoamidopropyl betaine
R NH
NO Na
OCH3
CH3 O
-+
Cocoamidopropyl betaine
Combination Products
�Formulating additional actives into foamers
�Corrosion inhibitors
�Scale inhibitors
�Biocides
�Paraffin inhibitors
�etc
�Facilitates easier chemical programs
�Less inventory
�Reduce exposure risks
�Saves on pumps, storage and freight
Confidential 16
Foam
�Selection of surface active foam stabiliser
�Type of foam to be stabilised
� Charged
� Nonionic
�Structure of surfactant hydrophobe
� Alkyl chain length
� Branching on alkyl chain
�Presence of polar entities capable of forming multiple hydrogen bonds
�Ability to lower the CMC
Foamer Chemical Requirements for Gas Well Deliquification
� Provide foam stability to carry liquids to surface
� Thermal stability
� Fluid compatibility (chloride, solids,..)
� Ability to unload hydrocarbon
� Break at surface before entering surface equipment
� Delivery (batch, continuous)
� Winterized
Confidential 17
Chemical Solutions
�Solid state� Dropped downhole to find aqueous environment
� Dissolve in the liquid
� Foam when liquid and gas mix
�Liquid Foamers� Delivered by various means at targeted locations
� Already in liquid state, so require less soak time
� Foam when liquid and gas mix
Foaming Technology
Yesterday, foamer selection was a lot like fishing. It was
an art.
Yesterday Today Tomorrow
Investigation of key factors that govern the foaming performance and foaming
mechanisms.*To be published in “Petroleum Science and Technology”
Journal
Modeling and prediction of foamer performance: a
proactive approach
Confidential 18
Factors That Influence Foaming
A 25 Factorial Design ( a 2 level with 5 factors) with two replicates (64 experiments)
Performance Response: % Unloading
Temperature 25oC 70oCOil 0 % 50% Chloride 2.4% 8%Foamer dosage 400ppm 1000 ppmOil type cycloalkane aliphatic
Factors Levels
Temperature 25oC 70oCOil 0 % 50% Chloride 2.4% 8%Foamer dosage 400ppm 1000 ppmOil type cycloalkane aliphatic
Factors Levels
Design Of Experiment
FOAM
FOAM
TemperatureTemperature ChlorideChloride % Oil% Oil
Confidential 19
Design Of Experiment
FOAM
FOAM
Foamer DosageFoamer Dosage Oil TypeOil Type
Cycloalkane
Aliphatic
FOAM
FOAM
Prediction of Foamer Performance
Predicted vs. Actual % Unloading
2222
Actual
Predicted
-11.08
14.33
39.75
65.16
90.58
-11.08 14.33 39.75 65.16 90.58
R2 = 0.917
Confidential 20
Conclusions
�Prediction and modeling of foamer performance with confidence
�A proactive approach to manage program
�“No touch” foaming testing
�Quick response when process variables change
�Foamer mapping
Laboratory Testing
Confidential 21
Laboratory Testing
� Standard Laboratory Testing
� Standard performance tests� ASTM D-3601 - Foam in Aqueous media (Bottle Test)
� ASTM D-3519 - Foam in Aqueous media (Blender Test)
� ASTM D-892 - Column/Cylinder Test Method (Dynamic Test)
� Specialised performance test
� Unloading rig
� Injection systems
� Well simulators
� Customer tests
� Example Protocol
Standard Chemical Testing
Product
Recommendation
Density
Ecotox Environmental
Profile
Flash Point
Thermal Stability
Materials Compatibility
Viscosity Profiles
Emulsification Tendency
Defoamer Compatibility
Chemical Compatibility
Product
Recommendation
Product
Recommendation
Density
Ecotox Environmental
Profile
Flash Point
Thermal Stability
Materials Compatibility
Materials Compatibility
Viscosity ProfilesViscosity Profiles
Emulsification Tendency
Emulsification Tendency
Defoamer Compatibility
Chemical Compatibility
Confidential 22
ASTM D-3601 (Foam in Aqueous media -Bottle Test)
� Quick and cheap test
� Established for aqueous, low viscosity system
� Using low shear to generate foam
� Some foamers are prone to perform better under shear rather thangas flow
� If high shear required use the blender test
� Result is a comparison of foam height and nature versus a control
ASTM D-3519 (Foam in Aqueous Media - Blender Test)
� Data Collected
� Foam Height
� Foam Life
� Drainage Half Life
� Foam characterization under high shear conditions
� Hydrocarbon influences difficult to assess due to affect on foam height and emulsification issues
� Some surfactants prone to generate more foam in high shear conditions
Confidential 23
ASTM D-892 & Modifications(Column/Cylinder Test Method – Dynamic Test)
� Data Collected
� Foam height versus Time
� Fluid carry over with given gas rate (0.01–10 ft/sec)
� Foam life
� Drainage half life
� Modifications
� Heating the liquid to provide more representative conditions
� Changes the size of the cylinder – gives different ID
� Still assess the same properties
Dynamic Unloading Rig
% Unloading vs Time
400 ppm active foamer and 75% Condensate
0
10
20
30
40
50
60
70
80
0 2 4 6 8 10 12
Time, min
% U
nlo
ad
ing
Novel Nalco Foamer (patent pending)
Traditional Foamer
timeFoam >1000ml
% Unloading vs Time
400 ppm active foamer and 75% Condensate
0
10
20
30
40
50
60
70
80
0 2 4 6 8 10 12
Time, min
% U
nlo
ad
ing
Novel Nalco Foamer (patent pending)
Traditional Foamer
% Unloading vs Time
400 ppm active foamer and 75% Condensate
0
10
20
30
40
50
60
70
80
0 2 4 6 8 10 12
Time, min
% U
nlo
ad
ing
Novel Nalco Foamer (patent pending)
Traditional Foamer
% Unloading vs Time
400 ppm active foamer and 75% Condensate
0
10
20
30
40
50
60
70
80
0 2 4 6 8 10 12
Time, min
% U
nlo
ad
ing
Time, min
% U
nlo
ad
ing
Novel Nalco Foamer (patent pending)
Traditional Foamer
Novel Nalco Foamer (patent pending)
Traditional Foamer
timeFoam >1000ml
100W
W Unloading%
initial
min 15tX
==
αααα-olefin sulfonate Betaine
High condensate
foamer
Carry over
arm
Gas In
Jacketed
cylinder
Foam Stability
Confidential 24
Capstring Injection Performance
�Capstring simulation
�Fitted with atomising nozzle at base of column
�Same principal and output as the unloading rig
Atomiser Performance
Confidential 25
Automated High Pressure & Temperature Foam Column Testing Apparatus
Pakulski M.“AUTOMATED HIGH PRESSURE, HIGH TEMPERATURE FOAM COLUMN TESTING APPARATUS”, Gas Well Deliquification Workshop, Denver, Colorado February 23 -26, 2009
� Lab simulator to make closer comparison to the field
� Temperature
� Pressure
Operator Test ProtocolProcedure for testing foamer performance
200 milliliter tap water (or produced water from a well, or artificial brine based on well water
analyses) is transferred into a 1000ml measuring cylinder (h = +/- 450mm. ∅ = 60mm,) 40ml white spirit, and foamer is added (1000- 5000ppm.) A nitrogen sparge (50l/hr) is applied to the cylinder via a P2 sintered gas dispersion tube. The height reached in the column after 2 minutes bubbling is noted, or the time taken to fill the column up to the 1000ml mark (1.) The gas sparge is removed and for those samples that reached the 1000ml mark and the time taken to collapse to half of the foam column level (+/- 600ml) is noted together with the time taken for the foam to collapse completely. At this stage, any observations regarding the mixture quality are noted (emulsions, solids, water quality, condensate quality.) The nature of the foam is noted. The following observations are noted:
- Foam build up time (s) - Half-life of foam column (or >240 s) - Foam type - Other observations
Foam build-up time
Foam build-up time
Foam build-up time
< 80 s good
80 < x < 120 moderate
> 120 poor
Foam half-life time Foam half-life time
Foam half-life time
< 240 good
60 < x < 240 moderate
< 60 s poor
Confidential 26
Taking Technology To The Field
Chemical Methods of Artificial Lift
� Soapsticks
� Batch treatments
� Squeeze treatments
� Continuous applications
�Chemical drip
�Capillary injection
� Combination products
Confidential 27
Pros & Cons of Chemical Methods
� Pros
� Set-up and operating cost
� Potential to use to abandonment
� Versatility for different completions and environments
� Can be used in addition to mechanical methods
� Tolerance of particulates
� Rapid response
� Automated continuous programs
� Can controls down hole corrosion, scale and paraffin problems
� Cons
� Placement can be difficult
� Soapsticks
� Capstrings
� Need to monitor stock
� Personnel intervention
�Well conditions change could render specific product ineffective
� Temperature stability on surface and down hole
� Environmental concerns
Well Suitability & Modelling- From The Lab To The Field
Confidential 28
Production Patterns
�Sharp decline in production rate
�Changes in water production
�Slugs of liquid coming through
�Decline in produced water &/or condensate
�Changes in pressure deltas
�Casing minus tubing versus time
Critical Velocity Model
INPUT DATA: PREDICTION OF LIQUID LOADING
Tubing I.D., inches 2.441 Desensitized Model - WATER ONLY
Wellhead Temperature, oF 85 vt, ft/sec 9.46
Wellhead Pressure, psig 500 Qg, Mscf/d 967
Gas Specific Gravity 0.68 vt, ft/sec (w/ Turner Adj. Factor of 20%) 11.35
Mole Fraction N2 0.002 Qg, Mscf/d (w/ Turner Adj. Factor of 20%) 1,161
Mole Fraction CO2 0.023
Mole Fraction H2S 0 Desensitized Model - CONDENSATE ONLY
Condensate Rate, bbls/d 57.4867 vt, ft/sec 6.08
Condensate API Gravity 55 Qg, Mscf/d 623
Water Rate, bbls/d 56.2397 vt, ft/sec (w/ Turner Adj. Factor of 20%) 7.30
Sodium - Na 17,000 Qg, Mscf/d (w/ Turner Adj. Factor of 20%) 747
Calcium - Ca 250
Potassium, - K 150 Desensitized Model - WATER & CONDENSATE
Magnesium - Mg 10 vt, ft/sec 8.00
Strontium - Sr 5 Qg, Mscf/d 818
Barium - Ba 3 vt, ft/sec (w/ Turner Adj. Factor of 20%) 9.60
Iron - Fe 12 Qg, Mscf/d (w/ Turner Adj. Factor of 20%) 982
Chloride - Cl 55,000
Sulfate - SO4 75 Desensitized Model - WATER & FOAM
Bicarbonate - HCO3 25 vt, ft/sec 6.426
Qg, Mscf/d 657
Confidential 29
Modeling Process, Output & Ranking
Variable Results Completion Details Is a completion diagram available?
Tubing I.D., inches Well depth (VD and TVD)
Casing I.D. inches Perforation depth and spacing
Wellhead Temperature, °F Well deviation
Wellhead Pressure, psig Is the well completed with a packer?
Botton Hole Temperature (degF) If yes, what depth is this at
Bottom Hole Pressure (psig) If not, is there access to the annulus?
Gas Specific Gravity Is there an injection string or plans to install one?
Mole Fraction N2 Are there any specific materials compatibilities?
Mole Fraction CO2
Is the tubing clean and free of deposits? Surfactants can remove
deposits & it is important to understand the fate of these & potential
impact on the process
Mole Fraction H2S Is a liquid level known?
Condensate Rate, bbls/d Treatment
Condensate API GravityIs a chemical storage tank, sight glass and injection pump available for
the application?
Water Rate, bbls/dDoes the operator have a company internal calculation to base the
economics of the foaming option?
Current gas rates (mmscfd) Surface Implications
What is the production pattern;
continuous, intermittent, shut in?Is there an injection point at the wellhead for the application of antifoam?
Sodium - Na What is the distance to the separation trains?
Calcium - Ca Do the level controllers in the inlet separator operate smoothly?
Potassium, - K Are there any water quality specs?
Magnesium - Mg Is water disposed overboard, storage tank, re-injected?
Strontium - Sr Is there a downstream compressor?
Barium - Ba
Iron - Fe
Chloride - ClSulfate - SO4
Bicarbonate - HCO3
INPUT DATA:
Brine
Chemistry /
ppm
INPUT DATA:
Variable A B C D E
Tubing I.D., inches 5.5 4.767 4.892 4.767 4.767
Casing I.D. inches 6.184 4.897 6.189 2.867 3.795
Wellhead Temperature, °F 72 60 68 55 60
Wellhead Pressure, psig 198 204 165 176 205
Botton Hole Temperature, °F 146 141 155 165 143
Bottom Hole Pressure, psig 1025 55 572 595 900
Gas Specific Gravity 0.59 0.59 0.59 0.59 0.59
Mole Fraction N2 0.011 0.011 0.011 0.011
Mole Fraction CO2 0.002 0.002 0.003 0.002
Mole Fraction H2S 0 0 0 0 0
Condensate Rate, bbls/d 1 2 1 1 1
Condensate API Gravity 56 56 56 56 56
Water Rate, bbls/d 4 33 2 9 1
Sodium - Na 65910 65910 64770 65910
Calcium - Ca 13560 13560 19830 13560
Potassium, - K 1468 1468 1805 1468
Magnesium - Mg 2523 2523 4138 2523
Strontium - Sr 420 420 1035 420
Barium - Ba 2 2 6 2
Iron - Fe 161 161 265 161
Chloride - Cl 136000 136000 20000 139200 136000
Sulfate - SO4 425 425 255 425
Bicarbonate - HCO3 35 35 10 35
Current gas rate mmscf/d 2.8 3 1.75 0 2.2
Well depth (TD and TVD) TD 10700 ft 99551ft TD 11065 ft TD 12557 ft TD
Packer depth 8311 ft 7276 ft 7819 ft 7756 ft 10412 ft
Perforation depth and spacing
A 10075 - 10212
B 10228 - 10284
C 10310 - 10354
D 10378 - 10440
8220 - 9785 ft
A 9045 - 9145
B 9178 - 9270
C 9285 - 9331
10939 ft
A 11387 - 11610
B 11660 - 11720
Brine
Chemistry
Well
Tubing A B C D E
ID / in 5.5 4.767 4.892 4.767 4.767
Crit
ical
rate
s
Water only 3,478 2,679 2,440 2,501 1,698
condensate only 2,183 1,675 1,581 1,561 1,061
water/condensate 3,092 2,447 2,164 2,263 1,391
water / foam 2,373 1,819 1,662 1,698 1,153
max. production rate / mscf/d 2,800 3,000 1,750 0 2,200
% above water critical -19 12 -28 -100 30
Total daily liquids (est.) 5 36 2 10 2
Casing A B C D E
ID / in 6.184 4.897 6.189 2.867 3.795
Crit
ical
rate
s
Crit
ical
rate
s
Water only 4,396 2,827 3,905 4,294 2,679
condensate only 2,760 1,767 2,530 2,681 1,675
water/condensate 3,909 2,582 3,464 3,881 2,195
water / foam 2,999 1,920 2,661 2,917 1,819
max. production rate / mscf/d 2,800 3,000 1,750 0 2,200
% above water critical -36 6 -55 -100 -18
Total daily liquids (est.) 5 36 2 10 2
Crit
ical
rate
s
Ranking
Hard decline
Production Trend
Bes
t Tria
l
Can
dida
te
Comment
Model shows loading in both the tubing and casing of this well. Liquid production is low, so this could
indicate DH liquid accumulation. A
C
ESteady decline, intermittent
rates > critical
Decline since year start
Hard decline
Model shows both the well tubing and casing are not far from critical conditions. Application of foamer
now could delay the onset of liquid loading and maintain continuous production.
Rise at year start, but now
decline
Bes
t Tria
l
Can
dida
teModel shows loading in both the tubing and casing of this well. Liquid production is low, so this could
indicate DH liquid accumulation.
Evidence to infer loading in both the well's tubing and casing. Liquid production is low, so this could
indicate liquid build up DH. Supported by production rate decline
Leas
t Suite
d
Model shows well to be producing above the tubing critical rate, but below critical in the larger ID
casing. Flow regime and liquid production would indicate this as a candidate for treatment.
B
D
Model shows both the well tubing and casing are not far from critical conditions. Application of foamer
now could delay the onset of liquid loading and maintain continuous production.
Production for this well is intermittent, but it would appear levels are already < critical for water and
foam combined. Possible batch candidate, although it may be beyond help from foamer
Rise to mid-year then
decline
Rise at year start, but now
decline
Leas
t Suite
d
Echometer
� A tool for finding the liquid level
� Can assist in treatment planning and suitability assessment
� Widely used in the industry
Confidential 30
Lab Testing & Product Selection
Product
Recommendation
Foamer Performance
Density
Ecotox Environmental
Profile
Flash Point
Thermal Stability
Materials Compatibility
Viscosity Profiles
Emulsification Tendency
Defoamer Compatibility
Chemical Compatibility
Field Application
� Treatment options
� Topside trial
� Batch
� Liquid batch
� Solid state
� Squeeze
� Continuous
� Drip
� Capillary string
� Well & process considerations
� Climate
� Supply / logistics
� Well completion
� Hardware limitations
� Easy to control treatment and optimise rate
� Rapid response to dosing
Confidential 31
Monitoring Performance
� Foamers will respond quickly in a system
� Beneficial for trials and optimisation
� KPIs
� Production rates� Gas, Liquids (water / condensate)
� Flowing time
� Shut-in period
�Wellhead temperature
� Other important parameters� Separation efficiency
� Oil in Water levels
� These are often dictated by the well and process set-up
� E.g. if there is no test separator then accurate monitoring of production rates can be difficult
Batch Treatment
�This can be applied in a various ways�Solid state soapsticks
� Manual or automated drop via production tubing
�Batching down the backside
� Only on packerless completions
�Batch and Fall
� Good if the well can be rocked
� If there is a very high level of loading
�Bull heading or tubing displacement
� Use a volume of flush to drive the chemical into location
�Squeeze
� Can be achieved with liquid or gas and the post-treatment flush
Confidential 32
Offshore Application
� Condensate loaded well (>95%)� 30,000 ppm foamer batched via production tubing
� Well shut-in for 24 hours
� Initial flow back, well failed to kick
� Shut-in for additional hour
� Production kicked with significant benefits
Down hole Batch Treatment
Variable
Previous
Flow
back
Trial
results % gain
Condensate within 30 mins/bbls 5 40 700
Gas Rate after 30mins/mmscfd 5 6.5 30
Condensate after 12 hours 50 81 62
Well uptime (days) 6 60 900
Offshore Application
�Trial Conclusions
�Batch treatments completed on a condensate dominant well
� Levels at >90% condensate
�Key differentiators observed by Operator
� Superior modelling of candidate wells
� Unrivaled performance in lab tests
� Knowledge and contribution of foamer expertise
� Minimal effect on PW quality
� Environmentally “green”, non-sub product, gold HQ
�Production benefits observed in many ways
� Key advantage being well shut in cycling went from every 6-8 days to 63 day interval
� No impact on BS&W or OiW
Confidential 33
Squeeze Application
Zinterl M. “Foamer Squeeze - The
Advancement of Foamer Batching”,
Gas Well Deliquification Workshop,
Denver, Colorado February 23 -26,
2009
Continuous Treatment
� Continuous injection is preferred
� Capillary strings are most efficient means
� Can occur via the gas lift system
� Depending on completion strings can be run down the producer (concentric) or banded on the tubing (eccentric)
� Various types of atomisers and nozzles available
� Placement is key to performance� Need to ensure that the chemical is delivered to the
correct location
� Typically aim for top perforations
� Can be used in addition to other artificial lift methods
Co
nfid
en
tial
34
Capstrin
g Treatm
ent
Date
Production rate / MSCF
Walk
er K
2
0.0
100
.0
200
.0
300
.0
400
.0
500
.0
600
.0
700
.0
2/21/05
4/21/05
6/21/05
8/21/05
10/21/05
12/21/05
2/21/06
4/21/06
6/21/06
8/21/06
10/21/06
12/21/06
Pro
du
ctio
n
Fo
am
er B
atc
h T
rend
Date
Production rate / MSCF
Date
Production rate / MSCF
Walk
er K
2
0.0
100
.0
200
.0
300
.0
400
.0
500
.0
600
.0
700
.0
2/21/05
4/21/05
6/21/05
8/21/05
10/21/05
12/21/05
2/21/06
4/21/06
6/21/06
8/21/06
10/21/06
12/21/06
Pro
du
ctio
n
Fo
am
er B
atc
h T
rend
Walk
er K
2
0.0
100
.0
200
.0
300
.0
400
.0
500
.0
600
.0
700
.0
2/21/05
4/21/05
6/21/05
8/21/05
10/21/05
12/21/05
2/21/06
4/21/06
6/21/06
8/21/06
10/21/06
12/21/06
Pro
du
ctio
n
Fo
am
er B
atc
h T
rend
Batch Vs Contin
uous Applicatio
n
>2
40
00
MS
CF
Confidential 35
Continuous Application Using Atomiser
Well #3, 35% CondensateWell #2, 24% Condensate
Onshore Application Batch & Continuous
� Batch and Continuous trials completed versus incumbent product
� Performance comparable or better
� Batch
� Equivalent performance at reduce treat volume
� Continuous
� First trial well neither product improved production
� Second application Product A gave excellent performance
� improvement over Incumbent
Timeline Product Treat Rate Ave. Production Rate
l / hr Mm3 / day
15 215
+1 hr 5 185
+15 hr 5 185
5 130
+7 hr 5 130
System flush and change out of product
Product A
Incumbent
WAV15-FR-4-17-1
NM3/D
WAV15-PT-4-17-2
barg
Plot-0
01/09/2008 13:49:29.828 01/10/2008 13:49:29.82830.00 days
10000
20000
30000
40000
50000
60000
70000
0
80000
0
70
57.686
1.2506E-12
Incu
mben
t: 5
0li
tres
Incu
mben
t: 1
00
litr
es
Pro
du
ct A
: 7
5li
tres
Pro
du
ct A
: 7
5li
tres
Pro
du
ct A
: 50 l
itre
s
Co
nfid
en
tial
36
Applicatio
n Above Critic
al Velocity
Date
Production rate / MSCF
0.0
20
0.0
40
0.0
60
0.0
80
0.0
100
0.0
120
0.0
140
0.0
160
0.0
3/4/05
3/11/05
3/18/05
3/25/05
4/1/05
4/8/05
4/15/05
4/22/05
4/29/05
5/6/05
5/13/05
5/20/05
5/27/05
6/3/05
6/10/05
6/17/05
6/24/05
7/1/05
Prod
uctio
n
Pre-F
oam
er T
rend
Tubin
g C
ritical V
elo
city
Ad
ded F
oam
er 5
-04-0
5
Date
Production rate / MSCF
Date
Production rate / MSCF
0.0
20
0.0
40
0.0
60
0.0
80
0.0
100
0.0
120
0.0
140
0.0
160
0.0
3/4/05
3/11/05
3/18/05
3/25/05
4/1/05
4/8/05
4/15/05
4/22/05
4/29/05
5/6/05
5/13/05
5/20/05
5/27/05
6/3/05
6/10/05
6/17/05
6/24/05
7/1/05
Prod
uctio
n
Pre-F
oam
er T
rend
Tubin
g C
ritical V
elo
city
Ad
ded F
oam
er 5
-04-0
5
Applicatio
n of C
hemical w
ith Plunger
Date
Production rate / MSCF
0.0
100.0
200.0
300.0
400.0
500.0
600.0
7/18/06
8/1/06
8/15/06
8/29/06
9/12/06
9/26/06
10/10/06
10/24/06
11/7/06
11/21/06
Production
Foam
er
PlungerFoam
er and Plunger
Date
Production rate / MSCF
Date
Production rate / MSCF
0.0
100.0
200.0
300.0
400.0
500.0
600.0
7/18/06
8/1/06
8/15/06
8/29/06
9/12/06
9/26/06
10/10/06
10/24/06
11/7/06
11/21/06
Production
Foam
er
PlungerFoam
er and Plunger
Confidential 37
Application of Combination ProductsWell A
Production
Gas Mscf/d 450
Water / BOWPD 12
Condensate / BOPD 0
Tubing Pressure / Psi 400
Casing Pressure / Psi 400
Treatment
Date Chemical
13/09/2007 Batch CI
23/11/2007 Foamer batch
19/12/2007 Foamer batch
05/02/2008 Foamer batch
07/02/2008Installed continuous
backside treatment
Corrosion Data
Pitting Rate / MPY 1.4 - 5.3
General Rate / MPY 2.4 - 7.3
Caliper Surveys 03/12/2007
06/06/2008
Well B
Production
Gas Mscf/d 330
Water / BOWPD 14
Condensate / BOPD 0
Tubing Pressure / Psi 400
Casing Pressure / Psi 800
Treatment
Date Chemical
26/09/2007 Batch CI
21/11/2007Installed continuous
backside treatment
Corrosion Data
Pitting Rate / MPY 4.5 - 12.2
General Rate / MPY 0.6 - 2.9
Caliper Surveys 29/11/2007
02/06/2008
Application Trouble Shooting
�Emulsion formation
�Surfactants can potentially increase emulsion tendencies
�Foamer treatments are often managed with antifoam and emulsion breakers as required
�Field evidence demonstrates no impact on process
�Process upsets
�Proper topside foam control should prevent any disruptions
� Correct defoamer application
�No reported impact on water quality specification
Confidential 38
Application Trouble Shooting
�No well response
�Dead well
� Insufficient gas or agitation
� Can rock or swab the well
� Apply gas sticks / pellets – introduce localised gas
�Flowing well
� Chemical not reaching the liquids
� Well conditions are not conducive to loading
– Modelling error
Application Trouble Shooting
�Capstring issues
�Plugging of the line
� Use only capstring qualified products
� Apply appropriate flushing procedures for shut down
�Compatibility
� Materials
� Chemicals
� Produced fluids
Confidential 39
Continuous Improvement Application Program
1. Collate well data (as per questionnaire)
2. Model & rank wells3. Prepare product recommendation / trial proposal
4. Performance measurement method understood?5. Similar Case Studies / Best Practices6. Understand all criteria for success
7. Nalco support specialists defined?
1. Supply chain capabilities2. Storage needs3. Equipment for well application?
– what / who / when4. Well sample points adequate?
5. Source monitoring equipment
1. Base line completed
2. Stock / delivery monitoring3. Well variable / performance monitoring
4. Communication of results
1. Optimisation plan2. Troubleshooting guide
3. Develop Case Study4. Evaluate new technology
Select Programme
Monitor Performance
Plan / Design
Measure / Monitor
Learn / Improve Act / DoGas Well
Foamer
Programme ApplyReview / Continuous
Improvement
1. Collate well data (as per questionnaire)
2. Model & rank wells3. Prepare product recommendation / trial proposal
4. Performance measurement method understood?5. Similar Case Studies / Best Practices6. Understand all criteria for success
7. Nalco support specialists defined?
1. Supply chain capabilities2. Storage needs3. Equipment for well application?
– what / who / when4. Well sample points adequate?
5. Source monitoring equipment
1. Base line completed
2. Stock / delivery monitoring3. Well variable / performance monitoring
4. Communication of results
1. Optimisation plan2. Troubleshooting guide
3. Develop Case Study4. Evaluate new technology
Select Programme
Monitor Performance
Plan / Design
Measure / Monitor
Learn / Improve Act / DoGas Well
Foamer
Programme ApplyReview / Continuous
Improvement
Select Programme
Monitor Performance
Plan / Design
Measure / Monitor
Learn / Improve Act / DoGas Well
Foamer
Programme ApplyReview / Continuous
Improvement
Foamer Performance Summary
� See great versatility of the foamer application� On- and Off- Shore
� Continuous and Batch� Continuous is preferable in majority of instances
� Optimisation is facile with rapid response
� Performance observed:� Above the critical velocity
� When the casing is loaded
� Instead of and with plungers
� Benefits:� Increased production
� Improved decline curve
� Extended flowing period
� Well clear out
� Extend well longevity
� Can be used to support asset integrity and flow assurance programs� Reduce chemical inventory and injection hardware requirements
Confidential 40
Workshop Summary
�Demonstrated the benefits chemical foamers can offer gas producers
�Applying a robust selection and testing process means best suited products are recommended
�Utilising surfactant chemistry expertise and the fundamentals of foam science facilitates the development of efficient deliquification chemicals
Questions
Confidential 41
Referenced Material
� Gas Well Deliquification, J. Lea, H. Nickens, M. Wells, ISBN 0-7506-7724-4
� Zinterl M. “Foamer Squeeze - The Advancement of Foamer Batching”, Gas Well Deliquification Workshop, Denver, Colorado February 23 -26, 2009
� Willis M., Visser J. “Selection and Application of Chemical Foamers for Offshore, North Sea”, Gas Well Deliquification Workshop, Denver, Colorado February 23 -
26, 2009
� Willis M., Hudsen J. “Foamer Field Trials”, 2008 Gas Well Deliquification Conference, Groningen NL
� Conrad G., Nguyen D. “The Use of Foamer and Injection Nozzle for Increasing Gas Production“, Gas Well Deliquification Workshop, Denver, Colorado February 23 -26, 2009
� Pakulski M.“Automated High Pressure, High Temperature Foam Column Testing
Apparatus”, Gas Well Deliquification Workshop, Denver, Colorado February 23 -
26, 2009
� http://www.echometer.com/ (visited 7th August 2009)
� http://www.kruss.info/index.php?content=http%3A//www.kruss.info/instruments/b
p2_e.html (visited 20th May 08)