• Surfactants to lower the interfacial tension between the oil and the
water or change the wettability of the rock
• Water soluble polymers to increase the viscosity of the water
• Surfactants to generate foams or emulsion
• Polymer gels for blocking or diverting flow
• Alkaline chemicas such a sodium carbonate to react with cride oil to
generate local surfactant and increase pH
• Combination of chemicals and methods
The role of polymer:
• Decreasing mobility ratio by increasing polymer solution viscosity
The role of surfactant:
• Lowering oil-water interfacial tension
• Altering rock wettability
• Lowering bulk-phase viscosity
• Promoting emulsification
The role of alkaline:
• In alkaline flooding, high-pH chemical system is injected. Alkaline and acid hydrocarbon
species in crude oil react to generate the surfactant.
The role of TFSA:
• Altering rock wettability towards a more water-wet
• Lowering oil-water interfacial tension.
CHEMICAL FLOODING
CHEMICAL FLOODING
Polymer
Polymer flooding
Polymers are made up of very large molecules and act as thickeners when dissolved in water that
result in high solution viscosity
Polymer types:
Parameter
Bio-polymers
Synthetic polymers
Such as
Xanthan
Polyacrylamides
Made by
Fermentation
Hydrolysis
Charge
Neutral
Negatively charged
Effect of salinity
Less sensitive
More sensitive
Viscosity
High
Medium
Price
Expensive
Less expensive
Effect of bacteria
Attacked
Not attacked
Effect of shear
Thinning
Thickening
1000
Polymer solution viscosity
1000 ppm Bio-polymer
1000 ppm HPAM
Apparent Viscosity, cp
Salinity, ppm
Solution viscosity affected by:
• Polymer type and Concentration
• Salinity
Permeability reduction and visco-elastic effects
All polymers exhibit shear thinning, non-Newtonian behavior in laboratory viscometers.
In porous media at very high shear rates, bio-polymers maintain this behavior while HPAM shows
behaves different than laboratory viscometers.
Viscosity of bio-polymers decrease with shear rate till
but retain original viscosity if shear rate is decreased back to
low values.
0
This behavior (shear thinning) is related to high molecule
elasticity short relaxation time (period required for
molecules to retain original shape after distortion).
Bio-polymers exhibit low apparent viscosity near injection
wells and, consequently; improved injectivity.
HPAM polymers exhibit long relaxation time and some permanent distortion if subjected to very
high shear rate and their apparent viscosity may increase (shear thickening).
Some permeability reduction results from injecting HPAM polymers into reservoir rocks.
Resistance factor, permeability reduction factor, and residual resistance factor are
the technique index of describing the retention amount of polymer and polymer
gel in the porous media. They are denoted by RF, Rk, and RRF.
P2 k w p
RF
P1 k p w
Rk
kw w
RF
kp p
RRF
P3
kw
after
P1 k w
Experimental procedure:
1. Saturating the core by formation water, injected water flooding, recorded the pressure P1.
2. Injected chemical flooding 4PV 5PV, recorded the pressure P2.
3. Injected subsequent water 4PV 5PV, recorded the pressure P3.
The injection rate is 0.3 mL/min, the time interval of pressure record is 30 min.
Inaccessible PV
• Polymer molecules are larger than water molecules
and are large relative to some pores in a porous
rock.
• Because of this, polymers do not flow through all
the pore space contacted by brine.
• The fraction of the pore space not contacted by the
polymer solution is called the inaccessible pore
volume (IPV).
• The magnitude of IPV can range from 1% to 30%,
depending on the polymer and porous medium.
Polymer retention
Polymer adsorption is the main form of retention.
Measured in laboratory using representative core and fluid samples.
Polymer adsorption (p) is a function of polymer concentration (Cpl) in the injected slug.
Mathematical expression is:
p a pC pl 1 b pC pl
p = polymer adsorption, mg/g or g/kg
ap, bp = constants depend on polymer type
Converted to represent volume of polymer solution per unit pore volume,
D pl p p 1 C pl s = rock solid density, kg/m3
= porosity, fraction
Cpl = polymer concentration in solution, g/m3
Dpl = polymer adsorption, fraction of floodable PV, usually
referred to as polymer frontal advance loss
Polymer retention
Polymer adsorption is the main form of retention.
Measured in laboratory using representative core and fluid samples.
Polymer adsorption (p) is a function of polymer concentration (Cpl) in the injected slug.
Mathematical expression is:
p a pC pl 1 b pC pl
p = polymer adsorption, mg/g or g/kg
ap, bp = constants depend on polymer type
Converted to represent volume of polymer solution per unit pore volume,
D pl p p 1 C pl s = rock solid density, kg/m3
= porosity, fraction
Cpl = polymer concentration in solution, g/m3
Dpl = polymer adsorption, fraction of floodable PV, usually
referred to as polymer frontal advance loss
Polymer degradation
Temperature
Temperatures in the range 120-130C, could cause most polymer solutions to crack and lose their viscosity
Hydrolysis
Can reduce viscosity of all polymers specially at high temperature. This effect more pronounced in low pH
environment.
Oxidation
Presence of oxygen, even in very low concentrations can prompt chemical reactions that lead to polymer loss.
Microbial
Some types of bacteria in the system can attack and break polymer molecules.
Share rate
High shear rates (in surface pipes, valves, well perforations and near injection wellbore) can break polymer
molecules into smaller segments.
Suitable polymer
A suitable polymer should exhibit:
Good viscosity characteristics
High water solubility and easy mixing
Low retention in reservoir rock
Shear, temperature, chemical and biological stability
Ability to flow in the reservoir rock
Reasonable injectivity
Acceptable resistance and residual resistance:
Relatively low values are desirable for mobility control.
High values are desirable for plugging and profile control.
Selecting polymer
Polymer concentration required to achieve a maximum mobility ratio.
M PF
krp
kro
p krw w behind
o krw w minimum
Polymer solution slug size required
V ps D pl IPV VF 1 Sor 1 H K1 0.78 0.22 p
logH K VDP 1 VDP 0.2
Total mass of polymer required for a flood
Polimer mass, kg 10-3Vb nEvV psC pl
w
0.25 4
Surfactants
In a system with water and oil, a surfactant will reduce the interfacial
tension between the two liquid phases, which “liberates” residual oil held
by capillary forces, i. e. a reduction of capillary pressure in the reservoir,
leaving it water-wet. This “liberated” oil can now be more easily mobilized
and produced.
• Many technically successful pilots have been done
• Several small commercial projects have been completed and several
more are in progress
• The problems encountered with some of the old pilots are well
understood and have been solved
• New generation surfactants will tolerate high salinity and high hardness
so there is no practical limit for high salinity reservoirs
• Sulfonates are stable to very high temperatures so good surfactants are
available for both low and high temperature reservoirs
• Current high performance surfactants cost less than $2/lb of pure
surfactant
Favorable Characteristics for Surfactant Flooding
• High permeability and porosity
• High remaining oil saturation (>25%)
• Light oil less than 50 cp--but recent trend is to apply to viscous oils up to
200 cp or even higher viscosity
• Short project life due to favorable combination of small well spacing and/or
high injectivity
• Onshore
• Good geological continuity
• Good source of high quality water
• Reservoir temperatures less than 300 F for surfactant and less than 220 F if
polymer is used for mobility control
SURFACTANTS CHARATERISTICS
• Surfactants or surface active agents are chemical substances that concentrate at a
surface or fluid/fluid interface when present at low concentration in a system.
• Most common surfactants monomer consist of a hydrocarbon portion (nonpolar lypophile) called tail and an ionic portion (polar - hydrophile) as the head.
• Classified according to the ionic nature of the head:
Anionic: sodium dodecyl sulfate (C12H25SO4Na+). Exhibit negative charge and yield anions when
dissolved in water.
Cationic: dodecyltrimethyl ammonium bromide (C12H25Na+Me3Br-). Exhibit positive charge and
yield cations when dissolved in water.
Nonionic: dodecyl hexaoxyethylene glycol monoether (C12H25[OCH2CH2]6OH). Neutral and do not
ionize in water but provide characteristics similar to surfactants.
• Anionic surfactants preferred
• –Low adsorption at neutral to high pH on both sandstones and
carbonates
• –Can be tailored to a wide range of conditions
• –Widely available at low cost in special cases
• –Sulfates for low temperature applications
• –Sulfonates for high temperature applications
• –Cationicscan be used as co-surfactants
• •Non-ionic surfactants have not performed as well for EOR as anionic
surfactants
• Anionic surfactants ionize in water into inorganic cations and hydrocarbon-sulfonate
anions.
• As the surfactant concentration increases, several of the sulfonate anions combine
together in the form of micelles. For this reason, surfactant floods are usually
referred to as Micellar Floods.
Critical Micelle Concentration
(CMC)
Surfactant Phase Behavior
• Winsor Type I Behavior
• Oil-in-water microemulsion
• Surfactant stays in the aqueous phase
• Difficult to achieve ultra-low interfacial tensions
• Winsor Type II Behavior
• –Water-in-oil microemulsion
• –Surfactant lost to the oil and observed as surfactant retention
• –Should be avoided in EOR
• Winsor Type III Behavior
• –Separate microemulsion phase
• –Bicontinuouslayers of water, dissolved hydrocarbons
• –Ultra-low interfacial tensions ~ 0.001 dynes/cm
• –Desirable for EOR
Optimal salinity
1.0E+00
IFT mo
IFT mw
IFT (dyne/cm)
1.0E-01
1.0E-02
1.0E-03
l
u
m
1.0E-04
Vo/Vs atau Vw/Vs)
20.0
16.0
Vo/Vs
12.0
Vw/Vs
8.0
4.0
0.0
0.2
0.6
1.0
1.4
1.8
2.2
2.6
3.0
Kadar Garam (% Berat NaCl)
At optimal salinity:
Interfacial tensions are equal and
minimum
Solubilization parameters are equal
and maximum
Displacement efficiency is maximum at optimal salinity
100
1.E-01
1.E-02
Displacement Efficiency
Interfacial Tension, mN/m
90
Salinity
Increasing
Salinity
Decreasing
1.E-03
80
70
60
50
40
30
20
10
1.E-04
0
0
0.4
0.8
1.2
1.6
2
Salinity, % NaCl
2.4
2.8
3.2
0
0.4
0.8
1.2
1.6
2
Salinity, % NaCl
2.4
2.8
3.2
Surfactant retention
Surfactant anions get retained in reservoir rocks due to:
Adsorption on positively-charged surfaces
Reaction with divalent cations
Trapping of oil-continuous micro-emulsions
48
10% Co-surfactant
Adsorption, micro g-mole/g clay
44
6% Co-surfactant
40
2% Co-surfactant
Use of co-surfactants can
reduce surfactant retention
No Co-surfactant
36
32
28
Langmuir Isotherm
24
20
16
s
12
8
4
0
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
Equilibrium Concentration, g-mole/m3
1.8
2
as Csl
1 bs Csl
Many studies relate surfactant retention in reservoir rocks to clay content and
water salinity
Laboratory and field tests can provide reliable retention values
1.1
0.7
Field data
0.6
Surfactant Retention, mg/g of Rock
Surfactant Retention, mg/g of Rock
1
Effect of Phase Trapping
0.5
0.4
0.3
0.2
0.1
0.9
Lab Data
Field Data
0.8
0.7
Lab data
0.6
0.5
0.4
0.3
0.2
0.1
0
0
0
Page 44
0.5
1
1.5
2
Salinity, % NaCl
2.5
3
3.5
0
4
8
12
16
Clay Content, % wt
20
24
Many studies relate surfactant retention in reservoir rocks to clay content and
water salinity
Laboratory and field tests can provide reliable retention values
1.1
0.7
Field data
0.6
Surfactant Retention, mg/g of Rock
Surfactant Retention, mg/g of Rock
1
Effect of Phase Trapping
0.5
0.4
0.3
0.2
0.1
0.9
Lab Data
Field Data
0.8
0.7
Lab data
0.6
0.5
0.4
0.3
0.2
0.1
0
0
0
Page 44
0.5
1
1.5
2
Salinity, % NaCl
2.5
3
3.5
0
4
8
12
16
Clay Content, % wt
20
24
Selecting suitable surfactant
Possible candidate reservoirs for surfactant flood applications:
Medium to high oil gravity
Reasonably low salinity and hardness of formation water
Temperatures less than 100 C
Relatively high residual oil saturation
Relatively low clay content with low cation exchange capacity
Select several surfactants based on preliminary screening
Conduct preliminary lab tests for further screening
Select 2 – 3 surfactants for detail lab tests
Find the right formulation and additives
Conduct core floods
Make final selection and design field pilot test
Selecting suitable surfactant
Determination of surfactant retention
Determination of residual oil saturation
Surfactant slug volume required
Mass of surfactant required
Estimating RF from SP floods
Surfactant Selection Criteria
• Minimal propensity to form liquid crystals, gels, macroemulsions
• Microemulsion viscosity < 10 cp
• Rapid coalescence to microemulsion
• Undesirable if greater than a few days and preferably less than one
day
• Slow coalescence indicates problems with gels, liquid crystals or
macroemulsions
Alkaline
WHAT IS ALKALINE FLOODING?
It is an EOR method in which an alkaline chemical
such as Sodium hydroxide,Sodium
Orthosillicate or Sodium carbonate is injected
during polymer flooding or water flooding
Operations.Alkaline flooding is also known as
Caustic flooding.
HOW THIS WORKS INSIDE THE
RESERVOIR?
The alkaline chemicals reacts with certain types of
oil,forming surfactants inside the reservoir
Eventually,the surfactants reduce the interfacial
tension between oil and water and trigger an
Increase in oil production.Wetting characteristics
of the reservoir also can change due to Formation
of surfactants inside the reservoir or it can be due
to some other reasons.
The use of alkali in a chemical flood is beneficial in many ways:
1. reduces the absorption of the surfactant on the reservoir rock.
2. alkali makes the reservoir rock more water-wet.
3. alkali is relatively inexpensive.
-Softened injection water is required in ASP i.e. very low concentrations
of divalent cations (hardness) such as Ca +2 and Mg +2 . Otherwise,
these cations react with the alkali agent and form a precipitate (e.g.
hydroxides), which could plug the pores of most reservoirs.
-Higher salinity of the water phase can also be undesirable; it can
decrease the solubility of surfactant molecules in the water. In essence,
the alkali, usually caustic soda, reacts with components present in some
oil to form soap.
CONSIDERATIONS FOR USING…
Alkaline flooding is not recommended for
carbonate reservoirs due to the abundance
of
Calcium:The mixture between the alkaline
chemical and the calcium ions can produce
Hydroxide precipitation that may damage
the formation.
CRITERIA FOR USING…
CRUDE OIL
Gravity
Viscosity
13 – 35 API
<200 cp
RESERVOIR
Avg. K
Depth
Temp.
>20 md
<about 9000 ft
<200 *F preferred
EFFECTIVENESS OF DIFF.
CHEMICALS…
i. Sodium Orthosillicate
upto 100%
ii. Sodium Carbonate
upto 65%
iii.Sodium Hydroxide
upto 80%
ADVANTAGES AND LATEST
TECHNOLOGY…
Alkaline flooding is usually more efficient if the
acid content of the reservoir oil is
Relatively high.
A new modification to the process is the addition
of surfactant and polymer to the alkali,
Giving rise to an Alkaline-surfactantpolymer(ASP) EOR method.
This method has shown to be an effective,less
costly form of micellar-polymer flooding.
PROBLEMS IN USING…
1.Scaling and plugging in the producing
wells.
2.High caustic consumption.
ASP
• Mobility control is critical. According to Malcolm Pitts, 99% of floods
will fail without mobility control
• Floods can start at any time in the life of the field
• Good engineering design is vital to success
• Laboratory tests must be done with crude and reservoir rock under
reservoir conditions and are essential for each reservoir condition
• Oil companies are in the business of making money and are risk
adverse so....
• Process design must be robust
• Project life must be short
• Chemicals must not be too expensive
• Don W. Green and G. Paul Willhite, 2003, Enhanced Oil Recovery, SPE Textbook Series Vol. 6, the Society of
Petroleum Engineers Inc., USA.
• Ezzat E. Gomaa, 2011, Enhanced Oil Recovery - Methods, Concepts, and Mechanisms, KOPUM IATMI.
• L.P. Dake, 2002, Fundamentals of Reservoir Engineering, Elsevier Science B.V. Amsterdam, the Netherlands.
• Larry W. Lake, 2005, Petroleum Engineering Handbook – Chemical Flooding, Society of Petroleum Engineers,
Richardson, Texas, USA.
• Hestuti, E., Usman, Sugihardjo, 2009, “Optimasi Rancangan Injeksi Kimia ASP untuk Implementasi Metode
EOR”, Simposium Nasional IATMI 2009, Bandung, IATMI 09 – 00X.
• Zhijan, Q., Zhang, Y., Zhang, X., Dai, J., 1998, “A successful ASP Flooding Pilot in Gudong Oil Field”, The 1998
SPE/DOE Improved Oil Recovery Symposium, Oklahoma, USA, SPE 39613.
• Harry L. Chang, Xingguang, S., Long, Xiao., Zhidong, G., Yuming, Y., Yuguo, X., Gang, C., Kooping, S., and
James, C. Mack, 2006, “Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in
Daqing Oil Field”, SPE Reservoir Evaluation & Engineering (Desember 2006), pp. 664 – 673.