Chemical methods for EOR porcess

1. EOR Chemical Methods
Basics of Chemical EOR Methods
Basics of Polymer Flooding
Colloidal Dispersion Gel Technology
Combination of Technologies
Example of CGSJ , Argentina
Basics of A/SP methods
Screening Criteria for EOR Chemical Methods
Overview of EOR Chemical Methods

2. Polymer flooding
Colloidal Dispersion Gels (CDG’s)
Alkaline flooding
Alkaline-Polymer (AP) flooding
Surfactant-Polymer (SP) flooding (Replace old Micellar
Polymer)
Alkaline-Surfactant-Polymer (ASP) flooding
Combination of technologies for conformance:
(e.g. Polymer gels followed by EOR Methods )
EOR Chemical Methods (Summary)

3. EOR Chemical Methods (Summary Cont’d)
The polymers used reduces water mobility and diverts water from
zones that are watered out. "freeing" the trapped oil making it easier
to flow to the production well
.
• Polyacrylamide powder or "PAM" is a non-toxic powder that is
having long-chain molecule is used in polymer flooding Water
injected becomes more "viscous" or thick, much like a gel and is
helpful in heavy oil recovery

4. EOR Chemical Methods (Summary Cont’d)
Polymer flooding has been the most applied EOR chemical method
in sandstone reservoirs.
The injection of alkali, surfactant, alkali-polymer (AP), surfactant-
polymer (SP) and Alkali-Surfactant-Polymer (ASP) are a one-step in
advance used to aid mobility and reduce interfacial tension
ASP and SP have been widely used during the last decade
With today’s technology, AP and ASP floods are applicable to
sandstone reservoirs mainly BUT other rocks too
Application is usually limited by the cost of the chemicals and their
adsorption onto the rock of the oil containing reservoir

5. EOR Chemical Methods(Summary Cont’d)
Surfactant-polymer (SP) seems to be a feasible recovery
process in both carbonate (e.g. Midland Farm Unit, Texas
starting in 4Q of 2011) and sandstone reservoirs.
* Well stimulation and wettability alteration
* Foam injection (Gas Shut-off or Gas injection profile modification) in
gas or WAG floods
• Applicability of chemical EOR methods has been extended to viscous
oil reservoirs (crude oil viscosities up to 5,000 cp at reservoir
conditions)
* water salinity has a great effect on mobility, adsorption and K
reduction
(e.g.) Adding salt to polymer leads to the change in shape of molecules
from inflated to spherical form.
–

6. Basic Scheme of Polymer Flooding
Polymer gels are designed to reduce the effects of reservoir
heterogeneity beyond the near wellbore area. and for unfavorable
mobility ratio.

7. Basic Scheme of Polymer Flooding
To reach a low mobility factor, the viscosity of water should be
increased many times
IF we do WF the fingering effect REDUCE the sweep efficiency.
But in polymer flooding is diferent
Fingering causes to flow water along with oil through production line

8. Polymer Flooding Criteria
The pre-gel solution
will preferentially enter
high permeability anomalies
Once the gels reduce the flow capacity in the “thief zones”, areal and
vertical sweep efficiency will be improved

9. Flooding Mobility Ratio(M)
For a waterflood where piston-like flow is assumed, with only water
flowing behind the front and only oil flowing ahead of the front,
M can be defined as:
Relative permeabilities (krw and kro) are measured at residual oil
saturation (Sor) and immobile water saturation (Swi), respectively;
represent the viscosity of oil (uo) and water (uw).

10. Fluid-Fluid and Fluid-Rock Interactions
Scheme of basic interactions during polymer flooding

11. Polymer Core Flooding (Lab. & Simulation):
Dynamic Ads., RF/RRF and Injectivity Test

12. CDG Technology: Coloidal Dispersion Gels
CDG is a variation of polymer flooding (PF) that can generate similar
incremental recovery factors than PF using less mass of polymer
(Economics!)
Additional benefits of CDG include:
Generate higher RF than PF at the same (or lower) polymer concentration
Injectivity can be controlled without impacting water viscosity, especially
in viscous and low permeable reservoirs
There are several ongoing projects in Argentina (Tordillo Field, 5
patterns), Colombia (Dina Field, 1 pattern) and the U.S.(6 )
CDG technology has been under scrutiny and represents a controversial
technology.
However, recent studies in Canada, Norway , U.S have reported
different studies describing operating mechanisms under this recovery
process .
Some service companies are working to develop new laboratory
procedures to expand the know how in this technology

13. Example : Model (Pilot) Description)

14. Example : Model (Pilot) Description)

15. CDG vs. Polymer Flooding Comparison
CDG and polymer flooding (PF) can generate similar
incremental oil recoveries. 80% of CDG viscosity BUP in 50
days in this simulation case.
CDG conc. of 650, 450, 300 ppm
(Differences are within simulation error)

16. Combination Well Conformance +
Chemical EOR

17. Combination Well Conformance +
Chemical EOR

18. Basics of EOR A/SP Methods When to Start ?

19. Basics of EOR A/SP Methods
typical values for Nc and Sor

20. EOR A/SP Methods – Decision Scheme
Other Factors that should be considered are
* Sandstone or . carbonate reservoir
* Adsorption of surfactants on rock

21. Basic Fluid-Fluid and Fluid-Rock Interactions
with Conventional Alkalis
Mineral
dissolution
and
precipitation
Water compatibility
with injection and
formation water
( scale formation)
Activation of
natural surfactants
(Emulsification and
IFT reduction)

22. Basic Fluid-Fluid and Fluid-Rock Interactions
with Conventional Alkalis
Alkali flooding is a process in which water at pH value of 10–12obtained
at HONa concentration of 0.01 to 1.0 wt%
Emulsification ,wettability gradients, oil-phase swelling, low IFTs ,
temperature,salinity are some of the factors that have influence on
alkali injection and can modifie the crude oil behavior.
There is an agreement on the fact that the acidic components in the
crude oil are most important factor for alkali flooding.
The effect of alkali solution on oil recovery is partly due to the chemical
reactions between the alkali and organic acids that exist in the crude
oil.
AS a result , a surfactant is produced and pressures between the
aqueous and oleic phases were reduced (oil-water IFT)

23. Acid Number of Crude Oils

24. Basic Fluid-Fluid and Fluid-Rock Interactions
with Surfactants

25. Surfactant Flooding
Surface active agents, ( surfactants) have at least
- one hydrophilic
- one hydrophobic group
in the same molecule
THEN IFTs between oil and brine are significantly lower .
High cost of surfactant
is a limitation and /or
a reason to coupled
it with other products.
Example of IFT vs.
Surfactant
Concentration for
a Formulation

26. Alkali-surfactant-polymer enhanced
recovery (ASP)
In this process, a very low concentration of surfactant is used to get
ultra low IFT between the trapped (remaining) oil and the injection
fluid/formation water.
The alkali also simultaneously reacts with the acidic components in
the crude oil to form additional surfactant in situ
As a result, continuously providing ultra low IFT and freeing the
trapped oil.
In the ASP process, polymer is used to increase the viscosity of the
injection fluid, to minimise channelling, and provide a better mobility
control.
Water drive is used to move the front towards the producing well.

27. Alkali-surfactant-polymer enhanced
recovery (ASP) Evaluation Diagram
Pore displacement
efficiency
improved by
alkali&surfactant
Areal & vertical
efficiency
improved by
polimer

28. Screening of EOR Chemical Methods I
Chemical composition of injection and produced water are key to
define the applicability of alkali (Water treatment can be too costly
and water mixing in the reservoir is not a controllable parameter)
Key variables that can quickly guide the applicability these
recovery processes includes:
* Well spacing (< 20 acres unless thin pays)
* Infill drilling might be required (check drilling costs)
* Thin pay zones (< 40 ft reduce chemical volumes and contributes
accelerating oil response)
* For thin pays lower than 20 ft and viscous oils, high permeability is
desirable (Horizontal wells might be required to have economic
injection rates)

29. Screening of EOR Chemical Methods II
High oil saturation (the higher the better)
Preferably reservoirs with no to weak bottom water of or close to
water disposal (Minimize chemical dilution)
Preferably sandstone formations. For carbonates SP is the only
available option with todays technology
Low clay content (< 20%) is desirable (The lower the surfactant
adsorption the better - < 0.5 mg/g rock)
For temperatures > 200°F and high salinity/ hardness expect higher
chemical costs
Etc,etc

30. Final Comments
Chemical EOR is still limited to sandstone reservoirs
Although polymer flooding and CDG are methods under evaluation
internationally, most SP and ASP projects are in Canada, China and
the U.S.
Chemical flooding has been shown to be sensitive to volatility of oil
markets despite recent advances (e.g. low surfactant concentrations)
and lower costs of chemical additives
Chemical flooding has shown important advances during the last
decade.
Therefore, micellar-polymer floods performed during the 1980’s are not
representative of technologies currently available

31. Final Comments
All EOR projects might be expensive if starts too late (>95% Wcut) or
delay rate of return
If injection and produced waters shows high salinity and hardness do
not try to justify water treatment to use ASP.
SP technology can tolerate harsh environments
SP in high salinity hardness/salinity may require higher surfactant
concentrations
However, high surfactant concentration costs are generally lower to
water treatments
Justify ASP with expensive water treatments (to reduce surfactant
concentration) does not guarantee technical and/or economical
success (Water chemistry in the reservoir can’t be controlled)

32. Final Comments
Confirm or reduce as much as possible uncertainties associated to
remaining oil saturations
Verify surfactant manufacture locations of chemical additives
Transportation and import costs of chemicals may impact negatively
project economics
Reservoir development plans under chemical flooding by phases
(modular units) seems to be a reasonable approach to minimize
CAPEX with the benefit of operational flexibility
Do not forget environmental regulations:
Confirm that water sources (if different than produced water) will be
available in the mid/long term (Changes in water sources will require
changes in chemical formulations)
Confirm water disposal strategies

34. MEOR Microbial Injection

35. MEOR Microbial Injection

36. Note
Data presented here were provided by C.
Norman mainly.
Other sources are lebeled in each slide