1. “Smart Water” for Enhanced Oil Recovery: A Comparison of Mechanism in Carbonates and Sandstones
Tor Austad
University of Stavanger, Norway
Force seminar on Low Salinity, NPD, 15. May, 2008.

2. Definition Primary recovery Secondary recovery Tertiary recovery
Use the energy stored in the reservoir
Pressure depletion
Secondary recovery
Pressure support by injection fluids already present in the reservoir
Gas injection
Water injection (formation water or water available)
Tertiary recovery
Injection of fluids/chemicals not initially present in the reservoir.
Chemicals: Polymers; Surfactants; Alkaline; etc.
“Smart water” to impose wettability alteration

3. “Smart Water” to obtain improved wetting conditions
Carbonates
Often neutral to preferential oil wet
Water injection difficult without wettability modification.
Sandstones
Optimal water flood at weakly water-wet condition (Morrow)
Mixed wet (oil-wetness linked to clays)

4. Chalk: SW as “smart water”

5. Sandstone: Low Salinity flooding
(15,000 ppm)
(1,500 ppm)
By: Webb et al

6. Low Salinity effect well documented by BP
(By: Lager et al. 2007)

7. Outline
What is the chemical mechanism for enhanced oil recovery by “Smart Water”??
Carbonates
Sandstones
Are there any similarities??

8. Wetting properties for carbonates
Carboxylylic acids, R-COOH
AN (mgKOH/g)
Bases (minor importance)
BN (mgKOH/g)
Charge on interfaces
Oil-Water
R-COO-
Water-Rock
Potential determining ions
Ca2+, Mg2+, SO42-, CO32-, pH - - - -
Ca Ca Ca2+ - - - -
SO SO SO42-

9. Model composition of FB and SW
Comp. Ekofisk Seawater
(mole/l) (mole/l) Na K Mg Ca Cl
HCO SO
Seawater: [SO42-]~2 [Ca2+]; [Mg2+]~ 2 [SO42-] ; [Mg2+]~4 [Ca2+]
[Mg2+..SO42-]aq = Mg2+ + SO42-
Stronger interaction as T increases.

10. Imbibition of modified SW
Effects of SO42-
Crude oil: AN=2.0 mgKOH/g
Initial brine: EF-water
Imbibing fluid: Modified SSW
T = 100 oC
Effcets of Ca2+
Crude oil: AN=0.55 mgKOH/g
Swi = 0;
Imbibing fluid: Modified SSW
Temperature: 70 oC

11. Affinity of Ca2+ and Mg2+ towards chalk
NaCl-brine,
T= 23 oC,
[Ca2+]= [Mg2+]= mole/l
SCN- as tracer
NaCl-brine,
T= 130 oC,
[Ca2+]= [Mg2+]= mole/l
SCN- as tracer

12. Substitution of Ca2+ by Mg2+
Slow injection of SW
1 PV/D
Slow injection of SW without Mg2+
1 PV/D

13. Effects of potential determining ions and temperature on spontaneous imbibition

14. Suggested wettability mechanism

15. Conditions for LoW Salinity effects (Morrow et al. 2006)
Porous medium
Sandstones (not documented in carbonates)
Clay must be present
Oil
Must contain polar components (acids and bases)
Water
FW must contain divalent cations (i. e. Ca2+, Mg2+ …Lager et al. 2007)
Initial FW must be present
Efficiencyn related to Swi
Low Salinity fluid (Salinity: ppm)
Appears to be sensitive to ion composition (Ca2+ vs. Na+)
pH of effluent water usually increases a little, but also decrease in pH has been observed. In both cases, Low Salinity effects were observed.
Are small changes in pH important for Low Salinity effects ??

16. Suggested mechanisms
Wettability modification towards more water-wet condition, generally accepted.
Migration of fines (Tang and Morrow 1999).
Increase in pH lower IFT; type of alkaline flooding (Mcguri et al. 2005).
Multicomponent Ion Exchange (MIE) (Lager et al. 2006).
Small changes in bulk pH can impose great changes in Zeta-potential of the rock (StatoilHydro)

17. Migration of fines
Clay particles are released and transported at the oil-water interface, creating water-wet surface spots.
Can improve sweep efficiency by blocking pores in already water flooded area.
BP observed Low Salinity effects without detecting fines in the produced fluid

18. Chemical reactions affecting pH
Clay acts as cation exchanger
Cation replacing order
Li+<Na+<K+<Mg2+<Ca2+<H+
pH change in solution
Increase in pH by dilution
Ca2+ + H2O = (Ca2+..OH-) + H+
Clay..Ca2+ + H+ = clay..H+ + Ca2+
Decrease in pH by ion exchange
Clay..Ca2+ + Na+ = clay..Na+ + Ca2+
Great buffering effects in real systems

19. Multicomp. Ion Exchange (MIE)
clay
clay
Difficult to write a model chemical reaction illustrating MIE

20. Low Salinity effects non-linear with salinity
Webb, Black, Edmond (2005)
Dead oil
Appears to be an upper critical value for Low Salinity effects
Low Salinity (1000 ppm)
Sea Water Equivalent (30,000 ppm)
Reservoir Brine (80,000 ppm)
It appears to be an upper critical salinity, which the Low Salinity fluid must stay below, to observe the Low Salinity effect

21. Chemical Facts
Wettability modification caused by changes in the aqueous phase.
The thermodynamic equilibrium between the phases (water/oil/rock), which has been established during geological time, is disturbed by changing the salinity of the water.
The solubility of polar organic component in water is affected by ion composition and salinity
Salting Out / Salting In effects
Salinity gradients to optimize conditions for surfactant flooding (oil in water, three-phase, water in oil)
CMC related to salt effects
Adsorption at interfaces (oil-water, water-rock)

22. Salting Out and Salting In effects
Organic material in water is solvated by formation of water structure around the hydrophobic part due to hydrogen bonds between water molecules. (structure makers)
Inorganic ions (Ca2+, Mg2+, Na+) break up the water structure around the organic molecule, and decreases the solubility (structure breakers, Salting Out).
The relative strength of cations as structure breakers is reflected in the hydration energy
Decrease in salinity below a critical ionic strength will increase the solubility of organic materials in the aqueous phase. This is called Sating In effect.

23. Hypothesis
The main mechanism for Low Salinity effects is related to changes in the solubility of polar organic components in the aqueous phase, described as a “Salting In” effect.

24. (1) Experiments to verify the hypothesis
Low Salinity fluid should be characterized in terms of Ionic strength rather than salinity
Compare Low Salinity effects using NaCl and CaCl2 ( [CaCl2] = ½ [NaCl] )
If the Low Salinity effect is quite similar for the two fluids, the Low Salinity mechanism is more linked to solubility properties rather than MIE at the rock surface.

25. (2) Experiments to verify the hypothesis
No correlation between AN and Low Salinity effect (Lager et al. 2006)
According to the hypothesis, the desorbed organic material must be partly soluble in water
Test Low Salinity effects for oils with and without water extractable acids and bases present.
Is there a correlation between AN and BN of extractable acids and bases and Low Salinity effect ???

26. (3) Experiments to verify the hypothesis
Test the difference in hysteresis for the adsorption and desorption of substituted benzoic acid onto kaolinite using FW and Low Salinity fluid.
Difference in hysteresis will reflect difference in solubility properties for FW and Low Salinity water
Temperature effects ?
Effects of Low Salinity fluid composition ??
+ Kaolinite

27. Conclusion on “Smart Water”
Carbonate
The chemistry of fluid-rock interaction is well characterized
Wetting agent: Carboxylic materials, difficult to remove
Wettability modifiers: Ca2+, Mg2+, SO42-, Temp.
Wetting modification at SW-salinity, which is not regarded as a Low salinity fluid.
Sandstone
The chemistry of fluid–rock interaction is more complicated
The organic material adsorbs differently onto clay minerals, but it is more easily removed compared to carbonates.
So fare, no single proposed mechanism has been clearly accepted for the observed Low Salinity effect.
A hypothesis involving “Salting In” effects has been suggested, and actual experiments are proposed to verify the hypothesis.

28. Conclusion on “Smart Water”
The chemical mechanism for using “Smart Water” for wettability alteration to enhance oil recovery is different for Carbonates and Sandstones.