“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.

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

“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)

Chalk: SW as “smart water”

Sandstone: Low Salinity flooding (15,000 ppm) (1,500 ppm) By: Webb et al. 2005.

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

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

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 - - - - Ca2+ Ca2+ Ca2+ + + + + + + + - - - - SO42- SO42- SO42- - - - - -

Model composition of FB and SW Comp. Ekofisk Seawater (mole/l) (mole/l) Na+ 0.685 0.450 K+ 0 0.010 Mg2+ 0.025 0.045 Ca2+ 0.231 0.013 Cl- 1.197 0.528 HCO3- 0 0.002 SO42- 0 0.024 Seawater: [SO42-]~2 [Ca2+]; [Mg2+]~ 2 [SO42-] ; [Mg2+]~4 [Ca2+] [Mg2+..SO42-]aq = Mg2+ + SO42- Stronger interaction as T increases.

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

Affinity of Ca2+ and Mg2+ towards chalk NaCl-brine, T= 23 oC, [Ca2+]= [Mg2+]= 0.013 mole/l SCN- as tracer NaCl-brine, T= 130 oC, [Ca2+]= [Mg2+]= 0.013 mole/l SCN- as tracer

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

Effects of potential determining ions and temperature on spontaneous imbibition

Suggested wettability mechanism

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: 1000-2000 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 ??

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)

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

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

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

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

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)

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.

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.

(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.

(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 ???

(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

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.

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