Enhancing Oil Recovery from Chalk Reservoirs by a Low-Salinity Water Flooding Mechanism and Fluid/Rock Interactions
Abstract
:1. Introduction
2. Experimental
2.1. Materials
2.1.1. Porous Media
2.1.2. Oil
2.1.3. Brines
2.1.4. Core Preparations and Flooding
3. Results and Discussion
3.1. Oil Recovery from Secondary Flooding with LS
- (1)
- Higher fluctuations were observed at 16 PV/day than 4 PV/day in the case of LSW 1:10 and 1:50 flooding. This may mean occasional resistance to the flow, hence a possible increase of the sweep efficiency.
- (2)
- The magnitude of dP was higher in case of dilution ratio 1:50 than 1:10, this is perhaps due to a higher availability of Ca2+ promoting precipitation of sulfate salt over the limit if diverting flow increasing the trapped oil.
- (3)
- Higher recovery in the case of dilution ratio 1:10 than 1:50, which has also been observed in the case of sulfate salt single brine flooding may support the above point (2). In [14], several dilutions of LSW were investigated and concluded that the dilution of 1:10 gave the best incremental oil recovery.
3.2. Ion Tracking from Secondary Flooding by LS Brines
4. Summary and Conclusions
- (1)
- Experimentally it is concluded that oil recovery response time depends on the ion dilution factor of the brine. LSW 1:10 gives earlier response than the LSW (1:50).
- (2)
- Divalent Ions have an effect in wettability alteration. Ca/Mg contributes largely in enhancing the sweep efficiency. But this effect increases in presence of SO42−. Highest recovery is obtained while flooding with SO4 brine than any other brine which shows that the presence of sulfate ion may contribute to the wettability alteration.
- (3)
- Increase in ion concentrations of Mg2+ and Ca2+ in the later part of modified brine injection confirms ion exchange between the ions and thus precipitation of magnesium.
- (4)
- 10 times SSW dilution ratio gives the best outcome. This is also in agreement with the case of single salt brine injection. For SO4 1:10 dilution, higher recovery was obtained compared to that with SO4 1:50.
- (5)
- Pressure drop in the secondary flooding may indicate fine migration during injection of single salt brine and LSW, though fines were not observed in the effluent samples during our experiments. This may be due to size of the particles being too small to be observed or the migration took place in the core, fines were trapped and the pressure was not high enough to overcome the trapping resistance of the particles.
Acknowledgments
Author Contributions
Conflicts of Interest
References
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Oil Used in Saturation of Cores | Core | Length (cm) | Diameter (cm) | swi (%) | sor (%) | Pore Volume (mL) | Porosity (%) | Flooding Sequence of Brines in the Core |
---|---|---|---|---|---|---|---|---|
Model Oil (n-decane + stearic acid, SA) | 1 | 5.92 | 3.78 | 23 | 24.4 | 34.23 | 51.8 | SSW/SO4 (1:10) |
2 | 6.01 | 3.78 | 21 | 35.8 | 34.23 | 51.8 | SSW/Mg (1:10) | |
4 | 5.95 | 3.78 | 22.3 | 32.2 | 31.94 | 50.12 | SSW/SO4 (1:50) | |
7 | 6.00 | 3.78 | 21.8 | 40.2 | 34.8 | 52.22 | SSW/Mg+Na (1:10) | |
8 | 6.00 | 3.78 | 28.5 | 23.1 | 33 | 50.99 | SSW/Mg (1:10) at 90 °C | |
Crude Oil X | 5 | 6.008 | 3.78 | 19.01 | 32.5 | 32.50 | 50.55 | SSW/LSW (1:10) |
6 | 6.00 | 3.78 | 21.1 | 38.4 | 34.50 | 52.04 | SSW/LSW (1:50) |
Property | Temperature | Model Oil (n-decane + 0.005M SA) | Crude Oil X |
---|---|---|---|
Density (g/cc) | 20 °C | 0.73 | 0.7827 |
50 °C | 0.705 | 0.7009 | |
70 °C | 0.67 | 0.7537 | |
Dynamic Viscosity (cP) | 70 °C | 0.41 | 0.4976 |
Components | Mole Fraction |
---|---|
i-C5 | 1.79 × 10−5 |
n-C5 | 0.000117 |
C6 | 0.002371 |
C7 | 0.013287 |
C8 | 0.039608 |
C9 | 0.062886 |
C10 | 0.881712 |
Ions/Brine | SSW | LSW 1:10 | LSW 1:50 | Mg+Na | SO42− Brine | SO42− Brine | Mg2+ Brine |
---|---|---|---|---|---|---|---|
(mole/L) | (mole/L) | (mole/L) | 1 to 10 | 1 to 10 | 1 to 50 | 1 to 10 | |
(mole/L) | (mole/L) | (mole/L) | (mole/L) | ||||
HCO3− | 0.002 | 0.0002 | 0.00004 | ||||
Cl− | 0.525 | 0.0525 | 0.0105 | 0.0493 | 0.009 | ||
SO42− | 0.024 | 0.0024 | 0.00048 | 0.0024 | 0.00048 | ||
Mg+2 | 0.045 | 0.0045 | 0.0009 | 0.0045 | 0.0045 | ||
Ca+2 | 0.013 | 0.0013 | 0.00026 | ||||
Na+ | 0.45 | 0.045 | 0.009 | 0.0403 | 0.0046 | 0.00092 | |
K+ | 0.01 | 0.001 | 0.0002 | ||||
TDS (ppm) | 33,388 | 3338.8 | 667.76 | 2785 | 336.2 | 67.24 | 423 |
TDS (g/L) | 33.33 | 3.33 | 0.667 | 2.78 | 0.336 | 0.067 | 0.423 |
Ionic Strength | 0.657 | 0.0657 | 0.01314 | 0.0538 | 0.007 | 0.0014 | 0.0135 |
pH | 7.83 | 7.32 | 6.74 | 5.85 | 7.12 | 6.74 | 6.11 |
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Hamouda, A.A.; Gupta, S. Enhancing Oil Recovery from Chalk Reservoirs by a Low-Salinity Water Flooding Mechanism and Fluid/Rock Interactions. Energies 2017, 10, 576. https://doi.org/10.3390/en10040576
Hamouda AA, Gupta S. Enhancing Oil Recovery from Chalk Reservoirs by a Low-Salinity Water Flooding Mechanism and Fluid/Rock Interactions. Energies. 2017; 10(4):576. https://doi.org/10.3390/en10040576
Chicago/Turabian StyleHamouda, Aly A., and Sachin Gupta. 2017. "Enhancing Oil Recovery from Chalk Reservoirs by a Low-Salinity Water Flooding Mechanism and Fluid/Rock Interactions" Energies 10, no. 4: 576. https://doi.org/10.3390/en10040576