1. Petroleum & Natural Gas Eng. Dept.
2008 SPE Saudi Arabia Section Technical Symposium
Investigation of Polymer Adsorption on Rock Surface of High Saline Reservoirs
Mohammed M. Amro
Petroleum & Natural Gas Eng. Dept.
King Saud University

2. Outline Introduction Oil Recovery Methods Experimental Work Summary
EOR Mechanisms
EOR Processes
Experimental Work
Experimental Procedures
Material Used
Results and Discussion
Summary

3. Causes for Poor Recovery
Physical Reasons:
Existence of the interfacial tension between oil and water, and wettability (capillary forces)
High mobility ratio between water and oil (viscous forces)
Geological Reason:
The heterogeneities in the reservoir rock

4. EOR Mechanisms The mechanisms of EOR:
Eliminate or reduce capillary and Interfacial tension to improve the displacement efficiency
Improve sweep efficiency by reducing the mobility ratio between injected and displaced fluids (Polymer, Thermal)
Act on both phenomena at same time (Nc)

5. Ratio of viscous forces to capillary forces
Capillary number
= Displacing fluid velocity [m/day]
= Displacing fluid viscosity [mPa.s]
s = Interfacial tension [mN/m]
Assumptions for waterflooding
Velocity = 1 m/day
Viscosity= 1 mPa.s
Interfacial tension o/w = 20 mN/m
Nc = 0.57*10^-6
In a reservoir, it is not practical to increase the pressure differential between producer and injector wells during water flooding. Infill drilling can reduce the distance between the wells by no more than a factor of two to four. This is usual process to increase the productivity of a reservoir. However, the reduction of is based on the economical aspects. Therefore, the only practical method of increasing the capillary number is to reduce the interfacial tension.
If the Nc can be increased of four orders of magnitude or more, residual oil saturation will be reduced significantly.
For waterflooding, Nc is 10-6 to 10-7 (under certain assumptions)
If the Nc can be increased to 10-4 to 10-2,
the residual oil saturation will be reduced significantly.

6. EOR Processes Tertiary Recovery Thermal Chemical Miscible/ Immiscible
Other
Steam drive
Steam stimulation
Hot water
In-situ combustion
Polymer
Surfactant
Caustic
Combination
CO2
Inert gas
Miscible Solvent
Flue gas
Microbial
Vibration
Electrical
Miscible solvent such as LPG, lean gas, alcohol
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7. Chemical Flooding
Offers good opportunity to maximizing the reserves in many depleted and waterflooded reservoirs
Opportunities exist under economic conditions and current oil prize
Chemical Properties Desirable:
Good solubility (low concentration)
High injectivity
Long-term stability against:
Electrolytes, - Bacteria, - Temperature
Oxidation, - pH-Value changes
Low adsorption on the rock, special focus on carbonate reservoirs (Polymer flooding)
Simple handling and Low cost

8. Polymer Flooding Decreasing the mobility ratio (M)
Influence on volumetric sweep efficiency EV
EV =EA EI
Therefore, ED→Sorw will be reached more faster
EA = Areal efficiency and
EI = vertical sweep efficiency

9. Mathematical Description of Polymer Rheology
Effective water viscosity
Effective polymer viscosity
Assumption: Vw = Vp (No ‘‘Inaccessible Pore Volume‘‘ for polymer)
The resistance factor describes the ratio of the mobility of water to the mobility of polymer solution
Case 1: Only viscosity increase : Kw = Kp
16-Apr-17

10. Mathematical Description of Polymer Rheology
Case 2: Viscosity increase and permeability decrease:
RRF describes the ratio of the mobility of water measured before the injection of polymer solution to the mobility of water after polymer injection.
Residual resistance factor (RRF)

11. Resistance factor (RF) and Residual resistance factor (RRF)
RF & RRF are important factors to determine the concentration of polymer needed to perform polymer flooding (e.g. RF = & RRF = 1.5) or water shut off (Rf = 6 & RRF = 4).

12. Experimental Procedure
Polymer solutions were prepared and evaluated at different salinities, shear rates, temperatures and concentrations.
Core samples were flooded with polymer solutions (const. flow rate = 2.5 ft/day) until full adsorption (const. Pressure drop and const. effluent viscosity); RF was calculated
The core samples were flooded with brine (Pressure drop and effluent viscosity were monitored); RRF was calculated.

13. Experimental Work Polymers (Xanthan, PAA), Biocide (Formaldehyde)
Brine (83% NaCl and 17% CaCl2)
Core samples (Berea SS with different K
ranged from 200 – 1300 mD)
Flooding apparatus.

14. Results and Discussion
Effect of Shear Rate and Salt Concentration on Polymer Solution Viscosity

15. Viscosity of polymer solution of different xanthan concentrations in 10% brine.
Increasing the shear rate reduces the polymer solution viscosity. At shear rate higher than 40 s-1, the effect of polymer concentration will be vanished. This means that increasing the shear rate drastically reduces the effect of polymer concentration

16. Effect of Salt concentration on Xanthan viscosity (14.7 s-1)

17. Effect of Salt concentration on PAA viscosity (14.7 s-1)

18. Resistance Factor (RF) & Residual Resistance Factor (RRF); Xanthan

19. Resistance Factor (RF) & Residual Resistance Factor (RRF); PAA

20. Effect of Injection Rate (Xanthan)

21. Effect of Injection Rate (PAA)
3000 ppm & 5% Brine

22. Effect of Temperature

23. RF & RRF (60 °C)

24. Polymer Accumulation

25. Conclusions
The viscosity decreases with increasing the shear rate up to a certain value beyond which it becomes almost constant.
Xanthan viscosity is more affected by the shear rate rather than salt concentration, while PAA viscosity depends strongly on both factors.
A reduction of permeability using polymer solution depends on the porous medium, the particular polymer, concentration of polymer, salinity, and injection rate.
Polyacrylamide (PAA) can reduce the heterogeneity in reservoir at low salinity. High PAA concentration will be needed to tolerate the high salinity.

26. Cont. Conclusions
Partially reversible adsorption (physical) from the rock surface occurred by brine flooding (RRF).
The flooding velocity and the permeability have great effect on the adsorption.
The temperature increase leads to delay the full adsorption on the rock surface. Therefore, more PV of solution is necessary .
Thus, xanthan can be recommended, as a good polymer candidate to be used in high salinity reservoirs.

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