Adjustable, Supramolecular Viscosity Modifiers as Displacement Fluids in EOR

We report a novel type of viscosity modifier relying on the supramolecular assemblies that have pH-adjustable viscosities and robust tolerance against high temperatures and salinities, and are resistant to shear-induced degradation. This technology is developed collaboratively by Texas A&M University, Incendium Technologies, and VaalbaraSoft.

When reservoir oil is displaced by plain waterflooding, the injected water fingers through the reservoirs because of the high mobility ratio (Rachford Jr. 1964). Water fingers leave most of the oil behind, which leads to inefficient oil recovery. Hence, the viscosity modifiers are often added in the displacing fluid, (i.e., water) to better match the viscosity of reservoir oil and enable a uniform advance of the waterfront to effectively sweep the reservoir oil.

Currently, for oil recovery applications, most commonly used viscosity modifiers are water-soluble polymers such as hydrolyzed polyacrylamide, polyvinyl alcohol, and poly(vinylpyrrolidone) (Taylor and Nasr-El-Din 1998). Likewise, water-soluble biopolymers, in particular polysaccharides such as xanthan and guar, are also used in some fields (­Alquraishi and Alsewailem 2012).

Current Technology Limitations

While the above-mentioned viscosity modifiers can satisfy part of the oil recovery needs, these polymers still experience some challenges that hinder their effectiveness. For example, when the viscosity of reservoir oil is high, so should the displacing fluid be to match the mobility ratio. The current heuristics suggest that polymer flooding should be applied in reservoirs with oil viscosities between 10 and 150 cP (Taber et al. 1997).

The key factor limiting the recommended range is that for oil viscosities greater than 150 cP, the injected-water-viscosity values required for a favorable mobility ratio correspond to prohibitively low values of polymer injectivity. In addition, pumping high-viscosity displacing fluids tends to lead to clogging in oil wells, which results in a major economic well operating loss. 

One potential solution is to use displacement fluids with an adjustable viscosity, with the fluid having a low viscosity at the injection site and a high viscosity upon reaching the oil phase. Furthermore, having an adjustable-­viscosity displacement fluid can help to reduce pumping-related operational costs because pumping efficacy generally decreases as fluid viscosity increases. The above-mentioned polymers do not offer viscosities that can be controlled in such a fashion.

It is also well-established that both polymer- and biopolymer-based viscosity modifiers usually degrade under high salinity and high temperatures. Likewise, high shear rates experienced during the flow of displacement fluids can lead to a shear-induced breakage of polymer chains. Such chemical fragmentation is accompanied by the permeant loss of viscous properties.

Limitations Overcome

In this work, we describe a novel adjustable viscosity modifier that can overcome the limitations of polymer-based ­viscosity modifiers. The technology is based on the complexation and supra­molecular assembly of a long-chain ­amino-amide and a dicarboxylic acid.

There are several key advantages of this viscosity modifier.

1. It allows the increase of viscosity by 12-fold by means of changing pH from 4 to 8 in a reversible manner.
2. Many oil reservoirs contain connate water with high concentrations of sodium chloride and divalent ions. Hence, high salt tolerance is a critical factor in the design of viscosity modifiers. For the supramolecular solution, there is no significant change (<10%) in the viscosity observed up to 5 wt%  salinity at typical shear rates experienced during the sweeping processes.
3. In oil reservoirs, the temperature increases with depth because of the geothermal gradient. Hence, viscosity modifiers should have high tolerance and low sensitivity to temperature. The viscosity of a supramolecular solution is less sensitive (about three times so) to temperature changes than that of polyacrylamide solution.
4. For a given pH, the viscosity of the supramolecular solution can also be strongly controlled, in the range of 100–100,000 cP, with the solution concentration.
5. Supramolecular assemblies involve weak intermolecular interactions (“physical bonds”) rather than covalent bonds, as in the case of polymer chains. Hence, while polymers permanently degrade and break up upon experiencing sudden extreme shear stresses and temperatures, supramolecular solutions merely disassemble and reassemble. For instance, when high-molecular-weight polymer macromolecules are forced to flow into narrow channels and pores, molecular scission processes may take place (Muggeridge et al. 2014).  Supramolecular solutions can adapt to the confining environment. Hence, supramolecular solutions can be considered as healable polymer solutions in a way.

Oil recovery efficiencies of water, supramolecular viscosity modifier (0.4 wt%), and polyacrylamide solution (0.4 wt%) are compared at three different pH values using laboratory sand column experiments (Figs. 1a through 1c) (Chen et al. 2014). The supramolecular solution shows a much higher displacement efficiency compared with water and polyacrylamide solution at basic pHs. Based on these trends, this technology is envisioned for use mainly in basic oil fields such as carbonate reservoirs.

The concept of using these novel gellants in oil recovery applications is that the viscosity of the injected system will be maintained at initially low values for easy injection and efficient pumping, and then increased by means of an external pH stimulus just before contacting oil (Fig. 2 above). The pH change can occur either naturally if the reservoir is basic such as a carbonate reservoir or can be induced externally using an acid or base slug.

Overall, there is a significant potential for application of supramolecular solutions in the United States and throughout the world. This is especially important because the current analysis indicates that 50% of the oil produced in the US and the world in the next 20 to 25 years will occur through the use of enhanced-oil-recovery technologies.

References

Alquraishi, A.A. and Alsewailem, F.D. 2012. Xanthan and Guar Polymer Solutions for Water Shutoff in High-Salinity Reservoirs.Carbohydr. Polym. 88 (3): 859–863.

Chen, I., Yegin, C., Zhang, M. et al. 2014. Use of pH-Responsive Amphiphilic Systems as Displacement Fluids in Enhanced Oil Recovery.SPE J. 19 (6) Preprint.

Muggeridge, A., Cockin, A., Webb, K. et al. 2014. Recovery Rates, Enhanced Oil Recovery and Technological Limits. Phil. Trans. R. Soc. A. 372 (2006)

Rachford Jr., H.H. 1964. Instability in Waterflooding Oil From Water-Wet Porous Media Containing Connate Water. SPE J. 4 (2): 133–148.

Taber, J.J., Martin, F.D., Seright, R.S. 1997. EOR Screening Criteria Revisited–Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects. SPE Res. Eng. 12 (3): 189-198.

Taylor, K.C. and Nasr-El-Din, H.A. 1998. Water-Soluble Hydrophobically Associating Polymers for Improved Oil Recovery: A Literature Review. J. Pet. Sci. Eng. 19 (3–4): 265–280.