In an increasingly energy-hungry world, the demand for oil continues to rise yet the supply is not limitless. It is becoming more and more challenging to find new oilfields from which oil can be extracted in adequate quantities. Currently identified supplies of crude oil are anticipated to be sufficient to meet energy needs for around 50 years.
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Techniques for increasing the amount of oil recovered are thus being adopted to extend the capacity of oil reserves, whereby delaying the need to identify new giant fields. The global average for oil recovery from existing oilfields is only between 20% and 40%, less than half the recovery rates typically achieved in gas fields. It has been estimated that improving oil recovery to match that of gas could more than double the time for which oil will be available. This would mitigate the issue of meeting energy demands by providing more time to develop alternative energy sources and technologies.
Enhanced oil recovery (EOR) techniques are thus of increasing importance and being deployed extensively across oilfields worldwide1.
Enhanced oil recovery
Oil is extracted by pressure gradients within the reservoir forcing the oil to flow into the production well. As the supply of oil diminishes the natural pressure gradient is lost and less oil is recovered. There are many techniques available for increasing oil recovery, which have demonstrated sustained increases in oil production rates2.
Water flooding is generally the preferred option for enhanced oil recovery due to the ready availability of sea water at oilfields. This involves injecting water into the oil reservoir to displace the oil and force it to flow into the production well. The efficiency of water flooding can be increased by adding polymers to the injected water, a practice known as polymer flooding. The presence of the polymer increases the viscosity of the injected water, which reduces the difference in the speeds at which the water and oil travel and minimizes the tendency of water to finger through oil3. This in turn results in more oil being pushed towards the production well and significantly improves oil recovery.
Typically synthetic polymers are used by the oil industry for polymer flooding. Historically these were unhydrolyzed polyacrylamide-based polymers, selected because of their good chemical stability. However, it became apparent that these polymers did not increase viscosity substantially and showed a high level of adsorption onto mineral surfaces. Consequently, the increases in recovery rates were not huge and lost polymer was continually needing to be replaced.
Today, partially hydrolysed polyacrylamide (HPAM) polymers are the most commonly used type of polymer. The conversion of some of the amide groups on the polyacrylamide to carboxylate groups provides greater viscosity, even when low concentrations of polymer are added to the injected water4. In addition, polymer loss is lower since the carboxyl groups of HPAM are repelled by the negatively charged sandstone thus reducing adsorption of the polymer to the rock surfaces.
There are, however, concerns regarding the ongoing viability of HPAM polymer flooding. The long-term stability of HPAM has not been assessed, yet the process of polymer flooding can last many months. There is thus the potential for degradation of the polymers to cause a reduction in viscosity, and consequently oil recovery rates. Furthermore, in oil reservoirs with a high temperature and/or high salinity thermal degradation and high adsorption levels are encountered. In addition, high reservoir temperatures can promote hydrolysis of more HPAM amide groups, leading to a reduction in viscosity.
There is consequently a need for new polymers that can resist hydrolysis at high temperature to optimise EOR by polymer flooding.
Evaluation of new polymers
A recent study evaluated four new polymers for signs of reduced viscosity over time at high temperature, with varying degrees of salinity and hardness5. The polymers tested were modified HPAM-based co-polymers functionalized with 2-acrylamido-2-methylpropane sulfonate (AMPS) monomers.
The sulfonated polyacrylamide co-polymers FLOCOMB C7035, AN132 VHM, SUPERPUSHER SAV55, and THERMOASSOCIATIF were aged at 80˚C for 90 days with and without an antioxidant. The evaluations were conducted in parallel using either CaCl2-NaCl or NaCl as the sample solvent.
The polymers were analysed after 90 days in powder form by Fourier transform infrared (FTIR) spectroscopy using a Nicolet™ 10 FTIR spectrometer and in D2O aqueous solution by nuclear magnetic resonance (NMR) using a Bruker 500 NMR spectrometer.
The polymer samples without antioxidant showed a severe reduction in viscosity in both NaCl and CaCl2-NaCl. THERMOASSOCIATIF started degrading immediately, whereas the others maintained their viscosity for at least 7 days.
When antioxidant was present, all polymer samples prepared in the NaCl medium showed an increase in viscosity with aging. In the CaCl2-NaCl samples, viscosity reduced for all polymers except AN132 VHM despite the presence of antioxidant. In contrast, AN132 VHM prepared in CaCl2-NaCl showed a viscosity increase after 90 days of aging. This indicates that the viscosity increase rate due to polymer hydrolysis was higher than the viscosity reduction rate due to the presence of divalent ions in the solution.
- Udy J, et al. Processes 2017, 5, 34; doi:10.3390/pr5030034
- Oil and Gas Authority 2017. Available at https://www.ogauthority.co.uk/media/4283/polymer-eor-industry-starter-pack-ver3.pdf
- Sheng JJ, et al J Can Pet Technol 2015;54:116–126.
- Hashmet MR, et al. J Dispers Sci Technol 2013;35:510–517.
- Akbari S, et al. Polymers 2017;9:480‑494.
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