The oil left behind in un-swept areas due to heterogeneities in the reservoir and viscous fingering is the target for polymer-flooding. Certain polymers (due to elastic properties) can exert normal forces, affecting capillary trapped oil.
However, if these effects are significant to reduce the residual oil saturation (improve the microscopic sweep) and lead to additional oil production beyond the effect expected from a pure viscosity increase, is still a matter of debate (Azad & Trivedi, 2019, 2020; Sheng et al., 2015).
Adding polymer to the injected water will both increase the viscosity and reduce the permeability; hence sweep is improved, water break through is delayed and oil production is accelerated.
1.3.1 Polymers’ effect on Mobility ratio
The reason for the poor macroscopic sweep (both due to heterogeneities in the reservoir and viscous fingering) is simply the ease of which the different phases move in the reservoir, i.e., their mobility. How mobile a phase will be is dictated by the reservoir rock’s permeability, 𝑘 towards that phase at residual saturation of the other phase and the viscosity, 𝜂 of the phase at prevailing conditions. The mobility, 𝜆 is defined as:
𝜆 =𝑘
𝜂. (1)
If the displacing phase (e.g., water or polymer solution) has a higher mobility, i.e., moves easier in the reservoir, than the displaced phase (oil), it will naturally reach the producer faster, and have contacted less of the reservoir volume, compared to when it is the displaced phase that has the higher mobility. Thus, the areal sweep will depend on the mobility ratio, Ψ the ratio of the mobility of the displacing and displaced phase. In the following the subscribed 𝑤, 𝑜 and 𝑝 are used for water, oil, and polymer solution, respectively. In this work, the symbol Ψ is used for the mobility ratio instead of the more commonly used 𝑀, to avoid confusion with the molecular weight (introduced later).
Ψ =𝜆𝑤
𝜆𝑜 = 𝜂𝑜
𝜂𝑤 𝑘𝑤
𝑘𝑜. (2)
Decreasing the mobility ratio will smooth the displacement front, whether the irregularity of the waterfront is caused by viscous fingering or heterogeneities, (that is water breaking through in high permeable zones). Viscous fingering is caused by the self-reinforcing nature of random instabilities, since it is easier for the water to move where water is already at a higher saturation, as the water permeability, 𝑘𝑤 is strongly dependent on the water saturation, 𝑠𝑤, as illustrated in the generic relative permeability plot in Figure 2.
Figure 2 Generic relative permeability curve.
0 0.2 0.4 0.6 0.8 1
0.0 0.2 0.4 0.6 0.8 1.0
Relative permebilty, kro and krw
Water saturation, sw
krw kro
different mobility ratios. From Darcy’s law for 1 dimensional, linear flow (e.g., a cylindrical core) the fractional flow of water, 𝑓𝑤 will be given by:
𝑓𝑤(𝑠𝑤) ≝ 𝑞𝑤
𝑞𝑜+𝑞𝑤=
𝑘𝑤(𝑠𝑤) 𝜂𝑤
⁄ 𝑘𝑤 (𝑠𝑤)
𝜂𝑤
⁄ +𝑘0 (𝑠𝑤) 𝜂𝑜
⁄ . (3)
Using the synthetic relative permeabilities in Figure 2 and changing the water viscosity, the fractional flow of water as a function of oil saturation is shown in Figure 3. It is plotted against the oil saturation to illustrate that for the same fractional flow of water, the oil saturation in the core decreases with decreasing mobility ration, showing that more of the oil has been produced for a lower water mobility, even for the simple case of a homogeneous linear core. For example, at a water cut, 𝑓𝑤 of 80%, at lowest water viscosity, that is highest mobility ratio, the oil saturation left in the core is 58%. If the water viscosity is increased so that the mobility ratio is reduced to 0.7, the oil saturation at the same water cut will be 52% and will be reduced further to approximately 47%
if the water viscosity is increased further to twice the viscosity of the oil, illustrating that for the same water cut, more of the oil will have been produced if the water viscosity is increased.
Figure 3 Fractional flow of water as a function of oil saturation for different mobility ratios.
Above, we have only looked at the viscosity change. The polymer will in most cases also change the permeability, due to adsorption and entrapment of
polymer molecules, so that 𝑘𝑝 < 𝑘𝑤. This will further improve the mobility ratio compared to what is expected from only viscosity considerations.
The permeability reduction effect will also be maintained during the post polymer water flood, positively influencing the sweep. A detailed description of the mechanisms improving the sweep can be found in Sorbie (1991).
A water-soluble polymer will also impact the water permeability more than the oil permeability, an effect often taken advantage of in disproportional permeability reduction-operations (DPR) (Langaas & Stavland, 2020; Stavland
& Nilsson, 2001).
1.3.2 Field considerations and challenges
Presently, polymer flooding is the most common water-based method for enhanced oil recovery (Sheng et al., 2015). The first pilot was performed as early as 1959 and indicated that the method would be profitable (Pye, 1964) and that the behaviour and results was as expected from the then prevailing theory (which is not much different from today’s theory).
Literature reviews by Standnes and Skjevrak (2014) and Manrique et al. (2017) of polymer project have revealed that polymer projects are more efficient the earlier they are implemented. Although there may be good reasons for a preceding water flood (understanding the reservoir, calibrate models, establish base line, etc.), injecting polymer solutions in secondary mode will in terms of oil production and reduced water production usually be preferable.
Accordingly, the abbreviation “EOR” is sometimes said, in a humoristic yet cautionary manner, to mean “Early Or Regret”.
As mention, an additional advantage of polymer injection is the reduced/delayed water production, reducing the energy and effort needed to lift, separate, rinse and re-inject huge amounts of dirty, often radioactive water. On the other hand, there is also a substantial downside of potentially producing polymer solution, but if the project is successfully designed, this will happen at a later stage, when much more of the oil in place has been produced.
issues related to polymer flooding. Among the successes criteria are implementing the method early, large enough volumes injected, and maintaining high enough injection rates. To maintain high enough injection rate, a reduction in injected viscosity may be necessary, which will be a compromise between desired mobility reduction and reasonable injectivity.
Among the problematic issues are premature production of polymer causing equipment failure and difficulties in separating oil and water, formation damage, injectivity loss, poor compatibility with mixing water (“make-up water”) or formation water, and loss of viscosity due to chemical, thermal, or mechanical degradation of the polymer. HPAM (hydrolyzed polyacrylamide) is the most used polymer for EOR and is, as will be discussed later, susceptible to mechanical degradation when subjected to shear and elongational stress which can occur in the porous media of the formation and in equipment. In porous media synthetic polymers are also prone to shear-thickening at high, near well velocity, which can result in injectivity problems.