Injection of steam has historically been the most widely applied EOR method. Heat from steam or hot water dramatically reduces heavy oils viscosity, thus improving its flow. The process involves: cyclic steam injection (“huff and puff”, where steam is first injected, followed by oil production from the same well); Continuous steam injection (where steam injected into wells drives oil to separate production wells); hot water injection, and steam assisted gravity drainage (SAGD) using horizontal wells, among others.

Miscible EOR employs supercritical CO₂ to displace oil from a depleted oil reservoir. CO₂ improve oil recovery by dissolving in, swelling, and reducing the viscosity of the oil. In deep high-pressure reservoirs, compressed nitrogen has been used instead of CO₂. Hydrocarbon gases (natural gas and flue gas) have also been used for miscible oil displacement in some large reservoirs. These displacements may simply amount to “pressure maintenance” in the reservoir42. CO₂ miscible flooding in crude oil reservoirs is a successful technique to reduce its amount in the atmosphere, in addition to increasing the mobility of the oil and, consequently, increase the reservoir productivity. It is preferred other than hydrocarbon gases since it does not only increase oil recovery but also causes a reduction of greenhouse gas emissions. Moreover, it is a cheap technology as an ultimate long-term geologic storage solution for CO₂ owing to its economic productivity from incremental oil production offsetting the cost of carbon sequestration, and exhibit high displacement efficiency and the potential for environmental contamination decrease through its disposal in the petroleum reservoir43.

Chemical flooding involves the injection of an agent not normally present in the reservoir to enhance the oil displacement. The chemical flooding processes involve the injection of three kinds of chemicals; alkaline, surfactant, and polymer (soluble and cross-linked polymers), in addition to other chemicals such as foaming agents, acids and solvents19 and/or combination of alkaline-surfactant-polymer flooding (ASP), and surely the most important substance in these methods is polymer flooding44. In the polymer flooding method, water-soluble polymers aimed to shut-off the high-permeability areas of the reservoir and increase injected water viscosity to increase the swept areas in the reservoir 45 leading to a more efficient displacement of moderately viscous oils. Addition of a surfactant to the polymer formulation may, under very specific circumstances, reduce oil-water interfacial tension and hence remobilizing the trapped oil 46, changing the wettability of the surface, forming emulsions, so enhance the oil production. For some oils, alkaline may convert some naphthenic acids within the oil to surfactants due to the formation of in-situ surfactant. The alkaline may also play a beneficial role in reducing surfactant retention in the rock. For all chemical flooding processes, the inclusion of a viscosifier (usually a water-soluble polymer) is required to provide an efficient sweep of the expensive chemicals through the reservoir.

Polymer flooding can be carried alone or in combination with other fluids such as alkaline materials for solubilizing the oil and comprise sodium carbonate, caustic soda, borate, and metaborate compounds, silicates, metasilicates, amines, basic polymeric species, or by combination with surfactant molecules3. Polymer flooding can increase recovery up to 5-30% OOIP 54. Polymer flooding process involves the injection of polymer “slug” followed by continued long-term water flooding to drive the polymer slug and the oil bank in front of it toward the production wells as shown in Figure 5. When water is injected into a reservoir, it seeks the path of least resistance (usually the layers of highest permeability) to the lower pressure region of the offset producing wells. If the oil in place has a higher viscosity than the injected water, the water will finger through this oil and result in a low sweep efficiency, or bypassed oil. Flooding tests generated according to the following steps; 1) The sand was firstly cleaned and evacuated then saturated by brine for 14 days followed by oil saturation, then brine flooded until oil cut ceased (i.e. oil cut <1%) and the residual oil amount calculated; 2) the polymer solution with different slug concentrations was flooded at simulated reservoir temperature to determine recovery factor.

One of the routine screening parameters used for a preliminary analysis of a reservoir is the mobility ratio that represents effects of relative permeability and viscosity of water and oil on mobility based on Darcy’s Law 44.

……. (1)

Where

Mobility ratio (M) is defined as mobility of the displacing phase divided by the mobility of the displaced phase. Water-soluble polymer reduce water mobility through different mechanisms: (1) increase the water phase viscosity; 2) reduce the relative permeability of water to the porous rock by adsorption/retention of the polymer in the rock pore throats56 and thereby creating a more efficient and uniform front to displace unswept oil from the reservoir; 3) Another parameter is the viscoelasticity associated with the use of high Molecular weight (M_w) or associative polymers which will recover additional entrapped oil compared to a conventional Newtonian fluid injection357. With a reduced mobility ratio, the sweeping efficiency is increased and, as a consequence, oil recovery is enhanced58. If the mobility ratio (M ≤ 1), the sweeping and displacement efficiencies of the oil by the water phase will be efficient and pistons like fashion 59. By contrast, if the mobility ratio (M > 1), is considered “unfavorable” and unstable because the more mobile displacing fluid will flow more readily than the displaced fluid, and lead to serious viscous fingerings or channel through the oil causing “breakthrough” leaving behind regions of unswept oil. As a result, some of the residual oil is bypassed resulting in poor recovery60. There is also a secondary effect, in which the polymer restores part of the reservoir pressure after its passage (residual resistance factor) 58. This occurs because the polymer builds up a resistance to flow in the portions of the reservoir it penetrates, due to the selective reduction of relative permeability that results from its adsorption58. This increased resistance to flow diverts subsequently injected water into poorly swept areas. Polymer adsorption reduces the relative permeability to the wetting phase more than the relative permeability to the non-wetting phase in water-wet reservoirs 5861. The reduction of the relative permeability to water is due to the improved competitive effects of both pore-size restriction and wettability brought about by polymer adsorption58. The most widely used polymers in enhanced oil recovery involve partially hydrolyzed polyacrylamides (HPAM) and hydrophobically associated polyacrylamides (HAPAM).

HPAM consists of a large proportion of intermediate hydrophilic amide groups and hydrophilic carboxyl groups. Both amide groups and carboxyl groups are linearly introduced onto the backbone of polymeric chains, providing HPAM with favorable solubility and desirable viscosity in fresh water and low salinity formation water 36. HPAM is a synthetic linear chain copolymer of acrylamide and acrylate monomers 62. They are flexible chain appears as a random coil and since it is a polyelectrolyte, it will interact with ions in solution. The main polyacrylamides used are anionic in nature3. Many key aspects need to be considered for the design of a polymer flood such as reservoir characteristics (lithology, stratigraphy, fractures), distribution of remaining oil, well pattern and spacing, polymer degradation, rheology of the polymer solution, compatibility with other chemicals, cost effectiveness 3. HPAM show good viscosifying properties, available in various molecular weights up to 30 million Dalton of relatively low price and can be used for temperatures up to 99 ^oC depending on brine hardness, so used currently in EOR applications. It is produced generally as free-flowing powders or as self-inverting emulsions. Some experiences reported that acrylamide-based polymers have some disadvantages, such as easy hydrolysis, easy adsorption in the stratum, poor shear stability and poor thermal stability38, and can be summarized as follow;

High sensitivity to thermal, mechanical and chemical degradation at high temperatures) typically above 200°F and exhibit decreasing viscosity by temperature increase63.

Highly susceptible to the presence of oil, surfactant and other reservoir chemicals.

Precipitation can occur if Ca²⁺or Mg²⁺is present in the water also, their carboxyl groups are screened by positive ions, leading to reduced viscosity and a limited application in wells with high temperature and salinity64 due to ionic groups shielding, which reduces repulsion and causes chain contraction.

Undergoes molecular weight degradation upon heating in oxygen presence 65.

Respond to physical or chemical stimuli, such as temperature, solvent, mechanical stress, radiation (UV, visible light), and ionic strength 66.

In polymer flooding, the ratio R_h/R_g [pore throat radius (R_h) to gyration radius (R_g)] of a polymer chain should be greater than five67 so, HPAM cause pore throat plugging after a given time68 because of its large molecular size69.

A comparison of different flooding scenarios indicating the cumulative oil recovery, resistance factor and residual resistance factor are summarized in table 2.

Most widely used water-soluble polymers including polyacrylamide and partially hydrolyzed polyacrylamide, are not suitable for high temperature, high salinity, and high flow rate injection owing to hydrolysis, decomposition, degradation, shear damage 3562, so these polymers modified by addition of hydrophobic moieties on the backbone structure36 to develop a novel temperature and salinity resistant mobility control agents (polymers) which known as hydrophobically associated polyacrylamides ( HAPAM)77. These polymers class have attracted much attention on both academic and industrial laboratories for polymer flooding in enhanced oil recovery 7879 because of their unique structures and properties, including their thickening properties, shear thinning, and anti-polyelectrolyte behavior which has been widely investigated in oil chemistry additives such as mobility control agents and rheology modifiers80. In addition to enhanced thermal stability, relative permeability modifiers, sweeping efficiency, salt-tolerance behavior and high viscosifying properties for IOR or EOR applications81. These polymers synthesized by modification of partially hydrolyzed polyacrylamide (HPAM) through grafting or incorporating hydrophobic chain cross-linking segments onto their hydrophilic main chain 33 or by copolymerization of hydrophilic and hydrophobic monomers 82. They considered as promised EOR candidates for polymer flooding in high salinity reservoirs, owing to their unique characteristics83 which can be summarized as follow;

In aqueous solutions, above a critical association concentration (C^∗), their hydrophobic groups develop intermolecular hydrophobic associations in nanodomains, leading to building up of a 3D-transient network structure in high ionic strength medium 84 so, providing excellent viscosity building capacity 798586, remarkable rheological properties and better stability with respect to salts than the unmodified HPAM precursors 87.

Reduce interfacial tension at the solid/liquid interface, since hydrophobic moieties associates forming aggregates or micelles.

Shows an unusual adsorption isotherm88 so, can be considered as a wettability modifier.

Does not undergo mechanical degradation under high shear stress such as those encountered in pumps and near the wellbore area, since the physical links between chains are disrupted before any irreversible degradation occurs, also they reform and retain their viscosity upon shear decreasing 89.

Highly resistance to physicochemical conditions (temperature, pH, and ion content) prevailing around the wells, so considered a prospective EOR candidate as thickeners or rheology modifiers in high temperature, high-pressure reservoirs 909192, reservoir stimulation93 and tertiary oil recovery 94.

Hydrophobically associating polyacrylamide are prepared conveniently by a micellar polymerization method, a lot of small molecule surfactants need to be added in order to enable hydrophobic monomer to be solubilized into micelles, and the addition of small molecule surfactants brings many negative influences 95. When hydrophilic surfmers are adopted to prepare HAPAM, homogeneous phase copolymerization of hydrophilic surfmers and acrylamide in aqueous solution can be carried out because of their solubility in water, and those drawbacks caused by the addition of small molecule surfactants can be avoided completely. Furthermore, when the concentration of surfmers is above their critical micellar concentration (CMC), their copolymerization with acrylamide follows the macroblock copolymerization mechanism, namely, surfmer molecules will incorporate into the macromolecular main chains as macroblock form. The macroblock macromolecular structure leads to more effectively hydrophobic associating of the hydrophobic side chains, stronger thickening property of HAPAM 81 and improved salinity resistance of HAPAM. Surfmers can copolymerize with the main monomer and they become covalently bound to particles surface forming integral polymeric materials. As a result, desorption of surfactant from the polymer particles or migration in the polymer films is impeded. Such improvements of latex and/or polymer stability properties96 have been reported for mechanical stability, electrolyte stability of the latex97, a decrease of surfactant migration98 and control of surface charge density99.