|Fig. 1: Fingering effect promoted by the unfavorable mobility ratio (top), and good oil recovery facilitated by the use of polymer flooding (bottom). (Source: G. Zerkalov)|
In the world of growing energy demand, oil plays the major role as the leading source of primary energy. The global oil consumption increased by 0.8 million b/d to reach approximately 101 million barrels consumed daily. The global production increased by more than twice the global consumption, by 2.1 million bbl/day, which is 2.3%.  Furthermore, the recent sharp decrease in oil prices forced oil companies to rethink their production strategies and optimize their expenses based on the changed oil price situation. While the exploration and development of new oil reserves continues, the implementation of EOR techniques has becomes more and more popular. According to Guenther Glatz, the lifetime of a reservoir usually consists of three phases:  initial (primary) recovery with naturally driven oil extraction mechanisms, secondary recovery with techniques used to maintain the reservoir pressure through water or gas injection, and tertiary recovery, often called enhanced oil recovery with a wide array of specific advanced techniques. When the production well is established, only 20-40% of the potential oil can be extracted through the first two phases.  The implementation of the EOR provides an opportunity to extract up to 30% of the original oil reserve in the well. Furthermore, it has been estimated that 2.0 × 1012 barrels of conventional oil and 5.0 × 1012 barrels of heavy oil remain in reservoirs worldwide after the exhaustion of the applications of conventional recovery methods.  The application of EOR helps extract these reserves and guarantee a continuing supply of oil in the future. Typical EOR mechanisms include chemical flooding, gas injection and thermal recovery. The displacement methods include the addition of the displacing substance into the reservoir through the injection well to displace the remaining oil. Chemical flooding includes the addition of water with some chemicals (surfactants and polymers) to enhance the oil displacement ability.
After the second phase (water or gas injection) there is still considerable amount of oil remaining, since it was not swept completely from the reservoir. One of the reasons for that phenomenon, outlined by Glatz, is the unfavorable mobility ratio.  Mobility ratio is defined as the ratio of mobility (λ) of the displacing fluid (water) to the mobility of the displaced fluid (oil), where mobility is permeability (κ) divided by viscosity (μ): 
|=||κwater / μwater
κoil / μoil
Thus, there is an inverse relation between the volumetric sweep efficiency and the mobility ratio. The value of M greater than unity is unfavorable, since this will cause the instability of the displacement process and so called "viscous fingering" effect. [2,5] Under the condition of a large viscosity difference between the displacing (water, lower viscosity) and displaced (oil, higher viscosity) fluid, the mobility ratio will become larger than one and, thus, poor recovery will be reached (Fig. 1). The fingering effect is highly undesirable as it promotes itself more and more and sharply reduces the production as soon as the finger reaches the production well site. In an endeavor to decrease the mobility ratio below one, the approach of using viscous fluid (polymer) to increase the viscosity of displacing fluid has been developed. This helps to promote the displacing fluid in a stable, uniform manner and decrease the chance of fingering effect thus increasing the efficiency of oil recovery
|Fig. 2: Polymer flooding. (Source: G. Zerkalov)|
Polymer flooding has been used for more than 40 years to effectively recover the remaining oil from the reservoir, up to 30% of the original oil in place. Due to decreased water production and enhanced oil production, the total cost of using the polymer flooding technique is less than that of water flooding. The polymer flooding efficiency ranges from 0.7 to 1.75 lb of polymer per barrel of incremental oil production.  Polymers added to water increase its viscosity and reduce water permeability due to mechanical entrapment, thus decreasing its mobility. The process usually starts with pumping water containing surfactants to reduce the interfacial tension between the oil and water phases and to alter the wettability of the reservoir rock to improve the oil recovery. Polymer is then mixed with water and injected continuously for an extended period of time (can take several years). When about 30% to 50% of the reservoir pore volume in the project area has been injected, the addition of polymer stops and the drive water is pumped into the injection well to drive the polymer slug and the oil bank in front of it toward the production wells (Fig. 2). 
Ideal mobility control agents will have high cost effectiveness, allow high injectivity, will be resistant to mechanical (up to 1000 m3 /m2-d flux when entering porous rock) and microbial degradation, will sustain high reservoir temperatures (up to 200°C) for extensive periods of time (5 to 10 years), will be effective when mixed with reservoir brines, will have low retention properties in porous rock, will be effective in presence of oil and gas, and not sensitive to acidity (pH) or various chemicals present at the oilfield. 
Most of the polymers used for EOR fall into two sets: synthetic polymers and biopolymers. The most commonly used among them are synthetic (PAM) and partially hydrolyzed polyacrylamide (HPAM), the biological polysaccharide, Xanthan, and some modified natural polymers, including HEC (hydroxyl ethyl cellulose), guar gum and sodium carboxymethyl cellulose, carboxyethoxyhydroxyethylcellulose.  Every polymer has its own advantages and disadvantages for a specific reservoir.
PAM (Polyacrylamide) with its high molecular weight (> 1.0 × 106 g/mol) was the first thickening agent used for aqueous solutions. PAM is stable up to 90°C at normal salinity and up to 62°C at seawater salinity. Therefore, it is somewhat restricted to on-shore operations only.  High salinity can dramatically reduce the viscosity properties of this compound.
Partially hydrolyzed polyacrylamide (HPAM) is one of the most popular polymer used today. HPAM is obtained by partial hydrolysis of PAM or by copolymerization of sodium acrylate with acrylamide.  HPAM's advantages include its tolerance to high mechanical forces present during the flooding of a reservoir, low cost, and its resistance to bacterial attack. This polymer can be used for temperatures up to 99°C depending on brine hardness. A few of its modifications, such as HPAMAMPS co-polymers and sulphonated polyacrylamide can withstand 104°C and 120°C respectively.  The disadvantage of HPAM lies in its high sensitivity to the brine salinity, hardness and presence of surfactants or other chemicals. This makes it very ineffective in reservoirs containing salts. 
Xanthan gum, a polysaccharide, is produced by different bacteria (one of which is Xanthomonas campestris) through fermentation of glucose or fructose. The molecule generally has very high molecular weight (2 - 50 × 106 g/mol) and very rigid polymer chains. This makes Xanthan gum relatively insensitive to high salinity and hardness. The polymer is compatible with most surfactants and other injection fluid additives used in tertiary oil recovery formulations. Xanthan gum is usually produced as broth in concentrated form that can be easily diluted to working concentrations without any complex mixing equipment. Xanthan is thermally stable in the range from 70°C to 90°C.  Nonetheless, this compound is very sensitive to bacterial degradation when injected into the field containing low-temperature regions in the reservoir. Furthermore, it has been reported that xanthan can have some cellular debris that cause plugging. 
Due to their different properties, polymers tend to work better or worse in different conditions. Thus, before the application, one should take into account several factors to select the optimal polymer used. To determine the best molecular weight of the polymer, it is necessary to consider reservoir permeability and oil viscosity.  It is also important to consider the cloud point of the polymer solution, which reflects polymer thermal stability in high salt brine and high temperature. Incorrect measurement of this parameter can result in precipitations during injection or flow through the reservoir.  Another essential parameter is the polymer retention, which encompasses possible mechanisms responsible for the reduction of mean velocity of polymer molecules during their flow through porous media. Retention is commonly attributed to polymer adsorption, however, some polymers can be mechanically entrapped in porous medium or hydrodynamically trapped in stagnant zones.  Thus, it is important to know the rock composition and polymer adsorption level to determine the best anionicity (degree of hydrolysis).
The world continues to rely heavily on oil for primary energy. As the extraction of oil becomes more challenging, new techniques are put in place to increase the amount of oil extracted. Polymers play major role in the Enhanced Oil Recovery; they help extract up to 30% of the original oil in place. Polymers help increase the viscosity of the displacing liquid (water) to drive the displaced liquid (oil) to the production well. A variety of polymers is used in different oil fields depending on working conditions of that field. Before the right polymer is chosen, a careful analysis should be conducted to ensure that the polymer is effective during an extensive period of time.
© Georgy Zerkalov. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
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