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Polymer waterflooding

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When conducting a polymer waterflood, a high-molecular-weight and viscosity-enhancing polymer is added to the water of the waterflood to decrease the mobility of the flood water and, as a consequence, improve the sweep efficiency of the waterflood. The primary purpose of adding polymer to most polymer waterfloods is to increase the viscosity of the flood water; however, polymer addition to the flood water in many instances also imparts a secondary permeability-reduction component. Polymer waterflooding is normally applied when the waterflood mobility ratio is high or the heterogeneity of the reservoir is high. Fig. 1 shows the polymer waterflooding process.[1]

How polymer flooding improves recovery

Waterflooding promotes improved sweep efficiency by improving the mobility ratio. Improved sweep efficiency imparted during polymer flooding is primarily accomplished by increasing the viscosity of the waterflood drive fluid. Conventional wisdom states that polymer waterflooding does not reduce irreducible oil saturation (residual oil saturation to waterflooding); [1][2][3] however, at least one paper[4] has called this contention into question when flooding with selected acrylamide polymers.

Polymer solutions

The principal beneficial property of polymer solutions for use in flooding oil reservoirs is the aqueous solution’s enhanced viscosity. Aqueous polymer solutions that are used for conformance improvement flooding normally exhibit non-Newtonian viscosity properties.

Viscosity of polymer solutions

The viscosity of a polymer solution is a measure of how "thick" a fluid is. For example, molasses is characterized as being "thicker" and more viscous than water. The viscosity of a fluid or solution may, in general terms, be defined as the solution’s resistance to being sheared or as the resistance of a fluid mass to change its form.

Fluid viscosity, μ, is defined as


where τ is shear stress and γ. is shear rate.

Many common fluids, such as water and motor oils, exhibit Newtonian viscosity. For fluids with Newtonian viscosities, the fluid’s viscosity is independent of the shear rate that the fluid is experiencing. That is, the value of the viscosity of a Newtonian fluid at a given temperature is a single value that is independent of shear rate.

The viscosity-enhancing power of a polymer is related to the size and extension of the polymer molecule in a particular aqueous solution.[2] For a number of reasons, the viscosity of a polymer solution that is measured in a viscometer and the effective viscosity of the polymer solution that is measured during flow through porous reservoir matrix rock often have different values.

To predict the viscosity-enhancing power of a polymer in a given solution, the polymer’s intrinsic viscosity, [η], can be measured by


where c is polymer concentration, η is polymer solution viscosity, and ηs is solvent viscosity. Intrinsic viscosity is obtained by determining the value Limc→0(η-ηs)/s) that is obtained from the plot of (η-ηs)/s) vs. polymer concentration and extrapolating the plotted data back to zero polymer concentration. For a given polymer in an aqueous solution, the intrinsic viscosity for the polymer increases with polymer molecular weight (MW) according to the Mark-Houwink equation:


where K′ and a are polymer-specific constants, and MP is the polymer molecular weight.

The empirical Flory equation[5] can be used to estimate the mean end-to-end distance of a polymer in solution. The Flory equation is


where dp is in Angstroms (10−10 m), and [η] is in dl/g.

Molecular weight and size

When all other factors are equal (such as polymer type and the brine solution into which the polymer is dissolved), as the molecular weight (MW) of the polymer increases, the size of the polymer increases. As the size of the polymer increases, so does the polymer’s viscosity enhancing ability when dissolved in a given brine. On the negative side, as the MW of a polymer increases, the propensity for the polymer to be retained during transport through matrix reservoir rock is increased, and the propensity for the polymer to exhibit injectivity problems is increased.

Because polymers used in polymer waterflooding are polydispersed in MW, polymer MW distribution is an important factor relating to how a given polymer will function during a polymer flood. Unfortunately, good MW distribution data are not readily and widely available for the polymers that are normally used in polymer flooding, because the determination of a polymer’s MW distribution is relatively expensive and time consuming.

Fig. 2 shows the MW distribution for a typical HPAM polymer sample used in polymer flooding. The high MW tail of the MW distribution is quite significant. The small number of polymer molecules in the polymer’s MW distribution have a disproportionately large effect on the viscosity-enhancing power of the polymer; are the polymer molecules that are first and most easily degraded by mechanical shear under intermediate- to high-shear flow conditions; are the polymer molecules that will be first and most easily retained during polymer transport through reservoir matrix rock; and are the polymer molecules that are most prone to causing injectivity damage.

Fig. 3 shows a series of MW distributions for a family of HPAM polymer samples. MAR-1 through MAR-9 denote sample numbers 1 through 9. When applied in a relatively high-permeability reservoir in which polymer retention during polymer transport and polymer injectivity are not major issues, polymers with higher molecular weights and narrower MW weight distributions perform relatively more effectively as viscosity-enhancing agents during a polymer waterflood.[2][6]

For a polymer that is dissolved in a given solvent, polymer MW is proportional to molecular size. For several illustrative polymers used in polymer waterflooding, their molecular size, as related to MW, is as follows. A 30% HPAM polymer of approximately 4×106 dalton (atomic mass units) MW dissolved in a good solvent is expected to be fibril in form and to have a diameter of 0.7 to 2.5 μm and a backbone chain length greater than 10 μm.[2][7] The hydrodynamic length of a xanthan molecule commonly used in polymer flooding has been reported to be approximately 1.5 μm.[2][8] The MW of such a xanthan molecule is approximately 4×106 daltons.


The non-Newtonian viscosity of polymer solutions used in polymer waterflooding normally exhibit shear-thinning behavior when subjected to sufficiently high shear rates (but not at low shear rates). The viscosity of a Newtonian fluid does not vary with the shear rate to which the fluid is subjected. For a shear-thinning fluid, the apparent viscosity of the fluid decreases as the fluid experiences increasing shear rates.

Figs. 4 and 4 show the shear-thinning viscosity behavior of two polymers of the type used in polymer flooding. In Fig. 4, at low shear rates (< 0.1 s−1), the viscosity behavior of the polymer solutions at all polymer concentrations is invariant with shear rate and, thus, is Newtonian. At shear rates exceeding 1.0 s−1, the viscosity of the polymer solutions decreases with increasing shear rate, thereby exhibiting shear-thinning viscosity behavior. The shear-thinning viscosity behavior of the polymer in Fig. 4 becomes relatively less pronounced as the concentration of the polymer in solution decreases. This trend is observed for all polymers that are used in polymer flooding. The shear-thinning viscosity reduction behavior results from the water-soluble high-MW polymers becoming uncoiled and unentangled when they are aligned and elongated in the fluid-flow shear field under sufficiently high shear-rate (~1 to 100 s−1) conditions. When the polymers are aligned and unentangled by the shear field in this shear-rate range, the polymers become less effective viscosity enhancing agents. At the low shear rates of Fig. 4 (< 0.1 s−1), the shear field is not strong enough to appreciably uncoil and untangle the polymer molecules. The viscosity is invariant over this shear-rate range, and the viscosity behavior is characterized as being Newtonian over this shear-rate range.

As expected, the apparent viscosity at any given shear rate increases as polymer concentration increases. For the studied AMPS polymer, Fig. 5 shows the dramatic and undesirable effect that increasing the salt concentration in the makeup water has on reducing the viscosity of the polymer solution at any given shear rate. Similar detrimental effects of increasing salt concentration are observed in polymer solutions of high-MW HPAM.[1] Note also the trend, which is quite generalized, that as the salt concentration of the polymer solution increases, the degree of shear thinning of the polymer solution decreases.

The shear-thinning viscosity behavior of these polymer solutions is favorable because the shear rate experienced by the polymer in the vast majority of the reservoir is usually quite low (approximately 1 to 5 s−1) and is a shear rate at which the polymer exhibits near maximum viscosity.[1] In the near-wellbore region, share rates are often in the shear-thinning range for the polymer (e.g., 1 to 100 s−1). This polymer shear thinning is fortuitous because the viscosity reduction improves the injectivity of the polymer solution.

The mathematical equation that describes the viscosity vs. shear-rate behavior (of the type of Figs. 4 and 5) for oilfield polymer solutions over the shear-rate range of approximately 1 to 100 s−1 is the power-law model that takes the form of


where K and n are, respectively, the power-law coefficient and exponent, and γ. is shear rate. For polymer-flood fluids that are shear thinning, the value of the power-law coefficient, n, ranges between 0 and 1 and equals 1 for these fluids when they are Newtonian. The viscosity behavior of a polymer solution becomes more shear thinning as the value of the power-law exponent, n, decreases. The numerical value of the viscosity and the power-law constant, K, become equal when the value of the shear rate, γ, equals 1.

As it relates to polymer solutions of polymer flooding, the power-law viscosity model is only applicable over a limited range of shear rates. For a description of other analytical mathematical expressions for describing polymer-solution viscosity vs. shear rate, especially expressions covering a wider range of shear rates, and for discussions on the viscoelastic properties and the extensional and elongational flow properties of high-MW polymer solutions,[2]. Extensional viscosity, which occurs under very high shear-rate conditions, can lead to pronounced increases in the apparent viscosity of polymer solutions and often leads to mechanical shear degradation of high-MW water-soluble polymers. The only location in a reservoir that a polymer solution is likely to experience extensional-viscosity conditions of any consequence is near wellbore to an injection or production well.

"Apparent viscosity" or "effective viscosity" refers to the viscosity of a polymer solution for which the viscosity is determined during flow of the polymer solution through porous media. This is discussed further later in this section.

Measuring viscosity

When measuring the viscosity of polymer solutions to be used in polymer waterflooding, the use of standard laboratory steady-shear viscometers is often quite satisfactory. In addition to the use of conventional viscometers, the screen factor (SF) device has been used extensively to measure viscosity properties of polymer solutions that are used in polymer flooding. Fig 6 shows the SF device. The SF "viscometer" consists of a small fluid reservoir in the glass unit that is in fluid communication above several wire-mesh screens, often three to five 100-mesh stainless-steel screens. A fluid sample of fixed volume is placed in the fluid reservoir, and the time is recorded for the fixed volume of fluid to flow through the screens under the influence of gravity. The SF value for a given polymer is the time it takes the fixed volume of polymer solution to flow through the screen viscometer divided by the time it takes the fixed volume of the solvent brine to flow through the screen viscometer. The SF value of a polymer solution is quite sensitive to the nature of the high-MW tail of the polymer’s MW distribution. Some practitioners suggest that the SF value better correlates with mobility and permeability reduction exhibited by the polymer solution as it is propagated through matrix reservoir rock. However, this contention is not universally agreed on. The SF measurement is a simple, straightforward, and useful qualitative viscosity characterization of polymer solutions for use in polymer flooding.[2][9]

Effects of salt, hardness, and pH

The effects of salt and hardness on polymer-flood biopolymers are of relatively small consequence at lower temperatures (< 170°F), as compared with the effects on HPAMs polymers that are used in polymer flooding at the same reservoir temperature. Salt insensitivity is one of the attractive features of polymer-flood biopolymers such as xanthan. Likewise, pH within the range likely to be encountered in low-temperature (< 140°F) oil reservoirs is of relatively small consequence to the viscosity and mobility-control properties of xanthan polymer.

The effect of salt and hardness on the viscosity and mobility-control function of polymer-flood HPAM, and similar and related synthetic polymers, is quite significant and can be very deleterious. Cations of dissolved salts reduce the electrostatic repulsion of the negatively charged hydrolyzed carboxylate pendant groups on the polymer backbone of HPAM. Cations do this by screening and collapsing the local negatively charged double layer formed around the carboxylate species. The degree of collapse of the negatively charged electrostatic fields surrounding the polymer’s carboxylate groups increases with increasing salt concentrations; and at constant salt concentration, with increasing charge of the cations of the salt. As the electrostatic fields surrounding the polymer’s carboxylate groups collapse, the electrostatic repulsive forces that promote polymer backbone-chain distension decrease. As Fig. 5 shows, this leads to substantial reduction in polymer-solution viscosity. As a rule of thumb, the polymer-solution viscosity decreases by a factor of 10 for every factor of 10 increase in NaCl concentration.[1] The negative impact of divalent hardness ions, such as Ca++ and Mg++, are much more deleterious at the same concentration than monovalent ions, such as Na+ and K+.

As the concentration hardness cations, such as Ca++, in the brine of a HPAM solution increases, the polymer becomes relatively more sensitive to mechanical shear degradation. The effect of pH on the viscosity of ionic HPAM can be significant. Decreasing the solution pH tends to convert the ionic salt form of the polymer’s carboxylate groups to the relatively nonionic carboxylic acid form of carboxylate groups. This diminishes the electrostatic repulsion of the ionic carboxylate groups along the polymer’s backbone and leads to less distention of the polymer molecule and to less viscosity-enhancing power for the polymer in a low pH solution. For a studied hydrolyzed-polyacrylamide polymer solution, its viscosity decreased by a factor of approximately four when the pH of the polymer solution was decreased from 9.8 to 4.[2]

Flow in porous media

Polymer solutions used in waterfloods must be able to be transported successfully and effectively through the reservoir. Thus, the manner in which polymer solution flows through porous rock and the associated polymer interaction with the pore walls of matrix reservoir rock are important aspects regarding the attainment of the technical and economic success of a polymer flood.

Polymer transport

Polymer retention during flow through reservoir matrix rock is discussed below. Polymer retention by adsorption and entrapment retards the rate of polymer propagation.

Inaccessible and excluded pore volume

Accelerating the rate of polymer propagation, as compared with the rate of an inert chemical tracer dissolved in the injected polymer solution, is the inaccessible pore volume (IPV) phenomenon. Two explanations for, and contributions to, the IPV phenomenon have been reported. The first IPV explanation is that the large size of the polymer molecules prevents entry into smaller and dead-end pores. This promotes propagation of the polymer molecules faster than an inert chemical tracer because the polymer flows only through the larger-pore flow paths.

The second IPV explanation is the wall-exclusion effect. It is hypothesized that polymer molecules flow and concentrate in the center of the pore-level flow channels of matrix reservoir rock because the polymer molecule flow and the free tumbling of the polymer molecules are excluded from the near-surface volume of the pore walls. Such flow behavior accelerates the rate of polymer propagation through the porous media relative to the rate of propagation of an inert chemical tracer.[1][2][10]

Mobility reduction

When polymer in solution flows through reservoir matrix rock, it imposes a mobility reduction that is the primary conformance-improvement benefit of polymer waterflooding. The mobility reduction can be imparted by one of two distinctly different mechanisms. First, the polymer can cause an increase in the viscosity of the brine being flooded through the porous media. This is normally the desired effect when flooding with polymer solutions for mobility control. The second mechanism reduces the permeability of the reservoir matrix rock. One measure of mobility reduction imparted by polymer-solution flow is the resistance factor, Rf, which is defined as


where λw is the mobility of the solvent of the polymer solution, and λp is the mobility of the polymer solution. When the polymer solution imparts no permeability reduction and for measurements made at ambient temperature,


where μeff is the effective viscosity of the polymer solution as it flows through the reservoir matrix rock. Alternatively, for a single-phase polymer solution flowing through matrix reservoir rock at a given temperature and there is no imparted permeability reduction,


where μw is the viscosity of the brine in which the polymer is dissolved.

Permeability reduction

Polymer flow through reservoir matrix rock can cause permeability reduction. A measure of the polymer-induced permeability reduction is the residual resistance factor, Rrf:


where kb is brine permeability measured before polymer flooding, and ka is brine permeability measured after polymer flooding.

Permeability reduction induced by polymers tends to be greater in lower permeability reservoir rock. This is, in general, counterproductive. Polymers, especially HPAMs, that undergo even a small amount of mechanical shear degradation often lose much of their permeability reduction propensity because the relatively small number of exceptionally large molecules of a given polymer MW distribution (especially for many HPAMs) are the first polymer molecules to be shear degraded. These large molecules contribute disproportionately to permeability reduction.

Extensional flow

As mentioned in the discussion on rheology, when flexible, coiled, high-MW polymers, such as HPAM, are forced to flow through matrix reservoir rock at exceptionally high rates and experience exceptionally high-flow shear fields, the polymer can enter extensional and elongational flow at which point the polymer solution’s apparent viscosity can rise rapidly. In this flow regime, the polymer is also often mechanically shear degraded. Solutions of well-designed polymer floods are likely to experience extensional flow of noticeable consequence only in certain instances in the very near-wellbore region adjacent to the injection or production well.

Polymer retention

Polymer retention will often profoundly affect the technical and economic success of a polymer-flooding project. The amount of oil that will be recovered per pound of polymer injected is inversely related to polymer retention.

Retention for a given polymer during a polymer flood:

  • Increases as the permeability decreases
  • Increases as the polymer molecular weight increases
  • Increases as the clay content in the reservoir rock increases
  • Usually decreases as oil wetness increases
  • Tends to increase in sand and sandstone reservoirs with decreasing anionic charge and increasing cationic charge of the polymer’s pendant groups
  • Has been reported to increase at times in the presence of crude oil

Polymer retention should be determined carefully, or at least estimated carefully, before initiating a polymer waterflood. Polymer retention for a given polymer flood is normally best estimated by conducting flooding experiments in reservoir rock with reservoir fluids at reservoir temperature.

"Field-measured values of retention range from 7 to 150 μg of polymer per cm3 of bulk volume, with a desirable retention level being less than approximately 20 μg/cm3."[2] Laboratory measurements of polymer retention in reservoir rock are usually reported as mass of polymer adsorbed per unit mass of rock, Γ, and is usually reported as μg/g of polymer adsorbed onto reservoir rock. Frequently, it is preferred to have polymer retention reported in terms of mass of polymer adsorbed per unit volume of reservoir rock, Γ v , or, more specifically, in terms of pounds of polymer adsorbed per acre-foot of reservoir, lbm/acre-ft. To convert from Γ to Γv,


where ϕ is porosity, ρRG is the density of the reservoir rock grains (no pore space included), Γv is in units of lbm/acre-ft, and Γ is in units of μg/g.[2] Polymer retention, as measured during field projects, has been reported to range from 20 to 400 lbm polymer/acre-ft bulk volume, with desirable retention reported to be less than 50 lbm/acre-ft.[11]


Polymer adsorption results primarily from physical adsorption and not chemisorption.[2] Polymer adsorption is often the major cause of polymer retention.[2] And, core to pore level investigation of polymer retention has been studied.[12][13][14] 

Mechanical entrapment

Mechanical entrapment of polymer during propagation through reservoir porous media results from the larger polymer molecules becoming lodged in narrow flow channels (e.g., pore throats). Gogarty found that the HPAM polymers, under the conditions of his flooding experiment studies, had an effective size between 0.4 and 2 μm.[15] There are several significant consequences of mechanical entrapment: [2] permeability reduction, loss of the entrapped polymer’s favorable viscosity enhancing functionality beyond the point of entrapment, loss of the largest of the polymer molecules first has a disproportionately large negative impact during the remainder of the polymer flood on viscosity and mobility-control properties, and loss of a disproportionately large portion of its viscosity and mobility control functionality relatively soon after the polymer solution is injected into a reservoir.

Hydrodynamic retention

Hydrodynamic retention is the least understood and least well defined retention mechanism.[2] Polymer retention can increase as the flow rate of the polymer solution through reservoir matrix rock increases.[2] Hydrodynamic retention is thought to normally be a relatively small contributor to the total polymer retention during a polymer flood.[2] This retention mechanism is more significant in lower permeability reservoir rock. Hydrodynamic retention is thought to result from polymer molecules becoming temporarily trapped in stagnant flow regimes by hydrodynamic drag forces.[2]


Polymer precipitation from solution, especially in the presence of high reservoir brine salinity, is another source of polymer retention. Precipitation is especially problematic when flooding with HPAM in high-temperature reservoirs with formation waters containing hardness divalent cations.

Polymer degradation

A decrease in the average molecular weight of the polymer can be caused by chemical, biological, mechanical, or thermal degradation.1,2 Polymer stability, the inverse of degradation, should be evaluated and quantified under reservoir conditions in terms of a time span relevant to the lifetime of the polymer flood in question.


Chemical free-radical species will degrade both biopolymers and synthetic polymers of polymer flooding. Free radicals cause chemical backbone scission of the polymer. Examples of free-radical sources that can be problematic for flooding and conformance-treatment polymers are free oxygen (O2), hydrogen peroxide, sodium hypochlorite of bleach, and gel breakers such as ammonium peroxide. The combination of free oxygen and ferric ions is particularly problematic in causing oxygen free-radical degradation of polymer-flood polymers, especially of acrylamide polymers. Another source of polymer-degrading free radicals is free-radical or free-radical-precursor impurities within the polymer that are induced, in this case, during the manufacturing process. Polymer-degradation problems, caused by low levels of free radicals, are most problematic when conducting high-temperature (> 150°F) polymer-flooding experiments, especially during the high-temperature laboratory evaluation of polymers for high-temperature flooding. A countervailing phenomenon relating to free-radical chemical degradation is that oil reservoirs tend to quite rapidly neutralize and consume chemical free-radical species.

Two procedures are recommended for removing free oxygen from polymer-solution samples to be used during laboratory evaluation of polymer solutions for high-temperature applications. The first procedure uses a glass ampoule, which is glass-blown sealed after oxygen removal, and high-quality vacuum to reduce oxygen content to < 10 ppb. The second procedure consists of bubbling high-purity argon gas through the polymer solution. The need to deoxygenate polymer-solution samples in the laboratory during high-temperature testing is an aboveground laboratory artifact because polymer solutions that exist in most reservoirs are in an anaerobic and chemically reducing environment.

Hydrolysis reactions are important degradation reactions for both biopolymers and synthetic polymers; however, the hydrolysis reaction degrades the polymers in a much different manner for each of these two polymer types. Both acid- and base-catalyzed hydrolysis of the carbon-oxygen-carbon bonds of the backbone monomer chemical linkages of polysaccharide biopolymers cause polymer backbone scission and serious polymer MW degradation. The pH sensitivity of a biopolymer being used in a polymer flood needs to be considered. Serious polymer hydrolysis questions are raised if an acid-stimulation treatment contacts a previously placed conformance-improvement biopolymer gel treatment.

Hydrolysis (autohydrolysis) reactions of the amide pendant groups of the acrylamide polymers are of significant concern when such polymer is being flooded through a high-temperature reservoir that contains a significant concentration of hardness divalent ions in the formation water. If an acrylamide polymer, which is dissolved in a hardness-containing brine, autohydrolyzes to excessively high levels at high temperatures, the acrylamide polymer will undergo a phase change to an undissolved solid state that causes the polymer to precipitate. When this happens, the polymer loses its viscosity-enhancing properties. Technically, this type of acrylamide-polymer autohydrolysis is not polymer degradation, but simply leads to a phase change of the polymer from being dissolved in solution to being an undissolved solid specie.


Biological degradation is a serious potential problem for biopolymers, especially for use in shallow reservoirs and for the biopolymer as it resides in surface tanks and tubulars. For a properly designed acrylamide-polymer flood that uses solid polymer as the polymer source, potential biological degradation is essentially not an issue.


The form of mechanical degradation that is of most concern for polymers of polymer waterflooding is shear degradation. All dissolved polymers mechanically degrade if subjected to a sufficiently high-flow shear rate. During polymer flooding, deleteriously high- flow shear rates can exist in surface-injection equipment (valves, orifices, pumps, and tubing), at downhole constrictions (tubing orifices, perforations, or screens), and at the formation face of the injection well.

Xanthan biopolymer is usually not mechanically shear degraded under polymer-flood injection conditions. Under most radial-flow injection conditions, high-MW acrylamide polymers are quite susceptible to mechanical shear degradation. This is especially true if the flooding brine is high in hardness and salinity. When a water-soluble polymer encounters a sufficiently high-velocity flow field, both shear and elongational stress destroy the polymer solution’s viscosity.[1] Maeker[16] and Seright[17] correlated permanent viscosity loss of a polymer solution to the product of the elongational stretch rate multiplied by the stretch length. The higher the MW of a given polymer, the more sensitive it is to mechanical shear degradation.


All waterflooding polymers have an upper temperature limit above which they are no longer chemically stable, both with and without the addition of an appropriate thermal stabilizer package. This upper temperature limit varies with water chemistries of the polymer-dissolution and reservoir brines, polymer chemistry, manufacturer, and polymer lots from a given manufacturer. For the most part, the upper limit of thermal stability is fixed for a waterflood polymer obtained from a given manufacturer. It must be determined if the polymer to be used is thermally stable under reservoir conditions at the reservoir temperature of the polymer flood and that it will be sufficiently stable for the life of the polymer flood.


Although once popular, the addition of chemical, biological, and thermal stabilizers to polymer waterflooding solutions has lost a lot of its original attractiveness because of toxicity, environmental concern, effectiveness, and cost issues. A stabilizer that historically has been used widely as both a biological and thermal stabilizer for polymer-flood polymers is formaldehyde. Formaldehyde is now considered highly toxic and is highly regulated. Also, a number of the stabilizers used to protect against free-radical degradation can become, in themselves, polymer-degrading free radicals at high temperatures. In addition, early practitioners of chemical stabilizers did not fully appreciate chemical loss and chromatographic separations issues. If a chemical stabilizer is to be considered, it is prudent to proceed cautiously.

Polymer injectivity

Polymer-solution injectivity is an important consideration for several reasons. First, the rate at which the polymer solution can be injected directly impacts the economics of a polymer-flood project. Second, routine injection well cleanup jobs may be required if polymer or polymer-microgel damages injectivity. These cleanup jobs can detract from the polymer flood’s economics and effectiveness. Injectivity decreases as polymer MW increases. Polymer-solution injectivity is more favorable when the polymer solution exhibits shear-thinning viscosity behavior.

Screening criteria for polymer flooding

The following screening guidelines can be used to determine where polymer waterflooding is most applicable, in terms of reservoir properties.[1][18]

  • Oil viscosity < 150 cp (preferably < 100 and > 10 cp) and API gravity > 15°
  • Matrix-rock permeability > 10 md, with no maximum
  • Reservoir temperature: low temperatures are best (best at < 176°F; maximum of approximately 210°F)
  • Water injectivity should be good with some spare capacity (hydraulic fracturing of injection wells may help)
  • Reservoir clay content should be low
  • Low salinity of the injection and reservoir brines are preferable

Polymer waterflooding has been conducted successfully in sandstone and carbonate matrix-rock reservoirs, fractured reservoirs, and in water-wet, mixed-wetting, and oil-wet reservoirs. For example, see DeHekker, et al.[19].


ka = permeability measured after polymer flooding, L2
kb = permeability measured before polymer flooding, L2
ki = permeability of phase i
M = mobility ratio
MP = polymer molecular weight
Rf = resistance factor
Rrf = residual resistance factor
dp = mean end-to-end distance or size of a polymer molecule dissolved in solution, L
n = power-law exponent
[η] = intrinsic viscosity
μ = viscosity
μeff = effective viscosity of a polymer solution
μi = viscosity of phase i
λi = mobility of phase i
λp = mobility of the polymer solution
λw = mobility of the brine solution
τ = shear stress


  1. 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 Lake, L.W. 1989. Enhanced Oil Recovery, 314-353. Englewood Cliffs, New Jersey: Prentice Hall.
  2. 2.00 2.01 2.02 2.03 2.04 2.05 2.06 2.07 2.08 2.09 2.10 2.11 2.12 2.13 2.14 2.15 2.16 2.17 Sorbie, K.S. 1991. Polymer-Improved Oil Recovery. Glasgow and London: Blackie.
  3. Improved Oil Recovery, 36. 1983. Oklahoma City, Oklahoma: Interstate Oil Compaction Commission.
  4. Demin, W., Jiecheng, C., Qingyan, Y. et al. 2000. Viscous-Elastic Polymer Can Increase Microscale Displacement Efficiency in Cores. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-63227-MS.
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  6. Argabright, P.A., Rhudy, J.S., and Phillips, B.L. 1982. Partially Hydrolyzed Polyacrylamides with Superior Flooding and Injection Properties. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 26-29 September 1982. SPE-11208-MS.
  7. Herr, J.W. and Routson, W.G. 1974. Polymer Structure and Its Relationship to the Dilute Solution Properties of High Molecular Weight Polyacrylamide. Presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, Texas, 6-9 October 1974. SPE-5098-MS.
  8. Whitecombe, P.J. and Macosko, C.W. 1978. J. Rheology 22: 493.
  9. Stahl, G.A., Moradi-Araghi, A., and Doe, P.H. 1988. High Temperature and Hardness Table 14. Copolymers of Vinylpyrrolidone and Acrylamide. In Water-Soluble Polymers for Petroleum Recovery, G.A. Stahl and D.N. Schulz eds., 121-130. New York and London: Plenum Press.
  10. Duda, J.L., Klaus, E.E., and Fan, S.K. 1981. Influence of Polymer-Molecule/Wall Interactions on Mobility Control. Society of Petroleum Engineers Journal 21 (5): 613-622. SPE-9298-PA.
  11. Lake, L.W. 1989. Enhanced Oil Recovery, 314-353. Englewood Cliffs, New Jersey: Prentice Hall.
  12. Huh, C., Lange, E.A., Cannella,W.J., 1990. Polymer retention in porous media. Paper SPE 20235 Presented at the SPE/DOE Seventh Symposium on Enhanced Oil Recovery, Tulsa, Oklahoma, 22–25 April,
  13. Yun, W., and A. R. Kovscek. 2015. “Microvisual Investigation of Polymer Retention on the Homogeneous Pore Network of a Micromodel.” Journal of Petroleum Science and Engineering 128. Elsevier: 115–27.
  14. HATZIGNATIOU, Dimitrios G., Hojat MORADI, and Arne STAVLAND. 2015. “Polymer Flow through Water- and Oil-Wet Porous Media.” Journal of Hydrodynamics, Ser. B 27 (5): 748–62.
  15. Gogarty, W.B. 1967. Mobility Control with Polymer Solutions. SPE J. 7 (2): 161–173. SPE-1566-PA.
  16. Maerker, J.M. 1976. Mechanical Degradation of Partially Hydrolyzed Polyacrylamide Solutions in Unconsolidated Porous Media. SPE J. 16 (4): 172–174. SPE-5672-PA.
  17. Seright, R.S. 1983. The Effects of Mechanical Degradation and Viscoelastic Behavior on Injectivity of Polyacrylamide Solutions. SPE J. 23 (3): 475–485. SPE-9297-PA.
  18. Taber, J.J., Martin, F.D., and Seright, R.S. 1997. EOR Screening Criteria Revisited—Part 2: Applications and Impact of Oil Prices. SPE Res Eval & Eng 12 (3): 199-206. SPE-39234-PA.
  19. DeHekker, T.G., Bowzer, J.L., Coleman, R.V. et al. 1986. A Progress Report on Polymer-Augmented Waterflooding in Wyoming's North Oregon Basin and Byron Fields. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 20-23 April 1986. SPE-14953-MS.

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See also


Polymer waterflooding design and implementation

Field performance of polymer waterflooding