Polymer Evaluation in the Laboratory
Polymer evaluation in the laboratory and selection workflows for chemical Enhanced Oil Recovery (EOR) face significant challenges due to the complex and variable conditions in reservoirs. One of the core difficulties is ensuring that polymers maintain their viscosifying power under varying conditions, such as reservoir temperature, salinity, and shear forces. A critical factor in this workflow is the steady propagation of polymers without causing plugging or unexpected pressure build-up, which can reduce injectivity.
Additionally, polymer solutions need to demonstrate viscosity stability over time, as losses due to retention, thermal effects, or chemical degradation can reduce effectiveness. However, current polymer selection practices suffer from a lack of standardization, making comparisons between different studies challenging. Various testing methods, such as rheological testing and core flooding, are used to assess polymer performance, but these often do not adequately replicate field conditions. For instance, laboratory tests typically involve higher filtration and pristine water conditions that do not reflect the contamination levels in real reservoirs. This disconnect between laboratory testing and field application introduces risks, such as inaccurate assessments of injectivity and polymer behavior, which can lead to costly failures in the field.
Furthermore, differences in polymer preparation methods, filtration standards, and mechanical degradation during injection are not consistently accounted for in testing protocols, which further complicates the development of a reliable, standardized polymer selection workflow for EOR applications.
This page will summarize the best practices about polymer selection and evaluation.
Table of Contents
Podcast - discussing laboratory best practices
We discuss polymer selection and evaluation with Randy Seright in this episode of the Excel Or Routine Podcast which can be found here.
You can also check our YouTube channel for additional videos and podcasts and navigate the Polymer Flooding Guide for more content. Check our Academy for training courses.
Thermal stability & oxidative degradation
Here is a list of relevant papers and publications on polymer thermal stability and evaluation protocols.
Xanthan stability is examined to define the polymer’s temperature limits as a mobility-control agent. Experiments explored hydrolysis, oxidation, and helix-coil transitions. In the absence of oxidizing agents, free-radical reactions are not dominant. Acid-catalyzed hydrolysis and base-catalyzed fragmentation are significant depending on pH. Using Arrhenius calculations, under ideal conditions (pH 7–8, moderate-to-high salinity, no oxygen), xanthan retains at least half its viscosity for 5 years up to 75–80°C. These limits suggest that new polymers are required for higher temperature floods. The study covers molecular structure, degradation mechanisms, and stresses the importance of sample preparation under oxygen-free conditions to evaluate xanthan viability in EOR.
At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAMs) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and for approximately 2 years at 120°C. Within experimental error, HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer showed similar stability to HPAM. Stability results were consistent across various brines. At 160°C+, the polymers were more stable in brine with 2% NaCl plus 1% NaHCO₃. Despite no use of chemical oxygen scavengers, the highest thermal stability to date was observed. These results suggest HPAMs are viable for EOR applications up to 120°C if contact with oxygen and divalent cations is minimized. Calculations suggest that oxygen entering reservoirs will be rapidly consumed by reactions with oil and pyrite, limiting oxidative degradation. Therefore, polymer floods in high-temperature reservoirs may remain effective, assuming careful oxygen management.
This study evaluated new EOR polymers—ATBS-rich, scleroglucan, NVP-based, and hydrophobic-associative types—for use in high-temperature (up to 180°C), hard-saline carbonate reservoirs. Using Arrhenius analysis under oxygen-free conditions, viscosity half-lives of over 5 years at 120°C and over 50 years at 99°C were projected for certain ATBS polymers. Corefloods in carbonate rocks (at 99°C) showed good polymer retention, resistance to degradation, and mechanical stability, all without chemical stabilizers. These findings mark a significant step in applying polymer flooding in harsh environments and demonstrate the benefit of oxygen-free methods in stability testing.
New sampling methods in Suriname’s Tambaredjo field revealed that HPAM polymers propagated more than 300 ft with no degradation, contrary to previous reports of significant loss. The polymer bank maintained low salinity and high viscosity. Shear-thickening behavior was observed, and polymers were injected above parting pressure, forming short fractures (~20 ft) that enhanced injectivity without harming sweep. Results suggest that past degradation reports may stem from oxygen exposure during sampling, not actual reservoir conditions. Using anaerobic sampling or radical-scavenger additives preserved viscosity.
This experimental study investigated HPAM and HPAM-ATBS terpolymer stability under varying dissolved oxygen (0–8000 ppb), Fe²⁺ (0–220 ppm), and Fe³⁺ (0–172 ppm) at 23°C and 90°C. Below 200 ppb O₂ and 30 ppm Fe²⁺, viscosity losses were minimal after 1 week. At 90°C, even 10 ppb O₂ in contact with steel caused >30% viscosity loss. At 23°C, degradation was negligible with ≤1000 ppb O₂. The study recommends physical oxygen exclusion methods over chemical scavengers. Fe³⁺ addition caused immediate crosslinking. Findings underscore the need for low oxygen and iron levels in EOR processes to preserve polymer integrity, especially at high temperatures.
Polymer Rheology & Injectivity
We provide a list of publications dealing with polymer rheology and injectivity.
For hydrophobically associative polymers, incorporating a small fraction of hydrophobic monomer into a hydrolyzed polyacrylamide (HPAM) polymer can promote intermolecular associations and thereby enhance viscosities and resistance factors. In this paper, we investigate the behavior of a new associative polymer in porous media. The tetra-polymer has low hydrophobic-monomer content and a molecular weight (Mw) of 12–17 million g/mol. Total anionic content is 15–25 mol%, including a few percent of a sulfonic monomer. This polymer is compared with a conventional HPAM with 18–20 million g/mol Mw and 35–40% anionic content.
Rheological properties (viscosity vs. concentration; and shear rate and elastic and loss moduli vs. frequency) were similar for the two polymers [in a 2.52% total dissolved solids (TDS) brine at 25°C]. For both polymers in cores with permeabilities from 300 to 13,000 md, no face plugging or internal-filter-cake formation was observed, and resistance factors correlated well using the capillary-bundle parameter. For the HPAM polymer in these cores, low-flux resistance factors were consistent with low-shear-rate viscosities. In contrast, over the same permeability range, the associative polymer provided low-flux resistance factors that were two to three times the values expected from viscosities. Moderate shear degradation did not eliminate this effect—nor did flow through a few feet of porous rock. Propagation experiments in long cores (up to 157 cm) suggest that the unexpectedly high resistance factors could propagate deep into a reservoir—thereby providing enhanced displacement compared with conventional HPAM polymers. Compared with HPAM, the new polymer shows a significantly higher level of shear thinning at low fluxes and a lower degree of shear thickening at high fluxes.
The flow behavior of xanthan in porous media was investigated experimentally and theoretically using effective medium theory. Rheological behavior was tested over a wide range of concentrations (300–1600 ppm), permeabilities (40–800 md), residual oil saturations (0–29%), temperatures (25–80°C), and lithologies (sandstone and carbonate). An apparent shear rate equation with no adjustable parameters was effective for correlating porous media flow with viscometer data. Unlike capillary bundle models, the experimental constant was larger, attributed to channel connectivity and variable cross-sections. Theoretical modeling using percolation theory for power-law fluids supported experimental findings, showing that xanthan predominantly flows through larger pores due to its shear-thinning nature.
This paper focuses on solution preparation and quality control activities associated with the Milne Point polymer flood on the North Slope of Alaska. This project uses ten different polymer injection locations with a variety of skid types and configurations, which had a notable impact on polymer quality control and dissolution operations.
Compared with bulk 500-750-kg polymer bags, silos greatly improved the storage capacity and increased the
overall quality of polymer wetting in system. Silos also required less physical effort when transferring polymer.
Polymer hydration skids that were made inhouse by the polymer supplier were more reliable and experienced
fewer polymer solution quality and startup issues than those that were outsourced. These inhouse skids also used a uniform programming software that made it relatively easy to train the operators on new hydration skids. For pumping polymer mother solution, triplex pumps provided the best run time and were most maintenance-friendly, compared with diaphragm or triple screw pumps. Although polymer solutions could be prepared that met our target viscosities without using a nitrogen blanket, corrosion and iron particulates raised substantial reliability and injectivity concerns if nitrogen blanketing was not used—especially when using black iron piping and when the make-up water contained dissolved iron. Inline static mixers were ineffective in mixing mother solution with dilution water when the mixing occurred close to the wellhead. Mixing the two streams too close to the wellhead led to substantial variations in wellhead viscosity measurements. Dedicating individual pumps for injection into a given well provided desirable flexibility in controlling rates and concentrations of polymer for the well.
Monitoring produced salinity and polymer concentration provided useful insights about improved sweep and
polymer retention associated with the polymer flood. The observed field behavior was consistent with laboratory studies indicating a “tailing” phenomenon associated with polymer retention at Milne Point.
This paper clarifies rheological behavior of xanthan and HPAM in porous media at low velocities. It shows that prior high resistance factors reported were due to slow-moving polymer fractions that do not penetrate deeply. Mechanical degradation or flow through rock reduces this effect. For HPAM, the paper confirms shear thickening at moderate-to-high fluxes and negligible shear thinning at practical field conditions. Xanthan behaves as expected, with shear thinning at moderate-to-high flux but Newtonian at low velocity. These insights improve understanding of realistic polymer behavior for EOR modeling.
For applications in which enhanced-oil-recovery (EOR) polymer solutions are injected, we estimate injectivity losses (relative to water injectivity) if fractures are not open. We also consider the degree of fracture extension that may occur if fractures are open. Three principal EOR polymer properties are examined that affect injectivity: (1) debris in the polymer, (2) polymer rheology in porous media, and (3) polymer mechanical degradation. An improved test was developed to measure the tendency of EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers.
Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft.
For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea.
Considering the polymer solutions investigated, satisfactory injection of more than 0.1 pore volume (PV) in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm³/cm² throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated implies that total injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects in which polymer solutions are injected.
In this paper, we clarify the impact of salinity and hardness on the rheology of partially hydrolyzed polyacrylamide (HPAM) in sandstones with permeability greater than 200 md. These findings are particularly relevant for modelers and simulators of polymer flooding, as they provide critical insights into HPAM injectivity, the conditions leading to fracture initiation, and the potential significance of viscoelasticity for enhancing oil recovery—particularly in mobilizing capillary-trapped residual oil, whether or not fractures are present.
To contextualize the study, the literature review first summarizes how various parameters—including polymer concentration, molecular weight (Mw), rock permeability, and oil saturation—affect HPAM rheology in sandstone reservoirs. This foundation sets the stage for our experimental investigation, which focuses on high-Mw HPAM (18–20 million g/mol with 30% hydrolysis) across a range of reservoir-relevant conditions. Specifically, we assess polymer behavior in sandstones with permeabilities ranging from 252 to 838 md, salinity levels from 0.1% to 10.5% total dissolved solids (TDS), and hardness levels from 0% to 0.1% calcium chloride (CaCl₂).
Our results confirm established trends: resistance factors increased with higher HPAM concentration but declined as salinity rose. Notably, in the shear-thickening regime, the maximum resistance factor correlated strongly with the expression C[μ]/(k/ϕ)^0.5, linking rheology to polymer concentration, viscosity, permeability, and porosity. Despite the variation in brine composition, the velocity dependence of HPAM rheology in sandstone remained largely consistent across salinities between 0.1% and 5% TDS. Furthermore, even at a constant 1% TDS, varying the CaCl₂ concentration from 0% to 0.1% caused only minor changes in the velocity dependence of polymer behavior.
To deepen the mechanistic understanding, we explore the relationship between the onset of shear thickening and the inverse of the polymer solution’s relaxation time, as determined from bulk rheological measurements. Interestingly, the extent of mechanical degradation remained relatively stable across a wide concentration range—from 25 ppm to 2,000 ppm—when tested in brine containing 1% NaCl and 0.05% CaCl₂.
Overall, these results provide a robust framework for simplifying and improving polymer flooding models. By capturing how key variables interact under realistic conditions, the study supports more accurate performance projections and optimized design of EOR operations involving HPAM.
This paper investigates how residual oil saturation (Sor), salinity, and temperature impact HPAM rheology in porous media. Experiments at 20°C in Berea sandstone tested velocities from 0.01 to 100 ft/d, Sor from 0 to 0.55, and various krw. Polymer rheology was also studied across salinities (0.105%–10.5% TDS) and temperatures (20°C–60°C). Results clarify when shear thickening occurs, impacting injectivity and fracture initiation. Shear thickening was evident for HPAM at all concentrations (25–2500 ppm), while shear thinning only appeared in concentrated systems. This study supports better modeling of viscoelastic effects and fracture propagation during polymer floods.
Mechanical degradation
We provide a list of references dealing with HPAM stability to shear degradation and the impact on propagation in porous media.
This paper investigates the dual impact of mechanical degradation and viscoelasticity on the injectivity of HPAM solutions. Through coreflood experiments, it shows that entrance pressure drop and degradation only begin above a critical flux. A model is introduced to predict entrance pressure drop as a function of sandface flux, permeability, and porosity. Re-injection into the same core at the same flux results in no further degradation. The study concludes that viscoelasticity and mechanical degradation near the wellbore dominate injectivity behavior. It proposes a new correlation (Umax/d_gr²) to predict screen factor loss across geometries, simplifying injectivity impairment estimates in polymer floods.
This paper investigates the mechanical degradation of polyacrylamides (PAMs) during flow through porous media, which is a critical issue in enhanced oil recovery (EOR). It presents methodologies to assess degradation, emphasizing resistance factor, screen factor, and molecular weight distributions. A key contribution is the use of sedimentation velocity measurements to determine molecular weight distributions of native and degraded PAMs. Mechanical degradation depends strongly on solution flux, porosity, permeability, and is associated with entrance effects. The study finds that degradation dramatically reduces resistance factors more than viscosities. Fluorescent labeling and band sedimentation techniques show that high molecular weight tails are selectively removed during degradation. The paper provides correlations (e.g., FLUX/D²) for predicting degradation severity.
During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.te settings and marks a major milestone for EOR in the region.
Polymer Retention
We provide a list of publications dealing with polymer retention, evaluation methods and the impact of retention on the design of a polymer flood.
Associated with the Milne Point polymer flood (on Alaska’s North Slope), this paper explores the unusual shape of hydrolyzed polyacrylamides (HPAM) breakout/propagation during dynamic polymer retention measurements in Milne Point core material. In contrast to conventional expectations, polymer retention does not delay the initial polymer arrival at the end of a Milne Point core. However, after effluent polymer concentrations rapidly rise to at least 50% of the injected value, the concentration gradually “tails” up over many pore volumes (PVs) before it finally achieves the injected value. To understand the origin and significance of this behavior, a wide range of core experiments were performed, including substantial variations in polymer concentration and molecular weight, core length, preservation state, sand grain size, and mineral composition. Illite was identified as primarily responsible for the tailing phenomenon. This phenomenon has important consequences that must be considered when projecting the performance of the field project. This work suggests that mineralogy analysis (especially for illite and kaolinite) may reveal whether tailing should be accounted for during simulations of polymer propagation/retention in a given field application.
At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).
For a polymer flooding field trial in a heavy oil reservoir on Alaska’s North Slope, polymer retention is a key parameter. Because of the economic impact of retention, this parameter was extensively studied using field core material and conditions. In this paper, multiple types of laboratory measurements were used to assess hydrolyzed polyacrylamides (HPAM) polymer retention, including a brine tracer, effluent viscosity, total effluent organic carbon, and effluent chemiluminescent nitrogen. Retention tests were conducted in different Milne Point Schrader Bluff sands, with extensive permeability, grain size distribution, X-ray-diffraction (XRD), and X-ray fluorescence (XRF) characterizations. Several important findings were noted. Polymer retention based on effluent viscosity measurements can be overestimated unless the correct (nonlinear) relation between polymer concentration and viscosity is used. Polymer degradation (either mechanical or oxidative) can also lead viscosity-based measurements to overestimate retention. Inaccessible pore volume (PV) (IAPV) can be overestimated if insufficient brine is flushed through the sand between polymer banks. Around 100 PVs of brine may be needed to displace mobile polymer to approach a true residual resistance factor and properly measure IAPV. Even for a sandpack with kwsor = 20 md, IAPV was zero for HPAM with a molecular weight (Mw) of 18 MM g/mol. Fine-grained particles (<20 µm) strongly impacted polymer retention values. Native NB#1 sand with a significant component of particles <20 µm exhibited 290 µg/g, while the same sand exhibited 28 µg/g after these small particles were removed. Polymer retention did not necessarily correlate with mineral composition. The NB#1, NB#3, and OA sands had similar elemental and clay compositions, but the NB#1 sand exhibited \~10 times higher retention than the NB#3 sand. Polymer retention did not necessarily correlate with permeability. NB#1 sand exhibited much higher retention than OA sand, even though NB#1 sand is twice as permeable as OA sand. No evidence of chromatographic separation of HPAM molecular weights was found in our experiments. Although retention tended to be greater without a residual oil saturation (than at S<sub>or</sub>), the effect was not strong. Aging a core (with high oil saturation) at 60°C reduced HPAM retention by a factor of two. Under similar conditions, polymer retention was greater for a higher Mw HPAM (18 MM g/mol) than for a lower Mw HPAM (10 to 12 MM g/mol). In many cases with high polymer retention values (e.g., 240 µg/g), polymer arrival at the end of the core was relatively quick, but achieving the injected concentration occurred gradually over many PVs. This effect was not caused by chromatographic separation of polymer molecular weights. Results from modeling of this behavior were consistent with concentration-dependent polymer retention. The form assumed for the retention function in a simulator can have an important impact on the timing and magnitude of the oil response from a polymer flood. Field-based observations can underestimate polymer retention, depending on when the tracer and polymer concentrations were measured and the assumptions made about reservoir heterogeneity.
The paper investigates HPAM polymer retention under aerobic and anaerobic conditions using static and dynamic methods. Retention was higher under aerobic conditions in the presence of iron minerals. For pyrite-rich media, retention was notably lower in anaerobic settings, while siderite-rich media showed similar retention regardless of oxygen presence. The study concludes that anaerobic tests are more representative when iron is involved, and emphasizes careful retention measurement techniques to avoid overestimation due to degradation.
The study compares polymer retention values obtained from lab and field during a polymer flood in the Tambaredjo field, Suriname. Lab tests showed low retention (0–20 µg/g), but field calculations revealed much higher values (50–250 µg/g). The paper highlights that field-derived retention values provide valuable data for project design, especially considering the limitations of core-based lab results.
This paper investigates how hydrolyzed polyacrylamide (HPAM) polymer concentration affects retention in porous media using both static and dynamic tests. Different behaviors were observed in dilute, semidilute, and concentrated regions. Retention is nearly independent of concentration in dilute and concentrated regions, but increases in the semidilute region. The study proposes a mechanism based on polymer orientation and coil interaction. Implications suggest that injecting a low-concentration polymer bank first can reduce retention in field applications.