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.
This paper examines xanthan stability to define the polymer’s temperature limitations as a mobility-control agent. Experiments probed the relative importance of hydrolysis, oxidation, and helix-coil transitions in xanthan degradation. In the absence of dissolved oxygen, free-radical oxidation/reduction reactions are not the dominant degradation mechanism. Depending on pH, acid-catalyzed hydrolysis and base-catalyzed fragmentation reactions may play important roles. Using Arrhenius calculations, under ideal conditions — no dissolved oxygen, pH 7–8, and moderate-to-high salinities — xanthan is estimated to maintain at least half its original viscosity for 5 years if temperature does not exceed 75–80°C. Above this temperature, new polymers are needed for chemical floods requiring mobility control.
HPAM solutions at elevated temperatures experience progressive hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable — HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and approximately 2 years at 120°C, without chemical oxygen scavengers or antioxidants. HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer with 25% AMPS showed similar stability to HPAM. Results were similar across brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl + 0.1% NaHCO₃. Above 160°C, polymers were more stable in 2% NaCl + 1% NaHCO₃. Calculations showed dissolved oxygen entering the reservoir before polymer injection will be consumed quickly and will not propagate far — providing two practical protections: pre-injection oxygen depletion and fast recovery from surface oxygen leaks.
This study identifies viable polymers for polymer flooding of high-temperature carbonate reservoirs with hard, saline brines. New ATBS polymers with high degree of polymerization, scleroglucan, NVP-based polymers, and hydrophobic associative polymers were examined for stability over a 2-year period under oxygen-free conditions at temperatures up to 180°C in brines with TDS from 0.69% to 24.4%, including divalent cations from 0.034% to 2.16%. Arrhenius analysis — a novel feature of this study — was used to project viscosity half-lives without waiting decades for conventional stability results. A set of ATBS polymers showed viscosity half-lives over 5 years at 120°C and over 50 years at 99°C — a major advance for extending polymer flooding to higher temperatures. Five promising polymers were evaluated in anaerobic corefloods at 99°C using carbonate cores, examining retention, rheology, mechanical degradation, and residual resistance factor.
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 paper describes an experimental study of the stability of HPAM and an HPAM-ATBS terpolymer in the presence of varying dissolved oxygen (0–8,000 ppb), Fe²⁺ (0–220 ppm), and Fe³⁺ (0–172 ppm). At 23°C with Fe²⁺ concentrations between 0 and 30 ppm, viscosity losses were insignificant after one week when dissolved oxygen was 200 ppb or less. Above this level, significant viscosity losses occurred, especially with iron present. At 90°C with only 10 ppb dissolved oxygen, contact with steel caused HPAM-ATBS viscosity losses greater than 30%. At 23°C, contact with steel caused no significant degradation up to 1,000 ppb dissolved oxygen. Fe³⁺ addition caused immediate crosslinking. Physical oxygen exclusion methods are advocated over chemical methods.
Polymer Rheology & Injectivity
We provide a list of publications dealing with polymer rheology and injectivity.
Inaccessible pore volume (IAPV) is intended to characterize the fraction of aqueous pore space in a porous medium that is not accessible to flowing polymer. Previous IAPV literature is contradictory in that no correlation is evident between measured IAPV values and rock permeability or porosity or polymer molecular weight or size in solution. Prior work by Gilman and MacMillan (1987) and Wang et al. (2021) demonstrated that much of the previous contradictory reports may result from the inadequacies of methods to measure IAPV. In particular, the “double-polymer/tracer bank” method incorporates a water flush between two polymer/tracer banks. The unfavorable mobility ratio as water displaces the second polymer bank causes viscous fingering and overestimation of IAPV if insufficient water is flushed. Dean et al. (2022) proposed a potentially improved method to determine IAPV, where a low concentration polymer bank is displaced by a more-concentrated, more-viscous polymer bank—so the mobility ratio is always favorable during the displacement. This paper tests this method for determining IAPV.
The tests used sandstone cores and bead packs with permeabilities ranging from 113 to 18600 mD, porosities ranging from 0.188 to 0.402, and core lengths ranging from 30.48 to 122-cm. Many tests involved 500-ppm HPAM (with no potassium iodide tracer) displacing 250-ppm HPAM (with a KI tracer). However, three sets of tests made five replicate determinations of IAPV using successive polymer banks with HPAM concentrations starting at 62.5 ppm and doubling in stages to 2000 ppm. This procedure tested the reproducibility of the method and whether the IAPV measurement depended on HPAM concentration.
With a given data set, multiple methods can be used to assign an IAPV value, including (1) the area between polymer and tracer breakout curves, (2) the difference in pore volume (PV) throughput (between polymer and tracer) upon attaining an effluent concentration of 50% of the injected concentration, and (3) the difference in PV during first breakout of polymer ahead of tracer. Significant differences in calculated IAPV values were noted for these different methods.
In general, the method of Dean et al. (2022) provides a substantial improvement over previous methods when measuring IAPV. However, caution must be exercised when interpreting the results of these tests with respect to projecting polymer-flood performance. Important uncertainties arise from assessments of IAPV—notably, in rock with permeability above 200 mD. These uncertainties arise partly because polymer retention can vary with polymer concentration—violating a key assumption of the method of Dean et al. From this work, it is arguable whether a significant IAPV exists in Berea sandstone or bead packs with permeability greater than 200-mD (when using 18-20-million g/mol HPAM).
This paper investigates the porous-media behavior of a new hydrophobically associative tetra-polymer with low hydrophobic-monomer content, Mw of 12–17 million g/mol, and 15–25 mol% total anionic content including a few percent of a sulfonic monomer. The associative polymer is compared with a conventional HPAM of 18–20 million g/mol and 35–40% anionic content. Bulk rheological properties were similar for both polymers. In cores from 300 to 13,000 md, neither polymer caused face plugging. The associative polymer provided low-flux resistance factors two to three times those expected from viscosity alone — an effect not eliminated by moderate shear degradation or flow through a few feet of rock. Propagation experiments in cores up to 157 cm suggest these high resistance factors could propagate deep into the reservoir. The associative polymer shows significantly higher shear thinning at low fluxes and lower shear thickening at high fluxes compared to conventional HPAM.
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. The project uses 10 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 storage capacity and overall quality of polymer solutions with less physical effort. Polymer hydration skids made in-house by the polymer supplier were more reliable and experienced fewer quality and startup issues than outsourced skids, and used uniform programming software for easier operator training. For pumping polymer mother solution, triplex pumps provided the best runtime and were most maintenance-friendly compared with diaphragm or triple screw pumps. Nitrogen blanketing was preferred to minimize corrosion and oxidative degradation due to soluble iron in the makeup water. Inline static mixers were ineffective in mixing mother solution with dilution water when mixing occurred close to the wellhead, leading to substantial variations in wellhead viscosity measurements. Dedicating individual pumps for injection into a given well provided desirable flexibility. Monitoring produced salinity and polymer concentration provided useful insights about sweep improvement and polymer retention. The observed field behavior was consistent with laboratory studies, indicating a tailing phenomenon associated with polymer retention at Milne Point.
This paper clarifies the rheology of xanthan and HPAM solutions in porous media, especially at low velocities. Previous literature reported resistance factors and apparent shear thinning at low fluxes noticeably greater than expected from viscosity measurements. The polymer component causing this behavior propagates slowly and generally will not penetrate deep into a formation. Particularly for HPAM solutions, this anomalous low-flux shear thinning can be reduced or eliminated by mechanical degradation or flow through a few feet of porous rock. Under practical EOR conditions, HPAM shear thinning is slight or nonexistent at the low velocities relevant to displacement deeper in the reservoir, while shear thickening at high velocities (near the wellbore) remains the dominant rheological phenomenon.
This paper estimates injectivity losses relative to water for EOR polymer solutions in the absence of open fractures, and considers the degree of fracture extension if fractures are open. Three principal EOR polymer properties affecting injectivity are examined: debris in the polymer, polymer rheology in porous media, and polymer mechanical degradation. An improved test was developed to measure polymer plugging tendency in porous media — demonstrating that plugging tendencies vary considerably among both HPAM and xanthan polymers. For xanthan solutions, pseudoplastic behavior in porous rock closely parallels viscometer behavior, and xanthan was remarkably resistant to mechanical degradation (only 19% viscosity loss at 24,600 psi/ft through 102-md Berea). HPAM in 573-md Berea showed Newtonian behavior at low-to-moderate fluxes and pseudodilatant (shear-thickening) behavior at high fluxes. The onset of mechanical degradation for HPAM occurred at 14 ft/d in 573-md Berea. Without fractures, satisfactory injection of more than 0.1 PV is expected only for the cleanest polymers.
Over the last two decades, high interest has been shown to explore whether viscoelastic polymer solutions can reduce the capillary trapped residual oil saturation (Sor) under practical reservoir conditions. To characterize this relatively less explored potential and identify the mechanisms that contribute to Sor reduction, we measured capillary desaturation curves (CDC) for viscoelastic polymer solutions, along with the evaluation of their ability to alter wettability. The studies were performed using both low- and high-salinity viscoelastic polymer solutions at high salinity and high temperature carbonate reservoir conditions.
A combination of bulk and in-situ rheological measurements, contact angle experiments, and desaturation experiments were conducted. Desaturation experiments were performed using 2500-ppm and 4000-ppm acrylamide-ATBS-copolymer solutions prepared in 5760- ppm-TDS and 57600-ppm-TDS brines in 105-to-111-mD oil-wet limestone cores saturated with 2.8-cP oil and 257600-ppm formation brine at 95°C. The desaturation experiments involved: a) performing bump water flooding up to 64 ft/day and a subsequent sequential glycerin flood to ensure that the residual oil was highly discontinuous and strongly trapped, and the core was well-swept; and b) initiating the desaturation process with polymer solutions using an imposed flux of 0.05 ft/day and continuing up to 100 ft/day.
Bump water flooding with high salinity brine and glycerin flood reduced the oil saturation by 25-30% in both experiments. At low flux rates (from 0.05 ft/day to 1 ft/day), both low and high salinity polymers did not reduce the oil saturation further. Such behavior is observed even though a) the shear thickening onset was noted at 0.25 ft/day for both solutions, and b) a slight reduction in contact angle (2-to-7 degrees) was observed. At 5 ft/day, both low and high polymer solutions showed a noticeable reduction in Sor—at computed critical capillary numbers of 4.0×10-5 and 4.82×10-5, respectively. Increasing the flux rate further up to 100 ft/day resulted in significant further oil desaturation, yielding additional residual oil recoveries of ~13% for the low salinity polymer solution and ~11% for the high salinity polymer solution. Although Sor reduction was observed at 5 ft/day in the lab, calculations indicate that achieving a flux above 5 ft/day in the target reservoir application and a significant Sor reduction would only be accomplished within ~30 ft from the wellbore.
In this work, CDC curves for low and high-salinity viscoelastic polymer solutions were reported for the first time under high salinity and high temperature oil-wet carbonate conditions. Examinations and interpretations of the developed CDC curves indicate that the observed Sor reduction in the lab cannot be expected in the carbonate reservoirs for the well spacings typically used for polymer flood projects.
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 experimentally clarifies how residual oil saturation (Sor), salinity, and temperature impact HPAM rheology in porous rock. HPAM rheology was determined in Berea sandstone for Darcy velocities from 0.01 to 100 ft/d, Sor from zero to 0.55, and krw from 0.03 to 1. Key findings: (1) residual oil moderates shear-thickening magnitude, but not enough to explain unexpectedly high HPAM injectivities in field polymer floods; (2) the [1-ϕ(1-Sor)]/[k·krw·ϕ(1-Sor)]^0.5 shift factor was validated with oil present; (3) the onset velocity for shear thickening was insensitive to salinity between 0.1% and 5% TDS; (4) the magnitude of shear-thickening resistance factors decreased with increased temperature by more than expected from water viscosity alone — a finding not explained by oxidative or mechanical degradation. Results are critical for predicting fracture initiation and HPAM viscoelasticity relevance in field polymer floods.
Global oil production increasingly comes from mature fields where recovery factors remain stubbornly low (typically around 35% of the original oil in place) despite decades of technological progress in petrophysics, reservoir simulation, and seismic imaging (OGA 2018; NPD 2019). At the same time, water production continues to grow: for many assets, 3–7 barrels of water must be handled, treated, and reinjected for every barrel of oil produced. This combination of low ultimate recovery and high water handling erodes project value, stresses surface facilities, and increases energy use and CO₂ emissions. When not addressed early, both recovery opportunities and economic windows for Enhanced Oil Recovery (EOR) are progressively lost.
Polymer flooding is a well-established water-based EOR method for improving macroscopic sweep efficiency by increasing injected water viscosity and reducing the water–oil mobility ratio. Numerous field applications have demonstrated its ability to delay water breakthrough, recover additional oil, and reduce water–oil ratio (WOR). However, even in reservoirs that are technically well suited for polymer injection, projects are frequently delayed or abandoned. Long decision cycles, fragmented workflows, and slow transitions between concept, laboratory work, design, and field deployment often limit the impact of polymer flooding more than chemistry or physics do.
To fully capture the benefits of polymer flooding, engineers need workflows that are both technically robust and fast to execute. The key challenge is not to reinvent polymer flooding, but to remove unnecessary delays in screening, data acquisition, laboratory evaluation, design, and piloting while still honoring basic reservoir-engineering principles and field constraints. This requires a clear sequence of decisions, early identification of key uncertainties, and a practical methodology that links polymer chemistry, surface facilities, reservoir behavior, and project economics.
The objective of this paper is to summarize best practices and propose an accelerated, field-centric workflow for polymer flooding, from reservoir screening and candidate selection through laboratory design, simulation, pilot implementation, and early decision gates for full-field deployment. The emphasis is on moderate-to-high permeability conventional reservoirs with active or planned waterflooding, where displacement efficiency is limited by heterogeneity and an adverse water–oil mobility ratio. The workflow is not intended to be universal or to cover all reservoir types (e.g., tight formations, heavily fractured systems, or carbonates at ultra-high temperature), but to provide a pragmatic, experience-based framework for rapidly moving technically suitable projects from the idea stage to polymer injection in the field.
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 influence of mechanical degradation and viscoelasticity on the injectivity of partially hydrolyzed polyacrylamide solutions. Injection pressures in linear corefloods are shown to be separable into two components: (1) an entrance pressure drop associated with polymer entering the sandstone, and (2) a constant pressure gradient throughout the remainder of the core. Entrance pressure drop is zero until polymer flux reaches the mechanical degradation threshold; thereafter it increases with flux. A new umax/dgr² correlation is developed to predict entrance pressure drop and degradation level directly from sandface flux, permeability, and porosity. This correlation eliminates the need for iterative procedures and is applicable to any flow geometry. A model is developed to estimate polyacrylamide injectivity in both linear and radial flow, accounting for entrance pressure drop and dilatant behavior near the wellbore.
This early paper describes methods for assessing mechanical degradation of polyacrylamides and investigates the factors influencing degradation during flow through porous media. A technique is described whereby polymer molecular weight distributions are determined from sedimentation velocity measurements using fluorescently labeled polymers in an ultracentrifuge. Molecular weight distributions of native and degraded polymers from three different HPAM products are presented and compared with viscosity, screen factor, and resistance factor assessments of degradation. A simple model for predicting degraded molecular weight distributions is presented based on the assumption that the probability of a molecule breaking in half scales with a characteristic molecular weight parameter. The work demonstrates that molecular weight distribution measurements provide polymer-concentration-independent comparisons among different polymer products — an advantage over viscosity and screen factor measurements which depend on concentration and salinity.
This paper confirms theoretical predictions that fractures with limited length and proper orientation can dramatically increase polymer injectivity and eliminate mechanical degradation, through field observations at the Kalamkas oil field in Western Kazakhstan. Step-rate tests and pressure transient analysis confirmed polymer injection above the formation parting pressure. A novel method was developed to anaerobically collect samples of fluids back-produced from injection wells using natural reservoir energy at the wellhead. Rheological measurements of back-produced polymer solutions revealed no mechanical degradation for the Kalamkas conditions. The open fracture area was high enough to ensure low flow velocity within the fracture (keeping the polymer mechanically stable). Contact with the formation rapidly depleted dissolved oxygen from injected fluids, promoting polymer chemical stability. The new back-production sampling method is quick, simple, inexpensive, and reliable.
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.
This paper explores the unusual shape of HPAM breakout/propagation during dynamic polymer retention measurements in Milne Point core material. In contrast to conventional expectations, polymer retention does not delay initial polymer bank arrival, but after effluent concentration rapidly rises to at least 50% of injected value, the concentration gradually tails up over many pore volumes before reaching the injected value. Wide-ranging experiments varied polymer concentration, molecular weight, core length, preservation state, sand grain size, and mineral composition. Illite is identified as primarily responsible for the tailing phenomenon. The effect was observed in cores with illite but not in packs of other minerals including kaolinite, montmorillonite, chlorite, calcium carbonate, dolomite, siderite, pyrite, or calcium sulfate. A model is proposed to account for tailing, with implications for projecting field polymer flood performance. Mineralogy analysis (especially illite and kaolinite) may reveal whether tailing should be incorporated into polymer flood simulations.
At the Milne Point polymer flood, polymer retention is dominated by illite clay. Illite and kaolinite do not delay polymer propagation but reduce effective polymer concentration and viscosity by approximately 30%, reducing oil displacement efficiency until full injected concentration is regained over several pore volumes. This work shows polymer retention on illite is insensitive to monovalent ion concentration but increases significantly with increased divalent cation concentration. Incorporating a small percentage of ATBS monomers into HPAM dramatically reduces retention. An extensive literature review reveals that polymer retention on sands and sandstones is only modestly sensitive to the presence of oil. Review of inaccessible pore volume (IAPV) literature suggests IAPV was commonly substantially overestimated, especially in rock more permeable than 500 md — which comprises the vast majority of current polymer flood targets. Bridging adsorption is proposed as the mechanism linking divalent cation concentration and retention.
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.
This paper examines whether HPAM retention differs under anaerobic vs. aerobic conditions, using both static (mixing with loose sand) and dynamic (coreflood) methods. On pure silica sand or Berea sandstone, polymer adsorption values are small with little aerobic/anaerobic difference. HPAM retention increases significantly with pyrite or siderite content. Under aerobic conditions, retention with iron minerals can be twice that measured anaerobically — because viscosity-based polymer detection under aerobic conditions overestimates retention through oxidative degradation. For pyrite-bearing samples, HPAM retention was significantly lower anaerobically; for siderite, aerobic/anaerobic conditions showed less difference. Under aerobic dynamic conditions, higher flow rates underestimate retention (211 mg/g at 6 ft/d vs. 43.2 mg/g at 30 ft/d with 10% pyrite); under anaerobic conditions, retention was consistent across flow rates (40.6–47.8 mg/g at 6–33 ft/d). If iron minerals are present, anaerobic conditions provide the most representative retention measurements.
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 the effect of HPAM polymer concentration on retention in porous media using both static and dynamic measurements. Results show that different retention behaviors exist in dilute, semidilute, and concentrated regions. In dilute and concentrated regions, retention has little dependence on concentration. In the semidilute region, retention is concentration dependent. If a porous medium is first contacted with dilute polymer solution sufficient to satisfy retention, no significant additional retention occurs upon exposure to higher concentrations. A concentration-related retention mechanism is proposed considering adsorbed polymer molecule orientation and molecular coil interactions. In the semidilute region, moderate coil interactions lead to mixed adsorbed-polymer orientation and concentration-dependent retention. Practical implication: reduced polymer retention may be achieved in field applications by first injecting a low-concentration polymer bank.