Abstract. Polymer floods in Canadian heavy oil fields have yielded remarkable recovery factors in spite of relatively low polymer solution viscosities (e.g., ~25 cp) displacing oils up to several thousand centipoise in viscosity. In contrast, at Daqing (the world’s largest polymer flood), 45-cp+ polymer solutions were typically injected while the oil viscosity was only ~10 cp. Several opinions have been offered to explain the success in Canada, with some claiming that the polymer/oil mobility ratio achieved during polymer injection was very substantially greater than one. Some have argued that ~25 cp polymer provides an economic optimum that balances some improvement in mobility ratio and oil production rates against injectivity reductions and polymer cost. Others have argued the success can dominantly be attributed to crossflow mechanisms induced by polymer flow within existing water fingers through the viscous oil. Still others have speculated that polymer induces emulsification of the oil, resulting in great-than-expected improvements in mobility ratio. At least one group advocates that relative permeabilities to water are surprisingly low—resulting in polymer/oil mobility ratios close to unity, in spite of the low injected viscosities. This presentation examines the strong and weak point of the various arguments. Improved understanding of polymer flooding of viscous oils should lead to true optimum polymer injection strategies.

Abstract. Chemical Flooding has been a successful joint development between Shell Research and Petroleum Development Oman (PDO) culminating in extensive implementation in South Oman reservoirs. Early investigations of polymer flooding at the Marmul field started in the late 1980’s and were resumed in earnest in the 2005-time frame due in large part to the increase in oil price.  Also, polymer suppliers have improved the quality of product, developed efficient field handling capabilities, and developed new grades.  This has been achieved without an increase in cost and the inflation adjusted price of HPAM is significantly lower than in the 1980’s.  An initial deployment at Marmul of 27 injectors was successful technically and economically and resulted in a 7 to 10% increase in oil recovery over waterflood.  Significantly, polymer injection has occurred for 15 years with no negative effects on production systems. These positive results have led to further expansion of polymer at Marmul, implementation at Nimr, and possible extension to other fields in Southern Oman (Karim West, Thayfut, etc.). A minimization of capital employed by PDO has been achieved by leasing facilities in partnership with polymer suppliers.

Alkaline-Surfactant-Polymer (ASP) formulations have been developed by Shell Research and pilot tested at Marmul. Recovery is estimated at 10% additional oil over polymer flood (20% over waterflood) due to the lowering of interfacial tension (IFT) between oil and injection brine. The initial formulation utilized sodium carbonate as alkali with specifically designed surfactants for chemical flooding. The formulation faced logistical challenges for commercial implementation due to the large quantity of sodium carbonate (2%). An improved formulation was developed utilizing liquid organic amine and commodity (low cost) surfactants. Pilot tests showed that the formulation with liquid amine performed equivalently and had significant economic advantages due to liquid handling, less chemical required, and the avoidance of water softening. Expansion of ASP at Marmul is in progress due to attractive economics and increased oil recovery.

Abstract. This work reviews global experiences with transitioning from polymer flooding back to water injection, focusing on Enhanced Oil Recovery (EOR) project performance. Polymer flooding significantly enhances oil recovery by improving sweep efficiency through increased fluid viscosity, but the subsequent return to water injection often leads to rapid viscous fingering and loss of incremental oil gains. Field data from diverse international projects—such as Kalamkas (Kazakhstan), Marmul (Oman), Daqing (China), Mangala (India), Carmopolis (Brazil), and heavy oil fields in Canada—consistently show rapid declines in oil production and increased water cuts upon resuming water injection. This trend highlights critical gaps between theoretical predictions, laboratory experiments, and actual reservoir performance. The study underscores the necessity of accurately modeling reservoir heterogeneities, polymer rheology, and mobility control to optimize polymer flood designs. Recommendations emphasize extending polymer injection until economic limits are reached, and refining simulation models through detailed laboratory and field calibration to improve predictive accuracy and sustainability of polymer flooding projects.

Abstract. Milne Point Field initiated the first polymer injection pilots on the North Slope of Alaska starting in 2018 and has rapidly progressed to full-field polymer injection within four years. The two initial pilot projects injected at an initial total rate of 6,000 barrels of water per day (bwpd) utilizing five horizontal injection wells. Expansion activities began two years later, in 2020, with the addition of three more polymer injection units. By the end of 2021, two more polymer injection units were added, followed by one in 2022 and another in 2023. Currently, Milne Point operates nine active polymer skids, and the field's polymer injection rate has reached 60,000 bwpd via 50 horizontal injection wells. Targeted reservoirs have average permeabilities ranging from 100 to 1000 md and in-situ oil viscosities ranging from 13 cp to 1300 cp. Both secondary and tertiary floods are being conducted in both greenfield and brownfield development areas, each with varying, yet all promising, results. The highest observed recovery is in a secondary polymer flood pattern at 34% of OOIP with an oil viscosity of 850 cp and water breakthrough after 5 years or 0.2 PV injection. Responses in injection well injectivities have ranged from as low as 0% up to a 50% loss to date and are observed to be correlated with well spacing and total reservoir mobility. The intent of this paper is to: a) provide an update on previously published results from 2022; b) highlight what has been done to date regarding moving from polymer flood concept to near full-field expansion; and c) present observed results with the hope that they can help set expectations for future polymer flood projects.

Abstract. cEOR technology has become the most important and effective measure for enhanced oil recovery in China. This work demonstrates the status of the cEOR applications in China, the progress of chemical agent study and pilot tests for adapting to complex reservoirs conditions. This work also discussed the secondary cEOR or quaternary recovery practices. The cEOR technology has been applied to heterogeneous clastic reservoirs with varied fluid properties, including medium viscosity oil, conventional heavy oil, viscous high temperature and high salinity (HTHS) oil and low-medium permeability conglomerate reservoirs. Special cEOR methods involve polymer flood, ASP flood, SP flood, polymeric surfactant flood and SP + PPG flood. The above cEOR measures have been widely applied to onshore mature fields. Polymer flood and SP flood pilots were conducted in offshore fields at different development stages, e.g. early, interim, and mature stages with water-cut <20%, between 20% and 60%, and >60%, respectively. In 2022, the CEOR technology was producing around 45,600 m³/day with developed STOIIP of 2694 × 106 m³, cumulative production >417 × 106 m³ and cumulative incremental oil >265 × 106 m³. Polymer and ASP flood applied to conventional medium viscosity oil reservoir achieved an incremental recovery by 12% and 20%, respectively. While high concentration polymer flood gained an average incremental recovery by 8.5% in conventional heavy oil reservoir. In the HTHS, viscous oil reservoir, incremental recovery by polymer flood reached 7.5%. SP flood applied to low-medium permeability conglomerate and HTHS reservoirs increased recovery by 20% and 18%, respectively. The successful cEOR technologies applied to diverse types of reservoirs with strong heterogeneity and varied fluid properties prove their feasibility and profitability. Established cases of the cEORs applied to offshore fields and secondary EOR process provide analogs for industry.

Abstract. Operators worldwide face the persistent challenge of offsetting reserve depletion caused by ongoing oil production. While the acquisition of new fields presents growth opportunities, revitalizing mature fields is a highly attractive alternative, leveraging existing infrastructure, accelerating production timelines, and enabling cost-effective recovery of remaining reserves. Among the enhanced oil recovery (EOR) methods available, Polymer Flooding has emerged as a proven and scalable technique to unlock additional reserves from aging assets while maintaining economic viability and environmental sustainability.

Polymer Flooding enables operators to expand reserves using existing infrastructure, thereby minimizing upfront capital investment. In contrast to greenfield developments, which require long lead times and high costs, Polymer Flooding projects can often be implemented and deliver incremental oil production within 6–9 months. This fast-track approach significantly shortens the time-to-extra-oil and accelerates cash flow generation. The cost per barrel of incremental oil remains low, and additional production revenues offset easily most of the investment.

This presentation explores how Polymer Flooding has expanded over the past decade to become a field-proven and mature technology. Two case studies will be presented, highlighting development strategies and achieved results in terms of incremental oil production:

- Argentina (multiple operators): A progressive ramp-up through modular development, now injecting in over 400 wells.

- Shengli Chengdao – Offshore China: A full-field polymer flooding project in an offshore environment with new platforms under development.

Drawing on successful large-scale applications worldwide, this presentation will provide practical insights into implementation strategies, challenges overcome, and lessons learned, demonstrating how Polymer Flooding can play a key role in sustaining domestic oil production while aligning with cost and environmental imperatives.

Abstract. Viscoelasticity in polymer solutions for enhanced oil recovery (EOR) has shown potential to reduce residual oil saturation (S_or) during high-flux coreflood experiments. However, its impact at the field scale remains uncertain. This study evaluates polymer-flood projects across nine countries using two methodologies: (1) comparing average Darcy velocity with shear thickening onset velocity and analyzing factors like well spacing, injector geometry, and reservoir thickness; (2) examining coreflood data in the context of fluid velocity, oil viscosity, permeability, flood mode, and pressure gradients. Findings reveal that most field conditions—especially with horizontal injectors—yield Darcy velocities far below those needed for viscoelastic effects (>1 ft/D), making Sor reduction via viscoelasticity improbable. Even in scenarios with elevated velocities, macroscopic pressure gradients suggest limited effectiveness. The paper also explores alternative Sor reduction mechanisms, including wettability alteration and differences between secondary and tertiary flooding. Researchers are encouraged to use realistic field-relevant fluxes in laboratory assessments.

Abstract. This presentation shares the practical outcomes and insights from a comprehensive polymer flooding evaluation conducted in Kuwait, culminating in the successful implementation of a pilot project. An extensive laboratory study was conducted to evaluate the feasibility and performance of polymer flooding for enhanced oil recovery (EOR) in high-salinity, high- temperature carbonate reservoirs typical of Kuwait. Eleven commercial polymer samples from leading global suppliers were systematically screened using standardized protocols that assessed fluid–fluid compatibility, rheological behavior, thermal stability, and filtration properties. The core evaluation workflow included filter ratio, screen factor, viscosity-shear profiles, capillary shear degradation, and static adsorption on reservoir rock. Single-phase core flood tests were performed to quantify injectivity and resistance factors, while two-phase oil displacement experiments demonstrated the displacement efficiency of selected polymers. A key finding was that the selected polymer achieved an additional 11% oil recovery over waterflooding in Berea sandstone cores, with a polymer retention of only 0.01 mg/g rock.

Abstract. The research work was carried out and the results of justification of applicability of polymer flooding (PF) technology for high-temperature terrigenous reservoir with low- viscosity oil, located in Western Siberia, were presented. Based on multifactor screening and analysis of application of enhanced oil recovery (EOR) methods at similar fields, polymer flooding was selected as one of the priority EOR methods. The results of comparison of ten different commercial polymer samples with different content of acrylamide tertiary butyl sulfonic acid monomer (ATBS) are presented. Laboratory tests covered key physicochemical properties of the polymer (molecular weight, degree of hydrolysis, dry matter content), viscosity characteristics at different shear rates and concentrations (from 500 to 3000 ppm), thermal stability and salt resistance of the polymer reagent to mineralized medium at a reservoir temperature of 96 °C. During the filtration tests on the core the following parameters were determined: oil displacement coefficient, residual oil saturation, flow resistance coefficients (RF, RRF), polymer viscosity at the outlet and the level of adsorption on the rock.

The efficiency of the polymer flooding was evaluated using hydrodynamic modeling. The modeling results show an increase in oil recovery factor (ORF) by 4-7% compared to conventional waterflooding.