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. Surfactants play a key role in the process of residual oil mobilization during

implementation of EOR technology. Surface active agents reduce the interfacial tension between the crude oil and brine and decrease the capillary number, increase the capillary sweep efficiency and forming oil/water emulsion, according to Winsor theory; Type-I, -II, -III, IV. Winsor classified oil-water emulsion systems by the number of phases present driven by surfactant behavior. During oil recovery process the aim to generate Winsor type-III emulsions because they have the lowest interfacial tension values. However, in addition to achieving very low IFT, undesirable processes also occur that form a very stable, unbreakable emulsion. Our tests aimed to investigate the quality and quantity of emulsions prepared with surfactants used in EOR by conventional static bottle test and dynamic tests by automatic device to characterize and select surfactants for industrial applications. An essential method for surfactant selection is to study the emulsifying effect and phase behavior. Phase behavior tests and emulsifying effect tests were performed using surfactants and surfactant blends as a function of stirring parameters. The stirring speed and stirring time influence the results of the phase behavior and emulsifying effect tests, although during the investigations other parameters

were unchanged. Based on the results of the tests, it was found that, with the traditional static bottle test, it is not possible to produce an emulsion similar to that produced by oil wells, because it is not possible to achieve the same level of dispersion as the flow generates through the pores of the reservoir rock.

Furthermore, the emulsions formed in the good emulsifying range showed the greatest similarity to real produced samples; therefore, it is important that the determination of the emulsifying /solubilizing capacity of surfactants always carried out under dynamic conditions.

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.

Abstract. This work reviews results from core and sand pack flooding experiments using gellan gum solutions to evaluate its potential as a conformance and water shut-off agent in oil reservoirs. The primary objective was to test the ability of gellan gum solutions to form gels instantaneously upon contact with brine. Injection pressure was found to correlate with salinity, increasing from less than 0.01 MPa to 0.36 MPa as brine salinity rose from 0 to 90 g/L. In contrast, progressive plugging was observed in distilled water–saturated porous media. Subsequent core flooding experiments conducted with epoxy core holders equipped with internal pressure taps demonstrated that gellan gum has a limited ability to penetrate high-permeability (700 mD) porous media, due to the presence of particulate gels in solution. This explains why polymers such as gellan gum have not been applied for polymer flooding. However, alternating injections of gellan gum solutions and brine in fractured cores achieved a maximal post-flush pressure of 0.5 MPa, compared with 0.083 MPa recorded for mature 0.5% HPAM gels prepared in low-salinity brine. Overall, these findings provide further evidence that gellan gum cannot be used for polymer flooding or in-depth conformance control, but its successful field application in the Kumkol and Karabulak fields (2013–2016) can be attributed to fracture-related conformance problems effectively treated by gellan gum.

Abstract. Polymer flooding (PF) is getting more and more interests due to its high incremental oil recovery factor and relative low cost compared to other enhanced oil recovery (EOR) techniques like thermal flooding and gas flooding. Although PF was first tested in 1960s in the USA and many field tests were conducted in many countries, commercial application of PF was only reported in limited reservoirs and all in sandstone reservoirs. Carbonate reservoirs are characterized by high temperature high salinity (HTHS) and low permeability, which put concerns on sufficient viscosity and polymer injectivity. This presentation will show that PF can be feasible with deepened understanding of EOR mechanisms of porous flow, wettability alternation, induced fracturing and overlooked injectivity. The screen envelop of PF can be expanded to low permeability and HTHS with newly developed and evaluated polymers and its flow tests in low permeability cores. Previous and recent field cases of PF in carbonate reservoirs in USA and UAE were reviewed and discussed. All field tests attained technical success and some got economic success. The conclusion is that PF can be tested in HTHS carbonate reservoirs and the benefits surpassed risks.

Abstract. Chemical enhanced oil recovery (CEOR) has been tested in many oilfields both in sandstone and carbonate reservoirs. And commercial application of CEOR has been reported in Canada, China, India, etc. As many peers may be very impressive of polymer flooding (PF) and alkali/surfactant/polymer flooding (ASP) in Daqing oilfield for the great oil production, CEOR in much higher temperature (65-80℃) reservoirs in China are more challenging but desirable. This presentation presented an update review on high temperature high salinity (HTHS) reservoirs chemical flooding oil recovery (CEOR) advances in China by reviewing four field tests (three onshore, one offshore). Enlarged PF in HTHS high permeability reservoirs showed that PF can be used to increase oil recovery factor and the cost can be lower than water flooding. After PF, surfactant/polymer (SP) with branched preformed particle gel (B-PPG) as a quartic recovery can increase oil production significantly with infill drilling. Total oil recovery can be 67% for 70℃ heavy oil. A very recent large-scale SP flooding field test in offshore reservoir showed success and promoted other two offshore CEOR projects. To compete with PF and SP, ASP flooding in a very high temperature (80-85℃) reservoir showed that oil rate increased from 38.8 ton/d to 166.3 ton/day and incremental oil recovery factor was 9.23% original oil in place without well infilling. These four tests in HTHS reservoirs showed that CEOR can be very promising, although the cost may be further reduced by deepened understanding of EOR mechanisms.

Abstract. CO2 flooding technology has been widely applied worldwide due to its ability to reduce crude oil viscosity, achieve miscibility, and cause oil expansion as a result of its polarity similar to that of crude oil. However, in low permeability reservoirs, the presence of preferential flow channels such as fractures allows CO2 to rapidly break through to production wells, leading to gas channeling. This phenomenon reduces oil displacement efficiency and increases carbon emissions. To address gas channeling during CO2 flooding, three types of plugging systems targeting mobility control have been developed: foam, polymer gel, and polymer particle gel.

Foam systems exhibit excellent mobility control ability owing to the Jamin effect, yet their stability remains a critical factor restricting field application. To overcome this limitation, three types of foam systems were developed: first, a regenerated cellulose (RC) stabilized CO2 foam system, in which biomass cellulose enhances the foam skeleton strength to achieve long-term stability. Second, a CO2 foam system stabilized by viscoelastic nano polymer microspheres, where water-absorbing viscoelastic polymer microspheres improve the viscosity and elasticity of the foam interfacial film. Third, a CO2 foam system constructed with a viscoelastic surfactant (VES), which forms denser wormlike micelles under CO2 induction, significantly enhancing foam stability.

Polymer gels are the most conventional plugging agents used in water shut-off treatments. However, under the strong acidic environment of supercritical CO2, their strength can be significantly compromised. Accordingly, three types of acid-resistant high strength polymer gels were developed: first, an inclusion-type polymer gel system based on host–guest interactions, where supramolecular interactions enhance gel strength. Second, a composite gel system reinforced with fly ash from solid waste in coal-fired power plants. Third, a strengthened polymer gel with an organic/inorganic dual-crosslinked network formed by phenolic resin and aluminum citrate.

With the growing demand for deep mobility control, polymer particle gels (microspheres) have attracted widespread attention due to their amoeba-like elastic deformation capability. Two types of acid-resistant polymer particle gels were developed: first, preformed particle gel (AR-PPG) synthesized by introducing cationic acid-resistant monomers. The cationic groups within the particle structure enhance electrostatic repulsion between molecular chains under acidic conditions, promoting hydration expansion and improving plugging performance. Second, for high-temperature environments, a dual-crosslinked polymer microsphere with delayed expansion properties was synthesized based on AR-PPG by incorporating an unstable crosslinking mechanism. This system demonstrates superior deep mobility control performance and enhanced acid resistance, effectively plugging CO2 gas channeling.

These three types of plugging systems provide a comprehensive technical solution for controlling gas channeling in CO2 flooding in low permeability reservoirs, offering significant application potential and promotion value. In the future, the environmental adaptability and economic efficiency of these materials may be further optimized to promote large-scale field application. Meanwhile, the integration of intelligent control and real-time monitoring technologies is expected to enable more precise and efficient management of the CO2 flooding process, thereby providing key technical support for enhancing oil recovery and reducing carbon emissions.

Abstract. This presentation outlines a novel laboratory protocol for surfactant–polymer (SP) enhanced oil recovery (EOR), aiming to mitigate chemical risks and improve field performance. The traditional EOR approach, which begins with polymer selection and uses treated water for lab tests, is contrasted with a new methodology that prioritizes surfactant selection and mandates reservoir-specific water and rock mineral composition analysis.

Key innovations include:

Advanced Laboratory Design: Incorporates dynamic adsorption measurements, rock/fluid compatibility tests, and comprehensive water composition reviews.

Surfactant Development: Introduction of DBSJ anionic cocogem surfactant and KOMAD

surfactant blend, both demonstrating high thermal stability, reversible adsorption, and EU REACH compliance.

Performance Metrics: Surfactant blends show significant interfacial tension (IFT) reduction and viscosity enhancement, even under high salinity and temperature conditions.

Compatibility Studies: Demonstrated synergy between surfactants and polymers, with

favourable hydrodynamic behaviour and thermodynamic stability.

Asphaltene Interaction: Adsorption studies reveal that asphaltene content in reservoir rock influences surfactant behaviour, with Langmuir-type isotherms fitting well across varying hydrophobized conditions.

Risk Mitigation Strategy: Emphasizes continuous quality control, mineralogical analysis, and monitoring of water supply changes to ensure safe and effective SP deployment.

The proposed protocol enhances chemical intelligence in EOR design, enabling safer, more efficient, and scalable field applications.

Abstract. The application of foam-based hydraulic fracturing fluids in low-pressure, mature reservoirs has gained attention globally as a means to minimize formation damage and optimize proppant placement. In 2024, a pioneering fluid frac operation using a nitrogen foam system was conducted in the CIS region for the first time. The operation was executed on two offset wells with similar geological and petrophysical properties. One well was stimulated using a conventional linear gel system, while the other utilized a nitrogen-foam-based fracturing fluid. Both treatments were accompanied by comprehensive microseismic monitoring and tracer diagnostics.

Microseismic analysis revealed that the foam-based treatment led to more controlled fracture height growth and longer effective fracture half-lengths, indicating a more targeted stimulation of the pay zone. Production data further demonstrated superior post-frac performance from the foam-treated well, with a 1.8x increase in initial oil rate compared to the conventionally treated offset. This paper presents an in-depth engineering evaluation of the treatments, supported by field data, simulation results, and diagnostic interpretations. The results confirm the potential of nitrogen foam fracturing for enhancing recovery in depleted, water-prone formations and set the stage for broader deployment of this technology across mature oil fields in the region.

Abstract. The presentation examines technology applied for the recovery of low-production oil and gas wells and enhancement of oil productivity using Slot Perforation Technology (SPT). The technology creates deep longitudinal slots along the wellbore without casing deformation or cement sheath destruction, increasing drainage area and improving reservoir permeability. This is an environmentally clean method (sand and water) that enables extraction of up to 75% of hydrocarbons and ensures stable flow for 20-25 years. Practical results in Canada and the USA demonstrated production increase from zero to 30-70 bbl/day even on wells with no effect after hydraulic fracturing. The presentation also provides comparative analysis with other reservoir stimulation methods. Additionally, an AI platform is being developed for calculating well recovery prospects, which reduces analysis time and improves forecast accuracy.

Abstract. Heavy oil reservoirs commonly exhibit low recovery factors, and conventional waterflooding often accelerates water breakthrough. Thermal and chemical EOR methods are frequently uneconomic in shallow, poorly consolidated, clay-rich sandstones due to high capital intensity and formation sensitivity. At the East Moldabek field, the Cretaceous reservoirs show a recovery factor of 0.07 compared to the design value of 0.33, with only 22% of recoverable reserves produced. Hydraulic fracturing (HF) was evaluated as an alternative technology to improve recovery and mitigate sand production. Laboratory testing, proppant material selection—including polymer-coated proppant—and performance forecasting preceded field trials. HF in one well yielded sustained oil production gains and reduced water cut, whereas results in two other wells were suboptimal. Post-analysis identified geological and operational factors critical to HF effectiveness and informed recommendations for candidate selection and treatment design. The study demonstrates that, when adapted to local conditions, HF can serve as a cost-effective recovery enhancement tool for shallow Cretaceous reservoirs, offering insights applicable to analogous fields.

Abstract. This paper presents an integrated systematic methodology for the selection, engineering design, and performance monitoring of bottomhole formation zone (BFZ) stimulation treatments. The comprehensive workflow encompasses all operational stages from candidate well selection and formation damage mechanism analysis to treatment fluid design and execution supervision.

Particular emphasis is placed on laboratory investigations, including bulk fluid compatibility tests and core flood experiments, for chemical reagent selection and optimization. This laboratory-based approach enables reliable prediction and enhancement of treatment efficiency.

Field case studies demonstrate successful applications of this methodology, including: productivity restoration following well kill operations, post-drilling stimulation optimization, and mechanical diverting agent implementation in wells with multistage hydraulic fracturing (MSHF). The results confirm substantial improvements in productivity indices and oil production rates, ensuring economic viability of the well intervention operations.