Overview of Polymer Flooding
Overview of Polymer Flooding. Polymer flooding is one of the most widely used Chemical Enhanced Oil Recovery (EOR) techniques, offering significant improvements in oil displacement efficiency, reduced water cut, and extended field life. Understanding its full scope—from theory to field application—is essential for optimizing project outcomes.
This page provides a collection of documents covering the entire spectrum of polymer flooding, including:
- Fundamental principles explaining how polymer flooding improves sweep efficiency.
- Technical reviews summarizing key research, field trials, and industry advancements.
- Guides and best practices for screening, design, and implementation.
- Case studies and field reports showcasing real-world applications and lessons learned.
You can also check our YouTube channel for additional videos and podcasts and navigate the Polymer Flooding Guide for more content or our Academy for online courses.
Table of Contents
Polymer Flooding - An Overview
We propose the slides from Randy Seright’s training course.
Polymer Flooding - Concept Overview
In this video, we demonstrate how Polymer Flooding enhances oil recovery by improving sweep efficiency and encouraging crossflow between reservoir layers. We also examine the impact of resuming water injection after polymer injection ends: due to unstable displacement, water preferentially flows through the high-permeability zones, bypassing the lower-permeability areas. As a result, without continued polymer injection, the mobility control is lost—and the effectiveness of the project rapidly declines
Publications - Polymer Flooding Overview
In the following section, we provide access to publications including Randy Seright’s.
This paper investigates the potential of various approaches for improving sweep in parts of the Daqing oil field that have been EOR targets. Studies indicated that the polymer flood should have provided excellent sweep throughout the majority of patterns considered. However, because ASP flooding is being considered to increase recovery efficiency, mobility control and sweep improvement will be especially important. Fractures present in some Daqing wells aided reservoir sweep rather than causing channeling, because they were narrow and far from the wellbore. Near-wellbore fractures substantially increased injectivity index during polymer injection and oil-productivity index in production wells. Mechanical shear degradation is the greatest polymer degradation concern; near-wellbore fractures mitigate it effectively. Several new polymers show potential at Daqing. Other approaches investigated include colloidal dispersion gels, foams, ASP foams, steam, microbes, and reduced-salinity polymer solutions.
A major decision point in every polymer flood is what happens when polymer injection stops and water injection resumes. This transition is widely modelled as a continuation of the flood — often with the expectation that residual resistance factors and polymer-induced conformance improvements will sustain oil production. Field evidence suggests the opposite: recovery efficiency declines rapidly, water cut spikes, and production rates quickly return to pre-polymer baseline levels.
This paper synthesizes theoretical frameworks and field case studies from Kazakhstan, China, India, Oman, Brazil, and Canada to document the dynamics of post-polymer water injection and explain why standard simulation approaches consistently overestimate recovery during this phase. Root causes examined include the role of viscous fingering, the overestimation of residual resistance factors in high-permeability rock, the failure of graded viscosity bank models to account for real reservoir heterogeneity, and the tendency for water to re-establish high-permeability preferential flow paths that dominated before polymer injection. Practical recommendations are developed for extending the injection phase and designing polymer banks with post-flood performance in mind.
The workflow used to select and characterize polymers for chemical EOR has remained essentially unchanged since the first field projects in the 1960s — viscosity curves, filtration tests, and then coreflood experiments from which parameters are extracted for history matching. This paper argues that this standard workflow is poorly suited to predicting real field behavior, and that it has systematically prevented engineers from correctly modelling polymer injection and forecasting injectivity.
Three sources of misrepresentation are examined. First, laboratory polymer solutions are pristine: field preparation through pumps, valves, and perforations alters molecular weight distribution and in-situ rheology in ways that laboratory tests do not replicate. Second, standard filtration protocols (filter ratio test, pre-filtration before coreflood) are inconsistent across the industry and do not reflect field conditions. Third, nearly all corefloods are run at fixed injection rate — mimicking an extrusion process rather than the constant-pressure-drop displacement that governs most of the reservoir. A revised, field-first workflow is proposed, along with practical recommendations for more representative polymer characterization.
This review presents our perspective on the factors that have brought polymer flooding to its current
state. Insights are provided on why HPAM is the dominant polymer used as well as what is needed to make alternative polymers and mobility-control methods viable. Explanation is given for why large polymer banks are needed for polymer flooding, and design of the injected polymer viscosity is detailed for cases with/without crossflow. The role of fractures and horizontal wells are discussed for improving injectivity and extending polymer flooding to recover oils with viscosities as high as 10,000 cP. Operational improvements are described to minimize mechanical and oxidative stability to allow HPAM polymers to be viable to 70 C and ATBS polymers to 120 C. Key factors affecting polymer retention are summarized. The paper points out unresolved issues and future directions for polymer flooding.
This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding at the Daqing oil field. Key design factors include: (1) recognizing when profile modification is needed before polymer injection and when zone isolation is valuable; (2) establishing optimum polymer formulations and injection rates; and (3) time-dependent variation of molecular weight in injected slugs. Oil recovery can be enhanced by 2–4% OOIP with profile modification before polymer injection in some wells. Injecting polymer separately into different layers improved profiles, sweep, injection rates, and reduced water cut. Bank sizes grew from 240–380 mg/L·PV in early pilots to 640–700 mg/L·PV in recent industrial sites. Economics and injectivity behavior can favor changing polymer molecular weight and concentration during injection. Polymers of 12 to 35 million Daltons Mw were designed. The optimum polymer injection volume was approximately 0.7 PV, with average concentration around 1,000 mg/L.
This paper provides an extensive review of polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods, covering the past 50 years. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding. The paper examines the validity of arguments commonly given to justify low polymer viscosities. For viscous oils (1,000 cp), designed polymer viscosities have sometimes been underestimated due to insufficient water injection while determining relative permeabilities, reliance on mobility ratios at the shock front, and overestimation of resistance factors. In homogeneous reservoirs, the ratio of produced-oil value to injected-fluid cost is fairly insensitive to polymer viscosity up to the base-case optimum. Reservoir heterogeneity and dissolution-equipment economics favor high polymer viscosities if injectivity is not limiting. Injection above the formation-parting pressure and fracture extension are crucial for acceptable injectivity in many floods. Experience and technical considerations favor the largest practical polymer bank.
This companion paper to Part 1 demonstrates applications of EOR screening criteria and examines the impact of oil prices on EOR activity. The CO2 screening criteria are used to estimate the total quantity of CO2 that might be needed for the world’s oil reservoirs. If only depth and oil gravity are considered, approximately 80% of the world’s reservoirs could qualify for some type of CO2 injection. Despite lower oil prices since 1986 reducing EOR project counts, actual incremental production has tracked closely with NPC predictions for $20/bbl scenarios. CO2 flooding incremental production has actually exceeded those predictions. Screening criteria are recommended as a first-pass filter prior to economic evaluation, particularly for large-scale portfolio analysis.
Screening criteria are proposed for all EOR methods based on both field results and oil recovery mechanisms. Data from EOR projects worldwide are examined to identify optimum reservoir and oil characteristics for successful projects. Oil gravity ranges for all current EOR methods are compiled and presented graphically. The current state of the art for all EOR methods is briefly described, with relationships between them noted. Steamflooding remains the dominant EOR method. All chemical flooding activity has declined, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously. Detailed screening criteria tables are provided for chemical (polymer, surfactant, micellar), thermal (steam, hot water, in-situ combustion), gas miscible (CO2, hydrocarbon, N2), and immiscible gas flooding.
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.
For polymer solutions used in enhanced oil recovery (EOR), viscoelasticity is a rheological phenomenon that has a strong flux dependency and has been tied to significant reductions in residual oil saturation (Sor) during laboratory corefloods at high flux conditions. However, an unanswered question is whether the polymer’s viscoelastic effects reduce Sor over a significant portion of a polymer-flooded reservoir.
Two methodologies are used to answer this question for polymer-flood projects across nine countries (Argentina, Austria, Canada, China, India, Oman, Russia, Suriname, and USA). For most polymer floods with horizontal injectors, the highest possible Darcy velocity is too low (0.01–0.2 ft/D) to reach the onset velocity for viscoelastic behavior (>1 ft/D for most field conditions). For most vertical polymer injectors, less than 1% of the reservoir experiences fluid velocities high enough for viscoelasticity to potentially be important.
This paper conveys the improbability of shear-thickening induced-viscoelasticity causing Sor reduction in field applications. It also discusses the potential role of wettability alteration by the polymer and secondary-vs.-tertiary polymer-flooding effects.