Polymer Flooding: Definition, EOR Method, and Mobility Control
What Is Polymer Flooding?
Polymer flooding is an enhanced oil recovery (EOR) method in which water-soluble polymer — typically partially hydrolysed polyacrylamide (HPAM) or xanthan biopolymer — is dissolved in the injection water to increase its viscosity. The thickened water reduces the mobility ratio between the displacing water and the displaced oil, suppressing viscous fingering and improving sweep efficiency. Polymer flooding is the most technically mature chemical EOR method, commercially deployed at scale in China's Daqing oil field, offshore in Oman, and in Permian Basin miscible floods, delivering incremental recoveries of 5–15% OOIP above what conventional waterflood achieves. It is most effective in reservoirs with high oil viscosity or severe permeability heterogeneity that causes injected water to channel through high-perm streaks.
Key Takeaways
- Polymer flooding increases injection water viscosity to reduce the mobility ratio and improve sweep — controlling viscous fingering and thief zone channelling.
- HPAM (partially hydrolysed polyacrylamide) is the dominant synthetic polymer; xanthan gum is used in higher-salinity or high-temperature reservoirs.
- Typical polymer concentration is 500–2,000 ppm; injection viscosity target is 5–50 cP depending on in-situ oil viscosity.
- Polymer adsorption onto reservoir rock reduces the effective polymer concentration — inaccessible pore volume and retention must be quantified in laboratory corefloods before design.
- Daqing oil field in China is the world's largest polymer flood, producing approximately 250,000 bbl/day of incremental oil since 1996.
How Polymer Flooding Works
In a conventional waterflood, the mobility ratio M = (krw/μw) ÷ (kro/μo). Water is typically 10–100× less viscous than oil, producing M >> 1 and causing water to finger through oil-saturated rock rather than advancing as a stable front. By adding polymer to the injection water to raise μw from 1 cP to 10–50 cP, M is reduced toward or below 1.0, stabilising the flood front. A stable front sweeps more of the reservoir before water breaks through at producers — increasing volumetric sweep and recovery factor.
Polymer flooding also acts as a conformance control agent: high-viscosity polymer preferentially enters high-permeability streaks, temporarily reducing their relative flow capacity and diverting subsequent injection into lower-permeability, oil-rich zones. This in-depth conformance improvement is distinct from near-wellbore gel treatments (which only seal the injector's immediate drainage area) and provides reservoir-scale sweep improvement over the life of the flood.
- EOR classification: chemical EOR (mobility control)
- Primary polymer: HPAM (partially hydrolysed polyacrylamide)
- Alternative polymer: xanthan gum (biopolymer, better salinity/temperature tolerance)
- Typical concentration: 500–2,000 ppm
- Target injection viscosity: 5–50 cP (matched to reservoir oil viscosity)
- Incremental recovery: 5–15% OOIP above waterflood
- Largest deployment: Daqing field, China (producing since 1996)
- Key screening criterion: reservoir temperature <95°C (HPAM degrades above this)
Mechanical degradation of HPAM through high-shear injection equipment is the most common cause of polymer EOR underperformance. HPAM is a long-chain polymer — its viscosity-building capability depends on molecular weight, which shear forces in pumps, valves, and perforations irreversibly destroy. Measure in-situ polymer viscosity at the injection wellbore using a rheometer on produced samples, not just at surface mix tanks. Specify low-shear injection equipment (progressive cavity pumps rather than centrifugal, choke-free wellhead manifolds, large-bore perforations) and validate with a polymer injectivity test on the lead injector before full-field rollout. A polymer programme where field viscosity is 30% of design viscosity due to shear degradation delivers 30% of expected incremental oil.
Polymer Flooding Synonyms and Related Terminology
Polymer flooding is also known as:
- Polymer EOR — positions it within the enhanced oil recovery classification
- Mobility control flooding — describes the mechanism rather than the agent
- Chemical EOR — broader category including surfactant and alkaline flooding
- ASP flooding — alkaline-surfactant-polymer flooding, a more advanced chemical EOR variant combining polymer with surfactant (wettability alteration) and alkaline agent (soap generation)
Related terms: Waterflood, Sweep Efficiency, Mobility Ratio, Wettability
Frequently Asked Questions About Polymer Flooding
What reservoir conditions are most suitable for polymer flooding?
Polymer flooding works best where the waterflood mobility ratio is unfavourable — oil viscosity above 5–10 cP — or where permeability heterogeneity is severe (permeability contrast between best and worst zones exceeds 5:1). Screening criteria include reservoir temperature below 90–95°C (higher temperatures degrade HPAM), formation water salinity below 100,000 ppm TDS (high salinity reduces HPAM viscosity; divalent ions Ca²⁺ and Mg²⁺ above 1,000 ppm cause precipitation), permeability above 20 mD (polymer cannot enter very tight pore throats), and remaining oil saturation after waterflood above 25% OOIP. The combination of moderate viscosity oil, significant remaining reserves, and an existing waterflood infrastructure makes polymer flooding a natural follow-on investment.
Why does Daqing demonstrate polymer flooding at such scale?
Daqing's Saertu reservoir has characteristics nearly ideal for polymer flooding: moderate oil viscosity (9–10 cP), highly heterogeneous fluvial sandstone with pronounced permeability layering, formation water salinity below 7,000 ppm (low divalent content, preserving HPAM viscosity), and reservoir temperature of 45°C (well below HPAM degradation threshold). China National Petroleum Corporation (CNPC) began polymer injection in 1996 and has produced an estimated 250,000 bbl/day of incremental oil at polymer slugs of 500–1,500 ppm. The technical success at Daqing validated polymer flooding at commercial scale and drove global EOR investment in chemical methods through the 2010s.
How does polymer flooding compare to surfactant EOR?
Polymer flooding improves sweep efficiency by controlling mobility — it does not recover oil trapped by capillary forces at the pore scale. Surfactant EOR reduces interfacial tension (IFT) between oil and water from 30 mN/m to <0.001 mN/m, mobilising capillary-trapped residual oil that waterflood and polymer cannot displace. Surfactant floods recover different oil than polymer floods; combining them (ASP flooding) addresses both capillary trapping and mobility control simultaneously. However, surfactant EOR costs 2–5× more than polymer flooding, requires complex reservoir chemistry management, and has a much shorter track record of successful field-scale deployment outside North America and China.
Why Polymer Flooding Matters in Oil and Gas
Polymer flooding is the most commercially proven chemical EOR method, with decades of field data from Daqing, offshore Oman (Marmul and Mukhaizna fields), and increasing deployments in the North Sea and Permian Basin. As conventional waterfloods mature and residual oil saturations increase, polymer flooding represents a cost-effective bridge between waterflood and more expensive miscible or thermal EOR — delivering incremental barrels at $15–30/bbl operating cost in favourable reservoirs. The global technical community continues to advance HPAM formulations for higher-temperature and higher-salinity applications, progressively expanding the reservoir base where polymer flooding is technically viable.