Enhanced Oil Recovery (EOR)

PAM Polymer Flooding for Enhanced Oil Recovery

Conventional waterflooding typically recovers 30-40% of original oil in place (OOIP). Published field results from polymer flooding projects generally report an incremental 5-15% OOIP on top of that, depending heavily on reservoir heterogeneity, oil viscosity and how early in field life the polymer is injected. The ranges on this page are representative of published industry data and screening studies; any specific project needs its own reservoir simulation and pilot before the economics can be trusted.

The mechanism is straightforward. PAM raises injection water viscosity, which improves the mobility ratio between the displacing water and the oil being displaced. Instead of fingering through the highest-permeability streaks and leaving oil behind in tighter rock, the injected water sweeps a larger fraction of the reservoir volume. The polymer is not doing chemistry on the oil — it is correcting a flow problem.

How Polymer Flooding Works

Mobility Ratio Improvement

Mobility ratio M = (water mobility) / (oil mobility). When M > 1, water fingers through the reservoir, bypassing oil. PAM at 500-2000 ppm increases water viscosity 5-20x, reducing M below 1 and forcing water to sweep more uniformly.

• PAM concentration: 500-2000 ppm in injection water
• Viscosity increase: 5-20x at 1000 ppm
• Molecular weight: 15-25M Da (high MW for viscosity)
• Hydrolysis degree: 25-35% (for salinity tolerance)

Reservoir Conditions

PAM polymer flooding works best in:

• Sandstone reservoirs (limestone adsorbs too much PAM)
• Permeability >50 mD (low-perm reservoirs plug)
• Temperature <90°C (standard PAM), <120°C (AMPS-modified)
• Salinity <50,000 ppm TDS (standard), <200,000 ppm (salt-tolerant grade)
• Oil viscosity 5-200 cP (heavy oil needs higher PAM concentration)

EOR Grade Selection

Reservoir Screening: Deciding If Polymer Flooding Fits

Polymer flooding fails more often from poor candidate selection than from poor polymer. The screening criteria below reflect the consensus ranges in EOR screening literature. A reservoir outside them is not automatically disqualified, but it needs a much stronger simulation case before spending on polymer.

The last row is the one most often ignored. Polymer flooding started early, before water cut climbs high, captures far more incremental oil than the same project started as a late-life salvage attempt — the sweep improvement has more mobile oil left to act on.

Project Economics: How the Numbers Are Built

Rather than quote a single project outcome, it is more useful to set out the calculation so you can run it on your own reservoir. Polymer cost per incremental barrel is the number that decides the project.

1. Polymer consumption. Injection rate × concentration. An injector taking 1,000 bbl/day of water at 1,500 ppm needs roughly 240 kg/day of polymer, so a 10-injector pattern runs around 2.4 t/day.
2. Polymer cost. At EOR-grade pricing, that pattern carries an annual polymer spend in the low single-digit millions of dollars, before facilities and produced-water handling.
3. Incremental oil. Take incremental recovery from simulation, not from a rule of thumb. Published projects commonly land in the 5-15% OOIP range.
4. Cost per incremental barrel. Polymer spend divided by incremental barrels. Published polymer flood projects widely report figures in the low single-digit dollars per incremental barrel, which is what makes the technique attractive against oil price.
5. Facilities and produced water. Often underestimated. Viscous produced water changes separator residence time and water treatment chemistry, and that capital and operating cost belongs in the case.

A pilot on a single pattern before field-wide rollout is standard practice, and it is also the point where polymer grade selection gets validated against real injectivity rather than lab viscosity.

Injection System Design

PAM polymer flooding requires careful injection system design to avoid mechanical degradation:

1. Dissolution: Dissolve PAM powder in fresh water at 0.5-1.0% concentration. Use low-shear mixing (30-60 RPM) for 2-4 hours. Never use high-shear pumps — they break polymer chains.
2. Maturation: Allow 4-8 hours for full hydration before injection. Partially hydrated PAM has lower viscosity and higher adsorption.
3. Dilution: Dilute to injection concentration (500-2000 ppm) with produced water or seawater. Use inline static mixers, not centrifugal pumps.
4. Injection: Use progressive cavity pumps or reciprocating pumps. Centrifugal pumps degrade PAM by 20-40% per pass.
5. Monitoring: Check viscosity at wellhead weekly. Viscosity drop >20% indicates mechanical degradation or bacterial attack.

The Four Ways Polymer Loses Viscosity

A polymer flood that stops working rarely does so for a mysterious reason. There are four degradation pathways, and each has a different diagnostic signature and a different fix.

The practical test is to measure viscosity at four points — mixing tank, after dilution, at wellhead, and at the injector after the choke. Whichever step shows the loss identifies the mechanism without guesswork.

Produced Water: The Consequence Nobody Budgets For

Injected polymer eventually breaks through to the producers, and the produced water comes back viscous. This affects the surface facility in ways worth planning for before breakthrough rather than after.

• Oil-water separation slows. Higher continuous-phase viscosity reduces droplet rise velocity, so existing separators may need longer residence time or a demulsifier change.
• Water clarification chemistry shifts. Residual polymer interferes with conventional coagulant dosing, and the flocculant programme normally has to be re-optimised by jar test rather than carried over unchanged.
• Re-injection quality. Produced water containing residual polymer can be reused as make-up, which saves polymer, but filterability has to be monitored or injectivity declines.
• Discharge compliance. Where produced water is discharged rather than reinjected, check the residual polymer and residual acrylamide monomer limits in the local regulation before breakthrough, not after.

Our EOR-Grade PAM

EOR applications demand the tightest specifications in the PAM industry. Our EOR grades:

• MW: 20-28M Da (±0.5M tolerance)
• Hydrolysis: 25-35% (±2% tolerance)
• Filterability ratio: <1.5 (critical for injectivity)
• Residual monomer: ≤0.05%
• Insoluble content: ≤0.1%
• Dissolution time: ≤90 minutes

Filterability ratio is the most important EOR-specific parameter — it measures how easily the polymer solution passes through reservoir rock. A ratio above 2.0 causes injectivity decline and plugging. We test every EOR batch for filterability before shipment.

HPAM Against the Alternatives

Hydrolysed polyacrylamide is the default EOR polymer, but it is not the only option, and knowing where it loses helps confirm whether it is right for a given reservoir.

In practice the decision is usually between conventional and AMPS-modified HPAM, made on reservoir temperature and water chemistry. Where a screening study shows conventional HPAM at the edge of its envelope, the incremental tonne cost of the modified grade is generally small against the cost of a flood that loses viscosity halfway through.

Field Monitoring Programme

A polymer flood needs a monitoring plan agreed before injection starts, because most of the diagnostic value comes from trends rather than single measurements.

• Injected polymer viscosity at mixing tank and wellhead, weekly, to catch shear and oxidative losses early.
• Filterability on each delivered batch and periodically on the mixed solution, to protect injectivity.
• Injectivity index per well, tracked continuously — a declining trend at constant rate and pressure is the earliest warning of plugging.
• Polymer concentration in produced fluid per producer, to identify breakthrough timing and channelling between specific injector-producer pairs.
• Water cut and oil rate per producer against a pre-polymer baseline, which is the only way to attribute incremental oil credibly.

Frequently Asked Questions

How much PAM does a typical polymer flood project consume?

A 1,000 barrel/day injection well at 1,500 ppm PAM concentration consumes approximately 240 kg/day of PAM powder. A 10-well pattern project consumes 2,400 kg/day — about 876 tons/year. We supply annual contracts for EOR projects with guaranteed pricing and delivery schedules.

What happens to PAM in the reservoir?

PAM adsorbs onto rock surfaces (50-200 µg/g rock), reducing effective permeability and improving sweep. The remainder flows through the reservoir and is produced with oil and water. Produced PAM is biodegradable and does not accumulate in the environment.

Can PAM polymer flooding work in carbonate reservoirs?

Carbonate reservoirs adsorb substantially more polymer per unit rock than sandstone, which is why screening guidelines favour sandstone. It is not categorically impossible, but the polymer consumed to satisfy adsorption before any sweep benefit appears often removes the economic case. Surfactant-polymer or alkaline-surfactant-polymer schemes are the more usual route in carbonates.

What is filterability ratio and why does it matter more than viscosity?

Filterability ratio measures how readily a polymer solution passes through a fine filter under constant pressure, comparing late-stage to early-stage flow. It is a proxy for whether microgels and undissolved material will plug reservoir pore throats. A solution can hit its viscosity target and still be unusable if filterability is poor, because injectivity will decline well by well. A ratio below 1.5 is the normal EOR acceptance criterion, and it is tested on every EOR batch before shipment.

Should injection be a continuous polymer bank or a tapered concentration?

Both are used. A constant-concentration bank is simpler operationally. Tapered designs start at higher concentration to establish the bank and then step down, which reduces total polymer for a similar sweep in some simulation cases. The decision should come from reservoir simulation on the specific pattern, since it depends on heterogeneity and injector-producer spacing.

How soon after injection starts should incremental oil appear?

Response time is governed by pattern size and injection rate, and is commonly months rather than weeks — typically after a meaningful fraction of a pore volume has been injected. This is why polymer flood pilots need patience and a pre-agreed monitoring plan; judging the project on the first few weeks of production data is the most common way a technically sound pilot gets cancelled early.

Can produced water be used as make-up water for polymer mixing?

Frequently yes, and it saves both fresh water and polymer where residual polymer remains. The constraints are hardness, dissolved oxygen, iron content, and bacterial load — each of which degrades the fresh polymer being mixed. Where produced water is used, oxygen scavenger and biocide handling become part of the routine programme rather than optional extras.