Screening Mature Fields for CO2-EOR Versus Polymer Flooding
Pick the wrong EOR method for a mature field and you pay for it — wasted capital, delayed production response, and conformance damage that may never come back. CO2 injection versus polymer flooding is not a desktop exercise. It sets well configuration, surface facility scope, injection infrastructure, and procurement lead times that can run for years. Even so, plenty of subsurface planning teams still work off informal rules of thumb instead of structured screening logic. Those projects then arrive at front-end engineering carrying incompatibilities nobody caught early enough.
What follows is the reservoir data you need, the miscibility checks that matter, and the selection criteria a planning team should work through before committing to either method.
Why Mature Fields Demand Rigorous Screening
A field does not become an EOR candidate until it has been through primary depletion and a waterflood cycle. By then reservoir pressure is down, water cuts are high, and the heterogeneity picture is well established. Remaining oil saturation is unevenly distributed, and the mechanisms that will mobilise it differ fundamentally between CO2 and polymer injection.
CO2-EOR goes after residual oil through miscibility or near-miscibility. It reduces interfacial tension, swells crude oil, and lowers viscosity. Polymer flooding goes after sweep efficiency instead — it thickens the injected water phase to pull the mobility ratio between displacing and displaced fluids down. Bolt the wrong mechanism onto a reservoir's dominant trapping mode and you waste the injected fluid and the opportunity along with it.
Screening is the first technical gate. Treat it as a genuine filter, not a formality.
Required Reservoir Data Before Screening Begins
You cannot evaluate either method without a minimum dataset. Gaps at this stage propagate into screening errors, and those are expensive to unwind.
For CO2-EOR:
- Reservoir pressure (current and historical), temperature, and depth
- Crude oil API gravity, composition (C5–C30 fractions), and molecular weight
- Minimum miscibility pressure (MMP) — measured or calculated from slim-tube or rising-bubble apparatus
- Current average reservoir pressure relative to MMP
- Permeability distribution and presence of natural fractures
- Existing CO2 source proximity and purity specification
For polymer flooding:
- Formation water salinity and divalent ion concentration (Ca²⁺, Mg²⁺)
- Reservoir temperature
- Crude oil viscosity at reservoir conditions
- Permeability — both average value and heterogeneity profile (Dykstra-Parsons coefficient or Lorenz coefficient)
- Residual resistance factor data for candidate polymers
High-salinity, high-temperature environments degrade polymer performance significantly. Quantify that before any injection scheme is designed.
Miscibility Assessment for CO2-EOR
The miscibility check is the single most consequential step in CO2-EOR screening. It decides whether the project runs in miscible mode — CO2 and oil forming a single phase at first contact or through multiple contacts — or in immiscible mode, where the recovery improvement is more modest.
MMP is primarily a function of reservoir temperature and crude oil composition, specifically the fraction of intermediate hydrocarbons (C2–C6). Lighter, higher-API crudes with significant intermediate fractions reach miscibility at lower pressures. Heavier, more asphaltic crudes need higher pressures, and those may sit above current reservoir pressure or the fracture gradient.
The assessment workflow:
- Obtain reservoir temperature and representative fluid sample (bottom-hole sample preferred over recombined surface sample).
- Measure or calculate MMP using slim-tube displacement or rising-bubble apparatus. Correlations may be used for preliminary screening but should not substitute for laboratory measurement at the feasibility stage.
- Compare MMP against current reservoir pressure. If current pressure is below MMP, determine whether pressure maintenance through CO2 injection alone can re-pressurize the reservoir to miscible conditions — this requires simulation.
- If miscible conditions cannot be achieved, evaluate immiscible CO2 flooding. The Shengli Oilfield assessment (Petroleum Exploration and Development, 2009) demonstrated that even immiscible CO2 injection can improve recovery in reservoirs where viscosity reduction and oil swelling are the dominant mechanisms, particularly in heterogeneous reservoirs with remaining oil in low-permeability zones.
That kind of weighted, multi-parameter scoring holds up better than single-criterion cutoffs.
Comparative Screening Criteria
The table below summarises the key technical parameters and how they favour one method over the other. All qualitative descriptors reflect the ranges discussed in the cited screening literature.
| Parameter | Favours CO2-EOR | Favours Polymer Flooding |
|---|---|---|
| Oil API gravity | Higher gravity, lighter composition | Lower gravity, higher viscosity |
| Reservoir depth | Sufficient depth for pressure to approach or exceed MMP | Shallow to moderate depth acceptable |
| Reservoir pressure | At or above MMP (miscible), or high enough for meaningful immiscible benefit | Adequate to sustain injectivity; pressure maintenance less critical |
| Permeability | Moderate to low acceptable if miscible conditions met | Moderate to high; very low permeability impairs injectivity |
| Heterogeneity | Moderate; high fracture density causes early CO2 breakthrough | High Dykstra-Parsons coefficient — polymer addresses conformance |
| Formation water salinity | Less sensitive | Low to moderate salinity required; high divalent content degrades polymer |
| Reservoir temperature | Moderate — high temperature raises MMP | High temperature degrades polymer viscosity; upper limit applies |
| Oil viscosity | Low to moderate — high viscosity reduces CO2 benefit | Moderate to high — viscosity ratio drives polymer selection |
| CO2 source availability | Required — proximity and purity are commercial constraints | Not applicable |
Illustrative Screening Scenario
The following is an illustrative example constructed to demonstrate the screening workflow. It does not represent a named field or published case study.
A planning team is weighing two reservoir units in a mature offshore field that has been on waterflood for several years. Unit A is a deeper, higher-pressure sandstone with light oil and a measured MMP close to current reservoir pressure. Unit B is a shallower, lower-pressure carbonate with moderately viscous oil, high water cut, and a Dykstra-Parsons coefficient that points to significant permeability contrast between layers.
For Unit A, the team runs the miscibility check. Current reservoir pressure sits close to, but slightly below, the measured MMP. A slim-tube test confirms near-miscible behaviour is achievable with modest pressure support. CO2-EOR screens as technically viable, subject to verifying a CO2 source within economic transport distance and confirming there are no extensive open fractures that would cause early gas breakthrough.
For Unit B, the miscibility check fails. The shallow depth and current pressure put the reservoir well below any achievable MMP for that crude composition, so CO2 injection would run in deeply immiscible mode with limited recovery benefit. But the permeability contrast and moderate oil viscosity fall well inside the polymer flooding screening envelope. Formation water salinity gets checked against the degradation thresholds for candidate hydrolysed polyacrylamide (HPAM) polymers, and divalent ion concentration turns out to be manageable with partial softening. Polymer flooding proceeds to feasibility.
That divergence — one method per reservoir unit in the same field — is a common outcome of rigorous screening. It is also why the work has to be done at the reservoir unit level, not the field level.
Pre-Commitment Screening Checklist
Before a method advances to feasibility study, the planning team should be able to answer each of the following:
CO2-EOR:
- MMP measured or reliably estimated from representative fluid sample
- Current reservoir pressure mapped against MMP across the target area
- Fracture characterisation sufficient to assess breakthrough risk
- CO2 source identified with composition, volume, and delivery pressure confirmed
- Surface facility scope for CO2 handling, compression, and recycling assessed
- Regulatory pathway for CO2 storage credit (if applicable) identified
Polymer Flooding:
- Formation water analysis complete, including divalent ion concentration
- Reservoir temperature confirmed within acceptable range for candidate polymer
- Injectivity test or analogue data available to confirm polymer can be placed at target rate
- Permeability profile characterised — Dykstra-Parsons or equivalent
- Polymer degradation testing at reservoir temperature and salinity completed or planned
- Produced fluid handling capacity for increased polymer-laden water confirmed
Both methods:
- Remaining oil saturation distribution mapped from surveillance data
- Injection pattern geometry evaluated for conformance
- Baseline production data sufficient to establish a credible pre-EOR decline trend
Conclusion and Next Steps
Screening is not a ranking exercise to justify a predetermined outcome. It is a technical filter that protects capital. CO2-EOR and polymer flooding solve different recovery problems, and the reservoir data has to drive the selection — not commercial preference, and not analogues pulled from dissimilar geology.
The immediate next step for any planning team is to audit the data inventory against the requirements listed above and identify the gaps. Missing MMP data, incomplete fluid samples, absent formation water analyses: none of these are minor oversights. They are screening blockers, and left unresolved they produce unreliable feasibility conclusions.
Once the screening gate is passed with a complete dataset, the selected method should proceed to reservoir simulation with history-matched models before any surface facility or procurement commitment is made. Where CO2 breakthrough risk is high and polymer injectivity is confirmed, a hybrid option may be worth evaluating as well.
