Wrong EOR picks don't get a second chance. Mobilise equipment, drill injection wells, and condition surface facilities for a polymer flood the reservoir temperature will kill — or sink capital into a CO₂ miscible flood where pressure can't hold miscibility — and you've spent the budget, deferred production, and recovered nothing extra. That screening decision is made months or years before first injection. It decides whether the project earns its cost of capital or becomes a write-down.
This article walks through how to match the three dominant EOR families — CO₂ flooding, polymer flooding, and thermal flooding — against reservoir and fluid properties, and how structured decision frameworks reduce the risk of a wrong selection.
Why Screening Fails in Practice
Most screening failures trace back to the same habit: applying one criterion in isolation. Viscosity alone does not select thermal; depth alone does not disqualify CO₂. What governs feasibility is how the parameters interact — oil gravity, reservoir temperature, permeability, depth, and fluid saturations. Recent work applying multi-criteria decision analysis (TOPSIS) to Iraqi reservoirs demonstrates that ranking EOR candidates requires simultaneous weighting of multiple reservoir attributes rather than sequential pass/fail gates (Rasul, 2026). A hybrid screening framework combining empirical criteria with machine-learning classification tells the same story: no single parameter is sufficient for CO₂ EOR selection (Ghafoori et al., 2026).
The Core Screening Parameters
Before comparing methods, establish a consistent parameter set for the candidate reservoir. The minimum dataset required for preliminary screening includes:
- Reservoir depth and pressure
- Reservoir temperature
- Oil API gravity and viscosity at reservoir conditions
- Formation water salinity and hardness
- Net pay thickness and areal extent
- Porosity and permeability (average and distribution)
- Current oil saturation and water cut
- Lithology (sandstone vs. carbonate)
Each EOR family has hard physical limits within this parameter space. Violate them and you don't get a marginal project. You get a failed one.
CO₂ Flooding: Miscibility Pressure Is the Governing Constraint
CO₂ flooding works by reducing interfacial tension between injected gas and reservoir crude, ideally achieving first-contact or multiple-contact miscibility. The critical technical constraint is minimum miscibility pressure (MMP). If reservoir pressure cannot sustain or be raised to MMP, the flood operates in an immiscible regime with substantially lower displacement efficiency.
MMP is a function of reservoir temperature and oil composition, particularly C₅–C₁₂ intermediate fractions. Lighter, higher-API crudes reach miscibility at lower pressures. Heavier crudes with fewer intermediates require higher pressures or may not achieve miscibility at all.
Depth is therefore a proxy for pressure: shallow reservoirs typically cannot sustain the pressures needed for miscible displacement. Conversely, very deep reservoirs may present injectivity challenges and elevated CO₂ compression costs.
Structural integrity matters disproportionately in CO₂ floods. CO₂ is buoyant relative to reservoir brine and will migrate upward, so reservoirs with strong top seals and limited vertical fracture connectivity retain injected gas more effectively. Gravity override in thick, steeply dipping formations reduces sweep efficiency unless a WAG (water-alternating-gas) scheme is designed to manage it.
The improved hybrid framework of Ghafoori et al. (2026) identifies oil gravity, reservoir depth, and temperature as the highest-weight parameters in CO₂ EOR screening, with permeability playing a secondary role compared to its dominance in chemical flooding.
Polymer Flooding: Mobility Ratio and Thermal Stability
Polymer flooding addresses the mobility ratio problem. When injected water is significantly more mobile than reservoir oil — because oil viscosity is high or water relative permeability is high — water fingers through the reservoir, bypassing oil. Polymer increases water-phase viscosity, improving the mobility ratio and sweep efficiency.
The governing constraints are:
Oil viscosity range. Polymer flooding is most effective when oil viscosity falls within a range where polymer can achieve a favourable mobility ratio without requiring impractically high polymer concentrations. Very heavy oils exceed the practical viscosity range for conventional polymer alone; ASP (alkaline-surfactant-polymer) or thermal methods become necessary.
Reservoir temperature. This is the critical kill criterion for polymer flooding. Hydrolysed polyacrylamide (HPAM), the dominant polymer used in field applications, degrades at elevated temperatures, and the polymer flooding screening criteria review flag temperature as a hard upper limit for HPAM-based floods. Above the thermal stability threshold, polymer degrades in the reservoir before it can improve sweep, and the project fails regardless of other favourable conditions.
Salinity and hardness. High-salinity formation water and divalent cations (Ca²⁺, Mg²⁺) reduce polymer viscosity and accelerate degradation. Reservoir brine chemistry must be characterised before polymer selection. Sulfonated polyacrylamides and biopolymers offer better salinity tolerance but introduce their own constraints around injectivity and biological degradation.
Permeability. Polymer must be injectable at practical rates without fracturing the formation. Very low-permeability reservoirs present injectivity constraints that may make polymer flooding uneconomic regardless of fluid properties.
Thermal Flooding: Viscosity Reduction Through Heat
Thermal methods — steam drive, cyclic steam stimulation (CSS), and in-situ combustion — target heavy and extra-heavy crudes where viscosity at reservoir conditions is too high for displacement by gas or polymer. Heat reduces oil viscosity by orders of magnitude, mobilising oil that would otherwise be immobile.
Depth. Steam injection becomes thermally inefficient beyond moderate depths. Heat loss to overburden and underburden increases with depth, and steam quality at the sandface degrades. Very deep reservoirs are generally screened out of steam-based thermal floods on heat-loss grounds alone.
Reservoir thickness. Thin reservoirs lose disproportionate heat to adjacent formations. A minimum net pay thickness is required to justify thermal projects; the Mongolia oilfield study identifies pay thickness as a primary screening parameter for thermal methods (Anuudari & Min, 2025).
Oil gravity and viscosity. Thermal methods target low-API, high-viscosity crudes. Applying steam to a light, low-viscosity oil produces minimal incremental recovery relative to cost — the oil is already mobile. The TOPSIS study of Iraqi reservoirs confirms that oil viscosity weighting is highest for thermal method selection among the criteria evaluated (Rasul, 2026).
Formation type. Unconsolidated or poorly consolidated sands are common hosts for heavy oil and are generally compatible with steam injection. Carbonates present challenges for steam floods due to lower porosity, different wettability behaviour, and potential for steam channelling through natural fractures.
Comparative Screening Matrix
The table below summarises the primary accept/reject criteria. Cells contain qualitative guidance only; project-specific MMP calculations, polymer rheology tests, and thermal simulation are required before investment decisions.
| Parameter | CO₂ Flood | Polymer Flood | Thermal (Steam) |
|---|---|---|---|
| Oil API gravity | Light to medium; intermediates needed for miscibility | Light to medium-heavy | Heavy to extra-heavy |
| Oil viscosity | Low to moderate | Moderate; upper limit governs | High to very high |
| Reservoir depth | Sufficient for MMP; not excessively deep | Moderate range | Shallow to moderate |
| Reservoir temperature | Relevant to MMP calculation | Hard upper limit for polymer stability | Drives steam quality design |
| Permeability | Less critical than for chemical | Must support injectivity | Must support steam injection |
| Formation water salinity | Moderate sensitivity | High sensitivity; divalents critical | Low sensitivity |
| Net pay thickness | Moderate requirement | Moderate requirement | Thicker preferred to limit heat loss |
| Lithology | Sandstone or carbonate with good seal | Sandstone preferred | Unconsolidated sand preferred |
Illustrative Scenario
This scenario is illustrative and does not represent a named field or project.
A mature sandstone reservoir at moderate depth produces a medium-gravity crude with moderate viscosity and high water cut. Reservoir pressure is declining. Three EOR candidates are evaluated:
- CO₂ flood: Reservoir pressure is borderline for MMP at current conditions. Pressure maintenance through CO₂ injection could sustain miscibility, but the structural map shows limited closure, raising concern about CO₂ migration. WAG design would be required. Preliminary screening: conditional — requires MMP lab measurement and seal integrity review.
- Polymer flood: Reservoir temperature is within HPAM stability range. Permeability is sufficient for injectivity. Formation water salinity is moderate and hardness is low. Mobility ratio calculation indicates polymer could meaningfully improve sweep. Preliminary screening: favourable — advance to core flood testing.
- Steam flood: Oil viscosity is too low for thermal to provide incremental benefit over waterflooding. Depth and pay thickness are adequate, but the fluid target is wrong. Preliminary screening: not recommended.
The TOPSIS-based approach would formalise this weighting, assign scores across all criteria simultaneously, and produce a ranked shortlist with sensitivity analysis showing which parameter uncertainties most affect the ranking (Rasul, 2026).
Screening Checklist for Field Engineers
- Confirm reservoir pressure relative to estimated MMP before advancing CO₂ flood evaluation.
- Measure formation water salinity and divalent ion concentration before specifying polymer type.
- Verify reservoir temperature against the thermal stability limit of any candidate polymer.
- Map net pay thickness distribution — thin zones disqualify steam on heat-loss grounds.
- Assess structural closure and seal integrity for any gas injection scheme.
- Calculate mobility ratio under current waterflood conditions to quantify the polymer target.
- Identify lithology heterogeneity — fractures, thief zones, and laminations affect sweep for all three methods differently.
- Apply multi-criteria scoring (TOPSIS or equivalent) when two or more methods pass preliminary filters, to avoid single-parameter bias.
- Require laboratory confirmation — MMP slim-tube tests for CO₂, core flood rheology for polymer, thermal simulation history-match for steam — before committing to pilot design.
Conclusion
Screening is not a formality before the real engineering begins — it is the decision that determines whether the real engineering is worth doing. CO₂ flooding is constrained primarily by miscibility pressure and structural integrity. Polymer flooding is constrained by temperature stability, salinity, and permeability. Thermal flooding is constrained by depth, pay thickness, and oil viscosity. Applying multi-criteria frameworks, as demonstrated in recent Iraqi and Mongolian reservoir studies, reduces the risk of eliminating viable candidates or advancing unsuitable ones.
The immediate next step for any team facing an EOR selection decision is to compile the parameter dataset listed above, run a structured multi-criteria screen, and identify which one or two methods warrant laboratory confirmation. That sequence — data, screen, lab, pilot — is how capital gets committed to projects that recover oil rather than projects that recover lessons.