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  • Tariq K. Siddiqui

Engineering CO2 EOR: Subsurface Considerations

Updated: Nov 12, 2022

By Tariq Siddiqui

CO2 Enhanced Oil Recovery (EOR) is well researched subsurface technology that is tested and proven in the field. When engineered well, it provides the additional post water-flood oil recovery (10-20 %) and helps in reducing the carbon footprint. The other subsurface technology to store CO2 is geological sequestration.

This article is a primer for executives and practitioners; it provides an overview of the subsurface consideration, before you embark on engineering the project. Upstream EP Advisors LLC can help you with CO2 EOR: CO2 Injection Variants

Generally, CO2 is not first contact miscible but achieves miscibility after several contacts. Due to this reason and its high cost, CO2 is injected in combination with other fluids. There are several variants of CO2 injection used in the field:

  • Continuous CO2 injection

  • CO2 injection followed by gas

  • CO2 injection followed by water

  • Water-Alternating-Gas (WAG) injection

  • CO2 Solvent injection

  • CO2 /Heat Injection followed by water

Geoscience/Reservoir Consideration

There are many factors that govern the CO2 injection, the important ones are:

  • Immiscible vs. Miscible Injection:

Miscible CO2 injection is more suitable in light to medium crudes,

Immiscible displacement (generally not used) may work on heavier crudes

  • Secondary vs. Tertiary Application:

CO2 can be used as a secondary and tertiary recover (after water-floding)

  • Horizontal vs. Vertical Displacement:

Reservoirs that have high dip or relief (vertically), the gravity segregation mechanism will help the vertical displacement of CO2 followed by the drive-gas that will achieve mobility control. In the low dip or relief reservoirs (horizontal), WAG displacement of CO2 will better achieve mobility control.

Mechanisms for Increased Recovery

Following reservoir factors will help improve CO2 recovery:

  • Miscibility Effects: Reduction in interfacial tension and residual oil saturation

  • Crude Oil Swelling: Increases the stock-tank oil (increase in FVF)

  • Reduction of Crude Oil Viscosity: increases the oil production rates

  • Increase in Injectivity: Improves the amount of gas injected

  • Internal Solution gas drive: improves the overall recovery

  • Improve relative permeability effects: will result in additional oil recovery

Reservoir Screening

Following are some geological and reservoir engineering consideration that can help in a successful design of CO2 injection.


Ensure, significant data is available or collected for the geological characterization of reservoir. Following factors may impair the performance of the CO2 injection & reduce the oil recovery:

  • Low Net-to-Gross (NTG) reservoirs are not suited for CO2 injection (low net pay)

  • Highly heterogeneous reservoirs cause premature CO2 breakthrough

  • Highly stratified reservoirs will cause injection fingering and must be avoided

  • Naturally fractured and highly faulted reservoirs will impair the performance

  • Volumetric Sweep: Miscible CO2 flood can theoretically recover 100% of remaining oil, natural heterogeneity will limit the volumetric sweep to ~ 60%

  • Poor permeability and porosity development will reduce storage and injection

  • Thin pay zones underlain by thick large aquifers.

  • Shale barriers; especially in vertical displacement are very detrimental

  • Baffles in the reservoirs will reduce the sweep efficiency

  • Vuggy Carbonates; especially if they highly vugular and fissured

  • Very deep reservoirs high injection pressure requirement may preclude deep zones


Oil In Place before starting CO2 EOR should be adequate to make economic sense post waterflood oil saturations (Soil) should be no less than 40%

  • Oil Gravity: Best API gravity range: 25 < API Gravity < 30 (Max. range 15-55 API)

  • Reservoir Temperatures: Best results are achieved when Temperature < 200 F

  • Compressibility: Avoid highly volatile & condensate reservoirs on your first trial

  • Initial Water Saturation: Initial Sw < 50%; Avoid tight/silty reservoirs (Sw > 50%)

  • Formation Water Salinity: < 200,000 ppm or else miscibility would be difficult

Data Review/Collection

Beside reviewing existing performance data and collecting standard reservoir data (Seismic, logs, cores, SCAL, fluid, pressure, temperature etc.), additional specific data is needed to evaluate the performance of CO2 flood:

  • Minimum Miscibility Pressure (MMP) test

  • Swelling test for Crude oil

  • Viscosity reduction test

  • Asphaltine precipitation test

  • Properties of carbonated water


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