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CO2 Injection Modeling - Saline Aquifer 


Static and Dynamic reservoir modeling are essential part of 'Reservoir Characterization,' of 'Potential Storage' sites to mature them to a 'Qualified Sites' ready for permitting for the storage development project. Its is essential for making strategic business decisions for a successful storage project. Both analytical and numerical simulation are used, and not all project stages need numerical modeling. Generally no modeling is done at the 'Site Screening' stage, and simple models are initialed at 'Site Selection' stage to more complex models at 'Site Characterization' phase.

Key Modeling Areas

The reservoir modeling efforts for CO2 trapping & leakage need to focus in four key areas:

  1. Structural & Geological Modeling

  2. Geochemical Modeling

  3. Geomechanical Modeling

  4. Hydrogeological Modeling

The modeling should be fit-for-purpose, not all mechanism are modeled for all phases. For example if team is modeling the post injection period, then geo-mechanical model may not be necessary.



Both spatial and temporal (time) scale are important.

  • Modeling area should include near field, mid-field and far-field regions

  • Simulation time period and time steps is also important depending amount of CO2 injected and total volume of the area modeled; 

    • For example if mineralization is considered then simulation may runs hundreds or even a thousand years.


Complexity of Models

Models could be very simple or even analytical at 'Site Selection' phase

  • For example 2D areal/sector model to track plume shape & direction and or vertical extent

More complicated and detailed models are build at 'Site Characterization' stage that are 3d and coupled. Best example is coupling of Geo-mechanical coupled model with geological model.

Data Collection

Following data needs to be collected for each modeling area:

  1. Data - Structural & Geological Modeling

    • All existing seismic data (2D, VSP)

    • All existing 3D seismic

    • Logs, cores

  2. Data - Geochemical Modeling

    • Compositions

    • pH & Salinity

    • Conductivity

  3. Data - Geomechanical Modeling

    • Tensile Stress, Young Modulus

    • Fracture Orientation 

    • Logs & cores

  4. Data - Hydrogeological Modeling

    • DST - Drill Stem Tests  (samples, permeability)

    • Injection & Fall-Off test (Injectivity, pressures permeability, KH) 

    • Multi-Well Tests (Detect baffles & permeability barriers)

    • Multi-Zone test )Effectiveness of caps & seals

Modeling Trapping & Leakage Mechanisms

It is essential to model injection period and trapping and leakage mechanisms for long-term storage security and regulatory verification. The CO2 is injected in the reservoir at supercritical condition (1079 psia and 88 0F). At this state, CO2 is in indistinguishable vapor liquid phase, but behaves like liquid. Supercritical phase is preferred as it ensures stability of CO2 in the reservoir. Injection of CO2 in the saline aquifer is a Drainage process; i.e. water saturation (wetting phase), decreases and CO2 saturation increases. There are three dominant forces acting on CO2 in reservoir; viscous or inertial forces is active during injection, the bouncy takes over as injection stops, and subsequently capillary forces also come into effect.



There are four CO2 trapping mechanisms and one CO2 leakage mechanism to to be understood and modeled.

  1. Structural & Stratigraphic Trapping

  2. Hysteresis Trapping

  3. Solunbility Trapping

  4. Mineral Trapping

  5. CO2 Seal Leakage

There are other mechanisms that simulators also model but are not relevant for CO2 Injection in saline aquifer; these are for example; desorption option in CO2 Coal-bed Methane (CBM) process or impact of Ashphaltene precipitation in CO-EOR application.

  1. Structural / Hydrodynamic Trapping  


Trapping mechanisms is very similar to to hydrocarbon trapping mechanism in geological and stratigraphic structures. Injection of CO2 in the saline aquifer is a Drainage process (black line in figure below); i.e. water saturation (wetting phase), decreases and CO2 saturation increases with injection to a maximum value (Sgmax). During injection inertial or viscous forces are dominant.


As the injection stops, the buoyant forces take over, and CO2 which is lighter than saline aquifer brine, rises to structural high and goes up the structure and is hydrodynamical trapped under a sealing cap rock or against a sealing fault or stratigraphic pinch out as in stratigraphic trap. As long as pressure and temperatures stays above critical conditions the CO2 is stored structurally in supercritical conditions. If conditions are not met, they are stored in a gas phase.


The CMG/GEM simulated example of structural trapping is shown below; only structural trapping is acting and most of the CO2 plume migrates upwards.


2.  Hysteresis Trapping  

After the injection stops and buoyant CO2 has moved up the structure, the displaced formation brine replaces the CO2, this path taken by brine in displacing CO2 is an Imbibition process (denoted by red line in figure below), different from Drainage process (black line) and this hysteresis in relative permeability cause the CO2 to be trapped as residual gas saturation (Sgt). In Hysteresis trapping capillary forces take over the buoyant forces, trapping ganglia of CO2 with low leakage risk.


The CMG/GEM simulated example of structural trapping with hysteresis is shown below; Due to hysteresis trapping in the reservoir, only a small plume of CO2 goes upwards.


3. Solubility Trapping

A part of pure supercritical CO2 may also dissolve in brine and go int aqueous phase. Solubility mechanism is  weaker than hysteresis and may take much longer time. It is governed by Henry's law.

The solubility constant of CO2, is a function of temperature, pressure and salinity. It increases with increase in pressure and decreases with increase in temperature. Li & Nghiem (1986) and Harvey (1996) methods are used, the latter method can handle wider temperature and pressure ranges. The risk of leakage in solubility trapping is low, however brine can migrate with aquifer flow and if encounter a weak leakage plane the Co2 may escape.


4. Mineral Trapping

Trapping by mineral is the slowest and may effect over hundred or even thousands of years. It is however, the safest form of trapping as buoyant forces are permanently disconnected reducing any chance of leakage. The process of mineralization involves complex mineral reactions that can be modeled in the simulators.  The degree of mineralization depends on availability of ions (Ca++, Mg++, Fe++). Anorthite, Illite and Annite dissolution provides the ions respectively.

5. CO2 Seal Leakage


There are to key areas in Geomechanical Modeling that critical to understand and manage risks with CO2 Injection in saline aquifers.

  1. Cap-Rock/ Seal Integrity 

  2. Induced Seismicity

  1. Cap-Rock / Seal Integrity

Onne of the critical parameter to be evaluated before issuing UIC permitting is to demonstrate that increase in pore pressure from CO2 injection will not violate the cap-rock seal integrity for CO2 to leak. As the injection starts, the pore press increases under total constant stress, the effective Normal stress starts decreasing until a point reaches when  tensile stress will cause the rock to fail and the CO2 will escape to the overburdened as a leak.

Barton - Bandis model is used to predict geomechanical failure in tensile stress. CMG/GEM Simulator offers excellent functionality to model this in a geomechanical model coupled with geological model. The fractures are define in and around seal blocks, the fracture open under reduced stress and have certain permeability to allow leakage. The figure blow shows reduction in effective stress (Right figure: Blue cells), and permeability in fractures is created (Left figure ; cells in red).


These induced fractures resulting from increasing pore pressure and reduced tensile stresses results in a seal failure allowing CO2 to leak into the overburden (Figure below)


2. Induced Seismicity

CO2 injection may increase the pore pressure in a reservoir, this will affect the stability of preexisting faults and fractures. When pore pressure exceeds in-situ stresses on faults or fractures, slippage may occur. This slippage or rupture caused by fluid injection is referred to as 'induced seismicity'.

There are simulators that combine (coupled models)  fluid flow simulations and combine them with deformation and stress analysis to asses potential for fault-slip from injection.

  • TOUGHFLAC -Non-isothermal multiphase flow in unfractured and fractured media with geomechanical coupling

  • STOMP: Non-isothermal multiphase flow in porous media, coupled with reactive transport

  • ABACUS:Geomechanical, single and two-phase flow

There are also earthquake simulator that can be coupled

  • OpenSHA

  • RSQSim

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